2000 Annual Reports
American Electric Power Company, Inc.
AEP Generating Company
Appalachian Power Company
Central Power and Light Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
West Texas Utilities Company
Audited Financial Statements and
Management's Discussion and Analysis
Contents
Page
Glossary of Terms i
Forward Looking Information iv
American Electric Power Company, Inc. and Subsidiary Companies
Selected Consolidated Financial Data A-1
Management's Discussion and Analysis of Results of Operations A-2
Consolidated Statements of Income A-8
Consolidated Balance Sheets A-9
Consolidated Statements of Cash Flows A-11
Consolidated Statements of Common Shareholders' Equity A-12
Schedule of Consolidated Cumulative Preferred
Stocks of Subsidiaries A-13
Schedule of Consolidated Long-term Debt of Subsidiaries A-14
Index to Notes to Consolidated Financial Statements A-15
Management's Responsibility A-16
Independent Auditors' Report A-17
AEP Generating Company
Selected Financial Data B-1
Management's Narrative Analysis of Results of Operations B-2
Statements of Income and Statements of Retained Earnings B-3
Balance Sheets B-4
Statements of Cash Flows B-6
Statements of Capitalization B-7
Index to Notes to Financial Statements B-8
Independent Auditors' Report B-9
Appalachian Power Company and Subsidiaries
Selected Consolidated Financial Data C-1
Management's Discussion and Analysis of Results of Operations C-2
Consolidated Statements of Income C-5
Consolidated Balance Sheets C-6
Consolidated Statements of Cash Flows C-8
Consolidated Statements of Retained Earnings C-9
Consolidated Statements of Capitalization C-10
Schedule of Long-term Debt C-11
Index to Notes to Consolidated Financial Statements C-12
Independent Auditors' Report C-13
Central Power & Light Company and Subsidiaries
Selected Consolidated Financial Data D-1
Management's Discussion and Analysis of Results of Operations D-2
Consolidated Statements of Income D-5
Consolidated Balance Sheets D-6
Consolidated Statements of Cash Flows D-8
Consolidated Statements of Retained Earnings D-9
Consolidated Statements of Capitalization D-10
Schedule of Long-term Debt D-11
Index to Notes to Consolidated Financial Statements D-12
Independent Auditors' Report D-13
Columbus Southern Power Company and Subsidiaries
Selected Consolidated Financial Data E-1
Management's Narrative Analysis of Results of Operations E-2
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings E-5
Consolidated Balance Sheets E-6
Consolidated Statements of Cash Flows E-8
Consolidated Statements of Capitalization E-9
Schedule of Long-term Debt E-10
Index to Notes to Consolidated Financial Statements E-11
Independent Auditors' Report E-12
Indiana Michigan Power Company and Subsidiaries
Selected Consolidated Financial Data F-1
Management's Discussion and Analysis of Results of Operations F-2
Consolidated Statements of Income F-5
Consolidated Balance Sheets F-6
Consolidated Statements of Cash Flows F-8
Consolidated Statements of Retained Earnings F-9
Consolidated Statements of Capitalization F-10
Schedule of Long-term Debt F-11
Index to Notes to Consolidated Financial Statements F-13
Independent Auditors' Report F-14
Kentucky Power Company
Selected Financial Data G-1
Management's Narrative Analysis of Results of Operations G-2
Statements of Income and Statements of Retained Earnings G-4
Balance Sheets G-5
Statements of Cash Flows G-7
Statements of Capitalization G-8
Schedule of Long-term Debt G-9
Index to Notes to Financial Statements G-10
Independent Auditors' Report G-11
Ohio Power Company and Subsidiaries
Selected Consolidated Financial Data H-1
Management's Discussion and Analysis of Results of Operations H-2
Consolidated Statements of Income H-5
Consolidated Balance Sheets H-6
Consolidated Statements of Cash Flows H-8
Consolidated Statements of Retained Earnings H-9
Consolidated Statements of Capitalization H-10
Schedule of Long-term Debt H-11
Index to Notes to Consolidated Financial Statements H-13
Independent Auditors' Report H-14
Public Service Company of Oklahoma and Subsidiaries
Selected Consolidated Financial Data I-1
Management's Narrative Analysis of Results of Operations I-2
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings I-4
Consolidated Balance Sheets I-5
Consolidated Statements of Cash Flows I-7
Consolidated Statements of Capitalization I-8
Schedule of Long-term Debt I-9
Index to Notes to Consolidated Financial Statements I-10
Independent Auditors' Report I-11
Southwestern Electric Power Company and Subsidiaries
Selected Consolidated Financial Data J-1
Management's Discussion and Analysis of Results of Operations J-2
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings J-5
Consolidated Balance Sheets J-6
Consolidated Statements of Cash Flows J-8
Consolidated Statements of Capitalization J-9
Schedule of Long-term Debt J-10
Index to Notes to Consolidated Financial Statements J-11
Independent Auditors' Report J-12
West Texas Utilities Company
Selected Financial Data K-1
Management's Narrative Analysis of Results of Operations K-2
Statements of Income and Statements of Retained Earnings K-4
Balance Sheets K-5
Statements of Cash Flows K-7
Statements of Capitalization K-8
Schedule of Long-term Debt K-9
Index to Notes to Financial Statements K-10
Independent Auditors' Report K-11
Combined Notes to Financial Statements L-1
Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters M-1
iv
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this
report, they have the meanings indicated below.
Term Meaning
2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the
amount of stranded costs and the recovery of such costs.
AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................ American Electric Power Company, Inc.
AEP Consolidated................... AEP and its majority owned subsidiaries consolidated.
AEP Credit....................,Inc. AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and unaffiliated domestic electric utility companies.
AEP East electric operating
companies..........................APCo, CSPCo, I&M, KPCo and OPCo.
AEPR............................... AEP Resources, 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.
AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale system sales of the member
companies.
AEP West electric operating
companies.......................... CPL, PSO, SWEPCo and WTU.
AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is
capitalized and recovered through depreciation over the service life of domestic
regulated electric utility plant.
Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
utilities.
Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and
OPCo.
APCo............................... Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................ Arkansas Public Service Commission.
Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation.
CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI............................... Corporate owned life insurance program.
Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................ Central Power and Light Company, an AEP electric utility subsidiary.
CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP.
CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit.
DHMV............................... Dolet Hills Mining Venture.
DOE................................ United States Department of Energy.
ECOM............................... Excess Cost Over Market.
ENEC............................... Expanded Net Energy Costs.
EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT.............................. The Electric Reliability Council of Texas.
EWGs............................... Exempt Wholesale Generators.
FASB............................... Financial Accounting Standards Board.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB ............................... First Mortgage Bond.
FUCOs.............................. Foreign Utility Companies.
GAAP............................... Generally Accepted Accounting Principles.
I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPC................................ Installment Purchase Contract.
IRS................................ Internal Revenue Service.
IURC............................... Indiana Utility Regulatory Commission.
ISO................................ Independent system operator.
Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary.
KPSC............................... Kentucky Public Service Commission.
KWH................................ Kilowatthour.
LIG................................ Louisiana Intrastate Gas.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
Midwest ISO........................ An independent operator of transmission assets in the Midwest.
MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool......................... AEP System's Money Pool.
MPSC............................... Michigan Public Service Commission.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatthour.
NEIL............................... Nuclear Electric Insurance Limited.
Nox................................ Nitrogen oxide.
Nox Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states
including seven of the states in which AEP companies operates.
NP................................. Notes Payable.
NRC................................ Nuclear Regulatory Commission.
Ohio Act........................... The Ohio Electric Restructuring Act of 1999.
Ohio EPA........................... Ohio Environmental Protection Agency.
OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary.
OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a
44.2% equity interest.
PCBs............................... Polychlorinated Biphenyls.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP.............................. Potentially Responsible Party.
PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO............................... The Public Utilities Commission of Ohio.
PUCT............................... The Public Utility Commission of Texas.
PUHCA.............................. Public Utility Holding Company Act of 1935, as amended.
PURPA.............................. The Public Utility Regulatory Policies Act of 1978.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
RTO................................ Regional Transmission Organization.
SEC................................ Securities and Exchange Commission.
SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
-------------------------------------
Types of Regulation.
-------------------
SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of
------------------------------------
Application of Statement 71.
SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
--------------------------------
Long-Lived Assets and for Long-Lived Assets to be Disposed of.
--------------------------------------------------------------
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
-------------------------------------
and Hedging Activities.
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light
Company, an AEP electric utility subsidiary .
STPNOC............................. STP Nuclear Operating Company, a non-profit Texas corporation which operates STP on behalf
of its joint owners including CPL.
Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Appeals Court................ The Third District of Texas Court of Appeals.
Texas Legislation.................. Legislation enacted in 1999 to restructure the electric utility industry in Texas.
Travis District Court.............. State District Court of Travis County, Texas.
TVA ............................... Tennessee Valley Authority.
U.K................................ The United Kingdom.
UN................................. Unsecured Note.
VaR................................ Value at Risk, a method to quantify risk exposure.
Virginia SCC....................... Virginia State Corporation Commission.
WV................................. West Virginia.
WVPSC.............................. Public Service Commission of West Virginia.
WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary.
Yorkshire.......................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP
and New Century Energies.
Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
FORWARD LOOKING INFORMATION
- -----------------------------------------------------------------------------
This discussion includes forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934. These forward-looking
statements reflect assumptions, and involve a number of risks and uncertainties.
Among the factors both foreign and domestic that could cause actual results to
differ materially from forward looking statements are: electric load and
customer growth; abnormal weather conditions; available sources of and prices
for coal and gas; availability of generating capacity; the impact of the merger
with CSW including actual merger savings being less than the related rate
reductions; risks related to energy trading and construction under contract; the
speed and degree to which competition is introduced to our power generation
business; the structure and timing of a competitive market for electricity and
its impact
on prices; the ability to recover net regulatory assets, other stranded costs
and implementation costs in connection with deregulation of generation in
certain states; new legislation and government regulations; the ability to
successfully control costs; the success of new business ventures; international
developments affecting our foreign investments; the economic climate and growth
in our service and trading territories both domestic and foreign; the ability of
the Company to successfully challenge new environmental regulations and to
successfully litigate claims that the Company violated the Clean Air Act;
successful resolution of litigation regarding municipal franchise fees in Texas;
inflationary trends; changes in electricity and gas market prices; interest
rates; foreign exchange rates, and other risks and unforeseen events.
AMERICAN ELECTRIC POWER COMPANY, INC.
AND SUBSIDIARY COMPANIES
A-17
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Selected Consolidated Financial Data
Year Ended December 31, 2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------
INCOME STATEMENTS DATA (in millions):
Total Revenues $13,694 $12,407 $11,840 $11,163 $11,017
Operating Income 2,026 2,325 2,280 2,198 2,368
Income From Continuing Operations 302 986 975 949 871
Discontinued Operations - - - - 132
Extraordinary Loss (35) (14) - (285) -
Net Income 267 972 975 664 1,003
December 31, 2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------
BALANCE SHEETS DATA (in millions):
Property, Plant and Equipment $38,088 $36,938 $35,655 $33,496 $32,443
Accumulated Depreciation
and Amortization 15,695 15,073 14,136 13,229 12,494
------- ------- ------- ------- -------
Net Property,
Plant and Equipment $22,393 $21,865 $21,519 $20,267 $19,949
======= ======= ======= ======= =======
Total Assets $54,548 $35,719 $33,418 $30,092 $29,228
Common Shareholders' Equity 8,054 8,673 8,452 8,220 8,334
Cumulative Preferred Stocks
of Subsidiaries:
Not Subject to Mandatory Redemption 61 63 222 223 382
Subject to Mandatory Redemption* 100 119 128 154 543
Trust Preferred Securities 334 335 335 335 -
Long-term Debt* 10,754 11,524 11,113 9,354 9,112
Obligations Under Capital Leases* 614 610 539 549 422
*Including portion due within one year
Year Ended December 31, 2000 1999 1998 1997 1996
- -----------------------------------------------------------------------------------------
COMMON STOCK DATA:
Earnings per Common Share:
Continuing Operations $0.94 $3.07 $3.06 $2.99 $2.79
Discontinued Operations - - - - 0.42
Extraordinary Loss (.11) (.04) - (0.90) -
----- ----- ----- ----- ------
Net Income $0.83 $3.03 $3.06 $2.09 $3.21
===== ===== ===== ===== =====
Average Number of Shares
Outstanding (in millions) 322 321 318 316 312
Market Price Range: High $48-15/16 $48-3/16 $53-5/16 $ 52 $44-3/4
Low 25-15/16 30-9/16 42-1/16 39-1/8 38-5/8
Year-end Market Price 46-1/2 32-1/8 47-1/16 51-5/8 41-1/8
Cash Dividends on Common* $2.40 $2.40 $2.40 $2.40 $2.40
Dividend Payout Ratio* 289.2% 79.2% 78.4% 114.8% 74.5%
Book Value per Share $25.01 $26.96 $26.46 $25.91 $26.45
The consolidated financial statements give retroactive effect to AEP's merger
with CSW, which was accounted for as a pooling of interests, as if AEP and CSW
had always been combined. *Based on AEP historical dividend rate.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Management's Discussion and Analysis of Results of Operations
American Electric Power Company, Inc. (AEP) is one of the largest
investor owned electric public utility holding companies in the U.S. serving
over 4.8 million retail customers in eleven states (Arkansas, Indiana, Kentucky,
Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West
Virginia) and selling bulk power at wholesale both within and beyond its
domestic retail service area. AEP has 38,000 megawatts of generation and over
38,000 miles of transmission lines and 186,000 miles of distribution lines in
the U.S. Subsidiaries own 1,250 megawatts as independent power producers in
Colorado, Florida and Texas. In recent years AEP has expanded its domestic
operations to include gas marketing, processing, storage and transportation
operations, electric, gas and coal trading operations and telecommunication
services and invested in and acquired foreign distribution operations in the
U.K., Australia and Brazil and electricity generating facilities in China and
Mexico. Subsidiaries also provide power engineering, generation and transmission
plant maintenance and construction, and energy management services worldwide.
AEP is one of the largest traders of electricity and gas in the U.S. In 2000 we
established an energy trading operation in Europe.
Presently AEP is in the process of restructuring its assets and
operations to separate the regulated operations from the non-regulated
operations and to functionally and, where permitted by law, structurally
unbundle its domestic vertically integrated electric utility business into
separate generation, transmission and distribution businesses. The purpose of
this restructuring is to focus our management and technical expertise to
maximize the potential for growth of both non-regulated and regulated
operations, to evaluate the performance of these separate and different
businesses and
to meet the separation requirements of federal and state restructuring
legislation and codes of conduct. Five of AEP's 11 states (Arkansas, Ohio,
Texas, Virginia, and West Virginia) are in various stages of transitioning to
deregulation of generation and to customer choice and market-based pricing from
monopoly and regulator set rates for the retail sale of electricity. When the
transition is implemented in those states, transmission will be regulated by the
Federal Energy Regulatory Commission and distribution services will continue to
be cost-based rate regulated by the states. Although we are actively supporting
the transition to competition, there is little progress in the remaining six
states. Therefore, in the near term, our retail electric business in Indiana,
Kentucky, Louisiana, Michigan, Oklahoma and Tennessee will continue to be
operated as an integrated public utility subject to state regulation. The
foreign energy delivery investments and operations are not cost-based rate
regulated but they are generally subject to different forms of price controls,
such as capped prices. As such these foreign investments and operations will be
included in our unbundled regulated business.
On November 1, 2000, AEP filed a restructuring plan under PUHCA with the
SEC seeking approval to form two wholly owned holding company subsidiaries of
AEP to separately own AEP's regulated and non-regulated subsidiaries and to
structurally separate into separate legal entities along functional lines (i.e.
generation, transmission and distribution) six of the electric utility operating
companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU). These six operating
companies do business in the states that are implementing restructuring
(Arkansas, Ohio, Texas, Virginia and West Virginia). The remaining domestic
electric operating companies will be functionally unbundled for internal
management and internal reporting purposes and for financial segment reporting
but will not be structurally unbundled into separate companies since state law
and/or regulation prohibits such action. One holding company will hold the
unbundled non-regulated electric generation subsidiaries and the non-regulated
domestic and foreign subsidiaries including the European trading company and the
foreign generating companies, while the other holding company will hold the
bundled domestic regulated electric utility companies and the foreign
distribution companies. The restructuring will facilitate management's strategy
to grow the deregulated wholesale electricity supply and electric and gas
trading business and to evaluate the other business operations to explore ways
to improve their results of operations and to continuously evaluate and where
necessary reshape our business to grow earnings and improve shareholder value.
The legal transfer of assets and structural separation plans will also require
FERC, certain state and other regulatory approvals.
2000 was a year of accomplishment that positions AEP for earnings
growth. In 2000 we completed the merger of AEP and CSW, greatly increasing the
scope and size of AEP; achieved the targeted merger savings; returned the two
unit 2,110 MW Cook Plant to service after an extended outage; reached a
settlement on a restructuring plan in Ohio that will allow our electric
generating and supply business in Ohio to transition over five years to market
pricing and recover its stranded cost, including generation-related regulatory
assets; continued to grow our domestic electricity and gas trading businesses to
become one of the largest electricity and gas traders; established and grew an
energy trading operation in Europe; added to our gas assets and operations with
the announcement in the first quarter of 2001 of the planned acquisition of
Houston Pipe Line Company; restructured our incentive compensation plans to more
closely align them with the creation of shareholder value; reduced our power
plant operation and maintenance costs while increasing plant availability;
established AEP Pro Serv, Inc. to market AEP's expertise in power engineering,
environmental engineering and generating plant maintenance services worldwide;
closed contracts to design, build, operate and market the output of new power
plants for Dow Chemical, Buckeye Power and Columbia Energy; and initiated a
re-design of our existing PeopleSoft financial software as part of an
enterprise-wide application to fully integrate our financial, work management
and supply chain software and to provide data on a business unit basis
consistent with our corporate separation initiative.
Although 2000 was a year marked by significant accomplishments that
position AEP for future earnings growth, it resulted in a reduction in earnings
and earnings per share due mainly to non-recurring items, such as: a loss
incurred from a court decision disallowing tax deductions for interest related
to AEP's COLI program; the write-off of non-recoverable merger costs; the
expensing of Cook nuclear restart costs in contrast to 1999 when a significant
portion of the restart costs were deferred with regulatory approval; the
write-off of certain extraordinary costs that were stranded and liabilities
incurred in connection with the restructuring of the regulation of the electric
utility business in Ohio, Virginia, and West Virginia to transition that portion
of AEP's domestic electricity supply business from cost-based rate regulation to
customer choice and market pricing; the recognition of losses associated with a
CSW investment in Chile which was sold in the fourth quarter; an impairment
writedown of AEP's investment in Yorkshire to reflect a pending sale of the
investment in 2001; and write-offs of unrecoverable contract costs and goodwill
on certain of CSW's non-regulated businesses acquired in the merger.
Earnings in 2001 are expected to improve significantly with the return
of Cook Plant's 2,110 MW of generating capacity due to the completion of restart
efforts and the cessation of significant restart costs at Cook and the growth of
our wholesale marketing and trading business.
Our focus for 2001 will be on completing our corporate separation plan
to separate our regulated and non-regulated businesses. We believe that a
successful implementation of this plan will support our business objective of
unlocking shareholder value by providing managers with a simpler structure
through which business unit performance can be more easily anticipated and
monitored thereby focusing management attention; permitting more efficient
financing; and meeting the regulatory codes of conduct required as part of
industry restructuring.
Although management expects that the future outlook for results of
operations is excellent there are contingencies, challenges and obstacles to
overcome and manage, such as new more stringent Federal EPA environmental
requirements and recent complaints and related litigation, further delays in
transition to competition supported in part by concerns that California's energy
crisis could happen in our service territory, the recovery of generation-related
regulatory assets and other stranded costs in Texas and any additional state
jurisdictions that we can successfully promote the adoption of customer choice
and a transition to market pricing from regulated rate setting, franchise fee
litigation in Texas, litigation concerning AEP's financial disclosures regarding
the extended Cook Plant safety outage and timing of the successful completion of
restart efforts, the amortization of transition regulatory assets from the
introduction of competition to our previously regulated domestic generation
business and the amortization of deferred costs from the successful effort to
restart Cook Plant and to merge AEP and CSW and the outcome of litigation to
recover $90 million of duplicate tax expense from May 2001 to April 2002
resulting from restructuring in Ohio. These challenges, contingencies and
obstacles, which are discussed in detail in the Notes to Consolidated Financial
Statements and in Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters, are receiving management's full attention and
we intend to work diligently to resolve these matters by finding workable
solutions that balance the interests of our customers, our employees and our
shareholders.
Results of Operations
Net Income
Although revenues increased by $1.3 billion net income declined to $267
million or $0.83 per share in 2000 from $972 million or $3.03 per share in 1999.
The decrease was primarily due to Cook Nuclear Plant restart costs, a
disallowance of tax deductions for corporate owned life insurance (COLI),
expensing of costs related to AEP's recently completed merger with CSW, write
offs related to non-regulated subsidiaries and an extraordinary loss from the
discontinuance of regulatory accounting for generation in certain states. In
1999 net income was virtually un-changed as increased expenses to prepare the
Cook Nuclear Plant for restart, net of related deferrals, were offset by a gain
from a sale of a 50% interest in a cogeneration project.
Revenues Increase
AEP's revenues include a significant number of transactions from the
trading of electricity and gas. Revenues from trading of electricity are
recorded net of purchases as domestic electric utility wholesale sales for
transactions in AEP's traditional marketing area (up to two transmission systems
from the AEP service territory) and as revenues from worldwide electric and gas
operations for transactions beyond two transmission systems from AEP. Revenues
from gas trading are recorded net of purchases and reported in revenues from
worldwide electric and gas operations. Trading transactions involve the purchase
and sale of substantial amounts of electricity and gas.
The level of electricity trading trans-actions tends to fluctuate due to
the highly competitive nature of the short-term (spot) energy market and other
factors, such as af-filiated and unaffiliated generating plant avail-ability,
weather conditions and the economy. The FERC rules, which introduced a greater
degree of competition into the wholesale energy market, have had a major effect
on the volume of electricity trading as most electricity is traded in the
short-term market.
AEP's total revenues increased 10% in 2000 and 5% in 1999. The table
below shows the changes in the components of revenues from domestic electric
utility operations and worldwide electric and gas operations. While worldwide
electric and gas operations revenues increased 12% in 2000, most of the increase
in total revenues was caused by the increased revenues from domestic electric
utility operations.
Increase (Decrease)
From Previous Year
(Dollars in Millions) 2000 1999
Amount % Amount %
Domestic Electric
Utility Operations:
Retail:
Residential $ 230 $ 18
Commercial 163 56
Industrial (71) 11
Other 25 7
------ -----
347 4.2 92 1.1
Wholesale 672 59.9 (145)(11.5)
Other (30)(6.8) 57 15.3
------ -----
Total Domestic
Electric Utility
Operations 989 10.1 4 -
Worldwide Electric
and Gas Operations 298 11.6 563 28.1
------ -----
Total $1,287 10.4 $ 567 4.8
====== =====
The increase in total revenues from domestic electric utility operations
in 2000 was primarily due to a 38% increase in wholesale sales volume and
increased retail fuel revenues as a result of higher gas prices used to generate
electricity. The reduction in industrial revenues in 2000 is attributable to the
expiration of a long-term contract on December 31, 1999. The significant
increase in wholesale sales volume, which accounted for a 60% increase in
wholesale revenues, resulted from efforts to grow AEP's energy marketing and
trading operations, favorable market conditions, and the availability of
additional generation due to the return to service of one of the Cook Plant
nuclear units in June 2000 and improved generating unit availability due mainly
to improved outage management. The second Cook Plant unit which returned to
service in December 2000 did not have a significant impact on revenues.
In 1999 revenues from domestic electric utility operations were
unchanged. A 1% gain in retail revenues was more than offset by a 12% decline in
wholesale revenues. The 12% decline in wholesale revenues in 1999 was
predominantly due to a decrease in wholesale energy sales and a reduction in net
revenues from power trading due to a decline in margins. The decrease in
wholesale sales reflects the expiration in July 1998 of a power contract which
supplied power to several municipal customers and the decision by another
wholesale customer who buys energy under a unit power agreement not to take
energy from AEP during an outage of that unit. The decline in wholesale margins
in 1999 reflects the moderation of weather and the effected capacity shortages
experienced in the summer of 1998.
Revenues from worldwide electric and gas operations increased 12% in
2000 due to increased natural gas and gas liquid product prices. Volumes of
natural gas remained consistent with the prior year, however, prices increased
significantly.
In 1999 revenues derived from worldwide electric and gas operations
increased 28%. This increase is primarily due to the acquisitions in December
1998, of CitiPower in Australia and of LIG, and the commercial operation of a
two-unit 250 MW coal-fired generating plant in China.
Operating Expenses Increase
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions) 2000 1999
Amount % Amount %
Fuel and
Purchased Power $ 679 19.7 $ (6) (0.2)
Maintenance and
Other Operation 342 12.8 79 3.0
Merger Costs 203 - - -
Depreciation and
Amortization 51 5.0 22 2.2
Taxes Other Than
Income Taxes 7 1.1 5 0.8
Worldwide Electric
and Gas
Operations 304 13.3 422 22.7
------ ----
Total $1,586 15.7 $522 5.5
====== ====
Fuel and purchased power expense increased 20% in 2000 due to a
significant increase in the cost of natural gas used for generation. Natural gas
usage for generation declined 5% while the cost of natural gas consumed rose
60%. Net income was not impacted by this significant cost increase due to the
operation of fuel recovery mechanisms. These fuel recovery mechanisms generally
provide for the deferral of fuel costs above the amounts included in rates or
the accrual of revenues for fuel costs not yet recovered. Upon regulatory
commission review and approval of the unrecovered fuel costs, the accrued or
deferred amounts are billed to customers.
The increase in maintenance and other operation expense in 2000 was
mainly due to increased expenditures to prepare the Cook Plant nuclear units for
restart following an extended NRC monitored outage and increased usage of and
prices for emissions allowances. The increase in Cook Plant restart costs
resulted from the effect of deferring restart costs in 1999 and an increase in
the restart expenditure level. The Cook Plant began an extended outage in
September 1997 when both nuclear generating units were shut down because of
questions regarding the operability of certain safety systems. In 1999 a portion
of incremental restart expenses were deferred in accordance with IURC and MPSC
settlement agreements which resolved all jurisdictional rate-related issues
related to the Cook Plant's extended outage. Unit 2 returned to service in June
and achieved full power operation on July 5, 2000 and Unit 1 returned to service
in December and achieved full power operation on January 3, 2001. The increase
in emission allowance usage and prices resulted from the stricter air quality
standards of Phase II of the 1990 Clean Air Act Amendments, which became
effective on January 1, 2000. The increase in maintenance and other operation
expense in 1999 was primarily due to a NRC required 10-year inspection of STP
Units 1 and 2 and increased expenditures to prepare the Cook Plant nuclear units
for restart. Although a portion of Cook Plant restart costs were deferred in
1999 pursuant to regulatory orders, net expenditures charged to expense
increased over 1998.
With the consummation of the merger with CSW, certain deferred merger
costs were expensed. The merger costs charged to expense included transaction
and transition costs not allocable to and recoverable from ratepayers under
regulatory commission approved settlement agreements to share net merger
savings.
Worldwide electric and gas operations expense in 2000 increased 13% to
$2.6 billion from $2.3 billion. The increase was due to the increase in natural
gas prices, the write down to market value of a CSW available-for-sale
investment in a Chilean-based electric company sold in December 2000 and the
effect of a gain in 1999 on the planned sale of a 50% interest in a cogeneration
project. Federal law limits ownership in qualifying cogeneration facilities to
50%. CSW Energy constructed the project and completed the sale of a 50% interest
in the project to an unaffiliated entity in 1999. Expenses of the worldwide
electric and gas operations increased in 1999 due to the addition of expenses of
businesses acquired in December 1998 and the start of commercial operation of
the two-unit 250 MW coal-fired generating plant in China.
Interest and Preferred Dividends
In 2000 interest and preferred stock dividends increased by 16% to
$1,160 million from $996 million in 1999 due to additional interest expense from
the ruling on the litigation with the government disallowing COLI tax deductions
and AEP's intention to maintain flexibility for corporate separation by issuing
short-term debt at flexible rates. The use of fixed interest rate swaps has been
employed to mitigate the risk from floating interest rates.
The 11% increase in interest and preferred stock dividends in 1999 was
due primarily to increased interest expense on long-term debt. Long-term debt
outstanding increased $564 million in 1999.
Other Income
Other income decreased from $139 million in 1999 to $33 million in 2000
primarily due to a write-down of AEP's Yorkshire investment to reflect a
proposed sale in 2001, losses of non-regulated subsidiaries accounted for on an
equity basis, and a charge for the discontinuance of an electric storage water
heater demand side management program.
Other income increased 46% in 1999 primarily due to gains from the sale
of investments at SEEBOARD and from interest income related to a cogeneration
power plant.
Income Taxes
Income taxes increased in 2000 primarily due to an unfavorable ruling in
AEP's suit against the government over interest deductions claimed relating to
AEP's COLI program and nondeductible merger related costs.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Income
- ------------------------------------------------------------------------------
(in millions - except per share amounts)
Year Ended December 31,
-------------------------------------
2000 1999 1998
---- ---- ----
REVENUES:
Domestic Electric Utility Operations $10,827 $ 9,838 $ 9,834
Worldwide Electric and Gas Operations 2,867 2,569 2,006
------- ------- -------
TOTAL REVENUES 13,694 12,407 11,840
------- ------- -------
EXPENSES:
Fuel and Purchased Power 4,128 3,449 3,455
Maintenance and Other Operation 3,017 2,675 2,596
Non-recoverable Merger Costs 203 - -
Depreciation and Amortization 1,062 1,011 989
Taxes Other Than Income Taxes 671 664 659
Worldwide Electric and Gas Operations 2,587 2,283 1,861
------- ------- -------
TOTAL EXPENSES 11,668 10,082 9,560
------- ------- -------
OPERATING INCOME 2,026 2,325 2,280
OTHER INCOME (net) 33 139 95
------- ------- --------
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES 2,059 2,464 2,375
INTEREST AND PREFERRED DIVIDENDS 1,160 996 898
------- ------- -------
INCOME BEFORE INCOME TAXES 899 1,468 1,477
INCOME TAXES 597 482 502
------- ------- -------
INCOME BEFORE EXTRAORDINARY ITEM 302 986 975
EXTRAORDINARY LOSSES:
DISCONTINUANCE OF REGULATORY ACCOUNTING
FOR GENERATION (35) (8) -
LOSS ON REACQUIRED DEBT - (6) -
------- ------- --------
NET INCOME $ 267 $ 972 $ 975
======= ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 322 321 318
=== === ===
EARNINGS PER SHARE:
Income Before Extraordinary Item $ 0.94 $3.07 $3.06
Extraordinary Losses (0.11) (.04) -
------ ----- ------
Net Income $ 0.83 $3.03 $3.06
====== ===== =====
CASH DIVIDENDS PAID PER SHARE $ 2.40 $2.40 $2.40
====== ===== =====
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
- ----------------------------------------------------------------------------------------------------------------------------
(in millions - except share data)
December 31,
2000 1999
---- ----
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 437 $ 609
Special Deposits - 50
Accounts Receivable:
Customers 827 553
Miscellaneous 2,883 1,486
Allowance for Uncollectible Accounts (11) (12)
Energy Trading Contracts 16,627 1,001
Other 1,268 1,311
------- -------
TOTAL CURRENT ASSETS 22,031 4,998
------- -------
PROPERTY PLANT AND EQUIPMENT:
Electric:
Production 16,328 15,869
Transmission 5,609 5,495
Distribution 10,843 10,432
Other (including gas and coal mining assets
and nuclear fuel) 4,077 4,081
Construction Work in Progress 1,231 1,061
------- -------
Total Property, Plant and Equipment 38,088 36,938
Accumulated Depreciation and Amortization 15,695 15,073
------- -------
NET PROPERTY, PLANT AND EQUIPMENT 22,393 21,865
------- -------
REGULATORY ASSETS 3,698 3,464
------- -------
INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS 782 862
------- -------
GOODWILL (NET OF AMORTIZATION) 1,382 1,531
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 1,620 136
------- -------
OTHER ASSETS 2,642 2,863
------- -------
TOTAL $54,548 $35,719
======= =======
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Balance Sheets
- ------------------------------------------------------------------------------------
December 31,
2000 1999
---- ----
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $ 2,627 $ 1,280
Short-term Debt 4,333 3,012
Long-term Debt Due Within One Year* 1,152 1,367
Energy Trading Contracts 16,801 964
Other 2,154 1,443
------- -------
TOTAL CURRENT LIABILITIES 27,067 8,066
------- -------
LONG-TERM DEBT* 9,602 10,157
------- -------
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES 334 335
------- -------
DEFERRED INCOME TAXES 4,875 5,150
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 203 213
------- -------
DEFERRED INVESTMENT TAX CREDITS 528 580
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 1,381 108
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES 637 607
------- -------
OTHER NONCURRENT LIABILITIES 1,706 1,648
------- -------
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES* 161 182
------- -------
COMMITMENTS AND CONTINGENCIES (Note 8)
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
2000 1999
---- ----
Shares Authorized. .600,000,000 600,000,000
Shares Issued. . . .331,019,146 330,692,317
(8,999,992 shares were held in treasury
at December 31, 2000 and 1999) 2,152 2,149
Paid-in Capital 2,915 2,898
Accumulated Other Comprehensive Income (Loss) (103) (4)
Retained Earnings 3,090 3,630
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY 8,054 8,673
------- -------
TOTAL $54,548 $35,719
======= =======
*See Accompanying Schedules.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Cash Flows
- --------------------------------------------------------------------------------------------------------------------------------
(in millions)
Year Ended December 31,
2000 1999 1998
---- ---- ----
OPERATING ACTIVITIES:
Net Income $ 267 $ 972 $ 975
Adjustments for Noncash Items:
Depreciation and Amortization 1,299 1,294 1,171
Deferred Federal Income Taxes (170) 180 (2)
Deferred Investment Tax Credits (36) (38) (37)
Amortization (Deferral) of Operating
Expenses and Carrying Charges (net) 48 (151) 15
Equity in Earnings of Yorkshire
Electricity Group plc (44) (45) (38)
Extraordinary Item 35 14 -
Deferred Costs Under Fuel Clause Mechanisms (449) (191) 36
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (1,632) (80) (329)
Fuel, Materials and Supplies 147 (162) (23)
Accrued Utility Revenues (79) (35) 5
Accounts Payable 1,322 74 270
Taxes Accrued 172 29 20
Payment of Disputed Tax and Interest
Related to COLI 319 (16) (303)
Other (net) 304 (231) 195
------- ------- -------
Net Cash Flows From Operating Activities 1,503 1,614 1,955
------- ------- -------
INVESTING ACTIVITIES:
Construction Expenditures (1,773) (1,680) (1,396)
Investment in CitiPower - - (1,054)
Investment in Gas Assets - - (340)
Other 19 7 (54)
------- ------- -------
Net Cash Flows Used For
Investing Activities (1,754) (1,673) (2,844)
------- ------- -------
FINANCING ACTIVITIES:
Issuance of Common Stock 14 93 96
Issuance of Long-term Debt 1,124 1,391 2,645
Retirement of Cumulative Preferred Stock (20) (170) (28)
Retirement of Long-term Debt (1,565) (915) (1,101)
Change in Short-term Debt (net) 1,308 812 264
Dividends Paid on Common Stock (805) (833) (827)
Other Financing Activities - (43) -
------- ------- -------
Net Cash Flows From Financing Activities 56 335 1,049
------- ------- -------
Effect of Exchange Rate Change on Cash 23 (2) -
------- ------- -------
Net Increase (Decrease) in Cash and
Cash Equivalents (172) 274 160
Cash and Cash Equivalents January 1 609 335 175
------- ------- -------
Cash and Cash Equivalents December 31 $ 437 $ 609 $ 335
======= ======= =======
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Consolidated Statements of Common Shareholders' Equity
- ------------------------------------------------------------------------------------------------------------
(in millions)
Accumulated
Other
Common Stock Paid-In Retained Comprehensive
Shares Amount Capital Earnings Income (Loss) Total
JANUARY 1, 1998 326 $2,036 $2,818 $3,356 $ 23 $8,233
Conforming Change in Accounting Policy - - - (13) - (13)
Reclassification Adjustment - 85 (85) - - -
--- ------ ------ ------ ----- ------
Adjusted Balance at Beginning of Period 326 2,121 2,733 3,343 23 8,220
Issuances 2 13 83 - - 96
Retirements and Other - - 2 3 - 5
Cash Dividends Declared - - - (827) - (827)
------
7,494
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - 6 6
Unrealized Loss on Securities - - - - (14) (14)
Adjustments for Gain
Included in Net Income - - - - (7) (7)
Minimum Pension Liability - - - - (1) (1)
Net Income - - - 975 - 975
------
Total Comprehensive Income 959
--- ------ ------ ------- ----- ------
DECEMBER 31, 1998 328 2,134 2,818 3,494 7 8,453
Conforming Change in Accounting Policy - - - (1) - (1)
--- ------ ------ ------- ----- ------
Adjusted Balance at Beginning of Period 328 2,134 2,818 3,493 7 8,452
Issuances 3 15 77 - - 92
Retirements and Other - - 3 - - 3
Cash Dividends Declared - - - (833) - (833)
------
7,714
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (13) (13)
Minimum Pension Liability - - - - 2 2
Net Income - - - 972 - 972
------
Total Comprehensive Income 961
--- ------ ------ ------- ----- -------
DECEMBER 31, 1999 331 2,149 2,898 3,632 (4) 8,675
Conforming Change in Accounting Policy - - - (2) - (2)
--- ----- ----- ----- ----- ------
Adjusted Balance at Beginning of Period 331 2,149 2,898 3,630 (4) 8,673
Issuances - 3 11 - - 14
Cash Dividends Declared - - - (805) - (805)
Other - - 6 (2) - 4
------
7,886
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Foreign Currency Translation Adjustment - - - - (119) (119)
Reclassification Adjustment
For Loss Included in Net Income - - - - 20 20
Net Income - - - 267 - 267
------
Total Comprehensive Income 168
--- ------ ------ ------ ----- -------
DECEMBER 31, 2000 331 $2,152 $2,915 $3,090 $(103) $8,054
=== ====== ====== ====== ===== ======
See Notes to Consolidated Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Cumulative Preferred Stocks of Subsidiaries
- --------------------------------------------------------------------------------------------------------
December 31, 2000
-----------------------------------------------------------------
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding(g) Millions)
- --------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 614,608 $ 61
====
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 333,100 $ 33
6.02% - 6-7/8% (c) (e) 1,650,000 513,450 52
7% (f) (f) 250,000 150,000 15
----
Total Subject to Mandatory
Redemption (c) $100
====
December 31, 1999
-----------------------------------------------------------------
Call
Price per Shares Shares Amount (In
Share (a) Authorized(b) Outstanding(g) Millions)
- --------------------------------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4.00% - 5.00% $102-$110 1,525,903 629,671 $ 63
====
Subject to Mandatory Redemption:
5.90% - 5.92% (c) (d) 1,950,000 343,100 $ 34
6.02% - 6-7/8% (c) (e) 1,950,000 597,950 60
7% (f) (f) 250,000 250,000 25
----
Total Subject to Mandatory
Redemption (c) $119
====
NOTES TO SCHEDULE OF CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES
(a) At the option of the subsidiary the shares may be redeemed at the call
price plus accrued dividends. The involuntary liquidation preference is
$100 per share for all outstanding shares.
(b) As of December 31, 2000 the subsidiaries had 13,592,750, 22,200,000 and
7,713,495 shares of $100, $25 and no par value preferred stock,
respectively, that were authorized but unissued.
(c) Shares outstanding and related amounts are stated net of applicable
retirements through sinking funds(generally at par) and reacquisitions of
shares in anticipation of future requirements. The subsidiaries
reacquired enough shares in 1997 to meet all sinking fund requirements on
certain series until 2008 and on certain series until 2009 when all
remaining
outstanding shares must be redeemed. The sinking fund provisions of the
series subject to mandatory redemption aggregate (after deducting sinking
fund requirements) of $5 million in 2002, $12 million in 2003, $12
million in 2004 and $2 million in 2005.
(d) Not callable prior to 2003; after that the call price is $100 per share.
(e) Not callable prior to 2000; after that the call price is $100 per share.
(f) With sinking fund.
(g) The number of shares of preferred stock redeemed is 209,563 shares in 2000, 1,698,276 shares in
1999 and 281,250 shares in 1998.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
Schedule of Consolidated Long-term Debt of Subsidiaries
- ----------------------------------------------------------------------------------------------------------------
Weighted Average
Maturity Interest Rate Interest Rates at December 31, December 31,
- -------- ----------------- ------------------------------ ----------------------
December 31, 2000 2000 1999 2000 1999
----------------- ---- ---- ---- ----
(in millions)
-------------
FIRST MORTGAGE BONDS
2000-2003 6.96% 5.91%-8.95% 5.25%-8.95% $ 1,247 $ 1,621
2004-2008 6.97% 6-1/8%-8% 6-1/8%-8% 1,140 1,148
2020-2025 7.74% 6-7/8%-8.80% 6-7/8%-8.80% 1,104 1,172
INSTALLMENT PURCHASE CONTRACTS (a)
2000-2009 5.53% 4.90%-7.70% 4.80%-7.70% 234 235
2011-2030 6.02% 4.875%-8.20% 3.332%-8.20% 1,447 1,477
NOTES PAYABLE (b)
2000-2021 7.14% 6.20%-9.60% 5.8675%-9.60% 1,181 2,030
SENIOR UNSECURED NOTES
2000-2004 6.99% 6.50%-7.45% 6.07%-7.45% 2,049 1,403
2005-2009 6.59% 6.24%-6.91% 6.24%-6.91% 475 488
2038 7.30% 7.20%-7-3/8% 7.20%-7-3/8% 340 340
JUNIOR DEBENTURES
2025-2038 8.05% 7.60%-8.72% 7.60%-8.72% 620 620
YANKEE BONDS AND EURO BONDS
2001-2006 8.51% 7.98%-8.875% 7.98%-8.875% 684 742
OTHER LONG-TERM DEBT (c) 280 300
Unamortized Discount (net) (47) (52)
------- -------
Total Long-term Debt
Outstanding (d) 10,754 11,524
Less Portion Due Within One Year 1,152 1,367
------- -------
Long-term Portion $ 9,602 $10,157
======= =======
NOTES TO SCHEDULE OF CONSOLIDATED LONG-TERM DEBT OF SUBSIDIARIES
(a) For certain series of installment purchase contracts interest rates are
subject to periodic adjustment. Certain series will be purchased on demand at
periodic interest-adjustment dates. Letters of credit from banks and standby
bond purchase agreements support certain series.
(b) Notes payable represent outstanding promissory notes issued under term loan
agreements and revolving credit agreements with a number of banks and other
financial institutions. At expiration all notes then issued and outstanding are
due and payable. Interest rates are both fixed and variable. Variable rates
generally relate to specified short-term interest rates. (c) Other long-term
debt consists of a liability along with accrued interest for disposal of spent
nuclear fuel (see Note 8 of the Notes to Consolidated Financial Statements) and
financing obligation under sale lease back agreements. (d) Long-term debt
outstanding at December 31, 2000 is payable as follows:
Principal Amount (in millions)
2001 $ 1,152
2002 1,167
2003 1,628
2004 884
2005 616
Later Years 5,354
-------
Total Principal
Amount 10,801
Unamortized
Discount (47)
-------
Total $10,754
=======
AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES
Index to Notes to Consolidated Financial Statements
- -----------------------------------------------------------------------------
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items Note 2
Merger Note 3
Nuclear Plant Restart Note 4
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Acquisitions Note 9
International Investments Note 10
Staff Reductions Note 11
Benefit Plans Note 12
Stock-Based Compensation Note 13
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Supplementary Information Note 17
Leases Note 18
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Trust Preferred Securities Note 21
MANAGEMENT'S RESPONSIBILITY
- ------------------------------------------------------------------
The management of American Electric Power Company, Inc. is responsible
for the integrity and objectivity of the information and representations in this
annual report, including the consolidated financial statements. These statements
have been prepared in conformity with generally accepted accounting principles,
using informed estimates where appropriate, to reflect the Company's financial
condition and results of operations. The information in other sections of the
annual report is consistent with these statements.
The Company's Board of Directors has oversight responsibilities for
determining that management has fulfilled its obligation in the preparation of
the financial statements and in the ongoing examination of the Company's
established internal control structure over financial reporting. The Audit
Committee, which consists solely of outside directors and which reports directly
to the Board of Directors, meets regularly with management, Deloitte & Touche
LLP - independent auditors and the Company's internal audit staff to discuss
accounting, auditing and reporting matters. To ensure auditor independence, both
Deloitte & Touche LLP and the internal audit staff have unrestricted access to
the Audit Committee.
The financial statements have been audited by Deloitte & Touche LLP,
whose report appears on the next page. The auditors provide an objective,
independent review as to management's discharge of its responsibilities insofar
as they relate to the fairness of the Company's reported financial condition and
results of operations. Their audit includes procedures believed by them to
provide reasonable assurance that the financial statements are free of material
misstatement and includes an evaluation of the Company's internal control
structure over financial reporting.
INDEPENDENT AUDITORS' REPORT
- ------------------------------------------------------------------------------
To the Shareholders and Board of Directors
of American Electric Power Company, Inc.:
We have audited the consolidated balance sheets of American Electric
Power Company, Inc. and its subsidiaries as of December 31, 2000 and 1999, and
the related consolidated statements of income, comprehensive income, common
shareholders' equity, and cash flows for each of the three years in the period
ended December 31, 2000. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on the
financial statements based on our audits. The consolidated financial statements
give retroactive effect to the merger of American Electric Power Company, Inc.
and its subsidiaries and Central and South West Corporation and its
subsidiaries, which has been accounted for as a pooling of interests as
described in Note 3 to the consolidated financial statements. We did not audit
the consolidated balance sheet of Central and South West Corporation and its
subsidiaries as of December 31, 1999, or the related consolidated statements of
income, comprehensive income, common shareholders' equity, and cash flows for
the years ended December 31, 1999 and 1998, which statements reflect total
assets of $14,162,000,000 as of December 31, 1999, and total revenues of
$5,537,000,000 and $5,482,000,000 for the years ended December 31, 1999 and
1998, respectively. Those consolidated statements, before the restatement
described in Note 3, were audited by other auditors whose report, dated February
25, 2000, has been furnished to us, and our opinion, insofar as it relates to
those amounts included for Central and South West Corporation and its
subsidiaries for 1999 and 1998, is based solely on the report of such other
auditors.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits and the report of
the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other
auditors, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of American Electric
Power Company, Inc. and its subsidiaries as of December 31, 2000 and 1999, and
the results of their operations and their cash flows for each of the three years
in the period ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States of America.
We also audited the adjustments described in Note 3 that were applied
to restate the 1999 and 1998 financial statements to give retroactive effect to
the change in the method of accounting for vacation pay accruals. In our
opinion, such adjustments are appropriate and have been properly applied.
Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of
Central and South West Corporation:
We have audited the consolidated balance sheets of Central and South West
Corporation (a Delaware corporation) and subsidiary companies as of December 31,
1999, and the related consolidated statements of income, stockholders' equity
and cash flows, for each of the two years in the period ended December 31, 1999
prior to the restatement (and, therefore, are not presented herein) for the
retroactive effect of the conforming change in the method of accounting for
vacation pay accruals and certain conforming reclassifications to the historical
financial statements as described in Note 3 to the restated consolidated
financial statements. These financial statements are the responsibility of the
Corporation's management. Our responsibility is to express an opinion on these
financial statements based on our audits. We did not audit the financial
statements of CSW UK Holdings (1999) and CSW UK Finance Company (1998) which
statements reflect total assets and total revenues of 20 percent and 31 percent
in 1999, and total revenues of 32 percent in 1998, respectively, of the related
consolidated totals. Those statements were audited by other auditors whose
reports have been furnished to us, and our opinion, insofar as it relates to the
amounts included for those entities, is based solely on the reports of the other
auditors.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits and the reports of other auditors
provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the
financial statements prior to the restatement referred to above present fairly,
in all material respects, the financial position of Central and South West
Corporation and subsidiary companies as of December 31, 1999, and the results of
their operations and their cash flows for each of the two years in the period
ended December 31, 1999, in conformity with accounting principles generally
accepted in the United States.
Arthur Andersen LLP
Dallas, Texas
February 25, 2000
AUDITOR's REPORT TO THE MEMBERS OF CSW UK HOLDINGS
We have audited the consolidated balance sheets of CSW UK Holdings and
subsidiaries as of 31 December 1999 and the related consolidated statement of
earnings and statement of cash flows for the years then ended. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, or a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above and not
included herein present fairly, in all material respects, the financial position
of CSW UK Holdings and subsidiaries at 31 December 1999 and the result of their
operations and cash flows for the year then ended in conformity with generally
accepted accounting principles in the United Kingdom.
Generally accepted accounting principles in the United Kingdom vary in certain
significant respects from generally accepted accounting principles in the United
States. Application of generally accepted accounting principles in the United
States would have affected results of operations and shareholders' equity as of
and for the year ended 31 December 1999 to the extent summarized in the notes to
the consolidated financial statements.
KPMG Audit Plc
Chartered Accountants
London, England
17 January 2000
AUDITOR'S REPORT TO THE MEMBERS OF CSW UK FINANCE COMPANY
We have audited the consolidated balance sheet of CSW UK Finance Company and
subsidiaries as of 31 December 1998 and the related consolidated statement of
earnings and statements of cash flows for the year then ended. These
consolidated financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audit.
We conducted our audit in accordance with generally accepted auditing standards
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management as well as evaluating the overall financial statement
presentation. We believe that our audit provides a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above and not
included herein present fairly, in all material respects, the financial position
of CSW UK Finance Company and subsidiaries at 31 December 1998 and the results
of their operations and cash flows for the year then ended in conformity with
generally accepted accounting principles in the United Kingdom.
Generally accepted accounting principles in the United Kingdom vary in certain
significant respects from generally accepted accounting principles in the United
States. Application of generally accepted accounting principles in the United
States would have affected results of operations and shareholders' equity as of
and for the year ended 31 December 1998 to the extent summarized in the notes to
the consolidated financial statements.
KPMG Audit Plc
Chartered Accountants
London, England
18 January 1999
AEP GENERATING COMPANY
B-9
AEP GENERATING COMPANY
Selected Financial
Data
- ---------------------------------------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $228,516 $217,189 $224,146 $227,868 $225,892
Operating Expenses 220,092 211,849 215,415 218,828 215,997
-------- -------- -------- -------- --------
Operating Income 8,424 5,340 8,731 9,040 9,895
Nonoperating Income 3,429 3,659 3,364 3,603 3,695
-------- -------- -------- -------- --------
Income Before Interest Charges 11,853 8,999 12,095 12,643 13,590
Interest Charges 3,869 2,804 3,149 3,857 4,159
-------- -------- -------- -------- --------
Net Income $ 7,984 $ 6,195 $ 8,946 $ 8,786 $ 9,431
======== ======== ======== ======== ========
December 31,
------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $642,302 $640,093 $636,460 $633,450 $632,257
Accumulated Depreciation 315,566 295,065 277,855 257,191 238,532
-------- -------- -------- -------- --------
Net Electric Utility Plant $326,736 $345,028 $358,605 $376,259 $393,725
======== ======== ======== ======== ========
Total Assets $374,602 $398,640 $403,892 $419,058 $442,911
======== ======== ======== ======== ========
Common Stock and Paid-in Capital $ 24,434 $ 30,235 $ 36,235 $ 40,235 $ 45,235
Retained Earnings 9,722 3,673 2,770 2,528 1,886
-------- -------- -------- -------- --------
Total Common Shareholder's Equity $ 34,156 $ 33,908 $ 39,005 $ 42,763 $ 47,121
======== ======== ======== ======== ========
Long-term Debt (a) $ 44,808 $ 44,800 $ 44,792 $ 69,570 $ 89,554
======== ======== ======== ======== ========
Total Capitalization
and Liabilities $374,602 $398,640 $403,892 $419,058 $442,911
======== ======== ======== ======== ========
(a) Including portion due within one year.
AEP GENERATING COMPANY
Management's Narrative Analysis of Results of Operations
AEP Generating Company is engaged in the generation and wholesale sale
of electric power to two affiliates under long-term agreements.
Operating revenues are derived from the sale of Rockport Plant energy
and capacity to two affiliated companies, I&M and KPCo pursuant to FERC approved
long-term unit power agreements. Under the terms of its unit power agreement,
I&M is required to buy all of AEGCo's Rockport capacity when the unit power
agreement with KPCo expires in 2004. The unit power agreements provide for
recovery of costs including a FERC approved rate of return on common equity and
a return on other capital net of temporary cash investments.
Net income increased $1.8 million or 29% as a result of the recordation
of income tax accrual adjustments and an increase in return on other capital.
Comparative net income was increased by the income tax accrual adjustments since
an unfavorable income tax accrual adjustment was recorded in 1999 and income tax
accrual adjustments are not included in billings under the terms of the unit
power agreements. Return on other capital increased as a result of higher
interest charges without an offset for earnings on temporary cash investments in
2000.
Income statement items which changed significantly were:
Increase
(Decrease)
(dollars in millions) From Previous Year
Amount %
Operating Revenues. . . . . $11.3 5
Fuel Expense. . . . . . . . 8.5 9
Maintenance Expense . . . . (0.9) (8)
Taxes Other Than Federal
Income Taxes . . . . . . . 0.5 10
Interest Charges. . . . . . 1.1 38
The increase in operating revenues reflects recovery under the unit
power agreements of higher fuel expense and an increase in the return on other
capital.
Fuel expense increased due to an increase in generation reflecting
greater availability of the Rockport Plant generating units in 2000 and an
increase in the cost of fuel.
The decrease in maintenance expense can be attributed to cost
containment efforts and the shorter duration in 2000 of maintenance outages for
boiler inspection and repair than in 1999.
Taxes other than federal income taxes increased due to an increase in
state income taxes which resulted from an increase in taxable income in 2000 and
adjustments to estimated prior year taxes following the filing of the 1999 and
1998 returns.
The increase in interest charges was primarily due to an increase in
interest rates in 2000. AEGCo's long-term debt interest rates are variable on a
daily basis which results in interest charges adjusting quickly to market rate
changes.
AEP GENERATING COMPANY
Statements of Income
- ------------------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $228,516 $217,189 $224,146
-------- -------- --------
OPERATING EXPENSES:
Fuel 102,978 94,481 96,791
Rent - Rockport Plant Unit 2 68,283 68,283 68,283
Other Operation 10,295 10,451 10,001
Maintenance 9,616 10,492 11,894
Depreciation 22,162 21,845 21,652
Taxes Other Than Federal Income Taxes 5,060 4,585 3,495
Federal Income Taxes 1,698 1,712 3,299
-------- -------- --------
TOTAL OPERATING EXPENSES 220,092 211,849 215,415
-------- -------- --------
OPERATING INCOME 8,424 5,340 8,731
NONOPERATING INCOME 3,429 3,659 3,364
-------- -------- --------
INCOME BEFORE INTEREST CHARGES 11,853 8,999 12,095
INTEREST CHARGES 3,869 2,804 3,149
-------- -------- --------
NET INCOME $ 7,984 $ 6,195 $ 8,946
======== ======== ========
Statements of Retained
Earnings
- --------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $3,673 $2,770 $2,528
NET INCOME 7,984 6,195 8,946
CASH DIVIDENDS DECLARED 1,935 5,292 8,704
------ ------ ------
RETAINED EARNINGS DECEMBER 31 $9,722 $3,673 $2,770
====== ====== ======
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Balance Sheets
- -----------------------------------------------------------------------------------------
December 31,
2000 1999
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $635,215 $629,286
General 2,795 2,400
Construction Work in Progress 4,292 8,407
-------- --------
Total Electric Utility Plant 642,302 640,093
Accumulated Depreciation 315,566 295,065
-------- --------
NET ELECTRIC UTILITY PLANT 326,736 345,028
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents 2,757 317
Accounts Receivable:
Affiliated Companies 21,374 22,464
Miscellaneous 2,341 2,643
Fuel - at average cost 11,006 17,505
Materials and Supplies - at average cost 3,979 3,966
Prepayments 145 150
-------- --------
TOTAL CURRENT ASSETS 41,602 47,045
-------- --------
REGULATORY ASSETS 5,504 5,744
-------- --------
DEFERRED CHARGES 760 823
-------- --------
TOTAL $374,602 $398,640
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
- ----------------------------------------------------------------------------------------------------------------------------------
December 31,
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares $ 1,000 $ 1,000
Paid-in Capital 23,434 29,235
Retained Earnings 9,722 3,673
-------- --------
TOTAL CAPITALIZATION AND COMMON SHAREHOLDER'S EQUITY 34,156 33,908
-------- --------
OTHER NONCURRENT LIABILITIES 358 592
-------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 44,808 44,800
Short-term Debt - Notes Payable - 24,700
Advances from Affiliates 28,068 -
Accounts Payable:
General 6,109 7,539
Affiliated Companies 7,724 19,451
Taxes Accrued 4,993 4,285
Rent Accrued - Rockport Plant Unit 2 4,963 4,963
Other 4,443 4,763
-------- --------
TOTAL CURRENT LIABILITIES 101,108 110,501
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 122,188 127,759
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credits 59,718 63,114
Amounts Due to Customers for Income Taxes 23,996 26,266
-------- --------
TOTAL REGULATORY LIABILITIES 83,714 89,380
-------- --------
DEFERRED INCOME TAXES 32,928 36,500
-------- --------
DEFERRED CREDITS 150 -
-------- ---------
CONTINGENCIES (Note 8)
TOTAL $374,602 $398,640
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Statements of Cash Flows
- ------------------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 7,984 $ 6,195 $ 8,946
Adjustments for Noncash Items:
Depreciation 22,162 21,845 21,652
Deferred Federal Income Taxes (5,842) (5,282) 5,544
Deferred Investment Tax Credits (3,396) (3,448) (3,454)
Amortization of Deferred Gain on Sale and
Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable 1,392 (2,213) (2,184)
Fuel, Materials and Supplies 6,486 (6,263) (855)
Accounts Payable (13,157) 14,394 2,892
Taxes Accrued 708 1,058 (193)
Other (net) 1,232 (1,570) 2,542
-------- -------- --------
Net Cash Flows From Operating Activities 11,998 19,145 29,319
-------- -------- --------
INVESTING ACTIVITIES:
Construction Expenditures (5,190) (8,349) (6,574)
Proceeds From Sales of Property - 331 2,254
-------- -------- ---------
Net Cash Flows Used For Investing Activities (5,190) (8,018) (4,320)
-------- -------- --------
FINANCING ACTIVITIES:
Return of Capital to Parent Company (5,801) (6,000) (4,000)
Retirement of Long-term Debt - - (25,000)
Change in Short-term Debt (net) (24,700) 250 12,700
Change in Advances From Affiliates (net) 28,068 - -
Dividends Paid (1,935) (5,292) (8,704)
-------- -------- --------
Net Cash Flows Used For Financing Activities (4,368) (11,042) (25,004)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 2,440 85 (5)
Cash and Cash Equivalents January 1 317 232 237
-------- -------- --------
Cash and Cash Equivalents December 31 $ 2,757 $ 317 $ 232
======== ======== =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $3,531,000,
$2,468,000 and $3,060,000 and for income taxes was $6,820,000, $6,565,000 and
$(2,131,000) in 2000, 1999 and 1998, respectively.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Statements of Capitalization
- ---------------------------------------------------------------------------------------------
December 31,
--------------------------
2000 1999
---- ----
(in thousands)
COMMON STOCK EQUITY (a) $ 34,156 $ 33,908
-------- --------
LONG-TERM DEBT
Installment Purchase Contracts - City of Rockport (b)
Series Due Date
1995 A, 2025 (c) 22,500 22,500
1995 B, 2025 (c) 22,500 22,500
Unamortized Discount (192) (200)
Amount Due Within One Year (44,808) (44,800)
-------- --------
- -
-------- --------
TOTAL CAPITALIZATION $ 34,156 $ 33,908
======== ========
(a) In 2000, 1999 and 1998, AEGCo returned capital to AEP in the amounts of
$5.8 million, $6 million and $4 million, respectively. There were no other
material transactions affecting common stock and paid-in capital in 2000,
1999 and 1998.
(b) Installment purchase contracts were entered into in connection with
the issuance of pollution control revenue bonds by the
City of Rockport, Indiana. Under the terms of the installment purchase
contracts, AEGCo is required to pay amounts sufficient
to enable the payment of interest and principal on the related
pollution control revenue bonds issued to refinance the
construction costs of pollution control facilities at the Rockport
Plant. On the Series 1995 A and B bonds the principal is
payable at maturity or on the demand of bondholders. AEGCo has
agreements that provide for brokers to remarket bonds
tendered. In the event the bonds cannot be remarketed, AEGCo has a
standby bond purchase agreement with a bank that provides
for the bank to purchase any bonds not remarketed. The purchase
agreement expires in 2001. Therefore, the installment purchase
contracts have been reclassified as due within one year.
(c) These series have an adjustable interest rate that can be a daily, weekly,
commercial paper or term rate as designated by AEGCo. AEGCo selected a
daily rate which ranged from 1.65% to 6.1% during 2000 and 1.4% to 5.2%
during 1999 and averaged 4.1% in 2000 and 3.2% in 1999. The interest rates
were 5% and 4.9% at December 31, 2000 and 4.95% and 4.8% at December 31,
1999 for Series A and Series B, respectively.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Index to Notes to Financial Statements
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Effects of Regulation Note 6
Commitments and Contingencies Note 8
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Leases Note 18
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
- -----------------------------------
To the Shareholder and Board of Directors
of AEP Generating Company:
We have audited the accompanying balance sheets and statements of
capitalization of AEP Generating Company as of December 31, 2000 and 1999, and
the related statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2000. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of AEP Generating Company as of
December 31, 2000 and 1999, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2000 in conformity
with accounting principles generally accepted in the United States of America.
Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
C-13
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,860,165 $1,650,937 $1,672,244 $1,628,515 $1,624,869
Operating Expenses 1,659,011 1,409,701 1,443,701 1,388,521 1,381,993
---------- ---------- ---------- ---------- ----------
Operating Income 201,154 241,236 228,543 239,994 242,876
Nonoperating Income (Loss) 11,752 8,096 (8,301) (222) 128
---------- ---------- ---------- ---------- ----------
Income Before Interest Charges 212,906 249,332 220,242 239,772 243,004
Interest Charges 148,000 128,840 126,912 119,258 109,315
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 64,906 120,492 93,330 120,514 133,689
Extraordinary Gain 8,938 - - - -
---------- ---------- ---------- ---------- ----------
Net Income 73,844 120,492 93,330 120,514 133,689
Preferred Stock Dividend
Requirements 2,504 2,706 2,497 7,006 15,938
---------- ---------- ---------- ---------- ----------
Earnings Applicable to
Common Stock $ 71,340 $ 117,786 $ 90,833 $ 113,508 $ 117,751
========== ========== ========== ========== ==========
Year Ended December 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $5,418,278 $5,262,951 $5,087,359 $4,901,046 $4,717,132
Accumulated Depreciation and
Amortization 2,188,796 2,079,490 1,984,856 1,869,057 1,782,017
---------- ---------- ---------- ---------- ----------
Net Electric Utility Plant $3,229,482 $3,183,461 $3,102,503 $3,031,989 $2,935,115
========== ========== ========== ========== ==========
Total Assets $6,646,153 $4,354,400 $4,047,038 $3,883,430 $3,800,737
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 975,676 $ 974,717 $ 924,091 $ 873,506 $ 835,838
Retained Earnings 120,584 175,854 179,461 207,544 208,472
---------- ---------- ---------- ---------- ----------
Total Common Shareholder's
Equity $1,096,260 $1,150,571 $1,103,552 $1,081,050 $1,044,310
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 17,790 $ 18,491 $ 19,359 $ 19,747 $ 29,815
Subject to Mandatory
Redemption 10,860 20,310 22,310 22,310 190,000
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 28,650 $ 38,801 $ 41,669 $ 42,057 $ 219,815
========== ========== ========== ========== ==========
Long-term Debt (a) $1,605,818 $1,665,307 $1,552,455 $1,494,535 $1,365,842
========== ========== ========== ========== ==========
Obligations Under Capital
Leases (a) $ 63,160 $ 64,645 $ 65,175 $ 60,110 $ 51,969
========== ========== ========== ========== ==========
Total Capitalization and
Liabilities $6,646,153 $4,354,400 $4,047,038 $3,883,430 $3,800,737
========== ========== ========== ========== ==========
(a) Including portion due within one year
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations
- ------------------------------------------------------------------------------
APCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to 909,000 retail customers in
southwestern Virginia and southern West Virginia. APCo as a member of the AEP
Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale
sales to neighboring utility systems and power marketers. APCo also sells
wholesale power to municipalities.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges and the receipt of capacity
credits. AEP Power Pool members are also compensated for their out-of-pocket
costs of energy delivered to the AEP Power Pool and charged for energy received
or purchased from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's per-centage share of revenues or
costs. APCo as a member of the AEP Power Pool shares in the revenues and costs
of the AEP Power Pool's wholesale sales to and net forward trades with other
utility systems and power marketers. Revenues from forward electricity trades
are recorded net of purchases as operating revenues for transactions in AEP's
traditional marketing area (up to two trans-mission systems from the AEP service
territory) and as nonoperating income for transactions beyond two transmission
systems from AEP. The AEP Power Pool also enters into power trading transactions
for options, futures and swaps. APCo's share of these transactions is recorded
in nonoperating income.
In February 2001 the U.S. District Court for the Southern District of
Ohio ruled against AEP and certain of its subsidiaries, including APCo, in a
suit over deductibility of interest claimed in AEP's consolidated tax return
related to a corporate owned life insurance (COLI) program. In 1998 and 1999
APCo paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1991-98. The payments were included in Other
Property and Investments pending the resolution of this matter. As a result of
the Court's decision, net income was reduced by $82 million in 2000.
Results of Operations
Net Income
Income before extraordinary items decreased $55.6 million or 46% in
2000 primarily due to the COLI decision. An extraordinary gain from the
discontinuance of SFAS 71 regulatory accounting of $9 million after tax was
recorded in June 2000. (See Note 7 of the Notes to Consolidated Financial
Statements).
Net income increased $27.2 million or 29% in 1999 primarily due to a
nonoperating gain in 1999 on the sale of real estate and mining assets by APCo's
inactive mining subsidiaries and a decline in operating expenses.
Operating Revenues
The 13% increase in operating revenues in 2000 resulted from APCo's
share of increased wholesale electricity transactions by the AEP Power Pool.
Operating revenues decreased 1% in 1999 primarily due to a de-crease in
wholesale sales and a decline in net revenues reflecting lower margins on
whole-sale trading transactions. The changes in the components of revenues were
as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
- ---------------------
2000 1999
---------------------------
Amount % Amount %
Retail:
Residential $ 15.5 $ 19.4
Commercial 9.2 17.1
Industrial (15.1) (4.4)
Other 1.7 0.9
------ ------
11.3 1 33.0 3
Wholesale 237.0 88 (80.6) (23)
Transmission and
Other (39.1)(44) 26.3 42
------ ------
Total $209.2 13 $(21.3) (1)
====== ======
Retail revenues increased in 1999 primarily due to a 2% increase in
retail sales reflecting higher residential and commercial sales. The increase in
retail sales was primarily due to colder winter weather and customer growth.
The increase in wholesale revenues in 2000 is due to a significant
increase in AEP Power Pool transactions. As a result of an affiliated company's
major industrial customer's decision not to continue its purchased power
agreement, additional power was available to the AEP Power Pool for wholesale
sales contributing to the increase in APCo's wholesale revenues. The decline in
wholesale revenues in 1999 reflects the termination of a contract with several
municipal customers in July 1998 and a decline in margins on regulated power
trading transactions. The decline in margins reflects the moderation in 1999 of
extreme weather in 1998 and capacity shortages experienced in the summer of
1998.
In 2000 transmission and other revenues decreased substantially due to
the combined effect of an unfavorable mark-to-market adjustment in 2000 on
outstanding forward trading contracts, a favorable adjustment to a provision for
revenue refunds recorded in 1999 in connection with the execution of a final
rate refund and a favorable adjustment to rental income in 1999 for agreed to
retroactive billings to telecommunications companies for pole attachments.
Operating Expenses
Operating expenses increased 18% in 2000 primarily due to an increase
in purchased power expense, other operation expense and federal income taxes
offset in part by a decrease in fuel expense. The decrease in operating expenses
in 1999 was mainly due to a decline in purchased power expense. Changes in the
components of operating expenses are as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
- ---------------------
2000 1999
-----------------------------
Amount % Amount %
Fuel $(75.6) (17) $ 7.2 2
Purchased Power 223.8 88 (49.0) (16)
Other Operation 33.0 13 (5.1) (2)
Maintenance 0.7 1 (11.0) (8)
Depreciation and
Amortization 14.2 10 5.1 4
Taxes Other Than
Federal Income
Taxes 8.8 8 1.5 1
Federal Income
Taxes 44.4 63 17.3 32
------ ------
Total $249.3 18 $(34.0) (2)
====== ======
Fuel expense decreased in 2000 due to the combined effect of the
discontinuance of deferral accounting for over or under recovery of fuel costs
in the West Virginia jurisdiction effective January 1, 2000 under the terms of a
rate settlement agreement and a decline in generation due to scheduled plant
maintenance. The increase in fuel expense in 1999 was primarily due to increases
in generation reflecting greater utilization of internally generated power.
The significant increase in purchased power expense in 2000 reflects
additional purchases of power from the AEP Power Pool as a result of increased
availability of generation. The AEP Power Pool was able to supply more energy to
APCo since an affiliate's out of service nuclear unit went on line in June 2000,
a major industrial customer discontinued purchasing power from an affiliate in
January 2000, and generating unit outage management improved.
The reduction in purchased power expense in 1999 was primarily due to
reduced capacity charges from the AEP Power Pool as a result of declines in
APCo's MLR and decreased purchases from the AEP Power Pool. The decline in
purchases from the AEP Power Pool can be attributed to increased internal
generation and the termination of a contract with several municipal customers.
The increase in other operation expense in 2000 was due to increased
marketing and trading costs including increased accruals for incentive
compensation and increased use of emission allowances due to stricter air
quality standards of Phase II of the 1990 Clean Air Act Amendments which became
effective January 1, 2000.
Maintenance expense decreased in 1999 primarily as a result of
expenditures during 1998 to restore service and make repairs following two
severe snowstorms.
Depreciation and amortization expense increased in 2000 due to the
amortization, beginning in July 2000, of a new transition regulatory asset
established in June 2000 for the net generation-related regulatory assets
related to the Company's Virginia and West Virginia jurisdictions that were
transferred to the distribution portion of the business and are being recovered
through regulated rates (see Note 7 for further discussion of the effects of
restructuring). Additional investments in distribution plant also contributed to
the increase in depreciation and amortization expense.
The increase in taxes other than federal income taxes in 2000 is
primarily due to an increase in the WV state income taxes due to disallowance of
the COLI program interest deductions.
Federal income taxes attributable to operations increased in 2000 due
to the disallowance of COLI interest deductions. The increase in 1999 is
primarily due to an increase in pre-tax operating income and changes in certain
book/tax differences accounted for on a flow-through basis for rate-making
purposes.
Nonoperating Income
The increase in nonoperating income in 1999 is primarily due to the
effect of non-regulated electricity trading and a gain on the sale of coal lands
and mining assets by APCo's inactive coal mining subsidiaries. In 1999
nonoperating income included a gain from APCo's share of the AEP Power Pool's
trading transactions outside of the AEP System's traditional marketing area. In
November 1999 the subsidiaries sold coal lands and mining assets to an
unaffiliated company that had been leasing the assets.
Interest Charges
Interest charges increased in 2000 due to recognizing previously
deferred interest payments to the IRS related to the COLI disallowances and
interest on resultant state income tax deficiencies.
Extraordinary Gain
The extraordinary gain recorded in June 2000 was the result of the
discontinuance of SFAS 71 for the generation portion of APCo's business.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $1,860,165 $1,650,937 $1,672,244
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 369,161 444,711 437,500
Purchased Power 477,910 254,100 303,116
Other Operation 282,610 249,616 254,718
Maintenance 124,493 123,834 134,856
Depreciation and Amortization 163,089 148,874 143,809
Taxes Other Than Federal Income Taxes 126,447 117,641 116,070
Federal Income Taxes 115,301 70,925 53,632
---------- ---------- ----------
Total Operating Expenses 1,659,011 1,409,701 1,443,701
---------- ---------- ----------
OPERATING INCOME 201,154 241,236 228,543
NONOPERATING INCOME (LOSS) 11,752 8,096 (8,301)
---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES 212,906 249,332 220,242
INTEREST CHARGES 148,000 128,840 126,912
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 64,906 120,492 93,330
EXTRAORDINARY GAIN - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(Inclusive of Tax Benefit of $7,872,000) 8,938 - -
---------- ---------- -----------
NET INCOME 73,844 120,492 93,330
PREFERRED STOCK DIVIDEND REQUIREMENTS 2,504 2,706 2,497
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 71,340 $ 117,786 $ 90,833
========== ========== ==========
See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ------------------------------------------------------------------------------------------
December 31,
---------------------------
2000 1999
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,058,952 $2,014,968
Transmission 1,177,079 1,151,377
Distribution 1,816,925 1,741,685
General 254,371 247,798
Construction Work in Progress 110,951 107,123
---------- ----------
Total Electric Utility Plant 5,418,278 5,262,951
Accumulated Depreciation and Amortization 2,188,796 2,079,490
---------- ----------
NET ELECTRIC UTILITY PLANT 3,229,482 3,183,461
---------- ----------
OTHER PROPERTY AND INVESTMENTS 56,967 126,592
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 322,688 33,954
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 5,847 64,828
Advances to Affiliates 8,387 -
Accounts Receivable:
Customers 243,298 109,525
Affiliated Companies 63,919 37,827
Miscellaneous 16,179 9,154
Allowance for Uncollectible Accounts (2,588) (2,609)
Fuel - at average cost 39,076 58,161
Materials and Supplies - at average cost 57,515 56,917
Accrued Utility Revenues 66,499 53,418
Energy Trading Contracts 2,036,001 143,777
Prepayments 6,307 7,713
---------- ----------
TOTAL CURRENT ASSETS 2,540,440 538,711
---------- ----------
REGULATORY ASSETS 447,750 436,894
---------- ----------
DEFERRED CHARGES 48,826 34,788
---------- ----------
TOTAL $6,646,153 $4,354,400
========== ==========
See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
- -------------------------------------------------------------------------------------------------------------
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $ 260,458
Paid-in Capital 715,218 714,259
Retained Earnings 120,584 175,854
---------- -----------
Total Common Shareholder's Equity 1,096,260 1,150,571
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 18,491
Subject to Mandatory Redemption 10,860 20,310
Long-term Debt 1,430,812 1,539,302
---------- ----------
TOTAL CAPITALIZATION 2,555,722 2,728,674
---------- ----------
OTHER NONCURRENT LIABILITIES 105,883 132,130
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 175,006 126,005
Short-term Debt 191,495 123,480
Accounts Payable - General 153,422 59,150
Accounts Payable - Affiliated Companies 107,556 42,459
Taxes Accrued 63,258 49,038
Customer Deposits 12,612 12,898
Interest Accrued 21,555 19,079
Energy Trading Contracts 2,091,804 140,279
Other 85,378 71,044
---------- ----------
TOTAL CURRENT LIABILITIES 2,902,086 643,432
---------- ----------
DEFERRED INCOME TAXES 682,474 671,917
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 43,093 57,259
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 259,438 26,256
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 97,457 94,732
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $6,646,153 $4,354,400
========== ==========
See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
--------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 73,844 $ 120,492 $ 93,330
Adjustments for Noncash Items:
Depreciation and Amortization 163,202 149,791 144,967
Deferred Federal Income Taxes 8,602 13,033 (2,338)
Deferred Investment Tax Credits (4,915) (4,972) (5,265)
Deferred Power Supply Costs (net) (84,408) 35,955 30,081
Provision for Rate Refunds (4,818) 4,818 (31,019)
Extraordinary Gain - Discontinuance of SFAS 71 (8,938) - -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (166,911) 10,989 (1,562)
Fuel, Materials and Supplies 18,487 (4,812) (5,006)
Accrued Utility Revenues (13,081) (7,433) 5,223
Accounts Payable 159,369 (9,273) 14,066
Taxes Accrued 14,220 13,319 (5,830)
Revenue Refunds Accrued 181 (95,267) 91,956
Incentive Plan Accrued 10,662 1,507 (3,429)
Disputed Tax and Interest Related to COLI 72,440 (4,124) (68,316)
Change in Operating Reserves (19,770) 7,451 10,052
Net Change in Energy Trading Contracts 3,749 (14,531) 3,529
Rate Stabilization Deferral 75,601 - -
Other (net) (9,647) (24,681) 13,011
---------- --------- ---------
Net Cash Flows From Operating Activities 287,869 192,262 283,450
---------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (199,285) (211,416) (204,869)
Proceeds from Sales of Property and Other 159 19,296 2,930
Net Cost of Removal and Other (7,500) (24,373) (9,286)
---------- --------- ---------
Net Cash Flows Used For
Investing Activities (206,626) (216,493) (211,225)
---------- --------- ---------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company - 50,000 50,000
Issuance of Long-term Debt 74,788 227,236 211,944
Retirement of Cumulative Preferred Stock (9,924) (2,675) (294)
Retirement of Long-term Debt (136,166) (116,688) (157,973)
Change in Short-term Debt (net) 68,015 47,080 (53,900)
Change in Advances to Affiliates (8,387) - -
Dividends Paid on Common Stock (126,612) (121,392) (118,916)
Dividends Paid on Cumulative Preferred Stock (1,938) (2,257) (2,278)
---------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (140,224) 81,304 (71,417)
---------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents (58,981) 57,073 808
Cash and Cash Equivalents January 1 64,828 7,755 6,947
---------- --------- ---------
Cash and Cash Equivalents December 31 $ 5,847 $ 64,828 $ 7,755
========== ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $124,579,000,
$125,900,000 and $124,027,000 and for income taxes was $63,682,000,
$55,157,000 and $65,102,000 in 2000, 1999 and 1998, respectively. Noncash
acquisitions under capital leases were $14,116,000, $13,868,000 and
$21,146,000 in 2000, 1999 and 1998, respectively.
See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
-----------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
Retained Earnings January 1 $175,854 $179,461 $207,544
Net Income 73,844 120,492 93,330
-------- -------- --------
249,698 299,953 300,874
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 126,612 121,392 118,916
Cumulative Preferred Stock:
4-1/2% Series 811 850 875
5.90% Series 307 425 455
5.92% Series 364 364 364
6.85% Series 289 579 579
-------- -------- --------
Total Cash Dividends Declared 128,383 123,610 121,189
Capital Stock Expense 731 489 224
-------- -------- --------
Total Deductions 129,114 124,099 121,413
-------- -------- --------
Retained Earnings December 31 $120,584 $175,854 $179,461
======== ======== ========
See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,096,260 $1,150,571
---------- ----------
PREFERRED STOCK - authorized shares 8,000,000 no par value
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series(a) 2000 (b) Year Ended December 31, December 31, 2000
- ------ ------------ ---------------------------- -----------------
2000 1999 1998
---- ---- ----
Not Subject to Mandatory Redemption:
4-1/2% $110.00 7,011 8,671 3,878 177,905 17,790 18,491
------ ------
Subject to Mandatory Redemption:
5.90% (c) (e) 10,000 20,000 - 47,100 4,710 5,710
5.92% (c) (e) - - - 61,500 6,150 6,150
6.85% (d) (f) 84,500 - - - - 8,450
------ ------
10,860 20,310
------ ------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 739,015 844,472
Installment Purchase Contracts 234,782 264,217
Senior Unsecured Notes 468,113 392,844
Junior Debentures 161,367 161,228
Other Long-term Debt 2,541 2,546
Less Portion Due Within One Year (175,006) (126,005)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,430,812 1,539,302
---------- ----------
TOTAL CAPITALIZATION $2,555,722 $2,728,674
========== ==========
(a) The sinking fund provisions of each series subject to mandatory redemption
have been met by purchase of shares in advance of the due date.
(b) The cumulative preferred stock is callable at the price indicated plus
accrued dividends. The involuntary liquidation preference is $100 per
share. The aggregate involuntary liquidation price for all shares of
cumulative preferred stock may not exceed $300 million. The unissued shares
of the cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance.
(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per
share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92%
series outstanding under sinking fund provisions at its option and all
outstanding shares must be reacquired in 2008. Shares redeemed in 2000 and
1999 may be applied to meet the sinking fund requirement.
(d) Commencing in 2000 and continuing through date of redemption, a sinking
fund for the 6.85% cumulative preferred stock will require the redemption
of 60,000 shares each year, in each case at $100 per share. The Company has
the non-cumulative option to redeem up to 60,000 additional shares on any
sinking fund date at a redemption price of $100 per share.
(e) Not callable until after 2002.
(f) This series of preferred stock was redeemed in 2000.
See Notes to Consolidated Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- ---------------------------------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
6.35 2000 - March 1 $ - $ 48,000
6.71 2000 - June 1 - 48,000
6-3/8 2001 - March 1 100,000 100,000
7.38 2002 - August 15 50,000 50,000
7.40 2002 - December 1 30,000 30,000
6.65 2003 - May 1 40,000 40,000
6.85 2003 - June 1 30,000 30,000
6.00 2003 - November 1 30,000 30,000
7.70 2004 - September 1 21,000 21,000
7.85 2004 - November 1 50,000 50,000
8.00 2005 - May 1 50,000 50,000
6.89 2005 - June 22 30,000 30,000
6.80 2006 - March 1 100,000 100,000
8.50 2022 - December 1 70,000 70,000
7.80 2023 - May 1 30,237 30,237
7.15 2023 - November 1 20,000 20,000
7.125 2024 - May 1 45,000 50,000
8.00 2025 - June 1 45,000 50,000
Unamortized Discount (2,222) (2,765)
-------- --------
Total $739,015 $844,472
======== ========
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
Industrial Development
Authority of
Russell County, Virginia:
7.70 2007 - November 1 $ 17,500 $ 17,500
5.00 2021 - November 1 19,500 19,500
Putnam County, West Virginia:
5.45 2019 - June 1 40,000 40,000
6.60 2019 - July 1 30,000 30,000
Mason County, West Virginia:
7-7/8 2013 - November 1 10,000 10,000
7.40 2014 - January 1 - 30,000
6.85 2022 - June 1 40,000 40,000
6.60 2022 - October 1 50,000 50,000
6.05 2024 - December 1 30,000 30,000
Unamortized Discount (2,218) (2,783)
-------- --------
Total $234,782 $264,217
======== ========
Under the terms of the installment purchase contracts, APCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2001 - June 27 $ 75,000 $ -
7.45 2004 - November 1 50,000 50,000
6.60 2009 - May 1 150,000 150,000
7.20 2038 - March 31 100,000 100,000
7.30 2038 - June 30 100,000 100,000
Unamortized Discount (6,887) (7,156)
-------- --------
Total $468,113 $392,844
======== ========
(a) A floating interest rate is determined monthly.
The rate on December 31, 2000 was 6.95%.
Junior debentures outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
8-1/4% Series A due
2026 - September 30 $ 75,000 $ 75,000
8% Series B due 2027
- March 31 90,000 90,000
Unamortized Discount (3,633) (3,772)
-------- --------
Total $161,367 $161,228
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.
At December 31, 2000, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2001 $ 175,006
2002 80,006
2003 100,007
2004 121,008
2005 80,010
Later Years 1,064,741
----------
Total Principal Amount 1,620,778
Unamortized Discount (14,960)
----------
Total $1,605,818
==========
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items Note 2
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Staff Reduction Note 11
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Supplementary Information Note 17
Leases Note 18
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Appalachian Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Appalachian Power Company and its
subsidiaries as of December 31, 2000 and 1999, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Appalachian Power Company and
its subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
D-13
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
---------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,771,177 $1,482,475 $1,406,117 $1,376,282 $1,300,688
Operating Expenses 1,464,079 1,188,490 1,123,330 1,124,963 1,019,498
---------- ---------- ---------- ---------- ----------
Operating Income 307,098 293,985 282,787 251,319 281,190
Nonoperating Income
(Loss) 7,235 8,113 760 8,277 (11,145)
---------- ---------- ---------- ---------- ----------
Income Before Interest
Charges 314,333 302,098 283,547 259,596 270,045
Interest Charges 124,766 114,380 122,036 131,173 127,451
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 189,567 187,718 161,511 128,423 142,594
Extraordinary Loss - (5,517) - - -
---------- ---------- ---------- ---------- -----------
Net Income 189,567 182,201 161,511 128,423 142,594
Preferred Stock Dividend
Requirements 241 6,931 6,901 9,523 13,563
Gain (Loss) on Reacquired
Preferred Stock - (2,763) - 2,402 -
---------- ---------- ---------- ---------- -----------
Earnings Applicable to
Common Stock $ 189,326 $ 172,507 $ 154,610 $ 121,302 $ 129,031
========== ========== ========== ========== ==========
December 31,
---------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $5,592,444 $5,511,894 $5,336,191 $5,215,749 $5,116,570
Accumulated Depreciation
and Amortization 2,297,189 2,247,225 2,072,686 1,891,406 1,732,252
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $3,295,255 $3,264,669 $3,263,505 $3,324,343 $3,384,318
========== ========== ========== ========== ==========
Total Assets $5,472,496 $4,847,850 $4,735,476 $4,897,380 $4,919,014
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $ 573,888 $ 573,888 $ 573,888 $ 573,888 $ 573,888
Retained Earnings 792,219 758,894 734,387 828,777 864,475
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $1,366,107 $1,332,782 $1,308,275 $1,402,665 $1,438,363
========== ========== ========== ========== ==========
Preferred Stock $ 5,967 $ 5,967 $ 163,204 $ 163,204 $ 250,351
========== ========== ========== ========== ==========
CPL - Obligated,
Mandatorily Redeemable
Preferred Securities of
Subsidiary Trust Holding
Solely Junior
Subordinated Dentures of
CPL 148,500 150,000 150,000 150,000 -
---------- ---------- ---------- ---------- -----------
Long-term Debt (a) $1,454,559 $1,454,541 $1,350,706 $1,414,335 $1,613,805
========== ========== ========== ========== ==========
Total Capitalization
and Liabilities $5,472,496 $4,847,850 $4,735,476 $4,897,380 $4,919,014
========== ========== ========== ========== ==========
(a) Including portion due within one year.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations
- --------------------------------------------------
CPL is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power and provides electric power to
approximately 680,000 retail customers in southern Texas. CPL also sells
electric power at wholesale to other utilities, municipalities and rural
electric cooperatives. CPL participates in power marketing and trading
activities conducted on its behalf by the AEP System.
CPL shares in the revenues and costs of the AEP Power Pool's wholesale
sales to and net forward trades with other utility systems and power marketers.
Revenues from trading of electricity are recorded net of purchases as operating
revenues.
Results of Operations
Income before extraordinary item increased $2 million or 1% in 2000
primarily as a result of increased retail energy sales, the post merger
implementation of AEP's power marketing and trading operations which increased
wholesale sales to neighboring utilities and power marketers and the effect of
an unfavorable adjustment in 1999 as a result of FERC's approval of a
transmission coordination agreement. These items were offset in part by a rise
in interest expense. Income before extraordinary item increased $26 million or
16% in 1999 as a result of lower interest charges and increased retail sales. In
1999 CPL recorded an extraordinary loss as a result of a write-off of
unamortized expenses associated with the reacquisition of long-term debt.
Operating Revenues
Operating revenues increased 19% in 2000 and 5% in 1999. The increase
in 2000 was primarily due to an increase in fuel-related revenues and a rise in
energy sales. Increases in retail and transmission revenues were the primary
reasons for the increase in 1999.
The following analyzes the changes in operating revenues:
Increase (Decrease)
From Previous Year
(dollars in millions)
- ---------------------
2000 1999
-----------------------------
Amount % Amount %
Retail:
Residential $109.5 $13.4
Commercial 66.9 16.1
Industrial 39.5 21.1
Other 6.9 3.7
------ -----
222.8 17 54.3 4
Wholesale 64.8 85 9.2 14
Transmission
and Other 1.1 1 12.9 15
------ -----
Total $288.7 19 $76.4 5
====== =====
Retail operating revenues increased 17% in 2000 due to an increase in
fuel and purchased power related revenues, reflecting rising prices for natural
gas and purchased power, and an increase in weather-related demand for
electricity. In 1999 an increase in fuel and purchased power related revenues
and a modest increase in usage accounted for the increase in retail revenues.
The increase in 1999 revenues was partially offset by a reduction in base rates
resulting from a PUCT rate order. Since the Texas fuel and purchased power
clause recovery mechanism provides for the accrual of revenues to recover fuel
and purchased power cost increases until reviewed and approved for billing to
customers by the PUCT, increases in fuel and purchased power expenses and
related accrued revenues do not adversely affect results of operations.
The significant increase in wholesale revenues in 2000 is attributable
to increased sales to other utilities and CPL's initial participation after the
merger in the AEP System's power marketing and trading operations. The volume of
electricity sales to other utilities, both affiliated and unaffiliated,
increased as demand for energy rose in response to warmer summer weather. Since
CPL became a subsidiary of AEP as a result of the merger in June 2000, CPL
shares in the AEP System's power marketing and trading transactions with other
non-affiliated entities. Trading involves the purchase and sale of substantial
amounts of electricity with non-affiliated parties. Revenues from trading are
recorded net of purchases.
Operating Expenses Increase
Total operating expenses increased 23% in 2000 and 6% in 1999 primarily
due to increased costs of fuel and purchased power and a rise in other operation
expense. The changes in the components of operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions)
- ---------------------
2000 1999
----------------------------
Amount % Amount %
Fuel $146.9 36 $ 18.0 5
Purchased Power 109.2 160 28.1 70
Other Operation 28.4 10 30.1 12
Maintenance (9.6) (14) 6.4 10
Depreciation and
Amortization 1.1 1 (7.1) (4)
Taxes Other Than
Federal Income
Taxes (4.5) (5) 13.6 19
Federal Income
Taxes 4.1 4 (23.9) (21)
------ ------
Total $275.6 23 $ 65.2 6
====== ======
Fuel expense increased in 2000 and 1999 primarily due to a rise in the
average cost of fuel primarily from a large increases in natural gas prices. CPL
uses natural gas as fuel for 71% of its generating capacity. The nature of the
natural gas market is such that both long-term and short-term contracts are
generally based on the current spot market price. Changes in natural gas prices
affect CPL's fuel expense, however, as explained above, they generally do not
impact results of operations.
The rise in purchased power expense in 2000 was due to an increase in
the cost of purchased electricity as a result of the rise in spot market natural
gas prices, an increase in the quantity of energy purchased to meet the rise in
demand, and increased cogeneration purchases. Purchased power expense increased
70% in 1999 due primarily to higher economy energy purchases reflecting the rise
in natural gas prices.
Other operation expense increased in 2000 due primarily to an increase in
transmission expenses that resulted from new prices for the ERCOT transmission
grid. Each year ERCOT establishes new rates to allocate the costs of the Texas
transmission system to Texas electric utilities. In addition to higher
transmission expenses, other operation expense increased due to higher
administrative expenses resulting from the Company's share of STP voluntary
severance expenses and Texas regulatory expenses.
In 1999 the increase in other operation expense was caused mainly by a
rise in outside service expenses associated with the Texas Legislation and
securitization of generation-related regulatory assets, as well as higher
transmission expenses. The increase in transmission expense was due primarily to
the settlement of a complaint with Texas Utilities Electric Company and the
absence in 1999 of a transmission service agreement adjustment made in 1998
related to a final order by the PUCT on a joint complaint filed by CPL and WTU
asserting that Texas Utilities Electric Company had been effectively double
charging for transmission service within ERCOT.
Maintenance expenses decreased in 2000 and increased in 1999 as a result
of a 10-year service inspection and refueling of STP Units 1 and 2 performed in
1999. Also contributing to the increase in maintenance expense in 1999 were
scheduled power plant repairs at some of CPL's other generating plants.
Taxes other than income taxes increased in 1999 due primarily to higher
franchise tax expenses.
Federal income tax expense associated with utility operations decreased
in 1999 as a result of reduced taxable income, the reclassification of certain
income tax related regulatory assets designated for securitization consistent
with the Texas Legislation, and prior year income tax liability adjustments.
Interest Charges
The increase in interest charges in 2000 can be attributed to higher
average interest rates associated with short term and long term debt. Interest
charges decreased in 1999 due primarily to the maturity and reacquisition of
long-term debt during 1998 and 1999.
Preferred Stock Dividends
Preferred stock dividends decreased in 2000 as a result of the redemption
of preferred stock in the fourth quarter of 1999, which resulted in a loss on
reacquired preferred stock recorded in 1999.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
---------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $1,771,177 $1,482,475 $1,406,117
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 550,903 403,989 385,944
Purchased Power 177,387 68,155 40,062
Other Operation 319,539 291,131 261,058
Maintenance 60,528 70,165 63,779
Depreciation and Amortization 178,786 177,702 184,805
Taxes Other Than Federal Income Taxes 80,009 84,538 70,927
Federal Income Tax 96,927 92,810 116,755
---------- ---------- ----------
Total Operating Expenses 1,464,079 1,188,490 1,123,330
---------- ---------- ----------
OPERATING INCOME 307,098 293,985 282,787
NONOPERATING INCOME 7,235 8,113 760
---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES 314,333 302,098 283,547
INTEREST CHARGES 124,766 114,380 122,036
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 189,567 187,718 161,511
EXTRAORDINARY LOSS ON REACQUIRED DEBT
(INCLUSIVE OF TAX $2,971,000) - (5,517) -
---------- ---------- -----------
NET INCOME 189,567 182,201 161,511
PREFERRED STOCK DIVIDEND REQUIREMENTS 241 6,931 6,901
LOSS ON REACQUIRED PREFERRED STOCK - (2,763) -
---------- ---------- -----------
EARNINGS APPLICABLE TO COMMON STOCK $ 189,326 $ 172,507 $ 154,610
========== ========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ------------------------------------------------------------------------------------------
December 31,
2000 1999
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,175,867 $3,152,319
Transmission 581,931 566,629
Distribution 1,221,750 1,157,091
General 237,764 307,378
Construction Work in Progress 138,273 101,550
Nuclear Fuel 236,859 226,927
---------- ----------
Total Electric Utility Plant 5,592,444 5,511,894
Accumulated Depreciation and Amortization 2,297,189 2,247,225
---------- ----------
NET ELECTRIC UTILITY PLANT 3,295,255 3,264,669
---------- ----------
OTHER PROPERTY AND INVESTMENTS 44,225 41,433
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 66,231 -
---------- -----------
CURRENT ASSETS:
Cash and Cash Equivalents 14,253 7,995
Special Deposits for Reacquisition of Long-term Debt - 50,000
Accounts Receivable:
General 67,787 49,228
Affiliated Companies 31,272 15,254
Allowance for Uncollectible Accounts (1,675) -
Fuel Inventory - at LIFO cost 22,842 26,434
Materials and Supplies - at average cost 53,108 58,196
Under-recovered Fuel Costs 127,295 30,423
Energy Trading Contracts 481,206 -
Prepayments 3,014 3,188
---------- ----------
TOTAL CURRENT ASSETS 799,102 240,718
---------- ----------
REGULATORY ASSETS 202,440 223,359
---------- ----------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249
---------- ----------
NUCLEAR DECOMMISSIONING TRUST FUND 93,592 86,122
---------- ----------
DEFERRED CHARGES 18,402 38,300
---------- ----------
TOTAL $5,472,496 $4,847,850
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
- -----------------------------------------------------------------------------------------------------
December 31,
---------------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 6,755,535 Shares $ 168,888 $ 168,888
Paid-in Capital 405,000 405,000
Retained Earnings 792,219 758,894
---------- ----------
Total Common Shareholder's Equity 1,366,107 1,332,782
Preferred Stock 5,967 5,967
CPL - Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely
Junior Subordinated Debentures of CPL 148,500 150,000
Long-term Debt 1,254,559 1,304,541
---------- ----------
TOTAL CAPITALIZATION 2,775,133 2,793,290
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 200,000 150,000
Advances from Affiliates 269,712 322,158
Accounts Payable - General 128,957 88,702
Accounts Payable - Affiliated Companies 40,962 35,344
Taxes Accrued 55,526 41,121
Interest Accrued 26,217 14,723
Energy Trading Contracts 489,888 -
Other 40,630 25,349
---------- ----------
TOTAL CURRENT LIABILITIES 1,251,892 677,397
---------- ----------
DEFERRED INCOME TAXES 1,242,797 1,234,175
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 128,100 133,306
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 65,740 -
---------- -----------
DEFERRED CREDITS 8,834 9,682
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $5,472,496 $4,847,850
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 189,567 $ 182,201 $ 161,511
Adjustments for Noncash Items:
Depreciation and Amortization 178,786 177,702 184,805
Refunds Due Customers - - (63,713)
Changes for Investments and Assets - - 18,669
Extraordinary Loss on Reacquired Debt - 5,517 -
Deferred Income Taxes 16,263 19,938 (8,328)
Deferred Investment Tax Credits (5,207) (5,207) (3,858)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (32,902) (13,426) 10,255
Fuel, Materials and Supplies 8,680 (4,476) (48)
Interest Accrued 11,494 (12,313) (1,343)
Fuel Recovery (96,872) (40,046) 52,364
Accounts Payable 45,873 (3,061) 41,179
Taxes Accrued 14,405 (5,734) 33,297
Transmission Coordination Agreement Settlement 15,519 (15,519) -
Other (net) 21,023 19,420 12,839
--------- --------- ---------
Net Cash Flows From Operating Activities 366,629 304,996 437,629
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (199,484) (210,823) (123,803)
Proceeds from Sales of Property and Other - 15,063 (7,181)
--------- --------- ---------
Net Cash Flows Used For Investing Activities (199,484) (195,760) (130,984)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 149,248 358,887 -
Redemption of Preferred Stock - (160,001) -
Retirement of Long-term Debt (151,440) (261,700) (64,000)
Change in Advances from Affiliates (net) (52,446) 161,860 17,517
Special Deposit for Reacquisitions 50,000 (50,000) -
Dividends Paid on Common Stock (156,000) (148,000) (249,000)
Dividends Paid on Cumulative Preferred Stock (249) (7,835) (7,219)
--------- --------- ---------
Net Cash Flows Used For Financing Activities (160,887) (106,789) (302,702)
--------- --------- ---------
Net Increase in Cash and Cash Equivalents 6,258 2,447 3,943
Cash and Cash Equivalents January 1 7,995 5,548 1,605
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 14,253 $ 7,995 $ 5,548
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts (including distributions on
Trust Preferred Securities) was $110,010,000, $125,222,000 and $99,239,000 and
for income taxes was $48,141,000, $78,393,000 and $94,245,000 in 2000, 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD
AS PREVIOUSLY REPORTED $764,225 $739,031 $833,282
CONFORMING CHANGE IN ACCOUNTING POLICY (5,331) (4,644) (4,505)
-------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD 758,894 734,387 828,777
NET INCOME 189,567 182,201 161,511
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 156,000 148,000 249,000
Preferred Stock 241 6,931 6,901
Other 1 - -
LOSS ON REACQUIRED PREFERRED STOCK - (2,763) -
-------- -------- ---------
BALANCE AT END OF PERIOD $792,219 $758,894 $734,387
======== ======== ========
See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDERS' EQUITY $1,366,107 $1,332,782
---------- ----------
PREFERRED STOCK - authorized shares 3,035,000 $100 par value
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2000 Year Ended December 31, December 31, 2000
- ------ ------------ ---------------------------- -----------------
2000 1999 1998
---- ---- ----
Not Subject to Mandatory Redemption:
4.00% $105.75 - - - 42,038 4,204 4,204
4.20% 103.75 - - - 17,476 1,748 1,748
Premium 15 15
---------- ----------
Total Preferred Stock 5,967 5,967
---------- ----------
TRUST PREFERRED SECURITIES:
CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely Junior Subordinated Debentures of CPL, 8.00%,
due April 30, 2037 148,500 150,000
---------- ----------
LONG-TERM (See Schedule of Long-term Debt):
First Mortgage Bonds 615,000 764,991
Installment Purchase Contracts 489,559 489,550
Senior Unsecured Notes 350,000 200,000
Less Portion Due Within One year (200,000) (150,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,254,559 1,304,541
---------- ----------
TOTAL CAPITALIZATION $2,775,133 $2,793,290
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
7.50 2020 - March 1 $ - $ 50,000
7.25 2004 - October 1 100,000 100,000
7.50 2002 - December 1 115,000 115,000
6-7/8 2003 - February 1 50,000 50,000
7-1/8 2008 - February 1 75,000 75,000
6.00 2000 - April 1 - 100,000
7.50 2023 - April 1 75,000 75,000
6-5/8 2005 - July 1 200,000 200,000
Unamortized Discount - (9)
-------- --------
Total $615,000 $764,991
======== ========
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
Matagorda County
Naviagation District,
Texas:
6.00 2028 - July 1 $120,265 $120,265
6.10 2028 - July 1 100,635 100,635
6-1/8 2030 - May 1 60,000 60,000
4.90 2030 - May 1 111,700 111,700
4.95 2030 - May 1 50,000 50,000
Guadalupe-Blanco
River Authority District,
Texas:
(a) 2015 - November 1 40,890 40,890
Red River Authority
District, Texas:
6.00 2020 - June 1 6,330 6,330
Unamortized Discount (261) (270)
-------- --------
Total $489,559 $489,550
======== ========
(a) A floating interest rate is determined monthly.
The rate on December 31, 2000 was 4.90%.
Under the terms of the installment purchase contracts, CPL is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(b) 2001 - November 23 $200,000 $200,000
(c) 2002 - February 22 150,000 -
-------- ---------
Total $350,000 $200,000
======== ========
(b) A floating interest rate is determined
monthly. The rate on December 31, 2000
was 7.35063%.
(c) A floating interest rate is determined
monthly. The rate on December 31, 2000
was 7.20313%.
At December 31, 2000, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2001 $ 200,000
2002 265,000
2003 50,000
2004 100,000
2005 200,000
Later Years 639,820
----------
Total Principal Amount 1,454,820
Unamortized Discount (261)
----------
Total $1,454,559
==========
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
- ------------------------------------------------------------
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items Note 2
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Trust Preferred Securities Note 21
Jointly Owned Electric Utility Plant Note 22
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
- --------------------------------------------
To the Shareholders and Board of Directors
of Central Power and Light Company:
We have audited the accompanying consolidated balance sheet and
consolidated statement of capitalization of Central Power and Light Company and
subsidiary as of December 31, 2000, and the related consolidated statements of
income, retained earnings, and cash flows for the year then ended. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audit. The consolidated financial statements of the Company for the years
ended December 31, 1999 and 1998, before the restatement described in Note 3 to
the consolidated financial statements, were audited by other auditors whose
report, dated February 25, 2000, expressed an unqualified opinion on those
statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the 2000 consolidated financial statements present
fairly, in all material respects, the financial position of Central Power and
Light Company and subsidiary as of December 31, 2000, and the results of their
operations and their cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America.
We also audited the adjustments described in Note 3 that were applied
to restate the 1999 and 1998 consolidated financial statements to give
retroactive effect to the conforming change in the method of accounting for
vacation pay accruals. In our opinion, such adjustments are appropriate and have
been properly applied.
Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of
Central Power and Light Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Central Power and Light Company (a Texas
corporation and a wholly owned subsidiary of Central and South West Corporation)
and subsidiary company as of December 31, 1999, and the related consolidated
statements of income, retained earnings and cash flows, for each of the two
years in the period ended December 31, 1999 prior to the restatement (and,
therefore, are not presented herein) for the retroactive effect of the
conforming change in the method of accounting for vacation pay accruals and
certain conforming reclassifications to the historical financial statements as
described in Note 3 to the restated consolidated financial statements. These
financial statements are the responsibility of Central Power and Light Company's
management. Our responsibility is to express an opinion on these consolidated
financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements prior to the restatement
referred to above present fairly, in all material respects, the financial
position of Central Power and Light Company and subsidiary company as of
December 31, 1999, and the results of their operations and their cash flows for
each of the two years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States.
Arthur Anderson LLP
Dallas, Texas
February 25, 2000
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
E-12
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
- ----------------------------------------------------------------------------------------------
Year Ended December 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,356,408 $1,229,994 $1,187,745 $1,094,851 $1,105,683
Operating Expenses 1,160,531 1,007,204 975,534 899,724 920,136
---------- ---------- ---------- ---------- ----------
Operating Income 195,877 222,790 212,211 195,127 185,547
Nonoperating Income (Loss) 5,153 2,709 (1,343) 3,137 (970)
---------- ---------- ---------- ---------- ----------
Income Before Interest
Charges 201,030 225,499 210,868 198,264 184,577
Interest Charges (net) 80,828 75,229 77,824 78,885 77,469
---------- ---------- ---------- ---------- ----------
Income Before Extraordinary
Item 120,202 150,270 133,044 119,379 107,108
Extraordinary Item (25,236) - - - -
---------- ---------- ---------- ---------- -----------
Net Income 94,966 150,270 133,044 119,379 107,108
Preferred Stock Dividend
Requirements 1,783 2,131 2,131 2,442 6,029
---------- ---------- ---------- ---------- ----------
Earnings Applicable
to Common Stock $ 93,183 $ 148,139 $ 130,913 $ 116,937 $ 101,079
========== ========== ========== ========== ==========
December 31,
------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
BALANCE SHEETS DATA: (in thousands)
Electric Utility Plant $3,266,794 $3,151,619 $3,053,565 $2,976,110 $2,899,893
Accumulated Depreciation 1,299,697 1,210,994 1,134,348 1,074,588 1,016,909
---------- ---------- ---------- ---------- ----------
Net Electric Utility Plant $1,967,097 $1,940,625 $1,919,217 $1,901,522 $1,882,984
========== ========== ========== ========== ==========
Total Assets $3,894,934 $2,809,990 $2,681,690 $2,613,860 $2,541,586
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $ 614,380 $ 613,899 $ 613,518 $ 613,138 $ 615,735
Retained Earnings 99,069 246,584 186,441 138,172 99,582
---------- ---------- ---------- ---------- ----------
Total Common Shareholder's
Equity $ 713,449 $ 860,483 $ 799,959 $ 751,310 $ 715,317
========== ========== ========== ========== ==========
Cumulative Preferred
Stock - Subject to
Mandatory Redemption (a) $ 15,000 $ 25,000 $ 25,000 $ 25,000 $ 75,000
========== ========== ========== ========== ==========
Long-term Debt (a) $ 899,615 $ 924,545 $ 959,786 $ 969,600 $ 897,281
========== ========== ========== ========== ==========
Obligations Under Capital
Leases (a) $ 42,932 $ 40,270 $ 42,362 $ 38,587 $ 36,134
========== ========== ========== ========== ==========
Total Capitalization and
Liabilities $3,894,934 $2,809,990 $2,681,690 $2,613,860 $2,541,586
========== ========== ========== ========== ==========
(a) Including portion due within one year.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Management's Narrative Analysis of
Results of
Operations
- ------------------------------------------------------------
Columbus Southern Power Company is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
667,000 retail customers in central and southern Ohio. CSPCo as a member of the
AEP Power Pool shares in the revenues and costs of the AEP Power Pool's
wholesale sales to neighboring utility systems and power marketers. CSPCo also
sells wholesale power to municipalities.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges and receipt of capacity
credits. AEP Power Pool members are also compensated for their out-of-pocket
costs of energy delivered to the AEP Power Pool and charged for energy received
from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's percentage share of AEP
Power Pool revenues and costs. CSPCo as a member of the AEP Power Pool shares in
the revenues and costs of the AEP Power Pool's wholesale sales to and net
forward trades with other utility systems and power marketers. Revenues from
forward electricity trades are recorded net of purchases as operating revenues
for transactions in AEP's traditional marketing area (up to two trans-mission
systems from the AEP service territory) and as nonoperating income for
transactions beyond two transmission systems from AEP. The AEP Power Pool also
enters into power trading transactions for options, futures and swaps. CSPCo's
share of these transactions is recorded in nonoperating income.
In February 2001 the U.S. District Court for the Southern District of
Ohio ruled against AEP and certain of its subsidiaries, including CSPCo, in a
suit over deductibility of interest claimed in AEP's consolidated tax return
related to a corporate owned life insurance (COLI) program. In 1998 and 1999
CSPCo paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1991-98. The payments were included in Other
Property and Investments pending the resolution of this matter. As a result of
the Court's decision, net income was reduced by $41 million in 2000.
Results of Operations
Net Income Decreases
Income before extraordinary item decreased by $30 million or 20%
primarily due to increases in federal income tax expense and related interest
charges as a result of the U.S. District Court's decision denying COLI
deductions. An extraordinary loss related to the discontinuance of SFAS 71
regulatory accounting of $25 million after tax was recorded in September 2000 in
connection with the PUCO approval of a plan to transition CSPCo's generation
business from cost based rate regulation to customer choice and market pricing.
Operating Revenues Increase
Operating revenues increased $126.4 million in 2000 due to a significant
increase in AEP Power Pool wholesale marketing and trading transactions. Changes
in the components of operating revenues were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Retail:
Residential $ 0.8
Commercial 14.1
Industrial (6.0)
Other 0.9
------
Wholesale 123.5 102.6
Transmission (0.1) (0.2)
Other (6.8) (32.1)
------
Total $126.4 10.3
======
The increase in wholesale revenues is due to a significant increase in
AEP Power Pool transactions. As a result of a major industrial customer's
decision in January 2000 not to continue purchasing power from an affiliate,
additional power was available to the AEP Power Pool for sale on the wholesale
market accounting in part for the increase in the CSPCo's wholesale Power Pool
revenues. The increase in AEP Power Pool wholesale sales also resulted from
growing AEP's power marketing and trading operation, favorable wholesale market
conditions and increased availability of generation. AEP generating unit
availability was increased due to the return to service of one of an affiliate's
nuclear generating units and improved generating unit outage management. With
the return to service in June 2000 of one of an affiliate's two nuclear
generating units that affiliate supplied more power to the AEP Power Pool at a
lower cost reducing the need to acquire higher cost power on the open market.
Operating Expenses Rise
Operating expenses increased by 15% in 2000 mostly due to increases in
purchased power expense, other operation expense and federal income taxes.
Changes in the components of operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Fuel $ 3.6 2.0
Purchased Power Expense 82.2 31.0
Other Operation Expense 31.2 16.3
Maintenance Expense 4.5 6.8
Depreciation 5.1 5.4
Taxes Other Than Federal
Income Taxes 3.1 2.6
Federal Income Taxes 23.6 27.5
------
Total $153.3 15.2
======
The increase in other operation expense was due to increased power
generation costs that resulted from higher emission allowance consumption,
increased emission allowance cost and increased costs for power trading
reflecting the growth of the power marketing and trading operation.
The increase in purchased power expense reflects additional purchases of
power from the AEP Power Pool as a result of increased availability of AEP Pool
generation. The AEP Power Pool was able to supply more energy to CSPCo since an
affiliate's out of service nuclear unit went on line in June 2000, a major
industrial customer discontinued purchasing power from an affiliate in January
2000, and generating unit outage managements improved.
Additional generating unit boiler repairs and maintenance of overhead
transmission and distribution lines accounted for the increase in maintenance
expense.
Depreciation expenses increased due to additional plant investment.
The increase in federal income tax expense was primarily due to the
court ruling related to the AEP's COLI program.
Nonoperating Income
The increase in nonoperating income in 2000 was due to an increase in
net gains from non-regulated AEP Power Pool trading transactions outside of the
AEP System's traditional marketing area. The AEP Power Pool enters into power
trading transactions for the purchase and sale of electricity and for options,
futures and swaps. The Company's share of the AEP Power Pool's gains and losses
from forward electricity trading transactions outside of the AEP System
traditional marketing area and for speculative financial transactions (options,
futures, swaps) is included in nonoperating income. The increase in nonoperating
income is also attributable to the reversal in the first quarter of 2000 of a
remaining provision for potential liability for clean-up of possible
environmental contamination after the state of Ohio reviewed the matter and
determined that no further corrective action would be required.
Interest Charges Increase
Interest charges increased as a result of the recognition of deferred
interest payments to the IRS related to the COLI disallowances.
Extraordinary Loss
An extraordinary loss was recorded in the third quarter of 2000 when
CSPCo discontinued the application of SFAS 71 regulatory accounting for the
generation portion of its business due to the approval by the PUCO in September
2000 of a stipulation agreement providing for a transition from cost based rate
regulation for CSPCo's generation business to customer choice and market
pricing.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Income
- -------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $1,356,408 $1,229,994 $1,187,745
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 189,155 185,511 189,031
Purchased Power 347,693 265,457 237,688
Other Operation 221,775 190,614 202,720
Maintenance 69,676 65,229 62,095
Depreciation 99,640 94,532 91,218
Taxes Other Than Federal Income Taxes 123,291 120,147 116,548
Federal Income Taxes 109,301 85,714 76,234
---------- ---------- ----------
TOTAL OPERATING EXPENSES 1,160,531 1,007,204 975,534
---------- ---------- ----------
OPERATING INCOME 195,877 222,790 212,211
NONOPERATING INCOME (LOSS) 5,153 2,709 (1,343)
---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES 201,030 225,499 210,868
INTEREST CHARGES 80,828 75,229 77,824
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 120,202 150,270 133,044
EXTRAORDINARY LOSS:
Discontinuance of Regulatory
Accounting for Generation
(inclusive of tax benefit of $14,148,000) (25,236) - -
---------- ---------- ----------
NET INCOME 94,966 150,270 133,044
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,783 2,131 2,131
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 93,183 $ 148,139 $ 130,913
========== ========== ==========
Consolidated Statements of Retained Earnings
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
-------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
Retained Earnings January 1 $246,584 $186,441 $138,172
Net Income 94,966 150,270 133,044
-------- -------- --------
341,550 336,711 271,216
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 240,600 87,996 82,644
Cumulative Preferred Stock - 7% Series 1,400 1,750 1,750
-------- -------- --------
Total Cash Dividends Declared 242,000 89,746 84,394
Capital Stock Expense 481 381 381
-------- -------- --------
Total Deductions 242,481 90,127 84,775
-------- -------- --------
Retained Earnings December 31 $ 99,069 $246,584 $186,441
======== ======== ========
See Notes to Consolidated Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance
Sheets
- ------------------------------------------------------------------------------------------
December 31,
-------------------------------
2000 1999
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,564,254 $1,544,858
Transmission 360,302 350,826
Distribution 1,096,365 1,032,550
General 156,534 141,137
Construction Work in Progress 89,339 82,248
---------- ----------
Total Electric Utility Plant 3,266,794 3,151,619
Accumulated Depreciation 1,299,697 1,210,994
---------- ----------
NET ELECTRIC UTILITY PLANT 1,967,097 1,940,625
---------- ----------
OTHER PROPERTY AND INVESTMENTS 39,848 80,008
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 172,167 21,278
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 11,600 5,107
Accounts Receivable:
Customers 73,711 77,418
Affiliated Companies 49,591 28,453
Miscellaneous 18,807 8,887
Allowance for Uncollectible Accounts (659) (3,045)
Fuel - at average cost 13,126 21,484
Materials and Supplies - at average cost 38,097 41,696
Accrued Utility Revenues 9,638 48,117
Energy Trading Contracts 1,085,989 90,103
Prepayments 46,735 37,969
---------- ----------
TOTAL CURRENT ASSETS 1,346,635 356,189
---------- ----------
REGULATORY ASSETS 291,553 339,103
---------- ----------
DEFERRED CHARGES 77,634 72,787
---------- ----------
TOTAL $3,894,934 $2,809,990
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
- -------------------------------------------------------------------------------------------------
December 31,
-------------------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 573,354 572,873
Retained Earnings 99,069 246,584
---------- ----------
Total Common Shareholder's Equity 713,449 860,483
Cumulative Preferred Stock -
Subject to Mandatory Redemption 15,000 25,000
Long-term Debt 899,615 924,545
---------- ----------
TOTAL CAPITALIZATION 1,628,064 1,810,028
---------- ----------
OTHER NONCURRENT LIABILITIES 47,584 43,056
---------- ----------
CURRENT LIABILITIES:
Short-term Debt - 45,500
Advances from Affiliates 88,732 -
Accounts Payable - General 89,846 28,279
Accounts Payable - Affiliated Companies 72,493 52,776
Taxes Accrued 162,904 143,477
Interest Accrued 13,369 13,936
Energy Trading Contracts 1,115,967 87,911
Other 60,701 34,375
---------- ----------
TOTAL CURRENT LIABILITIES 1,604,012 406,254
---------- ----------
DEFERRED INCOME TAXES 422,759 447,607
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 41,234 44,716
---------- ----------
DEFERRED CREDITS 12,861 41,875
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 138,420 16,454
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $3,894,934 $2,809,990
========== ==========
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- --------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 94,966 $ 150,270 $133,044
Adjustments for Noncash Items:
Depreciation 100,182 94,962 91,426
Deferred Federal Income Taxes (4,063) 10,481 17,101
Deferred Investment Tax Credits (3,482) (3,994) (4,224)
Deferred Fuel Costs (net) 5,352 8,889 (11,311)
Extraordinary Loss - Discontinuance of SFAS 71 25,236 - -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (29,737) 5,166 (5,910)
Fuel, Materials and Supplies 11,957 (7,777) (8,226)
Accrued Utility Revenues 38,479 (7,990) 11,638
Accounts Payable 81,284 9,292 476
Disputed Tax and Interest Related to COLI 39,483 (2,240) (37,243)
Other (net) 7,480 (13,426) 29,776
---------- --------- ---------
Net Cash Flows From Operating Activities 367,137 243,633 216,547
---------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (127,987) (115,321) (114,979)
Proceeds from Sale and Leaseback
Transactions and Other 1,560 1,858 2,637
---------- --------- ---------
Net Cash Flows Used For
Investing Activities (126,427) (113,463) (112,342)
---------- --------- ---------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 88,732 - -
Issuance of Long-term Debt - - 111,075
Retirement of Preferred Stock (10,000) - -
Retirement of Long-term Debt (25,274) (35,523) (122,206)
Change in Short-term Debt (net) (45,500) (7,000) (14,100)
Dividends Paid on Common Stock (240,600) (87,996) (82,644)
Dividends Paid on Cumulative Preferred Stock (1,575) (1,750) (1,750)
---------- --------- ---------
Net Cash Flows Used For
Financing Activities (234,217) (132,269) (109,625)
---------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents 6,493 (2,099) (5,420)
Cash and Cash Equivalents January 1 5,107 7,206 12,626
---------- --------- ---------
Cash and Cash Equivalents December 31 $ 11,600 $ 5,107 $ 7,206
========== ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $68,506,000, $72,007,000
and $73,917,000 and for income taxes was $81,109,000, $71,809,000 and
$53,410,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under
capital leases were $10,777,000, $6,855,000 and $11,107,000 in 2000, 1999 and
1998, respectively.
See Notes to Consolidated Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 713,449 $ 860,483
---------- ----------
PREFERRED STOCK - authorized shares 2,500,000 $100 par value
authorized shares 7,000,000 $25 par value
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2000 Year Ended December 31, December 31, 2000
- ------ ------------ ---------------------------- -----------------
2000 1999 1998
---- ---- ----
Subject to Mandatory Redemption:
7.00% (a) 100,000 - - 150,000 15,000 25,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 537,119 562,327
Installment Purchase Contracts 91,166 91,112
Senior Unsecured Notes 159,318 159,212
Junior Debentures 112,012 111,894
---------- ----------
Total Long-term Debt 899,615 924,545
---------- ----------
TOTAL CAPITALIZATION $1,628,064 $1,810,028
========== ==========
(a) Commencing in 2000, a sinking fund will require the redemption of 50,000
shares at $100 a share on or before August 1 of each year. The Company has
the right, on each sinking fund date, to redeem an additional 50,000 shares
which the company did in August 2000. Redemption of this series is
prohibited prior to August 1, 2000. The sinking fund provisions of the 7%
series aggregate $5,000,000 in 2002, 2003 and 2004.
See Notes to Consolidated Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- -------------------------------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
7.25 2002 - October 1 $ 56,500 $ 75,000
7.15 2002 - November 1 20,000 20,000
6.80 2003 - May 1 45,000 50,000
6.60 2003 - August 1 40,000 40,000
6.10 2003 - November 1 20,000 20,000
6.55 2004 - March 1 50,000 50,000
6.75 2004 - May 1 50,000 50,000
8.70 2022 - July 1 35,000 35,000
8.40 2022 - August 1 15,000 15,000
8.55 2022 - August 1 15,000 15,000
8.40 2022 - August 15 25,500 25,500
8.40 2022 - October 15 13,000 15,000
7.90 2023 - May 1 50,000 50,000
7.75 2023 - August 1 33,000 33,000
7.45 2024 - March 1 30,000 30,000
7.60 2024 - May 1 41,000 41,000
Unamortized Discount (1,881) (2,173)
-------- --------
Total $537,119 $562,327
======== ========
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by the Ohio Air Quality Development
Authority:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ -----------------
6-3/8 2020 - December 1 $48,550 $48,550
6-1/4 2020 - December 1 43,695 43,695
Unamortized Discount (1,079) (1,133)
------- -------
Total $91,166 $91,112
======= =======
Under the terms of the installment purchase contracts, CSPCo is
required to pay amounts sufficient to enable the payment of interest on and the
principal (at stated maturities and upon mandatory redemptions) of related
pollution control revenue bonds issued to finance the construction of pollution
control facilities at the Zimmer Plant.
Senior unsecured notes outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
6.85 2005 - October 3 $ 48,000 $ 48,000
6.51 2008 - February 1 52,000 52,000
6.55 2008 - June 26 60,000 60,000
Unamortized Discount (682) (788)
-------- --------
Total $159,318 $159,212
======== ========
Junior debentures outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
8-3/8 2025 - September 30 $ 75,000 $ 75,000
7.92 2027 - March 31 40,000 40,000
Unamortized Discount (2,988) (3,106)
-------- --------
Total $112,012 $111,894
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.
At December 31, 2000, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2001 $ -
2002 76,500
2003 105,000
2004 100,000
2005 48,000
Later Years 576,745
--------
Total Principal Amount 906,245
Unamortized Discount (6,630)
--------
Total $899,615
========
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
- --------------------------------------------------------------
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items Note 2
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Staff Reductions Note 11
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Supplementary Information Note 17
Leases Note 18
Lines of Credit and Factoring of Receivable Note 19
Unaudited Quarterly Financial Information Note 20
Jointly Owned Electric Utility Plant Note 22
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
- --------------------------------------------------
To the Shareholders and Board of Directors
of Columbus Southern Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Columbus Southern Power Company and
its subsidiaries as of December 31, 2000 and 1999, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Columbus Southern Power
Company and its subsidiaries as of December 31, 2000 and 1999, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2000 in conformity with accounting principles
generally accepted in the United States of America.
Deloitte & Touche LLP
Columbus, Ohio
February 26, 2001
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
F-14
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial
Data
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,548,476 $1,394,119 $1,405,794 $1,339,232 $1,328,493
Operating Expenses 1,583,178 1,285,467 1,239,787 1,131,444 1,108,076
---------- ---------- ---------- ---------- ----------
Operating Income (Loss) (34,702) 108,652 166,007 207,788 220,417
Nonoperating Income
(Loss) 9,933 4,530 (839) 4,415 2,729
---------- ---------- ---------- ---------- ----------
Income (Loss) Before
Interest Charges (24,769) 113,182 165,168 212,203 223,146
Interest Charges 107,263 80,406 68,540 65,463 65,993
---------- ---------- ---------- ---------- ----------
Net Income (Loss) (132,032) 32,776 96,628 146,740 157,153
Preferred Stock
Dividend Requirements 4,624 4,885 4,824 5,736 10,681
---------- ---------- ---------- ---------- ----------
Earnings (Loss)
Applicable to
Common Stock $ (136,656) $ 27,891 $ 91,804 $ 141,004 $ 146,472
========== ========== ========== ========== ==========
December 31,
-----------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $4,871,473 $4,770,027 $4,631,848 $4,514,497 $4,377,669
Accumulated
Depreciation and
Amortization 2,280,521 2,194,397 2,081,355 1,973,937 1,861,893
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $2,590,952 $2,575,630 $2,550,493 $2,540,560 $2,515,776
========== ========== ========== ========== ==========
Total Assets $5,818,547 $4,576,696 $4,148,523 $3,967,798 $3,897,484
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 789,656 $ 789,323 $ 789,189 $ 789,056 $ 787,856
Retained Earnings 3,443 166,389 253,154 278,814 269,071
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $ 793,099 $ 955,712 $1,042,343 $1,067,870 $1,056,927
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to
Mandatory
Redemption $ 8,736 $ 9,248 $ 9,273 $ 9,435 $ 21,977
Subject to Mandatory
Redemption (a) 64,945 64,945 68,445 68,445 135,000
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 73,681 $ 74,193 $ 77,718 $ 77,880 $ 156,977
========== ========== ========== ========== ==========
Long-term Debt (a) $1,388,939 $1,324,326 $1,175,789 $1,049,237 $1,042,104
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 163,173 $ 187,965 $ 186,427 $ 195,227 $ 130,965
========== ========== ========== ========== ==========
Total Capitalization
and Liabilities $5,818,547 $4,576,696 $4,148,523 $3,967,798 $3,897,484
========== ========== ========== ========== ==========
(a) Including portion due within one year.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations
- ------------------------------------------------
I&M is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to 565,000 retail customers in
its service territory in northern and eastern Indiana and a portion of
southwestern Michigan. As a member of the AEP Power Pool, I&M shares the
revenues and the costs of the AEP Power Pool's wholesale sales to neighboring
utilities and power marketers. I&M also sells wholesale power to municipalities
and electric cooperatives.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges or the receipt of capacity
credits. AEP Power Pool members are also compensated for the out-of-pocket costs
of energy delivered to the AEP Power Pool and charged for energy received from
the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is each company's
member load ratio (MLR) which determines each company's percentage share of
revenues or costs. I&M as a member of the AEP Power Pool shares in the revenues
and costs of the AEP Power Pool's wholesale sales to and net forward trades with
other utility systems and power marketers. Revenues from forward electricity
trades in AEP's traditional marketing area (up to two transmission systems from
the AEP service territory) are recorded net of purchases as operating revenues
and as nonoperating income for trades beyond two transmission systems from AEP.
The AEP Power Pool also enters into power trading transactions for options,
futures and swaps. I&M's share of these transactions is recorded in nonoperating
income.
I&M is committed under unit power agreements to purchase all of AEGCo's
50% share of the 2,600 MW Rockport Plant capacity unless it is sold to other
utilities. AEGCo is an affiliate that is not a member of the AEP Power Pool. A
long-term unit power agreement with an unaffiliated utility expired at the end
of 1999 for the sale of 455 MW of AEGCo's Rockport Plant capacity. An agreement
between AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant
capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began
purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity.
Results of Operations
During 2000 both of the Cook Plant nuclear units were successfully
restarted after being shutdown in September 1997 due to questions regarding the
operability of certain safety systems which arose during a NRC architect
engineer design inspection. See discussion in Note 4 of the Notes to
Consolidated Financial Statements.
In February 2001 the U.S. District Court for the Southern District of
Ohio ruled against AEP and certain of its subsidiaries, including I&M, in a suit
over deductibility of interest claimed in AEP's consolidated tax return related
to a corporate owned life insurance (COLI) program. In 1998 and 1999 I&M paid
the disputed taxes and interest attributable to the COLI interest deductions for
the taxable years 1991-98. The payments were included in Other Property and
Investments pending the resolution of this matter. As a result of the Court's
decision, I&M's net income was reduced by $66 million in 2000.
As a result of the costs incurred in 2000 to restart the Cook Plant
nuclear units and the disallowance of COLI interest deductions, net income
declined $165 million in 2000. In 1999 net income declined $64 million due
primarily to the cost of efforts to restart the Cook Plant units.
Operating Revenues
Operating revenues increased 11% in 2000 and decreased 1% in 1999. The
increase in operating revenues in 2000 was primarily due to increased wholesale
sales to the AEP Power Pool. The decrease in 1999 was primarily due to a decline
in margins on wholesale sales and net power trading transactions within the AEP
Power Pool's traditional marketing area. The following analyzes the changes in
operating revenues:
Increase (Decrease)
From Previous Year
(dollars in millions)
- ---------------------
2000 1999
------------------------------
Amount % Amount %
Retail:
Residential $(37.3) $ 3.4
Commercial (16.2) 0.7
Industrial (30.0) (5.7)
Other (5.0) (0.2)
------ ------
(88.5) (9) (1.8) -
Wholesale 253.7 84 (18.2) (6)
Transmission
and Other (10.8) (21) 8.3 20
------ ------
Total $154.4 11 $(11.7) (1)
====== ======
The increase in operating revenues in 2000 is primarily due to increased
wholesale sales to the AEP Power Pool. With the return to service of the Cook
Plant units and purchasing more power from AEGCo due to the expiration of
AEGCo's contract to sell power to an unaffiliated entity, I&M had more
electricity available to sell to the AEP Power Pool. A decline in retail sales
and retail price which led to a decrease in retail operating revenues partly
offset the increase in wholesale revenues.
Operating revenues decreased slightly in 1999 primarily due to reduced
margins on I&M's MLR share of wholesale sales and net revenues from regulated
power trading transactions in the AEP Power Pool's traditional marketing area.
The decline in margins reflects the moderation in 1999 of extreme weather in
1998 and capacity shortages experienced in the summer of 1998.
Operating Expenses Increase
Total operating expenses increased 23% in 2000 and 4% in 1999 primarily
due to costs related to the extended Cook Plant outage and efforts to restart
the Cook Plant units. Also contributing to the increase in operating expenses in
2000 was the unfavorable COLI tax ruling and the additional purchases of power
due to the expiration of an AEGCo unit power agreement to sell part of its
Rockport Plant generation to an unaffiliated utility. The changes in the
components of operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions)
- ---------------------
2000 1999
-----------------------------
Amount % Amount %
Fuel $ 25.5 14 $ 12.8 7
Purchased Power 60.4 22 (21.1) (7)
Other Operation 137.5 30 114.3 33
Maintenance 84.5 62 (22.3) (14)
Depreciation and
Amortization 4.9 3 4.9 3
Taxes Other Than
Federal Income
Taxes 11.0 19 (8.8) (13)
Federal Income
Taxes (26.1) (149) (34.1) (66)
------ ------
Total $297.7 23 $ 45.7 4
====== ======
The increase in fuel expense in 2000 reflects an increase in nuclear
generation as the Cook Plant units returned to service following an extended
outage. Fuel expense increased in 1999 primarily due to an increase in
coal-fired generation replacing power purchases from the AEP Power Pool.
Purchased power expense increased in 2000 due to increased purchases from
AEGCo. As a result of the expiration of AEGCo's power sale contract with an
unaffiliated utility on December 31, 1999, I&M was obligated to buy more of
AEGCo's share of Rockport Plant power. The decrease in purchased power expense
in 1999 reflects the purchase of less power in 1999 at lower prices from the AEP
Power Pool, AEGCo and unaffiliated entities.
The increases in other operation expense in 2000 and 1999 were primarily
due to expenditures to prepare the Cook Plant nuclear units for restart.
Maintenance expense increased in 2000 primarily due to expenditures to
prepare the Cook Plant units for restart. The decline in maintenance expense in
1999 was due to cost containment efforts including staff reductions at I&M's
fossil-fired power plants, in the engineering and maintenance staff of AEP
Service Corporation and in I&M's transmission and distribution operations.
In 1999 the IURC and MPSC approved settlement agreements which allowed
the deferral of $200 million of Cook Plant restart costs in 1999 for
amortization over five years from 1999 through 2003. As a result, other
operation and maintenance expense in 1999 reflected a net deferral of $160
million. See discussion in Note 4 of the Notes to Consolidated Financial
Statements.
The increase in taxes other than federal income tax in 2000 is primarily
attributable to an increase in Indiana supplemental net income tax reflecting
the COLI decision related interest deduction disallowance and a favorable
accrual adjustment recorded in December 1999 related to the filing of the 1998
tax return. The decrease in taxes other than federal income taxes in 1999 was
primarily due to a decline in estimated taxable income for Indiana supplemental
income tax.
Federal income taxes attributable to operations decreased in 2000 and
1999 due to decreases in pre-tax operating income. In 2000 the decrease was
partially offset by an increase in tax expense related to the unfavorable ruling
in the suit against the IRS over interest deductions claimed for the COLI
program.
Nonoperating Income
The increase in nonoperating income in 2000 and 1999 is primarily due to
the effect of net gains on non-regulated electricity trading transactions. The
AEP Power Pool enters into non-regulated 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. I&M's
share of the AEP Power Pool's non-regulated trading transactions are included in
nonoperating income.
Interest Charges
Interest charges increased in 2000 and 1999 due to increased borrowings
to support expenditures for the Cook Plant restart effort and in 2000 also due
to the recognition of deferred interest payments to the IRS on the disputed
taxes.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Income
- ------------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
---------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $1,548,476 $1,394,119 $1,405,794
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 210,870 185,419 172,592
Purchased Power 337,376 276,962 298,046
Other Operation 599,012 461,494 347,207
Maintenance 219,854 135,331 157,593
Depreciation and Amortization 154,920 149,988 145,112
Taxes Other Than Federal Income Taxes 69,761 58,713 67,592
Federal Income Tax Expense (Credit) (8,615) 17,560 51,645
---------- ---------- ----------
Total Operating Expenses 1,583,178 1,285,467 1,239,787
---------- ---------- ----------
OPERATING INCOME (LOSS) (34,702) 108,652 166,007
NONOPERATING INCOME (LOSS) 9,933 4,530 (839)
---------- ---------- ----------
INCOME (LOSS) BEFORE INTEREST CHARGES (24,769) 113,182 165,168
INTEREST CHARGES 107,263 80,406 68,540
---------- ---------- ----------
NET INCOME (LOSS) (132,032) 32,776 96,628
PREFERRED STOCK DIVIDEND REQUIREMENTS 4,624 4,885 4,824
---------- ---------- ----------
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ (136,656) $ 27,891 $ 91,804
==========- ========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance
Sheets
- ------------------------------------------------------------------------
December 31,
2000 1999
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,708,436 $2,587,288
Transmission 945,709 928,758
Distribution 863,736 818,697
General (including nuclear fuel) 257,152 244,981
Construction Work in Progress 96,440 190,303
---------- ----------
Total Electric Utility Plant 4,871,473 4,770,027
Accumulated Depreciation and Amortization 2,280,521 2,194,397
---------- ----------
NET ELECTRIC UTILITY PLANT 2,590,952 2,575,630
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 778,720 707,967
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 194,947 23,131
---------- ----------
OTHER PROPERTY AND INVESTMENTS 131,417 190,527
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 14,835 3,863
Accounts Receivable:
Customers 106,832 91,268
Affiliated Companies 48,706 48,901
Miscellaneous 27,491 18,644
Allowance for Uncollectible Accounts (759) (1,848)
Fuel - at average cost 16,532 27,597
Materials and Supplies - at average cost 84,471 84,149
Accrued Utility Revenues - 44,428
Energy Trading Contracts 1,229,683 97,946
Prepayments 6,424 7,631
---------- ----------
TOTAL CURRENT ASSETS 1,534,215 422,579
---------- ----------
REGULATORY ASSETS 552,140 624,810
---------- ----------
DEFERRED CHARGES 36,156 32,052
---------- ----------
TOTAL $5,818,547 $4,576,696
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
- ---------------------------------------------------------------------------------------------------------
December 31,
---------------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 733,072 732,739
Retained Earnings 3,443 166,389
---------- ----------
Total Common Shareholder's Equity 793,099 955,712
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 9,248
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,298,939 1,126,326
---------- ----------
TOTAL CAPITALIZATION 2,165,719 2,156,231
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 560,628 501,185
Other 108,600 242,522
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES 669,228 743,707
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 90,000 198,000
Short-term Debt - 224,262
Advances from Affiliates 253,582 -
Accounts Payable - General 119,472 78,784
Accounts Payable - Affiliated Companies 75,486 31,118
Taxes Accrued 68,416 48,970
Interest Accrued 21,639 13,955
Obligations Under Capital Leases 100,848 11,072
Energy Trading Contracts 1,275,097 95,564
Other 97,070 91,684
---------- ----------
TOTAL CURRENT LIABILITIES 2,101,610 793,409
---------- ----------
DEFERRED INCOME TAXES 487,945 622,157
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 113,773 121,627
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 81,299 85,005
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 156,736 17,887
---------- ----------
DEFERRED CREDITS 42,237 36,673
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $5,818,547 $4,576,696
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- ------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $(132,032) $ 32,776 $ 96,628
Adjustments for Noncash Items:
Depreciation and Amortization 163,391 153,921 149,209
Amortization of Incremental Nuclear
Refueling Outage Expenses (net) 5,737 8,480 14,142
Amortization (Deferral) of Nuclear
Outage Costs (net) 40,000 (160,000) -
Deferred Federal Income Taxes (125,179) 85,727 17,905
Deferred Investment Tax Credits (7,854) (8,152) (8,266)
Unrecovered Fuel and Purchased Power Costs 37,501 (84,696) (46,846)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (25,305) (19,178) 1,462
Fuel, Materials and Supplies 10,743 (12,880) (2,983)
Accrued Utility Revenues 44,428 (7,151) (6,756)
Accounts Payable 85,056 19,068 22,440
Taxes Accrued 19,446 13,809 (11,689)
Disputed Tax and Interest Related to COLI 56,856 (3,228) (53,628)
Other (net) (41,900) 12,831 (8,176)
--------- --------- ---------
Net Cash Flows From Operating Activities 130,888 31,327 163,442
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (171,071) (165,331) (147,627)
Proceeds from Sales of Property and Other 587 2,501 4,419
--------- --------- ---------
Net Cash Flows Used For Investing Activities (170,484) (162,830) (143,208)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 199,220 247,989 170,675
Retirement of Cumulative Preferred Stock (314) (3,597) (120)
Retirement of Long-term Debt (148,000) (109,500) (55,000)
Changes in Advances from Affiliates (net) 253,582 - -
Change in Short-term Debt (net) (224,262) 115,562 (10,900)
Dividends Paid on Common Stock (26,290) (114,656) (117,464)
Dividends Paid on Cumulative Preferred Stock (3,368) (5,856) (4,734)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities 50,568 129,942 (17,543)
--------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents 10,972 (1,561) 2,691
Cash and Cash Equivalents January 1 3,863 5,424 2,733
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 14,835 $ 3,863 $ 5,424
========= ========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $82,511,000,
$78,703,000 and $66,313,000 and for income taxes was $73,254,000,
$(71,395,000) and $36,413,000 in 2000, 1999 and 1998, respectively. Noncash
acquisitions under capital leases were $22,218,000, $10,852,000 and $9,658,000
in 2000, 1999 and 1998, respectively.
See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
- -------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
Retained Earnings January 1 $ 166,389 $253,154 $278,814
Net Income (Loss) (132,032) 32,776 96,628
--------- -------- --------
34,357 285,930 375,442
--------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 26,290 114,656 117,464
Cumulative Preferred Stock:
4-1/8% Series 230 244 247
4.56% Series 66 66 67
4.12% Series 74 78 79
5.90% Series 897 963 985
6-1/4% Series 1,203 1,250 1,266
6.30% Series 834 834 834
6-7/8% Series 1,186 1,238 1,255
--------- -------- --------
Total Cash Dividends Declared 30,780 119,329 122,197
Capital Stock Expense 134 212 91
--------- -------- --------
Total Deductions 30,914 119,541 122,288
--------- -------- --------
Retained Earnings December 31 $ 3,443 $166,389 $253,154
========= ======== ========
See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Capitalization
- -------------------------------------------------------------------------------
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 793,099 $ 955,712
---------- ----------
PREFERRED STOCK:
$100 Par Value - Authorized 2,250,000 shares
$25 Par Value - Authorized 11,200,000 shares
Call Price Number of Shares Redeemed Shares
December 31, Year Ended December 31, Outstanding
Series 2000 2000 1999 1998 December 31, 2000
- --------------------------------------------------------------------------------
Not Subject to Mandatory Redemption:
4-1/8% 106.125 3,750 97 771 55,389 5,539 5,914
4.56% 102 - 150 650 14,412 1,441 1,441
4.12% 102.728 1,375 - 200 17,556 1,756 1,893
---------- ----------
8,736 9,248
---------- ----------
Subject to Mandatory Redemption:
5.90% (a,b) - 15,000 - 152,000 15,200 15,200
6-1/4% (a,b) - 10,000 - 192,500 19,250 19,250
6.30% (a,b) - - - 132,450 13,245 13,245
6-7/8% (a,c) - 10,000 - 172,500 17,250 17,250
---------- ----------
64,945 64,945
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 308,976 356,820
Installment Purchase Contracts 309,717 309,568
Senior Unsecured Notes 397,435 297,282
Other Long-term Debt 211,307 199,259
Junior Debentures 161,504 161,397
Less Portion Due Within One Year (90,000) (198,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,298,939 1,126,326
---------- ----------
TOTAL CAPITALIZATION $2,165,719 $2,156,231
========== ==========
(a) Not callable until after 2002. There are no aggregate sinking fund
provisions through 2002. Sinking fund provisions require the redemption of
15,000 shares in 2003 and 67,500 shares in each 2004 and 2005.
(b) Commencing in 2004 and continuing through 2008 the Company may redeem, at
$100 per share, 20,000 shares of the 5.90% series, 15,000 shares of the
6-1/4% series and 17,500 shares of the 6.30% series outstanding under
sinking fund provisions at its option and all remaining outstanding shares
must be redeemed not later than 2009. Shares redeemed in 1999 and 1997 may
be applied to meet the sinking fund requirement.
(c) Commencing in 2003 and continuing through the year 2007, a sinking fund
will require the redemption of 15,000 shares each year and the redemption
of the remaining shares outstanding on April 1, 2008, in each case at $100
per share. Shares redeemed in 1999 and 1997 may be applied to meet the
sinking fund requirement.
See Notes to Consolidated Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- -----------------------------------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
6.40 2000 - March 1 $ - $ 48,000
7.63 2001 - June 1 40,000 40,000
7.60 2002 - November 1 50,000 50,000
7.70 2002 - December 15 40,000 40,000
6.10 2003 - November 1 30,000 30,000
8.50 2022 - December 15 75,000 75,000
7.35 2023 - October 1 20,000 20,000
7.20 2024 - February 1 30,000 30,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (1,024) (1,180)
-------- --------
$308,976 $356,820
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ -----------------
City of Lawrenceburg, Indiana:
7.00 2015 - April 1 $ 25,000 $ 25,000
5.90 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
(a) 2014 - August 1 50,000 50,000
7.60 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 50,000
(b) 2025 - June 1 50,000 50,000
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (2,283) (2,432)
-------- --------
$309,717 $309,568
(a) A variable interest rate is determined weekly. The average weighted
interest rate was 4.5% for 2000 and 3.2% for 1999.
(b) An adjustable interest rate can be a daily, weekly, commercial
paper or term rate as designated by I&M. A weekly rate was
selected which ranged from 2.9% to 5.9% in 2000 and from 2.2% to
5.6% in 1999 and averaged 4.2% and 3.2% during 2000 and 1999,
respectively.
Under the terms of the installment purchase contracts, I&M is required
to pay amounts sufficient to enable the cities to pay interest on and the
principal (at stated maturities and upon mandatory redemptions) of related
pollution control revenue bonds issued to finance the construction of pollution
control facilities at certain generating plants. On the two variable rate series
the principal is payable at the stated maturities or on the demand of the
bondholders at periodic interest adjustment dates which occur weekly. The
variable rate bonds due in 2014 are supported by a bank letter of credit which
expires in 2002. I&M has agreements that provide for brokers to remarket the
adjustable rate bonds due in 2025 tendered at interest adjustment dates. In the
event certain bonds cannot be remarketed, I&M has a standby bond purchase
agreement with a bank that provides for the bank to purchase any bonds not
remarketed. The purchase agreement expires in 2001. Accordingly, the variable
and adjustable rate installment purchase contracts have been classified for
repayment purposes based on the expiration dates of the standby purchase
agreement and the letter of credit.
Senior unsecured notes outstanding were as follows:
December 31,
---------------------
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2000 - November 22 $ - $100,000
(b) 2002 - September 3 200,000 -
6-7/8 2004 - July 1 150,000 150,000
6.45 2008 - November 10 50,000 50,000
Unamortized Discount (2,565) (2,718)
-------- --------
$397,435 $297,282
(a) A floating interest rate is determined monthly.
The rate on December 31, 1999 was 7.1%.
(b) A floating interest rate is determined quarterly.
The rate on December 31, 2000 was 7.31%.
Junior debentures outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ -----------------
8.00 2026 - March 31 $ 40,000 $ 40,000
7.60 2038 - June 30 125,000 125,000
Unamortized Discount (3,496) (3,603)
-------- --------
Total $161,504 $161,397
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of I&M.
At December 31, 2000, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2001 $ 90,000
2002 340,000
2003 30,000
2004 150,000
2005 -
Later Years 788,307
----------
Total Principal Amount 1,398,307
Unamortized Discount (9,368)
----------
Total $1,388,939
==========
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Merger Note 3
Nuclear Plant Restart Note 4
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Staff Reductions Note 11
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Supplementary Information Note 17
Leases Note 18
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Indiana Michigan Power Company and
its subsidiaries as of December 31, 2000 and 1999, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Indiana Michigan Power Company
and its subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001
KENTUCKY POWER COMPANY
G-11
KENTUCKY POWER COMPANY
Selected Financial Data
- -----------------------------------------------------------
Year Ended December 31,
---------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $410,403 $373,982 $362,999 $340,635 $323,321
Operating Expenses 360,665 319,307 311,106 293,779 281,978
-------- -------- -------- -------- --------
Operating Income 49,738 54,675 51,893 46,856 41,343
Nonoperating Income
(Loss) 2,070 (327) (1,726) (464) (594)
-------- -------- -------- -------- --------
Income Before Interest
Charges 51,808 54,348 50,167 46,392 40,749
Interest Charges 31,045 28,918 28,491 25,646 23,776
-------- -------- -------- -------- --------
Net Income $ 20,763 $ 25,430 $ 21,676 $ 20,746 $ 16,973
======== ======== ======== ======== ========
December 31,
---------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,103,064 $1,079,048 $1,043,711 $1,006,955 $951,602
Accumulated Depreciation
and Amortization 360,648 340,008 315,546 296,318 286,640
---------- ---------- ---------- ---------- --------
Net Electric Utility
Plant $ 742,416 $ 739,040 $ 728,165 $ 710,637 $664,962
========== ========== ========== ========== ========
Total Assets $1,512,016 $ 986,638 $ 921,847 $ 886,671 $833,579
========== ========== ========== ========== ========
Common Stock and
Paid-in Capital $ 209,200 $ 209,200 $ 199,200 $ 179,200 $159,200
Retained Earnings 57,513 67,110 71,452 78,076 84,090
---------- ---------- ---------- ---------- --------
Total Common
Shareholder's Equity $ 266,713 $ 276,310 $ 270,652 $ 257,276 $243,290
========== ========== ========== ========== ========
Long-term Debt(a) $ 330,880 $ 365,782 $ 368,838 $ 341,051 $293,198
========== ========== ========== ========== ========
Obligations Under
Capital leases (a) $ 14,184 $ 15,141 $ 18,977 $ 18,725 $ 12,850
========== ========== ========== ========== ========
Total Capitalization
and Liabilities $1,512,016 $ 986,638 $ 921,847 $ 886,671 $833,579
========== ========== ========== ========== ========
(a) Including portion due within one year.
KENTUCKY POWER COMPANY
Management's Narrative Analysis
of Results of Operations
- ----------------------------------------------------
KPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power serving 172,000 retail customers
in eastern Kentucky. KPCo as a member of the AEP System Power Pool (AEP Power
Pool) shares in the revenues and costs of the AEP Power Pool's wholesale sales
to neighboring utility systems and power marketers. KPCo also sells wholesale
power to municipalities.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges or the receipt of credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's percentage share of AEP
Power Pool revenues or costs. KPCo as a member of the AEP Power Pool shares in
the revenues and costs of the AEP Power Pool's wholesale sales to and net
forward trades with other utility systems and power marketers. Revenues from
forward electricity trades are recorded net of purchases as operating revenues
for transactions in AEP's traditional marketing area (up to two transmission
systems from the AEP service territory) and as nonoperating income for
transactions beyond two transmission systems from AEP. The AEP Power Pool also
enters into power trading transactions for options, futures and swaps. KPCo's
share of these transactions is recorded in nonoperating income.
In February 2001 the U.S. District Court for the Southern District of
Ohio ruled against AEP and certain of its subsidiaries, including KPCo, in a
suit over deductibility of interest claimed in AEP's consolidated tax return
related to a corporate owned life insurance (COLI) program. In 1998 and 1999
KPCo paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1992-98. The payments were included in Other
Property and Investments pending the resolution of this matter. As a result
of the Court's decision, net income was reduced by $8 million in 2000.
Net Income Decreases
Net income decreased $4.7 million or 18% in 2000 primarily due to the
COLI decision and an increase in maintenance expense.
Operating Revenues Increase
Operating revenues increased $36 million or 10% in 2000 due to a
significant increase in AEP Power Pool transactions. Changes in the components
of operating revenues were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Retail:
Residential $ 6.1 5.7
Commercial (0.2) (0.3)
Industrial (3.5) (3.7)
-----
2.4 0.9
Wholesale 37.2 49.0
Transmission 2.8 62.6
Other (6.0) (22.3)
-----
Total $36.4 9.7
=====
The increase in operating revenues is due to increased KWH sales to
residential customers as a result of colder weather and a significant increase
in AEP Power Pool wholesale transactions. As a result of an affiliated company's
major industrial customer's decision not to continue its purchased power
agreement, additional power was available to the AEP Power Pool for wholesale
sales contributing to the increase in the company's revenue. Purchased power
also increased due to the availability of the Rockport Plant from which the
company, under a unit power agreement, purchases 15% of the available power from
Rockport. Rockport Plant generated 8% more KWH in the year 2000 than in the year
1999. In 2000 other revenues decreased substantially due to the effect of
favorable adjustment to rental income in 1999 reflecting agreed to retroactive
revisions to the billings for pole attachments with telecommunications
companies.
Operating Expenses Increase
Operating expenses increased $41.4 million primarily due to increased
purchased power, maintenance costs and federal income taxes. Changes in the
components of operating expenses were as follows:
Increase (Decrease)
(dollars in millions) From Previous Year
Amount %
Fuel $(9.7) (11.5)
Purchased Power 41.6 38.6
Other Operation 0.8 1.6
Maintenance 4.4 20.6
Depreciation and
Amortization 1.8 6.2
Taxes Other Than Federal
Income Taxes (1.1) (10.6)
Federal Income Taxes 3.6 27.1
-----
Total $41.4 13.0
=====
Fuel expense decreased due to a decline in internal generation as a
result of planned outages in 2000 at the company's Big Sandy Plant Unit 2.
Purchased Power expense increased due to a significant increase in AEP Power
Pool wholesale transactions and affiliated power purchases under a unit power
agreement.
The planned outages at Big Sandy Plant caused the increase in
maintenance expense. Comparing 2000 to 1999, unit 1 of the Big Sandy Plant,
experienced 3.6 weeks of various outages compared to 1 week of outages in 1999.
Unit 2 experienced 6.8 weeks of outages in 2000 compared to 4.6 weeks in 1999.
An increase in transmission plant investment and improvements to
distribution facilities accounted for the increase in depreciation expense.
Taxes other than federal income taxes decreased due to decreased
Kentucky state income taxes as a result of lower pre-tax operating income partly
offset by the unfavorable ruling in AEP's suit against the government over
interest deductions claimed in prior years related to a COLI program.
The increase in federal income tax expense was primarily due to the
unfavorable ruling in AEP's suit against the government over interest deductions
claimed in prior years related to a COLI program.
Nonoperating Income Increase
Nonoperating income increased due to the favorable effect of
non-regulated electric trading outside the AEP Power Pool's traditional
marketing area. 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. The
company's share of the AEP Power Pool's non-regulated trading transactions are
included in nonoperating income.
Interest Charges Increase
The increase in interest charges resulted from the U.S. District Court's
unfavorable decision denying Federal income tax deductions for COLI interest
resulting in the incurrance of interest on taxes owed for prior years.
KENTUCKY POWER COMPANY
Statements of Income
- ---------------------------------------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $410,403 $373,982 $362,999
-------- -------- --------
OPERATING EXPENSES:
Fuel 74,638 84,369 83,303
Purchased Power 149,345 107,763 100,620
Other Operation 53,325 52,468 47,802
Maintenance 25,866 21,452 30,462
Depreciation and Amortization 31,028 29,221 28,080
Taxes Other Than Federal Income Taxes 9,709 10,854 9,687
Federal Income Taxes 16,754 13,180 11,152
-------- -------- --------
TOTAL OPERATING EXPENSES 360,665 319,307 311,106
-------- -------- --------
OPERATING INCOME 49,738 54,675 51,893
NONOPERATING INCOME (LOSS) 2,070 (327) (1,726)
-------- -------- --------
INCOME BEFORE INTEREST CHARGES 51,808 54,348 50,167
INTEREST CHARGES 31,045 28,918 28,491
-------- -------- --------
NET INCOME $ 20,763 $ 25,430 $ 21,676
======== ======== ========
Statements of Retained Earnings
- --------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $67,110 $71,452 $78,076
NET INCOME 20,763 25,430 21,676
CASH DIVIDENDS DECLARED 30,360 29,772 28,300
------- ------- -------
RETAINED EARNINGS DECEMBER 31 $57,513 $67,110 $71,452
======= ======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Balance
Sheets
- ----------------------------------------------------------------------------------------------------------------------------------
December 31,
---------------------------
2000 1999
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 271,107 $ 268,618
Transmission 360,563 355,442
Distribution 387,499 372,752
General 67,476 67,608
Construction Work in Progress 16,419 14,628
---------- ----------
Total Electric Utility Plant 1,103,064 1,079,048
Accumulated Depreciation and Amortization 360,648 340,008
---------- ----------
NET ELECTRIC UTILITY PLANT 742,416 739,040
---------- ----------
OTHER PROPERTY AND INVESTMENTS 6,559 12,406
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 76,657 8,010
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents 2,270 674
Accounts Receivable:
Customers 34,555 18,952
Affiliated Companies 22,119 15,223
Miscellaneous 6,419 8,343
Allowance for Uncollectible Accounts (282) (637)
Fuel - at average cost 4,760 10,441
Materials and Supplies - at average cost 15,408 18,113
Accrued Utility Revenues 6,500 13,737
Energy Trading Contracts 483,537 33,919
Prepayments 766 1,450
---------- ----------
TOTAL CURRENT ASSETS 576,052 120,215
---------- ----------
REGULATORY ASSETS 98,515 96,296
---------- ----------
DEFERRED CHARGES 11,817 10,671
---------- ----------
TOTAL $1,512,016 $ 986,638
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
- --------------------------------------------------------------------------------------------------------------------
December 31,
-----------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $50:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $ 50,450
Paid-in Capital 158,750 158,750
Retained Earnings 57,513 67,110
---------- --------
Total Common Shareholder's Equity 266,713 276,310
Long-term Debt 270,880 260,782
---------- --------
TOTAL CAPITALIZATION 537,593 537,092
---------- --------
OTHER NONCURRENT LIABILITIES 18,348 23,797
---------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 60,000 105,000
Short-term Debt - 39,665
Advances from Affiliates 47,636 -
Accounts Payable - General 32,043 9,923
Accounts Payable - Affiliated Companies 37,506 19,743
Customer Deposits 4,389 4,143
Taxes Accrued 11,885 9,860
Interest Accrued 5,610 4,843
Energy Trading Contracts 496,884 33,094
Other 14,517 12,020
---------- --------
TOTAL CURRENT LIABILITIES 710,470 238,291
---------- --------
DEFERRED INCOME TAXES 165,935 165,007
---------- --------
DEFERRED INVESTMENT TAX CREDITS 11,656 12,908
---------- --------
LONG-TERM ENERGY TRADING CONTRACTS 61,632 6,194
---------- --------
DEFERRED CREDITS 6,382 3,349
---------- --------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $1,512,016 $986,638
========== ========
KENTUCKY POWER COMPANY
Statements of Cash Flows
- -----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 20,763 $ 25,430 $ 21,676
Adjustments for Noncash Items:
Depreciation and Amortization 31,034 29,228 28,092
Deferred Income Taxes 3,765 2,596 3,607
Deferred Investment Tax Credits (1,252) (1,292) (1,415)
Deferred Fuel Costs (net) 2,948 828 (449)
Changes in Certain Current Assets
and Liabilities:
Accounts Receivable (net) (20,930) (6,618) (6,663)
Fuel, Materials and Supplies 8,386 (7,014) 3,199
Accrued Utility Revenues 7,237 (177) (579)
Accounts Payable 39,883 4,935 157
Taxes Accrued 2,025 2,604 1,126
Disputed Tax and Interest Related to COLI 5,943 (567) (5,376)
Other (net) (4,559) (3,019) (2,215)
--------- -------- --------
Net Cash Flows From Operating Activities 95,243 46,934 41,160
--------- -------- --------
INVESTING ACTIVITIES:
Construction Expenditures (36,209) (44,339) (43,769)
Proceeds from Sales of Property 266 168 -
--------- -------- --------
Net Cash Flows Used For
Investing Activities (35,943) (44,171) (43,769)
--------- -------- --------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company - 10,000 20,000
Issuance of Long-term Debt 69,685 79,740 29,816
Retirement of Long-term Debt (105,000) (83,307) (2,203)
Change in Short-term Debt (net) (39,665) 19,315 (16,150)
Change in Advances from Affiliates (net) 47,636 - -
Dividends Paid (30,360) (29,772) (28,300)
--------- -------- --------
Net Cash Flows From (Used For)
Financing Activities (57,704) (4,024) 3,163
--------- -------- --------
Net Increase (Decrease) in Cash and
Cash Equivalents 1,596 (1,261) 554
Cash and Cash Equivalents January 1 674 1,935 1,381
--------- -------- --------
Cash and Cash Equivalents December 31 $ 2,270 $ 674 $ 1,935
========= ======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $28,619,000, $29,845,000
and $27,857,000 and for income taxes was $7,923,000, $12,050,000 and
$8,607,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under
capital leases were $2,817,000, $2,219,000 and $4,890,000 in 2000, 1999 and
1998, respectively.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Statements of Capitalization
- -----------------------------------------------------------------
December 31,
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $266,713 $276,310
-------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 119,341 119,270
Senior Unsecured Notes 147,490 157,502
Notes Payable 25,000 50,000
Junior Debentures 39,049 39,010
Less Portion Due Within One Year (60,000) (105,000)
-------- --------
Long-term Debt Excluding Portion Due Within One Year 270,880 260,782
-------- --------
TOTAL CAPITALIZATION $537,593 $537,092
======== ========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Schedule of Long-term Debt
- -------------------------------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
8.95 2001 - May 10 $ 20,000 $ 20,000
8.90 2001 - May 21 40,000 40,000
6.65 2003 - May 1 15,000 15,000
6.70 2003 - June 1 15,000 15,000
6.70 2003 - June 1 15,000 15,000
7.90 2023 - June 1 14,500 14,500
Unamortized Discount (159) (230)
-------- --------
$119,341 $119,270
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Senior unsecured notes outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2000 - November 2 $ - $ 80,000
(b) 2002 - November 19 70,000 -
6.91 2007 - October 1 48,000 48,000
6.45 2008 - November 10 30,000 30,000
Unamortized Discount (510) (498)
-------- --------
147,490 157,502
Less Portion Due Within
One Year - 80,000
-------- --------
Total $147,490 $ 77,502
======== ========
(a) A floating interest rate is determined monthly.
The rate on December 31, 1999 was 7.23%.
(b) A floating interest rate is determined monthly.
The rate on December 31, 2000 was 7.4075%.
Notes Payable to Banks outstandings were as follows:
6.57 2000 - April 1 $ - $25,000
7.45 2002 - September 20 25,000 25,000
------- -------
Total $25,000 $50,000
======= =======
Junior debentures outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ -----------------
8.72 2025 - June 30 $40,000 $40,000
Unamortized Discount (951) (990)
------- -------
Total $39,049 $39,010
======= =======
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.
At December 31, 2000, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2001 $ 60,000
2002 95,000
2003 45,000
2004 -
2005 -
Later Years 132,500
--------
Total Principal Amount 332,500
Unamortized Discount (1,620)
--------
Total $330,880
========
KENTUCKY POWER COMPANY
Index to Notes to Financial Statements
- ------------------------------------------------------------------------------
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Commitments and Contingencies Note 8
Staff Reductions Note 11
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Leases Note 18
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
- -----------------------------------------------
To the Shareholder and Board of
Directors of Kentucky Power Company:
We have audited the accompanying balance sheets and statements of
capitalization of Kentucky Power Company as of December 31, 2000 and 1999, and
the related statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2000. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Kentucky Power Company as of December 31,
2000 and 1999, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2000 in conformity with
accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001
OHIO POWER COMPANY AND SUBSIDIARIES
H-14
OHIO POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial
Data
- -------------------------------------------------------------------------------------------------------
Year Ended December 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $2,227,902 $2,039,263 $2,105,547 $1,892,110 $1,911,708
Operating Expenses 2,001,075 1,750,434 1,816,175 1,615,717 1,614,547
---------- ---------- ---------- ---------- ----------
Operating Income 226,827 288,829 289,372 276,393 297,161
Nonoperating Income (Loss) (5,004) 7,000 588 14,822 6,374
---------- ---------- ---------- ---------- ----------
Income Before Interest
Charges 221,823 295,829 289,960 291,215 303,535
Interest Charges 119,210 83,672 80,035 82,526 85,880
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 102,613 212,157 209,925 208,689 217,655
Extraordinary Loss (18,876) - - - -
---------- ---------- ---------- ---------- ----------
Net Income 83,737 212,157 209,925 208,689 217,655
Preferred Stock
Dividend Requirements 1,266 1,417 1,474 2,647 8,778
---------- ---------- ---------- ---------- ----------
Earnings Applicable to
Common Stock $ 82,471 $ 210,740 $ 208,451 $ 206,042 $ 208,877
========== ========== ========== ========== ==========
December 31,
----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $5,577,631 $5,400,917 $5,257,841 $5,155,797 $4,996,621
Accumulated Depreciation
and Amortization 2,764,130 2,621,711 2,461,376 2,349,995 2,216,534
---------- ---------- ---------- ---------- ----------
Net Electric Utility Plant $2,813,501 $2,779,206 $2,796,465 $2,805,802 $2,780,087
========== ========== ========== ========== ==========
Total Assets $6,252,436 $4,677,209 $4,344,680 $4,163,202 $4,092,166
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 783,684 $ 783,577 $ 783,536 $ 783,497 $ 781,863
Retained Earnings 398,086 587,424 587,500 590,151 584,015
---------- ---------- ---------- ---------- ----------
Total Common Shareholder's
Equity $1,181,770 $1,371,001 $1,371,036 $1,373,648 $1,365,878
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 16,648 $ 16,937 $ 17,370 $ 17,542 $ 38,532
Subject to Mandatory
Redemption (a) 8,850 8,850 11,850 11,850 109,900
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 25,498 $ 25,787 $ 29,220 $ 29,392 $ 148,432
========== ========== ========== ========== ==========
Long-term Debt (a) $1,195,493 $1,151,511 $1,084,928 $1,095,226 $1,069,729
========== ========== ========== ========== ==========
Obligations Under Capital
Leases (a) $ 116,581 $ 136,543 $ 142,635 $ 157,487 $ 131,285
========== ========== ========== ========== ==========
Total Capitalization and
Liabilities $6,252,436 $4,677,209 $4,344,680 $4,163,202 $4,092,166
========== ========== ========== ========== ==========
(a) Including portion due within one year.
OHIO POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis
of Results of Operations
OPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to 696,000 retail customers in
northwestern, east central, eastern and southern sections of Ohio. OPCo supplies
electric power to the AEP Power Pool and shares the revenues and costs of the
AEP Power Pool's wholesale sales to neighboring utility systems and power
marketers. OPCo also sells wholesale power to municipalities and cooperatives.
The cost of the AEP System's generating capacity is allocated among the
AEP Power Pool members based on their relative peak demands and generating
reserves through the payment of capacity charges or the receipt of capacity
credits. AEP Power Pool members are also compensated for their out-of-pocket
costs of energy delivered to the AEP Power Pool and charged for energy received
from the AEP Power Pool.
The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues or costs. OPCo as a member of the AEP Power Pool shares in the revenues
and costs of the AEP Power Pool's wholesale sales to and net forward trades with
other utility systems and power marketers. Revenues from forward electricity
trades are recorded net of purchases as operating revenues for transactions in
AEP's
traditional marketing area (up to two transmission systems from the AEP service
territory) and as nonoperating income for transactions beyond two transmission
systems from AEP. The AEP Power Pool also enters into power trading transactions
for options, futures and swaps. OPCo's share of these transactions is recorded
in nonoperating income.
Results of Operations
In February 2001 the U.S. District Court for the Southern District of
Ohio ruled against AEP and certain of its subsidiaries, including OPCo, in a
suit over deductibility of interest claimed in AEP's consolidated tax returns
related to a corporate owned life insurance (COLI) program. In 1998 and 1999
OPCo paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1991-98. The payments were included in Other
Property and Investments pending the resolution of this matter. As a result of
the Court's decision, net income was reduced by $118 million in 2000.
Income before extraordinary item decreased $110 million or 52% in 2000
due predominantly to the disallowance of COLI related tax deductions. An
extraordinary loss related to the discontinuance of SFAS 71 regulatory
accounting, of approximately $19 million after tax, was recorded in September
2000 in connection with the PUCO's approval of a plan to transition OPCo's
generation business from cost based rate regulation to customer choice and
market pricing.
Net income increased $2 million or 1% in 1999 primarily due to a decline
in operation and maintenance costs reflecting cost containment efforts.
Operating Revenues and Energy Sales
Operating revenues increased 9% in 2000 following a decrease of 3% in
1999. The changes in the components of revenues were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions)
2000 1999
-----------------------------
Amount % Amount %
Retail:
Residential $ (4.2) $ 7.5
Commercial 1.7 0.4
Industrial (126.0) (5.0)
Other 0.2 -
------- ------
(128.3) (9) 2.9 -
Wholesale 322.1 56 (71.9) (11)
Transmission
and Other (5.2) (6) 2.7 3
------- ------
Total $ 188.6 9 $(66.3) (3)
======= ======
The increase in operating revenues in 2000 resulted from increased
wholesale sales to the AEP Power Pool and the Company's share of increased Power
Pool wholesale sales to and net revenues from trading of electricity with other
utility systems and power marketers. As a result of one of OPCo's major
industrial customers deciding not to continue its power purchase agreement, OPCo
was able to deliver additional power to the AEP Power Pool accounting for part
of the increase in wholesale revenues. Wholesale revenues also benefited from
the growth in AEP's marketing and trading operation, favorable wholesale market
conditions and increased availability of AEP Power Pool generation for wholesale
sales. The increase in AEP Power Pool generation availability was due to the
return to service of one of an affiliate's nuclear units in June 2000 and
improved generating unit outage management.
Operating revenues declined 3% in 1999 primarily due to a decline in
margins on wholesale sales and net power trading transactions and decreased
sales to the AEP Power Pool.
Operating Expenses
Operating expenses increased by 14% in 2000 mostly due to increases in
fuel expense, purchased power expense, other operation expense and federal
income taxes.
Operating expenses decreased 4% in 1999 from cost containment efforts and
lower fuel costs due mainly to a decrease in generation reflecting lower demand
for wholesale energy. Changes in the components of operating expenses were as
follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
---------------------
2000 1999
Amount % Amount %
----------------------------
------ --- ------ ----
Fuel $ 84.3 12 $(50.8) (7)
Purchased Power 20.9 13 12.4 8
Other Operation 80.2 25 (26.1) (7)
Maintenance 3.4 3 (18.3) (13)
Depreciation
and Amortization 6.9 5 4.6 3
Taxes Other Than
Federal Income
Taxes (0.3) - (3.5) (2)
Federal Income
Taxes 55.2 41 16.0 13
------ ------
Total Operating
Expenses $250.6 14 $(65.7) (4)
====== ======
Fuel expense increased in 2000 due to increases in generation and the
average cost of fuel consumed reflecting shutdown costs included in the cost of
coal delivered from affiliated mining operations. Fuel expense decreased in 1999
due to a 6% decrease in generation reflecting the decline in wholesale sales.
The increase in purchased power expense was due to a significant increase
in AEP Power Pool transactions.
Other operation expense increased in 2000 mainly due to increased power
generation costs. Increased emission allowance consumption and allowance prices
and increased costs of AEP's growing power marketing and trading operation,
including incentive compensation, accounted for the increase in generation
costs. The increase in emission allowance usage and prices resulted from the
stricter air quality standards of Phase II of the 1990 Clean Air Act Amendments
which became effective on January 1, 2000. The decrease in other operation
expense in 1999 was due to lower coal-fired power plant expenses reflecting cost
containment efforts, and an increase in gains on emission allowance sales. The
cost containment efforts included staff reductions in transmission and
distribution operations, at the power plants and within the engineering and
maintenance group of AEP Service Corporation which bills OPCo for operations
support services. These cost containment efforts were the primary reason for the
decrease in maintenance expense in 1999.
The increase in federal income tax expense in 2000 was primarily due to
the unfavorable ruling relating to AEP's COLI program. Federal income taxes
attributable to operations increased in 1999 due to changes in certain book/tax
differences accounted for on a flow-through basis for rate-making purposes and
an increase in pre-tax operating income.
Nonoperating Income
The decrease in nonoperating income in 2000 is due to the disallowance of
COLI-related tax deductions for coal-mining operations that are no longer
operating.
Extraordinary Loss
An extraordinary loss was recorded in the third quarter of 2000 when OPCo
discontinued the application of SFAS 71 regulatory accounting for the generation
portion of its business due to the approval in September 2000 of a stipulation
agreement by the PUCO providing for a transition from cost based rate regulation
for OPCo's generation business to customer choice and market pricing.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- ---------------------------------------------
Year Ended December 31,
------------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $2,227,902 $2,039,263 $2,105,547
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 771,969 687,672 738,522
Purchased Power 184,004 163,143 150,733
Other Operation 407,375 327,132 353,194
Maintenance 124,735 121,299 139,611
Depreciation and Amortization 155,944 149,055 144,493
Taxes Other Than Federal Income Taxes 165,552 165,891 169,353
Federal Income Taxes 191,496 136,242 120,269
---------- ---------- ----------
Total Operating Expenses 2,001,075 1,750,434 1,816,175
---------- ---------- ----------
OPERATING INCOME 226,827 288,829 289,372
NONOPERATING INCOME (LOSS) (5,004) 7,000 588
---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES 221,823 295,829 289,960
INTEREST CHARGES 119,210 83,672 80,035
---------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM 102,613 212,157 209,925
EXTRAORDINARY LOSS - Discontinuance of
Regulatory Accounting for Generation
(inclusive of Tax Benefit of $21,281,000) (18,876) - -
---------- ---------- -----------
NET INCOME 83,737 212,157 209,925
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,266 1,417 1,474
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 82,471 $ 210,740 $ 208,451
========== ========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Balance
Sheets
- --------------------------------------------------------------------------------------------------
December 31,
2000 1999
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,764,155 $2,713,421
Transmission 870,033 857,420
Distribution 1,040,940 999,679
General (including mining assets) 707,417 713,882
Construction Work in Progress 195,086 116,515
---------- -----------
Total Electric Utility Plant 5,577,631 5,400,917
Accumulated Depreciation and Amortization 2,764,130 2,621,711
---------- -----------
NET ELECTRIC UTILITY PLANT 2,813,501 2,779,206
---------- -----------
OTHER PROPERTY AND INVESTMENTS 109,124 221,756
---------- -----------
LONG-TERM ENERGY TRADING CONTRACTS 256,455 31,912
---------- -----------
CURRENT ASSETS:
Cash and Cash Equivalents 31,393 157,138
Advances to Affiliates 92,486 -
Accounts Receivable:
Customers 139,732 246,310
Affiliated Companies 126,203 89,215
Miscellaneous 39,046 22,055
Allowance for Uncollectible Accounts (1,054) (2,223)
Fuel - at average cost 82,291 129,022
Materials and Supplies - at average cost 96,053 95,967
Accrued Utility Revenues 264 45,575
Energy Trading Contracts 1,617,660 134,567
Prepayments and Other 32,882 38,472
---------- -----------
TOTAL CURRENT ASSETS 2,256,956 956,098
---------- -----------
REGULATORY ASSETS 714,710 594,385
---------- -----------
DEFERRED CHARGES 101,690 93,852
---------- -----------
TOTAL $6,252,436 $ 4,677,209
========== ===========
See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
- --------------------------------------------------------------------------------------------------------------------
December 31,
2000 1999
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $ 321,201
Paid-in Capital 462,483 462,376
Retained Earnings 398,086 587,424
---------- ----------
Total Common Shareholder's Equity 1,181,770 1,371,001
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,937
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 1,077,987 1,139,834
---------- ----------
TOTAL CAPITALIZATION 2,285,255 2,536,622
---------- ----------
OTHER NONCURRENT LIABILITIES 542,017 414,837
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 117,506 11,677
Short-term Debt - 194,918
Accounts Payable - General 179,691 180,383
Accounts Payable - Affiliated Companies 121,360 64,599
Customer Deposits 39,736 8,196
Taxes Accrued 223,101 179,112
Interest Accrued 20,458 16,863
Obligations Under Capital Leases 32,716 34,284
Energy Trading Contracts 1,662,315 131,844
Other 151,934 88,249
---------- ----------
TOTAL CURRENT LIABILITIES 2,548,817 910,125
---------- ----------
DEFERRED INCOME TAXES 621,941 676,460
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 25,214 35,838
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 206,187 24,677
---------- ----------
DEFERRED CREDITS 23,005 78,650
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $6,252,436 $4,677,209
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash
Flows
- --------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 83,737 $ 212,157 $ 209,925
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 200,350 193,780 172,085
Deferred Income Taxes (65,956) 3,666 3,042
Deferred Investment Tax Credits (3,399) (3,458) (3,525)
Deferred Fuel Costs (net) (56,869) (76,978) (44,694)
Extraordinary Loss - Discontinuance of SFAS 71 18,876 - -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 51,430 (49,309) (12,376)
Fuel, Materials and Supplies 46,645 (60,500) 18,612
Accrued Utility Revenues 45,311 (2,074) (5,915)
Accounts Payable 56,069 9,195 51,040
Disputed Tax and Interest Related to COLI 110,494 (6,272) (104,222)
Change in Operating Reserves 145,573 66,573 77,811
Other (net) 6,232 48,718 42,981
--------- --------- ---------
Net Cash Flows From Operating Activities 638,493 335,498 404,764
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (254,016) (193,870) (185,036)
Proceeds from Sales of Property and Other 6,354 5,900 5,910
--------- --------- ---------
Net Cash Flows Used For
Investing Activities (247,662) (187,970) (179,126)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 74,748 222,308 186,126
Changes in Advances to Affiliates (net) (92,486) - -
Retirement of Cumulative Preferred Stock (182) (3,392) (133)
Retirement of Long-term Debt (30,663) (158,638) (197,911)
Change in Short-term Debt (net) (194,918) 71,913 44,305
Dividends Paid on Common Stock (271,813) (210,813) (211,101)
Dividends Paid on Cumulative Preferred Stock (1,262) (1,420) (1,475)
--------- --------- ---------
Net Cash Flows Used For
Financing Activities (516,576) (80,042) (180,189)
--------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents (125,745) 67,486 45,449
Cash and Cash Equivalents January 1 157,138 89,652 44,203
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 31,393 $ 157,138 $ 89,652
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $87,120,000, $78,739,000
and $79,667,000 and for income taxes was $142,710,000, $94,606,000 and
$118,548,000 in 2000, 1999 and 1998, respectively. Noncash acquisitions under
capital leases were $17,005,000, $28,561,000 and $29,938,000 in 2000, 1999 and
1998, respectively.
See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Retained Earnings
- ----------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
Retained Earnings January 1 $587,424 $587,500 $590,151
Net Income 83,737 212,157 209,925
-------- -------- --------
671,161 799,657 800,076
-------- -------- --------
Deductions:
Cash Dividends Declared:
Common Stock 271,813 210,813 211,101
Cumulative Preferred Stock:
4.08% Series 59 61 63
4.20% Series 96 97 97
4.40% Series 139 142 143
4-1/2% Series 442 460 467
5.90% Series 428 472 487
6.02% Series 66 156 186
6.35% Series 32 32 32
-------- -------- --------
Total Dividends 273,075 212,233 212,576
-------- -------- --------
Retained Earnings December 31 $398,086 $587,424 $587,500
======== ======== ========
See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
- ------------------------------------------------------------------------------------------------------------------------------------
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,181,770 $1,371,001
---------- ----------
PREFERRED STOCK - authorized shares 3,762,403 $100 par value
authorized shares 4,000,000 $25 par value
Call Price Shares
December 31, Par Number of Shares Redeemed Outstanding
Series(a) 2000 Value Year Ended December 31, December 31, 2000
- ------ ------------ ----- ---------------------------- -----------------
2000 1999 1998
---- ---- ----
Not Subject to Mandatory Redemption:
4.08% $103 $100 - 373 425 14,595 1,460 1,460
4.20% 103.20 100 276 - - 22,824 2,282 2,310
4.40% 104 100 432 330 200 31,512 3,151 3,194
4-1/2% 110.00 100 2,181 3,631 1,096 97,546 9,755 9,973
------ ------
16,648 16,937
------ ------
Subject to Mandatory Redemption:
5.90% (b) - $100 - 10,000 - 72,500 7,250 7,250
6.02% (c) - 100 - 20,000 - 11,000 1,100 1,100
6.35% (c) - 100 - - - 5,000 500 500
------ ------
8,850 8,850
------ ------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 316,294 323,772
Installment Purchase Contracts 233,130 233,025
Senior Unsecured Notes 471,583 408,671
Notes Payable 30,000 30,000
Junior Debentures 131,980 131,860
Other Long-term Debt 12,506 24,183
Less Portion Due Within One Year (117,506) (11,677)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,077,987 1,139,834
---------- ----------
TOTAL CAPITALIZATION $2,285,255 $2,536,622
========== ==========
(a) The series subject to mandatory redemption are not callable until after
2002. The sinking fund provisions of each series subject to mandatory
redemption have been met by purchase of shares in advance of the due date.
(b) Commencing in 2004 and continuing through the year 2008, a sinking fund for
the 5.90% cumulative preferred stock will require the redemption of 22,500
shares each year and the redemption of the remaining shares outstanding on
January 1, 2009, in each case at $100 per share. Shares previously redeemed
may be applied to meet sinking fund requirements.
(c) Commencing in 2003 and continuing through 2007 cumulative preferred stock
sinking funds will require the redemption of 20,000 shares each year of the
6.02% series and 15,000 shares each year of the 6.35% series, in each case
at $100 per share. All remaining outstanding shares must be redeemed in
2008. Shares previously redeemed may be applied to meet the sinking fund
requirements.
See Notes to Consolidated Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- ------------------------------------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
6.75 2003 - April 1 $ 38,850 $ 40,000
6.55 2003 - October 1 32,135 32,135
6.00 2003 - November 1 25,000 25,000
6.15 2003 - December 1 50,000 50,000
8.80 2022 - February 10 50,000 50,000
7.75 2023 - April 1 40,000 40,000
7.375 2023 - October 1 40,000 40,000
7.10 2023 - November 1 20,000 23,000
7.30 2024 - April 1 21,500 25,000
Unamortized Discount (1,191) (1,363)
-------- --------
Total $316,294 $323,772
======== ========
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
Mason County, West
Virginia:
5.45% 2016 - December 1 $ 50,000 $ 50,000
Marshall County, West
Virginia:
5.45% 2014 - July 1 50,000 50,000
5.90% 2022 - April 1 35,000 35,000
6.85% 2022 - June 1 50,000 50,000
Ohio Air Quality
Development
5.15% 2026 - May 1 50,000 50,000
Unamortized Discount (1,870) (1,975)
-------- --------
Total $233,130 $233,025
======== ========
Under the terms of the installment purchase contracts, OPCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2001 - May 16 $ 75,000 $ -
6.75 2004 - July 1 100,000 100,000
7.00 2004 - July 1 75,000 75,000
6.73 2004 - November 1 48,000 48,000
6.24 2008 - December 4 37,225 50,000
7-3/8 2038 - June 30 140,000 140,000
Unamortized Discount (3,642) (4,329)
-------- --------
Total $471,583 $408,671
======== ========
(a) A floating interest rate is determined monthly.
The rate on December 31, 2000 was 7.26%.
Notes payable outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
6.20 2001 - January 31 $ 5,000 $ 5,000
6.20 2001 - January 31 7,000 7,000
6.20 2001 - January 31 18,000 18,000
------- -------
Total $30,000 $30,000
======= =======
Junior debentures outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ -----------------
8.16 2025 - September 30 $ 85,000 $ 85,000
7.92 2027 - March 31 50,000 50,000
Unamortized Discount (3,020) (3,140)
-------- --------
Total $131,980 $131,860
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.
Finance obligations were entered into by the Company's coal mining
subsidiaries for mining facilities and equipment through sale and leaseback
transactions. In accordance with SFAS 98, the transactions did not qualify as
sales and leasebacks for accounting purposes and therefore are shown as other
long-term debt. The terms on the remaining long-term debt obligation including
renewals end on December 24, 2001 and contain a bargain purchase option at
expiration of the agreement. At December 31, 2000, the interest rate was 6.98%.
At December 31, 2000, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2001 $ 117,506
2002 -
2003 145,985
2004 223,000
2005 -
Later Years 718,725
----------
Total Principal Amount 1,205,216
Unamortized Discount (9,723)
----------
Total $1,195,493
==========
OHIO POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items Note 2
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Staff Reductions Note 11
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Supplementary Information Note 17
Leases Note 18
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Ohio Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Ohio Power Company and its
subsidiaries as of December 31, 2000 and 1999, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2000. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Ohio Power Company and its
subsidiaries as of December 31, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001
PUBLIC SERVICE COMPANY OF OKLAHOMA
AND SUBSIDIARIES
I-11
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 962,609 $749,390 $780,159 $712,690 $735,265
Operating Expenses 865,940 650,677 665,085 630,666 635,527
---------- -------- -------- -------- --------
Operating Income 96,669 98,713 115,074 82,024 99,738
Nonoperating Income (Loss) 8,974 946 (91) 1,649 (35,511)
---------- -------- -------- -------- --------
Income Before Interest
Charges 105,643 99,659 114,983 83,673 64,227
Interest Charges 38,980 38,151 38,074 37,218 34,748
---------- -------- -------- -------- --------
Net Income 66,663 61,508 76,909 46,455 29,479
Preferred Stock Dividend
Requirements 212 212 213 364 816
Gain On Reacquired
Preferred Stock - - - 4,211 -
---------- -------- -------- -------- --------
Earnings Applicable to
Common Stock $ 66,451 $ 61,296 $ 76,696 $ 50,302 $ 28,663
========== ======== ======== ======== ========
December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $2,604,670 $2,459,705 $2,391,722 $2,339,908 $2,290,175
Accumulated Depreciation
and Amortization 1,150,253 1,114,255 1,082,081 1,031,322 987,283
---------- ---------- ---------- ---------- ----------
Net Electric Utility Plant $1,454,417 $1,345,450 $1,309,641 $1,308,586 $1,302,892
========== ========== ========== ========== ==========
Total Assets $2,142,156 $1,524,726 $1,470,939 $1,464,562 $1,447,107
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $ 337,230 $ 337,230 $ 337,230 $ 337,230 $ 337,230
Retained Earnings 137,688 139,237 142,941 135,245 143,944
---------- ---------- ---------- ---------- ----------
Total Common Shareholder's
Equity $ 474,918 $ 476,467 $ 480,171 $ 472,475 $ 481,174
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 5,283 $ 5,286 $ 5,287 $ 5,287 $ 19,826
========== ========== ========== ========== ==========
Preferred Securities of
Subsidiary Trust $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ -
========== ========== ========== ========== ===========
Long-term Debt (a) $ 470,822 $ 384,516 $ 384,064 $ 438,703 $ 438,369
========== ========== ========== ========== ==========
Total Capitalization
and Liabilities $2,142,156 $1,524,726 $1,470,939 $1,464,562 $1,447,107
========== ========== ========== ========== ==========
(a) Including portion due within one year.
PUBLIC SERVICE COMPANY OF OKLAHOMA
Management's Narrative Analysis
of Results of Operations
PSO is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 499,000 retail
customers in eastern and southwestern Oklahoma. PSO also sells electric power at
wholesale to other utilities, municipalities and rural electric cooperatives.
PSO participates in power marketing and trading activities conducted on its
behalf by the AEP System.
PSO shares in the revenues and costs of the AEP Power Pool wholesale
sales to and net forward trades with other utility systems and power marketers.
Revenues from trading of electricity are recorded net of purchases as operating
revenues.
Results of Operations Rise
Net income increased $5.2 million or 8.4% in 2000 due mainly to a gain
from the sale of a minority interest in Scientech, Inc. Scientech provides
services, systems and instruments, which describe, regulate, monitor and enhance
the safety and reliability of power plant operations and their environmental
impact.
Operating Revenues
Operating revenues rose 28% due to an increase in fuel and purchased
power revenues, reflecting price increases in fuel and purchased power expenses,
and an increase in power sales to neighboring utilities and power marketers.
Changes in the components of operating revenues were as follows:
Increase
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Retail:
Residential $ 65.8 22
Commercial 52.2 23
Industrial 37.4 23
Other 1.9 20
------
157.3
Wholesale 54.8 140
Transmission and Other 1.1 6
------ ---
Total $213.2 28
====== ===
Revenues from retail customers increased as a result of an increase in
fuel-related revenues that reflect rising prices for natural gas used for
generation and higher purchased power prices. The Oklahoma fuel clause recovery
mechanism provides for the accrual of fuel-related revenues until reviewed and
approved for billing to customers by the Oklahoma Corporation Commission. The
accrual of additional fuel and purchased power revenues is offset by increases
in fuel and purchased power expenses. As a result, accrued fuel-related revenues
do not impact results of operations.
The increase in wholesale revenues is attributable to increased sales
volumes to other utilities and prices reflecting the increase in gas prices and
PSO's participation in the AEP System's power marketing and trading operations.
The volume of electricity sales to other utilities, both affiliated and
unaffiliated, increased as demand for energy rose in response to warmer summer
weather. Since PSO became a subsidiary of AEP in June 2000 as a result of a
merger with CSW, PSO shares in the AEP System's power marketing and trading
transactions with other entities. Trading involves the purchase and sale of
substantial amounts of electricity at wholesale to non-affiliated parties.
Revenues from trading are recorded net of purchases.
Operating Expenses Increase
Operating expenses were $215.3 million more in 2000 than in 1999 largely
as a result of increased fuel and purchased power expenses. Changes in the
components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Fuel Expense $133.6 50
Purchased Power Expense 80.2 107
Other Operation (0.2) N.M.
Depreciation and
Amortization 1.7 2
Taxes Other Than Federal
Income Taxes (1.7) (5)
Federal Income Taxes 1.7 6
------
Total $215.3 33
======
N.M. = Not Meaningful
The increases in fuel and purchased power were due primarily to a rise
in the average unit fuel cost and higher prices for economy energy purchases
reflecting an increase in natural gas prices. As discussed above, changes in
fuel and purchased power expenses are generally reflected in revenues on an
accrual basis and as such did not impact results of operations.
Nonoperating Income
Nonoperating income increased $8 million primarily due to the gain from
the sale of PSO's minority interest in Scientech, Inc. in 2000.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of
Income
- -----------------------------------------------------------------------------------------------
Year Ended December 31,
---------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $962,609 $749,390 $780,159
-------- -------- --------
OPERATING EXPENSES:
Fuel 402,933 269,316 309,969
Purchased Power 155,087 74,893 57,222
Other Operation 121,697 121,896 109,285
Maintenance 45,858 45,809 36,981
Depreciation and Amortization 76,418 74,736 72,671
Taxes Other Than Federal Income Taxes 33,235 34,970 36,733
Federal Income Taxes 30,712 29,057 42,224
-------- -------- --------
Total Operating Expenses 865,940 650,677 665,085
-------- -------- --------
OPERATING INCOME 96,669 98,713 115,074
NONOPERATING INCOME (LOSS) 8,974 946 (91)
-------- -------- --------
INCOME BEFORE INTEREST CHARGES 105,643 99,659 114,983
INTEREST CHARGES 38,980 38,151 38,074
-------- -------- --------
NET INCOME 66,663 61,508 76,909
PREFERRED STOCK DIVIDEND REQUIREMENTS 212 212 213
-------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 66,451 $ 61,296 $ 76,696
======== ======== ========
Consolidated Statements of Retained Earnings
- -------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
---------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD AS
PREVIOUSLY REPORTED $142,019 $144,626 $136,996
CONFORMING CHANGE IN ACCOUNTING POLICY (2,782) (1,685) (1,751)
-------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD 139,237 142,941 135,245
NET INCOME 66,663 61,508 76,909
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 68,000 65,000 69,000
Preferred Stock 212 212 213
-------- -------- --------
BALANCE AT END OF PERIOD $137,688 $139,237 $142,941
======== ======== ========
See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Balance
Sheets
- -----------------------------------------------------------------------------
December 31,
2000 1999
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 914,096 $ 916,889
Transmission 396,695 392,029
Distribution 938,053 897,516
General 206,731 217,368
Construction Work in Progress 149,095 35,903
---------- ----------
Total Electric Utility Plant 2,604,670 2,459,705
Accumulated Depreciation and Amortization 1,150,253 1,114,255
---------- ----------
NET ELECTRIC UTILITY PLANT 1,454,417 1,345,450
---------- ----------
OTHER PROPERTY AND INVESTMENTS 38,211 46,205
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 52,629 -
---------- -----------
CURRENT ASSETS:
Cash and Cash Equivalents 11,301 3,173
Accounts Receivable:
Customers 60,424 32,301
Affiliated Companies 3,453 2,283
Allowance for Uncollectible Accounts (467) -
Fuel - at LIFO cost 28,113 24,143
Materials and Supplies - at average cost 29,642 34,289
Under-recovered Fuel Costs 43,267 6,469
Energy Trading Contracts 382,380 -
Prepayments 1,559 1,572
---------- ----------
TOTAL CURRENT ASSETS 559,672 104,230
---------- ----------
REGULATORY ASSETS 29,338 16,717
---------- ----------
DEFERRED CHARGES 7,889 12,124
---------- ----------
TOTAL $2,142,156 $1,524,726
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
- ---------------------------------------------------------------------------------------------------
December 31,
--------------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $ 157,230 $ 157,230
Paid-in Capital 180,000 180,000
Retained Earnings 137,688 139,237
---------- ----------
Total Common Shareholder's Equity 474,918 476,467
---------- ----------
Cumulative Preferred Stock Not Subject
To Mandatory Redemption 5,283 5,286
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 450,822 364,516
---------- ----------
TOTAL CAPITALIZATION 1,006,023 921,269
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 20,000 20,000
Advances from Affiliates 81,120 79,169
Accounts Payable - General 104,379 44,088
Accounts Payable - Affiliated Companies 64,556 35,517
Customer Deposits 19,294 17,751
Taxes Accrued 1,659 18,480
Interest Accrued 8,336 5,420
Energy Trading Contracts 389,279 -
Other 12,137 8,059
---------- ----------
TOTAL CURRENT LIABILITIES 700,760 228,484
---------- ----------
DEFERRED INCOME TAXES 312,060 281,916
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 35,783 37,574
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 35,292 55,483
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 52,238 -
---------- -----------
CONTINGENCIES (Note 8)
TOTAL $2,142,156 $1,524,726
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Cash
Flows
- ------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
-------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 66,663 $ 61,508 $ 76,909
Adjustments for Noncash Items:
Depreciation and Amortization 76,418 74,736 72,671
Deferred Income Taxes 25,453 14,521 (1,651)
Deferred Investment Tax Credits (1,791) (1,791) (1,795)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (28,826) (1,668) (13,308)
Fuel, Materials and Supplies 677 (8,985) (5,809)
Other Property and Investments 7,994 (2,108) (2,835)
Accounts Payable 89,330 (8,000) 2,196
Taxes Accrued (16,821) (4,615) 23,095
Fuel Recovery (36,798) (21,709) 30,605
Transmission Coordination Agreement Settlement (15,063) 15,063 -
Other (net) (1,621) (5,509) 13,035
--------- --------- ---------
Net Cash Flows From Operating Activities 165,615 111,443 193,113
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (176,851) (103,122) (68,897)
Proceeds from Sales of Property and Other Items - (8,659) (8,271)
--------- --------- ---------
Net Cash Flows Used For Investing Activities (176,851) (111,781) (77,168)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 105,625 33,232 -
Retirement of Long-term Debt (20,000) (33,700) (55,231)
Change in Advances from Affiliates (net) 1,951 63,277 11,018
Dividends Paid on Common Stock (68,000) (65,000) (69,000)
Dividends Paid on Cumulative Preferred Stock (212) (212) (213)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities 19,364 (2,403) (113,426)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 8,128 (2,741) 2,519
Cash and Cash Equivalents January 1 3,173 5,914 3,395
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 11,301 $ 3,173 $ 5,914
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $33,732,000, $37,081,000
and $37,772,000 and for income taxes was $25,786,000, $23,871,000 and
$37,712,000 in 2000, 1999, and 1998, respectively.
See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of
Capitalization
- ----------------------------------------------------------------------------------------------------------------------------
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 474,918 $ 476,467
---------- ----------
PREFERRED STOCK - authorized shares 700,000, cumulative $100 par value
redeemable at the option of PSO upon 30 days notice.
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2000 Year Ended December 31, December 31, 2000
- ------ ------------ ---------------------------- -----------------
2000 1999 1998
---- ---- ----
Not Subject to Mandatory Redemption:
4.00% $105.75 25 9 - 44,606 4,460 4,463
4.24% 103.19 - - - 8,069 807 807
Premium 16 16
---------- ----------
5,283 5,286
---------- ----------
TRUST PREFERRED SECURITIES
PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely Junior Subordinated Debentures of PSO, 8.00%,
due April 30, 2037 75,000 75,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 317,465 337,160
Installment Purchase Contracts 47,357 47,356
Senior Unsecured Notes 106,000 -
Less Portion Due Within One Year (20,000) (20,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 450,822 364,516
---------- ----------
TOTAL CAPITALIZATION $1,006,023 $ 921,269
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Schedule of Long-term Debt
- -------------------------------------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
6.43 2000 - March 30 $ - $ 10,000
5.89 2000 - December 15 - 10,000
5.91 2001 - March 1 6,000 6,000
6.02 2001 - March 1 5,000 5,000
6.02 2001 - March 1 9,000 9,000
6.25 2003 - April 1 35,000 35,000
7.25 2003 - July 1 65,000 65,000
7.38 2004 - December 1 50,000 50,000
6.50 2005 - June 1 50,000 50,000
7.38 2023 - April 1 100,000 100,000
Unamortized Discount (2,535) (2,840)
-------- --------
$317,465 $337,160
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
Oklahoma Environmental
Finance Authority (OEFA):
5.90 2007 - December 1 $ 1,000 $ 1,000
Oklahoma Development
Finance Authority (ODFA):
4.875 2014 - June 1 33,700 33,700
Red River Authority
of Texas:
6.00 2020 - June 1 12,660 12,660
Unamortized Discount (3) (4)
------- -------
Total $47,357 $47,356
======= =======
Under the terms of the installment purchase contracts, PSO is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2002 - November 21 $106,000 $ -
======== =========
(a) A floating interest rate is determined monthly.
The rate on December 31, 2000 was 7.376%.
At December 31, 2000, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2001 $ 20,000
2002 106,000
2003 100,000
2004 50,000
2005 50,000
Later Years 147,360
--------
Total Principal Amount 473,360
Unamortized Discount (2,538)
--------
Total $470,822
========
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Merger Note 3
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Trust Preferred Securities Note 21
Jointly Owned Electric Utility Plant Note 22
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:
We have audited the accompanying consolidated balance sheet and
consolidated statement of capitalization of Public Service Company of Oklahoma
and subsidiaries as of December 31, 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the year then ended.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audit. The consolidated financial statements of the Company for the years
ended December 31, 1999 and 1998, before the restatement described in Note 3 to
the consolidated financial statements, were audited by other auditors whose
report, dated February 25, 2000, expressed an unqualified opinion on those
statements.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provide a reasonable
basis for our opinion.
In our opinion, the 2000 consolidated financial statements present
fairly, in all material respects, the financial position of Public Service
Company of Oklahoma and subsidiaries as of December 31, 2000, and the results of
their operations and their cash flows for the year then ended in conformity with
accounting principles generally accepted in the United States of America.
We also audited the adjustments described in Note 3 that were applied to
restate the 1999 and 1998 consolidated financial statements to give retroactive
effect to the conforming change in the method of accounting for vacation pay
accruals. In our opinion, such adjustments are appropriate and have been
properly applied.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of
Public Service Company Oklahoma:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Public Service Company of Oklahoma (an Oklahoma
corporation and a wholly owned subsidiary of Central and South West Corporation)
and subsidiary companies as of December 31, 1999, and the related consolidated
statements of income, retained earnings and cash flows, for each of the two
years in the period ended December 31, 1999 prior to the restatement (and,
therefore, are not presented herein) for the retroactive effect of the
conforming change in the method of accounting for vacation pay accruals and
certain conforming reclassifications to the historical financial statements as
described in Note 3 to the restated consolidated financial statements. These
financial statements are the responsibility of Public Service Company of
Oklahoma's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements prior to the restatement
referred to above present fairly, in all material respects, the financial
position of Public Service Company of Oklahoma and subsidiary companies as of
December 31, 1999, and results of their operations and their cash flows for each
of the two years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States.
Arthur Andersen LLP
Dallas, Texas
February 25, 2000
SOUTHWESTERN ELECTRIC POWER COMPANY
AND SUBSIDIARIES
J-12
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial
Data
- ------------------------------------------------------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,124,210 $971,527 $952,952 $939,869 $920,786
Operating Expenses 995,932 824,465 802,274 800,396 786,669
---------- -------- -------- -------- --------
Operating Income 128,278 147,062 150,678 139,473 134,117
Nonoperating Income (Loss) 3,851 (1,965) 2,451 4,029 (21,178)
---------- -------- -------- -------- --------
Income Before Interest
Charges 132,129 145,097 153,129 143,502 112,939
Interest Charges 59,457 58,892 55,135 50,536 50,349
---------- -------- -------- -------- --------
Income Before Extraordinary
Item 72,672 86,205 97,994 92,966 62,590
Extraordinary Loss - (3,011) - - -
---------- -------- -------- -------- --------
Net Income 72,672 83,194 97,994 92,966 62,590
Preferred Stock Dividend
Requirements 229 229 705 2,467 3,053
Gain (Loss) on Reacquired
Preferred Stock - - (856) 1,819 -
---------- -------- -------- -------- ---------
Earnings Applicable to
Common Stock $ 72,443 $ 82,965 $ 96,433 $ 92,318 $ 59,537
========== ======== ======== ======== ========
December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $3,319,024 $3,231,431 $3,157,911 $3,081,443 $3,044,314
Accumulated Depreciation
and Amortization 1,457,005 1,384,242 1,317,057 1,225,865 1,192,356
---------- ---------- ---------- ---------- ----------
Net Electric Utility Plant $1,862,019 $1,847,189 $1,840,854 $1,855,578 $1,851,958
========== ========== ========== ========== ==========
Total Assets $2,662,534 $2,106,215 $2,081,454 $2,134,618 $2,141,999
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $ 380,660 $ 380,660 $ 380,660 $ 380,660 $ 380,660
Retained Earnings 293,989 283,546 296,581 320,148 317,835
---------- ---------- ---------- ---------- ----------
Total Common Shareholder's
Equity $ 674,649 $ 664,206 $ 677,241 $ 700,808 $ 698,495
========== ========== ========== ========== ==========
Preferred Stock $ 4,704 $ 4,706 $ 4,707 $ 30,639 $ 48,496
========== ========== ========== ========== ==========
Trust Preferred Securities $ 110,000 $ 110,000 $ 110,000 $ 110,000 $ -
========== ========== ========== ========== ==========
Long-term Debt (a) $ 645,963 $ 541,568 $ 587,673 $ 589,980 $ 642,555
========== ========== ========== ========== ==========
Total Capitalization
and Liabilities $2,662,534 $2,106,215 $2,081,454 $2,134,618 $2,141,999
========== ========== ========== ========== ==========
(a) Including portion due within one year.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
SWEPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 428,000 retail
customers in northeastern Texas, northwestern Louisiana, and western Arkansas.
SWEPCo also sells electric power at wholesale to other utilities, municipalities
and rural electric cooperatives. SWEPCo participates in power marketing and
trading activities conducted on its behalf by the AEP System.
SWEPCo shares in the revenues and costs of the AEP Power Pool's wholesale
sales to and net forward trades with other utility systems and power marketers.
Revenues from trading of electricity are recorded net of purchases as operating
revenues.
Results of Operations
The $10.5 million or 13% decrease in net income in 2000 is due to
increased operating expenses. While the $14.8 million or 15% decrease in 1999 is
primarily the result of increased other operation and maintenance expenses, the
write-off of acquisition expenses attributable to CSW's efforts to acquire the
non-nuclear assets of Cajun Power Cooperative, increased interest charges and
the effect of an extraordinary loss from the discontinued regulatory accounting
for SWEPCo's Texas and Arkansas generating business.
Operating Revenues
Operating revenues significantly increased in 2000 from higher fuel and
purchased power revenues due to increased fuel and purchased power expense,
increased retail energy sales, the post merger favorable impact of AEP's power
marketing and trading operations, which added new wholesale revenues, and the
effect of an unfavorable revenue adjustment in 1999 as a result of FERC's
approval of a transmission coordination agreement. The transmission coordination
agreement provides the means by which the AEP West electric operating companies
plan, operate and maintain their separate transmission assets as a single
system. The agreement also establishes the method by which these companies
allocate transmission revenues received under open access transmission tariffs.
In 1999 the AEP West electric operating companies filed a revised transmission
coordination agreement which included changes that ensure a revenue allocation
in proportion to each company's respective revenue requirement for service it
provides under a revised open access transmission tariff. In the third quarter
of 1999, SWEPCo and the other AEP West electric operating companies recorded the
estimated impact of the reallocation of open access transmission tariff revenues
to 1997 which caused SWEPCo to record a reduction to revenues in the third
quarter of 1999.
The following analyzes the changes in operating revenues:
Increase (Decrease)
From Previous Year
(dollars in millions)
- ---------------------
2000 1999
------------------------------
Amount % Amount %
Retail:
Residential $ 32.7 $(19.9)
Commercial 21.1 0.5
Industrial 18.4 1.6
Other 3.3 1.0
------ ------
75.5 10 (16.8) (2)
Wholesale 68.7 40 32.2 23
Transmission 32.1 N.M. (5.3) N.M.
Other (23.6) (86) 8.5 44
------ ------
Total $152.7 16 $ 18.6 2
====== ======
N.M. = Not Meaningful
Revenues from retail customers increased in 2000 as a result of an
increase in fuel and purchased power revenues and a rise in sales volume caused
by warmer summer temperatures. The increase in fuel and purchased power revenues
reflects rising prices for natural gas used for generation and related higher
costs for purchased power. The Texas and Arkansas fuel clause recovery
mechanisms provide for the accrual of fuel-related revenues until reviewed and
approved for billing to customers by the regulator. The accrual of additional
fuel-related revenues is generally offset by increases in fuel and purchased
power expenses. As a result fuel-related revenues do not impact results of
operations.
The significant increase in wholesale revenues in 2000 is attributable to
increased sales to other utilities and SWEPCo's initial participation in the AEP
System's power marketing and trading operations after the merger of CSW and AEP.
The volume of wholesale electricity sales to other utilities, both affiliated
and unaffiliated, increased as demand for energy rose in response to warmer
summer weather. Since SWEPCo became a subsidiary of AEP as a result of the
merger in June 2000, SWEPCo shares in the AEP System's power marketing and
trading transactions with other entities. Trading transactions involve the
purchase and sale of substantial amounts of electricity which are accounted for
as revenues net of purchases.
Wholesale revenues increased 23% in 1999 due mainly to an increase in
sales to other utilities as a result of increased demand.
Operating Expenses Increase
Total operating expenses increased 21% in 2000 primarily due to
significant increases in the cost of fuel and purchased power. In 1999 the
operating expenses increased 3% primarily due to increased maintenance expense.
The changes in the components of operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions)
---------------------
2000 1999
------------------------------
Amount % Amount %
Fuel $119.2 31 $ 8.2 2
Purchased Power 40.4 108 1.9 5
Other Operation 17.1 12 1.8 1
Maintenance 10.9 17 13.0 25
Depreciation and
Amortization (4.2) (4) 10.3 11
Taxes Other Than
Federal Income
Taxes (2.2) (4) (3.7) (6)
Federal Income
Taxes (9.8) (29) (9.3) (22)
------ -----
Total $171.4 21 $22.2 3
====== =====
Fuel expense increased in 2000 and 1999 due to an increase in the average
unit cost of fuel as a result of an increase in the spot market price for
natural gas and an increase in generation to meet the rise in retail and
wholesale demand for electricity. The modest increase in fuel expense in 1999
resulted from an increase in the generation of electricity to meet the rising
wholesale demand for electricity.
The major increase in purchased power expense in 2000 was primarily
caused by an increase in firm energy contract purchases, increased capacity
charges and increased economy energy purchases. Purchased power expense for 1999
increased due primarily to an increase in economy energy purchases.
Other operation expense increased in 2000 due primarily to increased
regulatory and consulting expenses.
Maintenance expense increased in 2000 as a result of costs to restore
service and make repairs following a severe ice storm in December. The increase
in 1999 can be attributed to higher power station maintenance, increased
tree-trimming and additional overhead line maintenance.
The increase in depreciation and amortization in 1999 is the result of
increased depreciable plant and a provision for excess earnings. The Texas
Legislation provides that each year during the 1999 through 2001 rate freeze
period, electric utilities are subject to an earnings test. See description of
earnings test in Note 7 of the Notes to Consolidated Financial Statements.
A decline in franchise taxes in 2000 and ad valorem taxes in 1999 led to
the reduction in taxes other than federal income taxes in 2000 and 1999.
The decreases in federal income tax expense attributable to operations in
2000 and 1999 were primarily due to decreases in pre-tax operating income and an
unfavorable tax accrual adjustment made in 1998.
Nonoperating Income
The increase in nonoperating income in 2000 was due to the effect of a
1999 write off of Cajun Electric Power Cooperative acquisition expenses
following CSW's decision not to continue to pursue the acquisition of Cajun
Electric Power Cooperative non-nuclear assets. SWEPCo had deferred approximately
$13 million in acquisition costs related to its attempt to acquire Cajun's
non-nuclear assets.
Interest Charges
Interest charges for 1999 increased primarily due to increased levels of
short-term borrowings and additional interest expenses in connection with
changes to the transmission coordination agreements.
Extraordinary Loss
An extraordinary loss of $3 million net of tax was recorded in the third
quarter of 1999 when SWEPCo discontinued the application of SFAS 71 regulatory
accounting for the generation portion of its business in Texas and Arkansas as a
result of legislation passed in those states providing for a transition from
cost based rate regulation for SWEPCo's generation business to customer choice
market pricing.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
- -----------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $1,124,210 $971,527 $952,952
---------- -------- --------
OPERATING EXPENSES:
Fuel 498,805 379,597 371,414
Purchased Power 77,792 37,371 35,483
Other Operation 159,459 142,385 140,627
Maintenance 75,123 64,241 51,219
Depreciation and Amortization 104,679 108,831 98,479
Taxes Other Than Federal Income Taxes 56,283 58,458 62,207
Federal Income Taxes 23,791 33,582 42,845
---------- -------- --------
Total Operating Expenses 995,932 824,465 802,274
---------- -------- --------
OPERATING INCOME 128,278 147,062 150,678
NONOPERATING INCOME (LOSS) 3,851 (1,965) 2,451
---------- -------- --------
INCOME BEFORE INTEREST CHARGES 132,129 145,097 153,129
INTEREST CHARGES 59,457 58,892 55,135
---------- -------- --------
INCOME BEFORE EXTRAORDINARY ITEM 72,672 86,205 97,994
EXTRAORDINARY LOSS (net of tax of $1,621,000) - (3,011) -
---------- -------- ---------
NET INCOME 72,672 83,194 97,994
PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 705
LOSS ON REACQUIRED PREFERRED STOCK - - (856)
---------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK $ 72,443 $ 82,965 $ 96,433
========== ======== ========
Consolidated Statements of Retained Earnings
BALANCE AT BEGINNING OF PERIOD AS
PREVIOUSLY REPORTED $288,019 $300,592 $324,050
Conforming Change in Accounting Policy (4,473) (4,011) (3,902)
-------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD 283,546 296,581 320,148
NET INCOME 72,672 83,194 97,994
LOSS ON REACQUIRED PREFERRED STOCK - - (856)
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 62,000 96,000 120,000
Preferred Stock 229 229 705
-------- -------- --------
BALANCE AT END OF PERIOD $293,989 $283,546 $296,581
======== ======== ========
See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
- ----------------------------------------------------------------------------------------
December 31,
2000 1999
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,414,527 $1,402,062
Transmission 519,317 484,327
Distribution 1,001,237 958,318
General 325,948 333,949
Construction Work in Progress 57,995 52,775
---------- ----------
Total Electric Utility Plant 3,319,024 3,231,431
Accumulated Depreciation and Amortization 1,457,005 1,384,242
---------- ----------
NET ELECTRIC UTILITY PLANT 1,862,019 1,847,189
---------- ----------
OTHER PROPERTY AND INVESTMENTS 39,627 37,080
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 63,028 -
---------- -----------
CURRENT ASSETS:
Cash and Cash Equivalents 1,907 3,043
Accounts Receivable:
Customers 42,310 49,939
Affiliated Companies 11,419 6,053
Allowance for Uncollectible Accounts (911) (4,428)
Fuel Inventory - at average cost 40,024 60,844
Materials and Supplies - at average cost 25,137 26,420
Under-recovered Fuel Costs 35,469 -
Energy Trading Contracts 457,936 -
Prepayments 16,780 15,953
---------- ----------
TOTAL CURRENT ASSETS 630,071 157,824
---------- ----------
REGULATORY ASSETS 57,082 47,180
---------- ----------
DEFERRED CHARGES 10,707 16,942
---------- ----------
TOTAL $2,662,534 $2,106,215
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
December 31,
---------------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $ 135,660 $ 135,660
Paid-in Capital 245,000 245,000
Retained Earnings 293,989 283,546
---------- ----------
Total Common Shareholder's Equity 674,649 664,206
Preferred Stock 4,704 4,706
SWEPCO - obligated, mandatorily redeemable
preferred securities of subsidiary trust
holding solely Junior Subordinated
Debentures of SWEPCO 110,000 110,000
Long-term Debt 645,368 495,973
---------- ----------
TOTAL CAPITALIZATION 1,434,721 1,274,885
---------- ----------
OTHER NONCURRENT LIABILITIES 11,290 9,255
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 595 45,595
Advances from Affiliates 16,823 140,897
Accounts Payable - General 107,747 60,689
Accounts Payable - Affiliated Companies 36,021 39,117
Customer Deposits 16,433 14,236
Taxes Accrued 11,224 24,374
Interest Accrued 13,198 9,792
Energy Trading Contracts 466,198 -
Other 15,064 12,623
---------- ----------
TOTAL CURRENT LIABILITIES 683,303 347,323
---------- ----------
DEFERRED INCOME TAXES 399,204 376,504
---------- ----------
DEFERRED INVESTMENT TAX CREDITS 53,167 57,649
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS 18,288 40,599
---------- ----------
LONG-TERM ENERGY TRADING CONTRACTS 62,561 -
---------- -----------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $2,662,534 $2,106,215
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
- --------------------------------------------
Year Ended December 31,
-------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 72,672 $ 83,194 $ 97,994
Adjustments for Noncash Items:
Depreciation and Amortization 104,679 108,831 98,479
Deferred Income Taxes 14,653 (17,347) (11,909)
Deferred Investment Tax Credits (4,482) (4,565) (4,631)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (1,254) (11,134) 41,077
Fuel, Materials and Supplies 22,103 (21,891) (14,436)
Accounts Payable 43,962 (12,953) (25,852)
Taxes Accrued (13,150) 1,185 10,305
Transmission Coordination Agreement Settlement (24,406) 24,406 -
Fuel Recovery (38,357) (2,490) 18,391
Other (net) 25,208 8,731 17,045
--------- --------- ---------
Net Cash Flows From Operating Activities 201,628 155,967 226,463
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (120,671) (111,019) (83,120)
Other 446 (4,167) (5,202)
--------- --------- ---------
Net Cash Flows Used For Investing Activities (120,225) (115,186) (88,322)
--------- --------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 149,360 - -
Retirement of Cumulative Preferred Stock (1) (1) (27,988)
Retirement of Long-term Debt (45,595) (46,144) (2,354)
Change in Advances from Affiliates (net) (124,074) 100,192 15,530
Dividends Paid on Common Stock (62,000) (96,000) (120,000)
Dividends Paid on Cumulative Preferred Stock (229) (229) (1,183)
--------- --------- ---------
Net Cash Flows Used For Financing Activities (82,539) (42,182) (135,995)
--------- --------- ---------
Net Increase (Decrease) in Cash and
Cash Equivalents (1,136) (1,401) 2,146
Cash and Cash Equivalents January 1 3,043 4,444 2,298
--------- --------- ---------
Cash and Cash Equivalents December 31 $ 1,907 $ 3,043 $ 4,444
========= ========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $51,110,611, $55,254,000
and $50,341,000 and for income taxes was $27,993,879, $55,677,000 and
$57,977,000 in 2000, 1999, and 1998, respectively.
See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of
Capitalization
- ------------------------------------------------------------------------------------------------
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 674,649 $ 664,206
---------- ----------
PREFERRED STOCK - authorized 1,860,000 shares $100 par value
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2000 Year Ended December 31, December 31, 2000
- ------ ------------ ---------------------------- -----------------
2000 1999 1998
---- ---- ----
Not Subject to Mandatory Redemption:
4.28% $103.90 - - - 7,386 739 739
4.65% $102.75 - 1 - 1,907 190 191
5.00% $109.00 12 2 20 37,715 3,771 3,772
Premium 4 4
---------- ----------
4,704 4,706
---------- ----------
TRUST PREFERRED SECURITIES
SWEPCo-obligated, mandatorily redeemable preferred securities of subsidiary
trust holding solely Junior Subordinated Debentures of SWEPCo, 7.875%,
due April 30, 2037 110,000 110,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 315,477 360,430
Installment Purchase Contracts 180,486 181,138
Senior Unsecured Notes 150,000 -
Less Portion Due Within One Year (595) (45,595)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 645,368 495,973
---------- ----------
TOTAL CAPITALIZATION $1,434,721 $1,274,885
========== ==========
See Notes to Consolidated Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
- ------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
5-1/4 2000 - April 1 $ - $ 45,000
6-5/8 2003 - February 1 55,000 55,000
7-3/4 2004 - June 1 40,000 40,000
6.20 2006 - November 1 5,795 5,940
6.20 2006 - November 1 1,000 1,000
7.00 2007 - September 1 90,000 90,000
7-1/4 2023 - July 1 45,000 45,000
6-7/8 2025 - October 1 80,000 80,000
Unamortized Discount (1,318) (1,510)
-------- --------
$315,477 $360,430
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ -----------------
DeSoto:
7.60 2019 - January 1 $ 53,500 $ 53,500
Sabine:
6.10 2018 - April 1 81,700 81,700
Titus County:
6.90 2004 - November 1 12,290 12,290
6.00 2008 - January 1 13,520 13,970
8.20 2011 - August 1 17,125 17,125
Unamortized Premium 2,351 2,553
-------- --------
$180,486 $181,138
Under the terms of the installment purchase contracts, SWEPCo is
required to pay amounts sufficient to enable the payment of interest on and the
principal (at stated maturities and upon mandatory redemptions) of related
pollution control revenue bonds issued to finance the construction of pollution
control facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
- ------ ------------------
(a) 2002 - March 1 $150,000 $ -
======== ========
(a) A floating interest rate is determined monthly.
The rate on December 31, 2000 was 6.97%.
At December 31, 2000, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2001 $ 595
2002 150,595
2003 55,595
2004 52,885
2005 595
Later Years 384,665
--------
Total Principal Amount 644,930
Unamortized Premium 1,033
--------
Total $645,963
========
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items Note 2
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 12
Business Segments Note 14
Financial Instruments, Credit and Risk Management Note 15
Income Taxes Note 16
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Trust Preferred Securities Note 21
Jointly Owned Electric Utility Plant Note 22
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Southwestern Electric Power Company:
We have audited the accompanying consolidated balance sheet and
consolidated statement of capitalization of Southwestern Electric Power Company
and subsidiaries as of December 31, 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the year then ended.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audit. The consolidated financial statements of the Company for the years
ended December 31, 1999 and 1998, before the restatement described in Note 3 to
the consolidated financial statements, were audited by other auditors whose
report, dated February 25, 2000, expressed an unqualified opinion on those
statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the 2000 consolidated financial statements present
fairly, in all material respects, the financial position of Southwestern
Electric Power Company and subsidiary as of December 31, 2000, and the results
of their operations and their cash flows for the year then ended in conformity
with accounting principles generally accepted in the United States of America.
We also audited the adjustments described in Note 3 that were applied to
restate the 1999 and 1998 consolidated financial statements to give retroactive
effect to the conforming change in the method of accounting for vacation pay
accruals. In our opinion, such adjustments are appropriate and have been
properly applied.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of
Southwestern Electric Power Company:
We have audited the accompanying consolidated balance sheets and consolidated
statements of capitalization of Southwestern Electric Power Company (a Delaware
corporation and a wholly owned subsidiary of Central and South West Corporation)
and subsidiary company as of December 31, 1999, and the related consolidated
statements of income, retained earnings and cash flows, for each of the two
years in the period ended December 31, 1999 prior to the restatement (and,
therefore, are not presented herein) for the retroactive effect of the
conforming change in the method of accounting for vacation pay accruals and
certain conforming reclassifications to the historical financial statements as
described in Note 3 to the restated consolidated financial statements. These
financial statements are the responsibility of Southwestern Electric Power
Company's management. Our responsibility is to express an opinion on these
consolidated financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements prior to the restatement
referred to above present fairly, in all material respects, the financial
position of Southwestern Electric Power Company and subsidiary company as of
December 31, 1999, and results of their operations and their cash flows for each
of the two years in the period ended December 31, 1999, in conformity with
accounting principles generally accepted in the United States.
Arthur Andersen LLP
Dallas, Texas
February 25, 2000
WEST TEXAS UTILITIES COMPANY
K-11
WEST TEXAS UTILITIES COMPANY
Selected Financial
Data
- ----------------------------------------------------------------------------------------------------
Year Ended December 31,
-----------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $ 572,794 $ 445,709 $ 424,953 $ 397,779 $ 377,057
Operating Expenses 520,453 391,910 365,677 353,195 327,499
---------- ---------- ---------- ---------- ----------
Operating Income 52,341 53,799 59,276 44,584 49,558
Nonoperating Income (Loss) (1,675) 2,488 2,712 1,463 (9,922)
---------- ---------- ---------- ---------- ----------
Income Before Interest
Charges 50,666 56,287 61,988 46,047 39,636
Interest Charges 23,216 24,420 24,263 24,570 25,241
---------- ---------- ---------- ---------- ----------
Income Before
Extraordinary Item 27,450 31,867 37,725 21,477 14,395
Extraordinary Loss - (5,461) - - -
---------- ---------- ---------- ---------- -----------
Net Income 27,450 26,406 37,725 21,477 14,395
Preferred Stock Dividend
Requirements 104 104 104 144 264
---------- ---------- ---------- ---------- ----------
Gain on Reacquired
Preferred Stock - - - 1,085 -
---------- ---------- ---------- ---------- ----------
Earnings Applicable to
Common Stock $ 27,346 $ 26,302 $ 37,621 $ 22,418 $ 14,131
========== ========== ========== ========== ==========
December 31,
------------------------------------------------------------
2000 1999 1998 1997 1996
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,229,339 $1,182,544 $1,146,582 $1,108,845 $1,088,141
Accumulated Depreciation
and Amortization 515,041 495,847 473,503 441,281 414,777
---------- ---------- ---------- ---------- ----------
Net Electric Utility Plant $ 714,298 $ 686,697 $ 673,079 $ 667,564 $ 673,364
========== ========== ========== ========== ==========
Total Assets $1,088,932 $ 861,205 $ 819,446 $ 826,858 $ 837,412
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $ 139,450 $ 139,450 $ 139,450 $ 139,450 $ 139,450
Retained Earnings 122,588 113,242 114,940 117,319 120,901
---------- ---------- ---------- ---------- ----------
Total Common Shareholder's
Equity $ 262,038 $ 252,692 $ 254,390 $ 256,769 $ 260,351
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 2,482 $ 2,482 $ 2,482 $ 2,483 $ 6,291
========== ========== ========== ========== ==========
Long-term Debt (a) $ 255,843 $ 303,686 $ 303,518 $ 303,351 $ 303,182
========== ========== ========== ========== ==========
Total Capitalization
and Liabilities $1,088,932 $ 861,205 $ 819,446 $ 826,858 $ 837,412
========== ========== ========== ========== ==========
(a) Including portion due within one year.
WEST TEXAS UTILITIES COMPANY
Management's Narrative Analysis
of Results of
Operations
- ------------------------------------------------------
WTU is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power and provides electric power to
approximately 190,000 retail customers in west and central Texas. WTU also sells
electric power at wholesale to other utilities, municipalities and rural
electric cooperatives. WTU participates in power marketing and trading
activities conducted on its behalf by the AEP System.
WTU shares in the revenues and costs of the AEP Power Pool's wholesale
sales to and net forward trades with other utility systems and power marketers.
Revenues from trading of electricity are recorded net of purchases as operating
revenues.
Results of Operations
Income before extraordinary items decreased $4.4 million or 14%. The
decrease was primarily due to a decrease in nonoperating income, as a result of
the termination of merchandise sales and the cost of phasing out the merchandise
sales program. The decrease in nonoperating income is partially offset by a
decrease in interest charges.
An extraordinary loss related to the discontinuance of SFAS 71 regulatory
accounting for WTU's generation business of $5.5 million after tax was recorded
in September 1999.
Operating Revenues
A 29% increase in operating revenues was due to increased fuel and
purchases power revenues, reflecting higher fuel and purchased power expenses,
and an increase in weather-related demand for electricity. Under the operation
of a fuel and purchase power clause mechanism in Texas, revenues are accrued to
reflect fuel and purchased power cost increases. The accrued revenues are
subsequently reviewed and approved for recovery by the PUCT. As a result changes
in fuel and purchase power revenues do not generally impact results of
operations.
Changes in the components of operating revenues were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Retail:
Residential $ 31.7 24
Commercial 18.9 24
Industrial 13.3 26
Other 9.3 25
------
73.2
Wholesale 47.8 46
Transmission 3.7 11
Other 2.4 128
------
Total $127.1 29
======
Revenues from retail customers increased significantly as a result of an
increase in fuel and purchase power related revenues reflecting rising prices
for natural gas used for generation and related higher purchased power prices.
Since the Texas fuel and purchase power clause recovery mechanism provides for
the accrual of revenues to recover fuel and purchase power cost changes until
reviewed and approved for billing to customers by the PUCT, increases in fuel
and purchased power expenses and related accrued revenues do not adversely
effect results of operations.
The significant increase in wholesale revenues is attributable to
increased sales to other utilities and WTU's participation in the AEP System's
power marketing and trading operations. The volume of electricity sales to other
utilities, both affiliated and unaffiliated, increased as demand for energy rose
in response to warmer summer weather. Since WTU became a subsidiary of AEP as a
result of the merger in June 2000, WTU shares in the AEP System's power
marketing and trading transactions with other non-affiliated entities. Trading
involves the purchase and sale of substantial amounts of electricity to
non-affiliated parties. Revenues from trading are recorded net of purchases.
Operating Expenses
Operating expenses were $520.5 million or 33% more than in 1999 largely
as a result of increased fuel and purchased power expenses. Changes in the
components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Fuel $ 59.8 48
Purchased Power 66.1 107
Other Operation (1.2) (1)
Maintenance 1.6 8
Depreciation and
Amortization 4.4 9
Taxes Other Than Federal
Income (2.9) (10)
Federal Income Taxes 0.8 6
------
Total $128.6 33
======
The substantial increase in fuel expense was primarily due to a rise in
the average cost of fuel resulting from an increase in spot market prices of
natural gas. WTU uses natural gas as fuel for 72% of its generating capacity.
The nature of the natural gas market is such that both long-term and short-term
contracts are generally based on the current spot market price. Consequently,
changes in natural gas prices affect WTU's fuel expense. However, as explained
above they generally do not impact results of operations.
Purchased power expense increased due primarily to an increase in the
cost per MWH purchased to replace generation at a power plant which was out of
service for 90 days as a result of a control room fire and to the adverse impact
of natural gas prices on wholesale purchased power prices.
The increase in maintenance expense was due to an increase in power plant
maintenance and overhead line maintenance. The increase in power plant
maintenance was partly due to repair of the fire damaged control room.
Depreciation and amortization expense increased due to the recordation of
increased accruals for estimated excess earnings under the Texas Legislation.
The decrease in taxes other than federal income taxes was primarily due
to lower ad valorem and state franchise taxes.
Nonoperating Income
Nonoperating income decreased $4.2 million primarily due to the
termination of merchandise sales and the cost of phasing out the merchandise
sales program.
Interest Charges
The decrease in interest charges of $1.2 million or 5% resulted from a
reduction in long-term borrowings.
Extraordinary Loss
The extraordinary loss of $5.5 million was recorded in the third quarter
of 1999 when WTU discontinued the application of SFAS 71 regulatory accounting
for the generation portion of its business as a result of Texas Jurisdictional
Legislation which provides for a transition from cost based rate regulation for
WTU's generation business to customer choice and market based pricing for the
supply of electricity at retail.
WEST TEXAS UTILITIES COMPANY
Statements of Income
- ---------------------------------------------------------------
Year Ended December 31,
---------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING REVENUES $ 572,794 $ 445,709 $ 424,953
---------- ---------- ----------
OPERATING EXPENSES:
Fuel 183,154 123,348 122,836
Purchased Power 127,583 61,532 48,131
Other Operation 93,078 94,290 90,061
Maintenance 21,241 19,604 16,666
Depreciation and Amortization 55,172 50,789 42,750
Taxes Other Than Federal Income Taxes 25,321 28,267 24,638
Federal Income Taxes 14,904 14,080 20,595
---------- ---------- ----------
Total Operating Expenses 520,453 391,910 365,677
---------- ---------- ----------
OPERATING INCOME 52,341 53,799 59,276
NONOPERATING INCOME (LOSS) (1,675) 2,488 2,712
---------- ---------- ----------
INCOME BEFORE INTEREST CHARGES 50,666 56,287 61,988
INTEREST CHARGES 23,216 24,420 24,263
---------- ---------- -----------
INCOME BEFORE EXTRAORDINARY ITEMS 27,450 31,867 37,725
EXTRAORDINARY LOSS - (net of tax of $2,941,000) - (5,461) -
---------- ---------- -----------
NET INCOME 27,450 26,406 37,725
PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104
---------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK $ 27,346 $ 26,302 $ 37,621
========== ========== ==========
Statements of Retained
Earnings
- -----------------------------------------------------------------------------------------------------------------
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD AS
PREVIOUSLY REPORTED $115,856 $117,189 $119,479
CONFORMING CHANGE IN ACCOUNTING POLICY (2,614) (2,249) (2,160)
-------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD 113,242 114,940 117,319
NET INCOME 27,450 26,406 37,725
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 18,000 28,000 40,000
Preferred Stock 104 104 104
-------- -------- --------
BALANCE AT END OF PERIOD $122,588 $113,242 $114,940
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Balance Sheets
- -----------------------------------------------------------------------------------------------------------------
December 31,
2000 1999
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $ 431,793 $ 429,783
Transmission 235,303 220,479
Distribution 416,587 403,206
General (including nuclear fuel) 110,832 113,945
Construction Work in Progress 34,824 15,131
---------- ----------
Total Electric Utility Plant 1,229,339 1,182,544
Accumulated Depreciation and Amortization 515,041 495,847
---------- ----------
NET ELECTRIC UTILITY PLANT 714,298 686,697
---------- ----------
OTHER PROPERTY AND INVESTMENTS 23,154 21,570
---------- ----------
ENERGY TRADING CONTRACTS - LONG-TERM 20,944 -
---------- -----------
CURRENT ASSETS:
Cash and Cash Equivalents 6,941 6,074
Accounts Receivable:
Customers 36,217 45,928
Affiliated Companies 16,095 4,837
Allowance for Uncollectible Accounts (288) (186)
Fuel - at average cost 12,174 17,133
Materials and Supplies - at average cost 10,510 14,029
Underrecovered Fuel Costs 67,655 14,652
Energy Trading Contracts 152,174 -
Prepayments 851 619
---------- ----------
TOTAL CURRENT ASSETS 302,329 103,086
---------- ----------
REGULATORY ASSETS 24,808 29,745
---------- ----------
DEFERRED CHARGES 3,399 20,107
---------- ----------
TOTAL $1,088,932 $ 861,205
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
- -------------------------------------------------------------------------------------------------------------------------------
December 31,
---------------------------
2000 1999
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $ 137,214 $137,214
Paid-in Capital 2,236 2,236
Retained Earnings 122,588 113,242
---------- --------
Total Common Shareholder's Equity 262,038 252,692
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 2,482 2,482
Long-term Debt 255,843 263,686
---------- --------
TOTAL CAPITALIZATION 520,363 518,860
---------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 40,000
Advances from Affiliates 58,578 21,408
Accounts Payable - General 45,562 39,611
Accounts Payable - Affiliated Companies 42,212 19,770
Customer Deposits 2,659 2,396
Taxes Accrued 18,901 12,458
Interest Accrued 3,717 4,165
Energy Trading Contracts 154,919 -
Other 7,906 5,510
---------- --------
TOTAL CURRENT LIABILITIES 334,454 145,318
---------- --------
DEFERRED INCOME TAXES 157,038 148,992
---------- --------
DEFERRED INVESTMENT TAX CREDITS 24,052 25,323
---------- --------
REGULATORY LIABILITIES AND DEFERRED CREDITS 32,236 22,712
---------- --------
ENERGY TRADING CONTRACTS - LONG-TERM 20,789 -
---------- ---------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $1,088,932 $861,205
========== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Statements of Cash Flows
- ----------------------------------------
Year Ended December 31,
--------------------------------------
2000 1999 1998
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 27,450 $ 26,406 $ 37,725
Adjustments for Noncash Items:
Depreciation and Amortization 55,172 50,789 42,750
Deferred Federal Income Taxes 8,164 12,026 (6,626)
Deferred Investment Tax Credits (1,271) (1,275) (1,321)
Extraordinary Loss - Discontinuance of SFAS 71 - 5,461 -
CHANGES IN CERTAIN ASSETS AND LIABILITIES:
Accounts Receivable (net) (1,445) (18,890) (21,119)
Fuel, Materials and Supplies 8,478 (3,785) (660)
Accounts Payable 28,393 7,229 305
Taxes Accrued 6,443 2,427 (1,344)
Fuel Recovery (53,003) (10,672) 7,988
Other Property and Investments (1,584) (2,057) (1,344)
Transmission Coordination Agreement Settlement 15,465 (15,465) -
Other (net) 2,016 10,448 4,972
--------- --------- ---------
Net Cash Flows From Operating Activities 94,278 62,642 61,326
--------- --------- ---------
INVESTING ACTIVITIES:
Construction Expenditures (64,477) (49,443) (36,867)
Other - (3,832) (5,782)
--------- --------- ---------
Net Cash Flows Used For Investing Activities (64,477) (53,275) (42,649)
--------- --------- ---------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (48,000) - -
Change in Advances from Affiliates (net) 37,170 16,835 4,573
Dividends Paid on Common Stock (18,000) (28,000) (40,000)
Dividends Paid on Cumulative Preferred Stock (104) (105) (104)
--------- --------- ---------
Net Cash Flows From (Used For)
Financing Activities (28,934) (11,270) (35,531)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents 867 (1,903) (16,854)
Cash and Cash Equivalents at Beginning of Period 6,074 7,977 24,831
--------- --------- ---------
Cash and Cash Equivalents at End of Period $ 6,941 $ 6,074 $ 7,977
========= ========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $19,088,000,
$17,577,000 and $17,250,000 and for income taxes was $(906,000), $3,309,000
and $29,533,000 in 2000, 1999 and 1998, respectively.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Statements of
Capitalization
- ---------------------------------------------------------------------------
December 31,
-----------------------------
2000 1999
---- ----
(in thousands)
COMMON SHAREHOLDER'S EQUITY $262,038 $252,692
-------- --------
PREFERRED STOCK - authorized 810,000 shares $100 par value
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2000 Year Ended December 31, December 31, 2000
- ------ ------------ ---------------------------- -----------------
2000 1999 1998
---- ---- ----
Not Subject to Mandatory Redemption:
4.40% $107.00 1 2 - 23,672 2,367 2,367
Premium 115 115
-------- --------
2,482 2,482
-------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 211,533 259,376
Installment Purchase Contracts 44,310 44,310
Less Portion Due Within One Year - (40,000)
-------- --------
Long-term Debt Excluding Portion Due Within One Year 255,843 263,686
-------- --------
TOTAL CAPITALIZATION $520,363 $518,860
======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Schedule of Long-term Debt
- --------------------------------------------------
First mortgage bonds outstanding were as follows:
December 31,
--------------------
2000 1999
---- ----
(in thousands)
% Rate Due
7-3/4 2007 - June 1 $ 25,000 $ 25,000
6-7/8 2002 - October 1 35,000 35,000
7 2004 - October 1 40,000 40,000
6-1/8 2004 - February 1 40,000 40,000
7-1/2 2000 - April 1 - 40,000
6-3/8 2005 - October 1 72,000 80,000
Unamortized Discount (467) (624)
-------- --------
$211,533 $259,376
Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into, in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2000 1999
---- ----
(in thousands)
% Rate Due
Red River Authority
of Texas:
6 2020 - June 1 $44,310 $44,310
======= =======
Under the terms of the installment purchase contracts, WTU is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
At December 31, 2000, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2001 $ -
2002 35,000
2003 -
2004 80,000
2005 72,000
Later Years 69,310
--------
Total $256,310
========
WEST TEXAS UTILITIES COMPANY
Index to Notes to Financial Statements
- -----------------------------------------
The notes listed below are combined with the notes to financial statements for
AEP and its other subsidiary registrants. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items Note 2
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 12
Business Segments Note 14
Financial Instrument, Credit and Risk Management Note 15
Income Taxes Note 16
Lines of Credit and Factoring of Receivables Note 19
Unaudited Quarterly Financial Information Note 20
Jointly Owned Electric Utility Plant Note 22
Related Party Transactions Note 23
INDEPENDENT AUDITORS' REPORT
- -----------------------------------------------
To the Shareholders and Board of
Directors of West Texas Utilities Company:
We have audited the accompanying balance sheet and statement of
capitalization of West Texas Utilities Company as of December 31, 2000, and the
related statements of income, retained earnings, and cash flows for the year
then ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audit. The financial statements of the Company for the
years ended December 31, 1999 and 1998, before the restatement described in Note
3 to the financial statements, were audited by other auditors whose report,
dated February 25, 2000, expressed an unqualified opinion on those statements.
We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.
In our opinion, the 2000 financial statements present fairly, in all
material respects, the financial position of West Texas Utilities Company as of
December 31, 2000, and the results of its operations and its cash flows for the
year then ended in conformity with accounting principles generally accepted in
the United States of America.
We also audited the adjustments described in Note 3 that were applied to
restate the 1999 and 1998 financial statements to give retroactive effect to the
conforming change in the method of accounting for vacation pay accruals. In our
opinion, such adjustments are appropriate and have been properly applied.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 26, 2001
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To the Stockholders and Board of Directors of
West Texas Utilities Company:
We have audited the accompanying balance sheets and statements of capitalization
of West Texas Utilities Company (a Texas corporation and a wholly owned
subsidiary of Central and South West Corporation) as of December 31, 1999, and
the related statement of income, retained earnings and cash flows, for each of
the two years in the period ended December 31, 1999 prior to the restatement
(and, therefore, are not presented herein) for the retroactive effect of the
conforming change in the method of accounting for vacation pay accruals and
certain conforming reclassifications to the historical financial statements as
described in Note 3 to the restated financial statements. These financial
statements are the responsibility of West Texas Utilities Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States. Those standards require that we plan and perform the audit
to obtain reasonable assurance about whether the financial statements are free
of material misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements. An audit
also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, the financial statements prior to the restatement referred to
above present fairly, in all material respects, the financial position of West
Texas Utilities Company as of December 31, 1999, and results of its operations
and its cash flows for each of the two years in the period ended December 31,
1999, in conformity with accounting principles generally accepted in the United
States.
Arthur Andersen LLP
Dallas, Texas
February 25, 2000
L-48
NOTES TO FINANCIAL STATEMENTS
- -----------------------------------------------------------------------------
The notes to financial statements that follow are a combined presentation for
AEP and its subsidiary registrants. The following list of footnotes shows the
registrant to which they apply:
1. Significant Accounting Policies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
2. Extraordinary Items AEP, APCo, CPL, CSPCo, OPCo, SWEPCo, WTU
3. Merger AEP, CPL, I&M, KPCo, PSO, SWEPCo, WTU
4. Nuclear Plant Restart AEP, I&M
5. Rate Matters AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
OPCo, SWEPCo, WTU
6. Effects of Regulation AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
KPCo, OPCo, PSO, SWEPCo, WTU
7. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO,
SWEPCo, WTU
8. Commitments and Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
9. Acquisitions AEP
10. International Investments AEP
11. Staff Reductions AEP, APCo, CSPCo, I&M, KPCo, OPCo
12. Benefit Plans AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, WTU
13. Stock Based Compensation AEP
14. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
15. Financial Instruments, Credit AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
and Risk Management OPCo, PSO, SWEPCo, WTU
16. Income Taxes AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
KPCo, OPCo, PSO, SWEPCo, WTU
17. Supplementary Information AEP, APCo, CSPCo, I&M, OPCo
18. Leases AEP, AEGCo, APCo, CSPCo, I&M, KPCo, OPCo
19. Lines of Credit AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
and Commitment Fees OPCo, PSO, SWEPCo, WTU
20. Unaudited Quarterly AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
Financial Information OPCo, PSO, SWEPCo, WTU
21. Trust Preferred Securities AEP, CPL, PSO, SWEPCo,
22. Jointly Owned Electric
Utility Plant CPL, CSPCo, PSO, SWEPCo, WTU
23. Related Party Transactions AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
1. Significant Accounting Policies:
Business Operations - AEP's principal business conducted by its eleven domestic
electric utility operating companies is the generation, transmission and
distribution of electric power. Nine of AEP's eleven domestic electric utility
operating companies, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU, are
SEC registrants. AEGCo is a domestic generating company wholly-owned by AEP that
is an SEC registrant. These companies are subject to regulation by the FERC
under the Federal Power Act and follow the Uniform System of Accounts prescribed
by FERC. They are subject to further regulation with regard to rates and other
matters by state regulatory commissions.
Wholesale marketing and trading of electricity and gas is conducted in the
United States and Europe. In addition AEP's domestic operations includes
non-regulated independent power and cogeneration facilities and an intra-state
midstream natural gas operation in Louisiana.
AEP's international operations include regulated supply and distribution of
electricity and other non-regulated power generation projects in the United
Kingdom, Australia, Mexico, South America and China.
In addition to the above energy related operations, AEP is also involved in
domestic factoring of accounts receivable, investing in leveraged leases and
providing energy services worldwide and communications related services
domestically.
Rate Regulation - The AEP System is subject to regulation by the SEC under the
PUHCA. The rates charged by the domestic utility subsidiaries are approved by
the FERC and the state utility commissions. The FERC regulates wholesale
electricity operations and transmission rates and the state commissions regulate
retail generation and distribution rates. The prices charged by foreign
subsidiaries located in the UK, Australia, China, Mexico and Brazil are
regulated by the
authorities of that country and are generally subject to price controls.
Principles of Consolidation - AEP's consolidated financial statements include
AEP Co., Inc. and its wholly-owned and majority-owned subsidiaries consolidated
with their wholly-owned subsidiaries. The consolidated financial statements for
APCo, CPL, CSPCo, I&M, OPCo, PSO and SWEPCo include the registrant and its
wholly-owned subsidiaries. Significant intercompany items are eliminated in
consolidation. Equity investments that are 50% or less owned are accounted for
using the equity method with their equity earnings included in Other Income, net
for AEP and nonoperating income for the registrant subsidiaries.
Basis of Accounting - As cost-based rate-regulated electric public utility
companies, the financial statements for AEP and each of the registrant
subsidiaries reflect the actions of regulators that result in the recognition of
revenues and expenses in different time periods than enterprises that are not
rate regulated. In accordance with SFAS 71, "Accounting for the Effects of
Certain Types of Regulation," regulatory assets (deferred expenses) and
regulatory liabilities (deferred revenues) are recorded to reflect the economic
effects of regulation by matching expenses with their recovery through regulated
revenues. Application of SFAS 71 for the generation portion of the business was
discontinued as follows: in Ohio by OPCo and CSPCo in September 2000, in
Virginia and West Virginia by APCo in June 2000, in Texas by CPL, WTU, and
SWEPCo in September 1999 and in Arkansas by SWEPCo in September 1999. See Note
7, "Industry Restructuring" for additional information.
Use of Estimates - The preparation of these financial statements in conformity
with generally accepted accounting principles requires in certain instances the
use of estimates and assumptions that affect the reported amounts of assets and
liabilities along with the disclosure of contingent liabilities at the date of
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
Property, Plant and Equipment - Domestic electric utility property, plant and
equipment are stated at original cost of the acquirer. The property, plant and
equipment of SEEBOARD, CitiPower and LIG are stated at their fair market value
at acquisition plus the original cost of property acquired or constructed since
the acquisition, less disposals. Additions, major replacements and betterments
are added to the plant accounts. For cost-based rate regulated operations
retirements from the plant accounts and associated removal costs, net of
salvage, are deducted from accumulated depreciation. The costs of labor,
materials and overheads incurred to operate and maintain plant are included in
operating expenses.
Allowance for Funds Used During Construction (AFUDC) - AFUDC is a noncash
nonoperating income item that is capitalized and recovered through depreciation
over the service life of domestic regulated electric utility plant. For domestic
regulated electric utility plant, it represents the estimated cost of borrowed
and equity funds used to finance construction projects. The amounts of AFUDC for
2000, 1999 and 1998 were not significant. Effective with the discontinuance of
the application of SFAS 71 regulatory accounting for domestic generating assets
in Arkansas, Ohio, Texas, Virginia and West Virginia and for AEP's other
nonregulated operations interest is capitalized during construction in
accordance with SFAS 34, "Capitalization of Interest Costs." The amounts of
interest capitalized was not material in 2000, 1999, and 1998.
Depreciation, Depletion and Amortization - Depreciation of property, plant and
equipment is provided on a straight-line basis over the estimated useful lives
of property, other than coal-mining property, and is calculated largely through
the use of composite rates by functional class as follows:
Functional Class Annual Composite
of Property Depreciation Rates Ranges
2000
Production:
Steam-Nuclear 2.8% to 3.4%
Steam-Fossil-Fired 2.3% to 4.5%
Hydroelectric-
Conventional
and Pumped Storage 2.7% to 3.4%
Transmission 1.7% to 3.1%
Distribution 3.3% to 4.2%
Other 2.5% to 20.0%
Functional Class Annual Composite
of Property Depreciation Rates Ranges
1999
Production:
Steam-Nuclear 2.8% to 3.4%
Steam-Fossil-Fired 3.2% to 5.0%
Hydroelectric-
Conventional
and Pumped Storage 2.7% to 3.4%
Transmission 1.7% to 2.7%
Distribution 2.8% to 4.2%
Other 2.0% to 20.0%
Functional Class Annual Composite
of Property Depreciation Rates Ranges
1998
Production:
Steam-Nuclear 2.8% to 3.4%
Steam-Fossil-Fired 3.2% to 4.4%
Hydroelectric-
Conventional
and Pumped Storage 2.7% to 3.4%
Transmission 1.7% to 2.7%
Distribution 3.3% to 4.2%
Other 2.5% to 20.0%
The following table provides the annual composite depreciation rates generally
used by the AEP registrant subsidiaries for the years 2000, 1999 and 1998 which
were as follows:
Nuclear Steam Hydro Transmission Distribution General
AEGCo - % 3.5% - % - % - % 2.8%
APCo - 3.4 2.9 2.2 3.3 3.2
CPL 2.8 2.3 - 2.3 3.5 4.2
CSPCo - 3.2 - 2.3 3.6 3.3
I&M 3.4 4.5 3.4 1.9 4.2 3.8
KPCo - 3.8 - 1.7 3.5 2.5
OPCo - 3.4 2.7 2.3 4.0 2.7
PSO - 2.7 - 2.3 3.4 6.4
SWEPCo - 3.3 - 2.7 3.6 4.6
WTU - 2.7 - 3.1 3.3 6.8
Depreciation, depletion and amortization of OPCo's coal-mining assets is
provided over each asset's estimated useful life or the estimated life of the
mine, whichever is shorter, and is calculated using the straight-line method for
mining structures and equipment. The units-of-production method is used to
amortize coal rights and mine development costs based on estimated recoverable
tonnages at a current average rate of $5.07 per ton in 2000, $2.32 per ton in
1999 and $1.85 per ton in 1998. These costs are included in the cost of coal
charged to fuel expense. See Note 5 "Rate Matters" regarding the closure and
possible sale of affiliated mines.
Cash and Cash Equivalents - Cash and cash equivalents include temporary cash
investments with original maturities of three months or less.
Inventory - Except for CPL, PSO and WTU, the domestic utility companies value
fossil fuel inventories using a weighted average cost method. CPL, PSO and WTU,
utilize the LIFO method to value fossil fuel inventories. SWEPCo continues to
use the weighted average cost method pending approval of its request to the
Arkansas Commission to utilize the LIFO method. Natural gas inventories held by
LIG are marked-to-market.
Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts
receivable for the domestic utility subsidiaries, except
APCo, and unaffiliated companies.
Foreign Currency Translation - The financial statements of subsidiaries outside
the U.S. which are included in AEP's consolidated financial statements are
measured using the local currency as the functional currency and translated into
U.S. dollars in accordance with SFAS 52 "Foreign Currency Translation". Assets
and liabilities are translated to U.S. dollars at year-end rates of exchange and
revenues and expenses are translated at monthly average exchange rates
throughout the year. Currency translation gain and loss adjustments are recorded
in shareholders' equity as "Accumulated Other Comprehensive Income (Loss)". The
non-cash impact of the changes in exchange rates on cash, resulting from the
translation of items at different exchange rates is shown on AEP's Consolidated
Statement of Cash Flows in "Effect of Exchange Rate Change on Cash." Actual
currency transaction gains and losses are recorded in income.
Energy Marketing and Trading Transactions - The AEP System engages in wholesale
electricity and natural gas marketing and trading transactions (trading
activities). Trading activities involve the sale of energy under physical
forward contracts at fixed and variable prices and the trading of energy
contracts including exchange traded futures and options, over-the-counter
options and swaps. The majority of these transactions represent physical forward
electricity contracts in AEP's traditional marketing area (up to two
transmission systems from AEP's service territory) and are typically settled by
entering into offsetting contracts. The net revenues from these transactions in
AEP's traditional marketing area are included in revenues from domestic electric
utility operations on AEP's consolidated statements of income.
The AEP System also purchases and sells electricity and gas options, futures and
swaps, and enters into forward purchase and sale contracts for electricity
(outside its traditional marketing area) and gas. These transactions represent
non-regulated trading activities that are included in revenues from worldwide
electric and gas operations on AEP's consolidated statements of income.
All of the registrant subsidiaries except AEGCo participate in the AEP System's
wholesale marketing and trading of electricity. APCo, CSPCo, I&M, KPCo and OPCo
record revenues from trading of electricity net of purchases as operating
revenues for forward electricity trades in AEP's traditional marketing area and
as nonoperating income for forward electricity trades beyond two transmission
systems from AEP and for speculative financial transactions (options, futures
and swaps). CPL, PSO, SWEPCo and WTU record revenues from trading of electricity
net of purchases as operating revenues.
The AEP System follows EITF 98-10 and EITF 00-17, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities" and "Measuring the
Fair Value of Energy-Related Contracts in Applying Issue 98-10", respectively.
EITF 98-10 requires that all energy trading contracts be marked-to-market. The
effect on AEP's consolidated statements of income of marking open trading
contracts to market in the regulated jurisdictions are deferred as regulatory
assets or liabilities for those open electricity trading transactions within
AEP's marketing area that are included in cost of service on a settlement basis
for ratemaking purposes. Non-regulated jurisdictions with open electricity
trading transactions within AEP's marketing area are marked-to-market and
included in domestic electric utility operations revenues on AEP's consolidated
statements of income. Non-regulated and regulated jurisdictions open electricity
trading contracts outside the traditional marketing area are accounted for on a
mark-to-market basis and included in worldwide electric and gas operations
revenues on AEP's consolidated statements of income. Open gas trading contracts
are accounted for on a mark-to-market basis and included in worldwide electric
and gas operations on AEP's consolidated statements of income.
APCo, CSPCo and OPCo account for open forward electricity trading contracts on a
mark-to-market basis and include the mark-to-market change in revenues for open
contracts in AEP's traditional marketing area and in nonoperating income for
open contracts beyond AEP's traditional marketing area.
I&M and KPCo account for open forward electricity trading contracts on a
mark-to-market basis and defer the mark-to-market change as regulatory assets or
liabilities for those open contracts in AEP's traditional marketing area and
include the mark-to-market change in nonoperating income for open contracts
beyond AEP's traditional marketing area.
CPL, PSO, SWEPCo and WTU account for open forward electricity trading contracts
on a mark-to-market basis. CPL includes the mark-to-market change for open
electricity trading contracts in revenues. PSO defers as regulatory assets or
liabilities the mark-to-market change for open forward electricity trading
contracts that are included in cost of service on a settlement basis for
ratemaking purposes. SWEPCo and WTU include the jurisdictional share of the
mark-to-market change in revenues for open electricity trading contracts for
those jurisdictions that are not subject to SFAS 71 cost based rate regulation
and defer as regulatory assets or liabilities the jurisdictional share of the
mark-to-market change for open contracts that are included in cost of service on
a settlement basis for ratemaking purposes.
Unrealized mark-to-market gains and losses from all trading activity are
reported as assets and liabilities, respectively.
Hedging and Related Activities - In order to mitigate the risks of market price
and interest rate fluctuations, AEP's foreign subsidiaries, SEEBOARD and
CitiPower, utilize interest swaps, currency swaps and forward contracts to hedge
such market fluctuations. Changes in the market value of these swaps and
contracts are deferred until the gain or loss is realized on the underlying
hedged asset, liability or commodity. To qualify as a hedge, these transactions
must be designated as a hedge and changes in their fair value must correlate
with changes in the price and interest rate movement of the underlying asset,
liability or commodity. This in effect reduces AEP's exposure to the effects of
market fluctuations related to price and interest rates.
AEP, APCo, CSPCo, I&M, and OPCo enter into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued. These anticipatory debt
instruments are entered into in order to manage the change in interest rates
between the time a debt offering is initiated and the issuance of the debt
(usually a period of 60 days). Gains or losses from these transactions are
deferred and amortized over the life of the debt issuance with the amortization
included in interest charges. There were no such forward contracts outstanding
at December 31, 2000 or 1999. See Note 15 - "Financial Instruments, Credit and
Risk Management" for further discussion of the accounting for risk management
transactions.
Revenues and Fuel Costs - Domestic revenues include the accrual of service
provided but un-billed at month-end as well as billed revenues. The cost of fuel
consumed is charged to expense as incurred. Under governing regulatory
com-mission retail rate orders, any resulting fuel cost over or under-recoveries
are deferred as regula-tory liabilities or regulatory assets in accordance with
SFAS 71. These deferrals generally are billed or refunded to customers in later
months with the regulator's review and approval. Wholesale jurisdictional fuel
cost increases and decreases over amounts included in base rates are expensed
and billed as incurred. See Note 5 "Rate Matters" and Note 7 "Industry
Restruct-uring" for further information about fuel recovery. Levelization of
Nuclear Refueling Outage Costs - In order to match costs with regulated
revenues, which include outage costs on a normalized basis, incremental
operation and maintenance costs associated with periodic refueling outages at
I&M's Cook Plant are deferred and amortized over the period beginning with the
commencement of an outage and ending with the beginning of the next outage.
Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement
agreements approved by the IURC and the MPSC to resolve all issues related to an
extended outage of the Cook Plant, I&M deferred $200 million of incremental
operation and maintenance costs during 1999. The deferred amount is being
amortized to expense on a straight-line basis over five years from January 1,
1999 to December 31, 2003. I&M amortized $40 million in 1999 and 2000, leaving
$120 million as an SFAS 71 regulatory asset at December 31, 2000 on the
Consolidated Balance Sheets of AEP and I&M.
Income Taxes - The AEP System follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the
liability method, deferred income taxes are provided for all temporary
differences between the book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in regulated revenues (that
is, deferred taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are recorded and related
regulatory assets and liabilities are established in accordance with SFAS 71 to
match the regulated revenues and tax expense.
Investment Tax Credits - Investment tax credits have been accounted for under
the flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral basis.
Investment tax credits that have been deferred are being amortized over the life
of the regulated plant investment.
Debt and Preferred Stock - Where appropriate gains and losses from the
reacquisition of debt used to finance domestic regulated electric utility plant
are generally deferred and amortized over the remaining term of the reacquired
debt in accordance with their rate-making treatment. If the debt is refinanced,
the reacquisition costs attributable to the portions of the business that are
subject to cost based regulatory accounting under SFAS 71 are generally deferred
and amortized over the term of the replacement debt commensurate with their
recovery in rates. Gains and losses on the reacquisition of debt for operations
not subject to SFAS 71 are reported as a component of net income.
Debt discount or premium and debt issuances expenses are deferred and amortized
over the term of the related debt, with the amortization included in interest
charges.
Where rates are regulated redemption premiums paid to reacquire preferred stock
of the domestic utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its recovery in rates in accordance with SFAS 71.
Goodwill - The amount of acquisition cost in excess of the fair value allocated
to tangible assets obtained through an acquisition accounted for as a purchase
combination is recorded as goodwill on AEP's consolidated balance sheet.
Amortization of goodwill is on a straight-line basis generally over 40 years
except for the portion of goodwill associated with gas trading and marketing
activities which is being amortized on a straight-line basis over 10 years. The
recoverability of goodwill (evaluated on undiscounted operating cash flow
analysis) is reviewed when events or changes in circumstances indicate that the
carrying amount may exceed fair value.
Other Assets - Other assets on AEP's consolidated balance sheet are comprised
primarily of nuclear decommissioning and spent nuclear fuel disposal trust funds
and licenses for CitiPower operating franchises. Securities held in trust funds
for decommissioning nuclear facilities and for the disposal of spent nuclear
fuel are included in Other Assets at market value in accordance with SFAS 115,
"Accounting for Certain Investments in Debt and Equity Securities." Securities
in the trust funds have been classified as available-for-sale due to their
long-term purpose. Under the provisions of SFAS 71, unrealized gains and losses
from securities in these trust funds are not reported in equity but result in
adjustments to the liability account for the nuclear decommissioning trust funds
and to regulatory assets or liabilities for the spent nuclear fuel disposal
trust funds in accordance with their treatment in rates.
Comprehensive Income - Comprehensive income is defined as the change in equity
(net assets) of a business enterprise during a period from transactions and
other events and circumstances from non-owner sources. It includes all changes
in equity during a period except those resulting from investments by owners and
distributions to owners. There were no material differences between net income
and comprehensive income for AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, and WTU.
Components of Other Comprehensive Income - The following table provides the
components that comprise the balance sheet amount in Accumulated Other
Comprehensive Income for AEP.
December 31,
Components 2000 1999 1998
- -------------------------------------------------
(millions)
Foreign Currency
Adjustments $ (99) $ 20 $ 33
Unrealized Losses
on Securities - (20) (20)
Minimum Pension
Liability (4) (4) (6)
----- ---- ----
$(103) $ (4) $ 7
===== ==== ====
Segment Reporting - The AEP System has adopted SFAS No. 131, which requires
disclosure of selected financial information by business segment as viewed by
the chief operating decision-maker. See Note 14 "Business Segments" for further
discussion and details regarding segments.
Common Stock Options - AEP follows Accounting Principles Board Opinion 25 to
account for stock options. Compensation expense is not recognized at the date of
grant, because the exercise price of stock options awarded under the stock
option plan equals the market price of the underlying stock on the date of
grant.
EPS - AEP's basic earnings per share is determined based upon the weighted
average number of common shares outstanding during the years presented. Diluted
earnings per share for AEP is based upon the weighted average number of common
shares and stock options outstanding during the years presented. Basic and
diluted are the same in 2000, 1999 and 1998.
AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU are wholly-owned
subsidiaries of AEP and are not required to report EPS.
Reclassification - Certain prior year financial statement items have been
reclassified to conform to current year presentation. Such reclassification had
no impact on previously reported net income.
2. Extraordinary Items:
Extraordinary Items - Extraordinary items were recorded for the discontinuance
of regulatory accounting under SFAS 71 for the generation portion of the
business in the Ohio, Virginia, West Virginia, Texas and Arkansas state
jurisdictions. See Note 7 "Industry Restructuring" for descriptions of the
restructuring plans and related accounting effects. The following table shows
the components of the extraordinary items reported on AEP's consolidated
statements of income:
Year Ended
December 31,
2000 1999
---- ----
(in millions)
Extraordinary Items:
Discontinuance of Regulatory
Accounting for Generation:
Ohio Jurisdiction
(Net of Tax of $35 Million) $(44) $ -
Virginia and West Virginia
Jurisdictions (Inclusive of
Tax Benefit of $8 Million) 9 -
Texas and Arkansas
Jurisdictions (Net of Tax
of $5 Million) - (8)
Loss on Reacquired Debt
(Net of Tax of $3 Million) - (6)
---- ----
Extraordinary Items $(35) $(14)
==== ====
There were no extraordinary items in 1998.
3. Merger:
On June 15, 2000, AEP merged with CSW so that CSW became a wholly-owned
subsidiary of AEP. Under the terms of the merger agreement, approximately 127.9
million shares of AEP Common Stock were issued in exchange for all the
outstanding shares of CSW Common Stock based upon an exchange ratio of 0.6 share
of AEP Common Stock for each share of CSW Common Stock. Following the exchange,
former shareholders of AEP owned approximately 61.4 percent of the corporation,
while former CSW shareholders owned approximately 38.6 percent of the
corporation.
The merger was accounted for as a pooling of interests. Accordingly, AEP's
consolidated financial statements give retroactive effect to the merger, with
all periods presented as if AEP and CSW had always been combined. Certain
reclassifications have been made to conform the historical financial statement
presentation of AEP and CSW.
The following table sets forth revenues, extraordinary items and net income
previously reported by AEP and CSW and the combined amounts shown in the
accompanying financial statements for 1999 and 1998:
Year Ended December 31,
1999 1998
---- ----
(in millions)
Revenues:
AEP $ 6,870 $ 6,358
CSW 5,537 5,482
------- -------
AEP After
Pooling $12,407 $11,840
======= =======
Year Ended December 31,
1999 1998
---- ----
(in millions)
Extraordinary Items:
AEP $ - $ -
CSW (14) -
---- ---
AEP After
Pooling $(14) $ -
==== ===
Net Income:
AEP $520 $536
CSW 455 440
Conforming
Adjustment (3) (1)
---- ----
AEP After Pooling $972 $975
==== ====
The combined financial statements include an adjustment to conform CSW's
accounting for vacation pay accruals with AEP's accounting. The effect of the
conforming adjustment was to reduce net assets by $16 million at December 31,
1999 and reduce net income by $3 million and $1 million for the years ended
December 31, 1999 and 1998, respectively.
The following table shows the vacation accrual conforming adjustment for CSW's
registrant utility subsidiaries:
Net Asset Net Income Reductions
-
Reduction At Year Ended December 31,
-----------------------
December 31, 1999 1999 1998
----------------- ------ ------
(in millions) (in millions)
CPL $5.3 $0.7 $0.1
PSO 2.8 1.1 -
SWEPCo 4.5 0.5 0.1
WTU 2.6 0.4 0.1
In connection with the merger, $203 million ($180 million after tax) of
non-recoverable merger costs were expensed by AEP through December 31, 2000.
Such costs included transaction and transition costs not recoverable from
ratepayers. Also included in the merger costs were non-recoverable change in
control payments. Merger transaction and transition costs of $45 million
recoverable from ratepayers were deferred pursuant to state regulator approved
settlement agreements. The deferred merger costs are being amortized over five
to eight year recovery periods depending on the specific terms of the
settlement agreements, with the amortization ($4 million for AEP for the year
2000) included in depreciation and amortization expense.
The following table shows the deferred merger cost and amortization expense of
the applicable subsidiary registrants:
Amortization
Expense for the
Merger Cost Deferral Year Ended
at December 31, 2000 December 31, 2000
-------------------- -----------------
(in millions)
CPL $15.7 $1.3
I&M 7.6 0.7
KPCo 2.7 0.3
PSO 8.3 0.5
SWEPCo 6.6 0.5
WTU 4.6 0.4
Merger transition costs are expected to continue to be incurred for several
years after the merger and will be expensed or deferred for amortization as
appropriate. The state settlement agreements provide for, among other things, a
sharing of net merger savings with certain regulated customers over periods of
up to eight years through rate reductions beginning in the third quarter of
2000. In connection with the merger, the PUCT approved a settlement agreement
that provides for, among other things, sharing net merger savings with Texas
customers of CPL, SWEPCo and WTU over six years after consummation of the merger
through rate reduction riders. The settlement agreement results in rate
reductions for Texas customers totaling $221 million over a six-year period
commencing with the merger's consummation. The rate reduction was composed of
$84 million of net merger savings and $137 million to resolve issues associated
with CPL's, SWEPCo's and WTU's rate and fuel reconciliation proceedings in
Texas. Under the terms of the settlement agreement, base rates cannot be
increased until three years after consummation of the merger.
The IURC and MPSC approved merger settlement agreements that, among other
things, provide for sharing net merger savings with I&M's retail customers over
eight years through reductions to customers' bills. The terms of the Indiana
settlement require reductions in customers' bills of approximately $67 million
over eight years. Under the Michigan settlement, billing credits will be used to
reduce customers' bills by approximately $14 million over eight years for net
guaranteed merger savings. The Indiana settlement extends the base rate freeze
in the Cook Plant extended outage settlement agreement until January 1, 2005 and
requires additional annual deposits of $6 million to the nuclear decommissioning
trust fund for the Indiana jurisdiction for the years 2001 through 2003. As a
result of an appeal of the Indiana settlement agreement by a consumer group, I&M
has not reflected the reductions in Indiana jurisdictional customers' bills.
Instead, pending the result of the appeal, I&M recorded a liability ($1 million
at December 31, 2000) for the reduction due to its Indiana customers under the
settlement.
The KPSC approved a settlement agreement that, among other things, provides for
sharing net merger savings with KPCo's customers over eight years through
reductions to customers' bills and prohibits a general increase in base rates or
other charges for three years following consummation of the merger. The Kentucky
customers' share of the net merger savings is expected to be approximately $28
million.
A merger settlement agreement for PSO was approved by the Oklahoma Corporation
Commission that, among other things, provides for sharing approximately $28
million in guaranteed net merger savings over five years with Oklahoma
customers, prohibits an increase in Oklahoma base rates prior to January 1, 2003
and requires an application to join an RTO be filed with FERC by December 31,
2001.
The Arkansas Commission approved an agreement related to the merger which, among
other things, provides for $6 million of net merger savings to reduce SWEPCo
customers rates over five years in Arkansas and prohibits a base rate increase
being effective prior to January 1, 2002.
SWEPCo's Louisiana customers will receive approximately $18 million of merger
savings over eight years according to a merger approval order issued by the
Louisiana Public Service Commission. In addition, the order capped base rates
for five years after the consummation of the merger (until June 2005) and
required that benefits from off-system sales be shared with ratepayers.
If actual merger savings are significantly less than the merger savings rate
reductions required by the merger settlement agreements in the eight-year period
following consummation of the merger, future results of operations, cash flows
and possibly financial condition could be adversely affected.
Most of the merger settlement agreements approved by the regulatory commissions
require the electric operating companies to join regional transmission
organizations. APCo, CSPCo, I&M, KPCo, OPCo and several other unaffiliated
utilities formed the Alliance RTO before the consummation of the merger. As a
condition of FERC's approval of the merger, CPL, PSO, SWEPCo and WTU were
required to join an RTO prior to December 31, 2000 and to transfer the operation
and control of their transmission facilities to that RTO by December 15, 2001.
CPL and WTU are members of ERCOT. PSO and SWEPCo are members of SPP. ERCOT and
SPP are transmission pooling organizations in certain geographic areas of the
U.S. whose goals include enhancement of bulk electric transmission reliability.
The SPP has filed with FERC to be approved as an RTO. Due to the FERC's inaction
on approving the SPP RTO, in December 2000 PSO and SWEPCo filed with the FERC
requesting an extension of time to join an RTO until 75 days following the
FERC's approval of an RTO for the SPP service area. Initial filings to gain FERC
approval for the Alliance RTO were made and conditional approval was granted by
the FERC. The Alliance RTO made compliance filings as requested by the FERC and
these were accepted in January 2001. Final FERC approval of the SPP RTO is
pending.
The divestiture of 1,904 MW of generating capacity was required as a condition
of regulatory approval of the merger by the FERC and PUCT. Under the
FERC-approved merger agreement the divestiture of 550 MW of generating capacity
comprised of 300 MW of capacity in SPP and 250 MW of capacity in ERCOT is
required. The FERC is requiring AEP and CSW to divest their entire ownership
interest in and operational control of the entire generating facilities that
produce the capacity to be divested. The FERC required divestiture of the
identified ERCOT capacity must be completed by March 15, 2001 and for the SPP
capacity by July 1, 2002. The FERC found that certain energy sales in SPP and
ERCOT would be a reasonable and effective interim mitigation measure until the
required SPP and ERCOT divestitures could be completed. In February 2001, AEP
announced the sale of Frontera, one of the plants required to be divested by the
settlement agreements approved by the FERC. The Texas settlement calls for the
divestiture of a total of 1,604 MW of generating capacity within Texas inclusive
of 250 MW ordered to be divested by FERC. The Texas divestiture cannot proceed
until two years after the merger closes to satisfy the requirements to use
pooling-of-interests accounting treatment. The FERC divestiture is not limited
by the pooling rules because it is regulatory ordered.
The current annual dividend rate per share of AEP Common Stock is $2.40. The
dividends per share reported on the statements of income for prior periods
represent pro forma amounts and are based on AEP's historical annual dividend
rate of $2.40 per share. If the dividends per share reported for prior periods
were based on the sum of the historical dividends declared by AEP and CSW, the
annual dividend rate would be $2.60 per combined share for the years ended
December 31, 1999 and 1998.
4. Nuclear Plant Restart:
The restart of both units of I&M's Cook Plant was completed with Unit 2 reaching
100% power on July 5, 2000 and Unit 1 achieving 100% power on January 3, 2001.
Cook Plant is a 2,110 MW two-unit plant owned and operated by I&M under licenses
granted by the NRC. I&M shut down both units of the Cook Plant in September 1997
due to questions regarding the operability of certain safety systems that arose
during a NRC architect engineer design inspection.
Settlement agreements in the Indiana and Michigan retail jurisdictions that
address recovery of Cook Plant related outage costs were approved in 1999. The
IURC approved a settlement agreement in March 1999 that resolved all matters
related to the recovery of replacement energy fuel costs and all outage/restart
costs and related issues during the extended outage of the Cook Plant. The
settlement agreement provided for, among other things, the deferral of
unrecovered fuel revenues accrued between September 9, 1997 and December 31,
1999; the deferral of up to $150 million of restart related nuclear operation
and maintenance costs in 1999 above the amount included in base rates; the
amortization of the deferred fuel revenues and non-fuel operation and
maintenance cost deferrals over a five-year period ending December 31, 2003; a
freeze in base rates through December 31, 2003; and a fixed fuel recovery charge
through March 1, 2004. The regulatory approved deferrals were recorded in 1999
as a regulatory asset in accordance with SFAS 71.
In December 1999 the MPSC approved a settlement agreement for two open Michigan
power supply cost recovery reconciliation cases that resolves all issues related
to the Cook Plant extended outage. The settlement agreement limits I&M's ability
to increase base rates and freezes the power supply cost recovery factor until
January 1, 2004; permits the deferral of up to $50 million in 1999 of
jurisdictional non-fuel nuclear operation and maintenance expenses; authorizes
the amortization of power supply cost recovery revenues accrued from September
9, 1997 to December 31, 1999 and non-fuel nuclear operation and maintenance cost
deferrals over a five-year period ending December 31, 2003. The regulatory
approved deferrals were recorded in the fourth quarter of 1999.
The amounts of restart costs charged to other operation and maintenance expenses
were as follows:
Year Ended December 31,
2000 1999 1998
---- ---- ----
Costs Incurred $297 $ 289 $78
Deferred Pursuant to
Settlement Agreements - (200) -
Amortization of Deferrals 40 40 -
---- ----- ---
Charged to O&M Expense $337 $ 129 $78
==== ===== ===
At December 31, 2000 and 1999, deferred restart costs of $120 million and $160
million, respectively, remained in regulatory assets to be amortized through
2003. Also pursuant to the settlement agreements, accrued fuel-related revenues
of $38 million and $37 million in 2000 and 1999, respectively, were amortized.
At December 31, 2000 and 1999, fuel-related revenues of $113 million and $150
million, respectively, were included in regulatory assets and will be amortized
through December 31, 2003 for both jurisdictions.
The amortization of restart costs and fuel-related revenues deferred under
Indiana and Michigan retail jurisdictional settlement agreements will adversely
affect results of operations through December 31, 2003 when the amortization
period ends. The annual amortization of restart cost and fuel-related revenue
deferrals is $78 million.
5. Rate Matters:
Texas Jurisdictional Fuel Filings - AEP's Texas electric operating companies
(CPL, SWEPCo and WTU) have been experiencing significant natural gas fuel price
increases which have resulted in under-recoveries of fuel costs and the need to
seek increases in fuel rates and surcharges to recover these under-recoveries.
CPL Fuel Filings - In July 2000 CPL filed with the PUCT an application to
implement an increase in fuel factor revenues effective with the September 2000
billing month. Additionally, CPL proposed to implement an interim fuel surcharge
to collect its under-recovered fuel costs, including accumu-lated interest, over
a twelve-month period begin-ing in October 2000.
In September 2000 the PUCT approved a settlement. The settlement provided for an
increase in fuel factor revenues of $173.5 million annually and provided for a
two-phase surcharge totaling $86.4 million. The recovery of the first phase
surcharge of $21.3 million for previously under-recovered fuel costs including
accumulated interest for the period from December 1, 1999 through May 31, 2000
was authorized to be collected in September through December 2000. The second
surcharge was not to exceed $65.1 million for projected under-recoveries for the
period from June 2000 through August 2000 and was authorized to be collected
January through September 2001. A September 2000 compliance filing showed the
actual under-recovery for June 2000 through August 2000 to be $93.7 million. The
remaining under-recovery amount of $28.6 was carried forward into a January 2001
filing.
In January 2001 CPL filed with the PUCT an application to implement an increase
in fuel factors of $175.9 million, effective with the March 2001 billing month
over the ten months March 2001 through December 2001. Additionally, CPL proposed
to implement an interim fuel surcharge of $51.8 million, including accumulated
interest, over a nine-month period beginning in April 2001 to collect its
under-recovered fuel costs. Approval by the PUCT is pending.
SWEPCo Fuel Filings - In November 2000 SWEPCo filed with the PUCT an application
for authority to implement an increase in fuel factor revenues effective with
the January 2001 billing month. SWEPCo also proposed to implement an interim
fuel surcharge to collect its under-recovered fuel costs, including accumulated
interest, over a six-month period beginning in January 2001.
In January 2001 the PUCT approved SWEPCo's application. The order allows an
increase in fuel factors of $12 million on an annual basis including accumulated
interest beginning in January 2001 and a surcharge of $11.8 million for the
billing months of February through July 2001.
In June 2000 SWEPCo filed with the PUCT an application for authority to
reconcile fuel costs and to request authorization to carry the unrecovered
balance forward into the next reconciliation period. During the reconciliation
period of January 1, 1997 through December 31, 1999, SWEPCo incurred $347
million of Texas jurisdiction eligible fuel and fuel-related expenses.
On December 27, 2000, SWEPCo reached a settlement. The settlement resulted in a
reduction of $2.25 million of eligible Texas jurisdictional fuel expense, which
was prorated equally over thirty-six months of the reconciliation period. The
settlement also provides that depreciation and lease expense associated with new
aluminum railcars will qualify for treatment as eligible fuel expense from
January 1, 2000 forward. Parties to the settlement will support SWEPCo in
seeking to amend its 1999 excess earnings report to include 1999 railcar
depreciation expense in the depreciation component of the calculation. In
February 2001, the PUCT approved the settlement, which did not have a material
effect on SWEPCo's results of operations.
WTU Fuel Filings - In August 2000 WTU filed with the PUCT an application for
authority to implement an increase in fuel factors effective with the October
2000 billing month. WTU also proposed to implement an interim fuel surcharge to
collect its under-recovered fuel costs from August 1, 1999 through June 30, 2000
including accumulated interest, over a six-month period beginning in November
2000.
In December 2000, the PUCT approved WTU's application. The order allows an
increase in fuel factors of $42.6 million on an annual basis including
accumulated interest and provides for a surcharge of $19.6 million for
previously under-recovered fuel costs.
In January 2001 WTU filed with the PUCT an application for authority to
implement an increase in fuel factor revenues of $46.5 million effective with
the March 2001 billing. Approval by the PUCT is pending.
In December 2000 WTU filed with the PUCT an application for authority to
reconcile fuel costs. During the reconciliation period of July 1, 1997 through
June 30, 2000, WTU incurred $348 million of Texas jurisdiction eligible fuel and
fuel-related expenses. Approval by the PUCT is pending.
OPCo's Recovery of Fuel Costs - Pursuant to PUCO - approved stipulation
agreements the cost of coal burned at the Gavin Plant was subject to a 15-year
predetermined price of $1.575 per million Btu's with quarterly escalation
adjustments through November 2009. To the extent the actual cost of coal burned
at the Gavin Plant was below the predetermined prices, the stipulation agreement
provided OPCo with the opportunity to recover over its term the Ohio
jurisdictional share of OPCo's investment in and the liabilities and future
shutdown costs of its affiliated mines as well as any fuel costs incurred above
the pre-determined rate and deferred for future recovery under the agreements.
As a result of the Ohio Act introducing customer choice and a transition to
market based pricing for electricity supply in Ohio, these stipulation
agreements were superseded effective January 1, 2001. OPCo filed under the
provisions of the Ohio Act for recovery of all of its generation related
regulatory assets including fuel costs deferred under these predetermined price
stipulation agreements. Under the terms of OPCo's PUCO-approved stipulated
transition plan, recovery of generation-related regulatory assets at December
31, 2000, which were $518 million, over seven years was approved.
The Muskingum coal strip mine and Windsor deep coal mine which supplied all of
their output to OPCo have been closed. Efforts are underway to reclaim the
properties, sell or scrap all mining equipment, terminate both capital and
operating leases and perform other activities necessary to reclaim the mines.
Mine reclamation activities should be completed within two to three years;
postremediation monitoring is anticipated to continue for five years after
completion of reclamation.
OPCo currently plans to close the Meigs deep coal mine by the end of 2001 unless
ongoing efforts to sell it are successful. Currently efforts are being made to
sell the active Meigs and shutdown Windsor and Muskingum mines.
FERC - The FERC issued orders 888 and 889 in April 1996 which required 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, and to
pay their own transmission service 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. The FERC 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 an Open Access Transmission
Tariff conforming with the FERC's pro-forma transmission tariff, subject to the
resolution of certain pricing issues. The 1996 tariff incorporated transmission
rates which were the result of a settlement of a pending rate case, but which
were being collected subject to refund from certain customers who opposed the
settlement and continued to litigate the reasonableness of AEP's transmission
rates. On July 30, 1999, the FERC issued an order in the litigated rate case
that would reduce AEP's rates for the affected customers below the settlement
rate. AEP and certain of the affected customers sought rehearing of the
Commission's Order.
On December 10, 1999, AEP filed a settlement agreement with the FERC resolving
the issues on rehearing of the July 30, 1999 order. On March 16, 2000, the FERC
approved the settlement agreement. Under terms of the settlement, the AEP System
is required to make refunds retroactive to September 7, 1993 to certain
customers affected by the July 30, 1999 FERC order. The refunds were made in two
payments. Pursuant to FERC orders the first payment was made in February 2000
and the second payment was made on August 1, 2000. APCo, CSPCo, I&M, KPCo, and
OPCo recorded provisions in 1999 and 2000 for the earnings impact of the
required refunds including interest.
The settlement agreement also reduced the rates for transmission service. A new
lower rate of $1.55 kw/month was made effective January 1, 2000, for all
transmission service customers. Also as agreed, a new rate of $1.42 kw/month
took effect on June 16, 2000 upon consummation of the AEP/CSW merger. Prior to
January 1, 2000, the rate was $2.04 kw/month. Unless the market volume of
physical power transactions grows to increase the utilization of the AEP
System's transmission lines, the new open access transmission rate will
adversely impact future results of operations and cash flows. Since the rate has
been reduced the volume of transmission usage has increased on the AEP System
mainly due to increased competition in the wholesale electricity market.
West Virginia
On May 12, 1999, APCo, an AEP subsidiary doing business in WV, filed with the
WVPSC for a base rate increase of $50 million annually and a reduction in ENEC
rates of $38 million annually. On February 7, 2000, APCo and other parties to
the proceeding filed a Joint Stipulation with the WVPSC for approval.
The Joint Stipulation's main provisions include no change in either base or ENEC
rates effective January 1, 2000 from those base and ENEC rates in effect from
November 1, 1996 until December 31, 1999 (these rates provide for recovery of
regulatory assets including any generation-related regulatory assets through
frozen transition rates and a wires charge of 0.5 mills per KWH); the continued
suspension of annual ENEC recovery proceedings and cessation of existing
deferral accounting for all over or under recovery of fuel and purchased power
costs net of system sales effective January 1, 2000; and the retention, as a
regulatory liability, on the books of a net cumulative deferred ENEC
overrecovery balance of $66 million as established by a WVPSC order on December
27, 1996. The Joint Stipulation also provides that when deregulation of
generation occurs in WV, APCo will use this retained regulatory liability to
reduce generation-related regulatory assets and, to the extent possible, any
additional costs or obligations that restructuring and deregulation of APCo's
generation business may impose. The elimination of ENEC recovery proceedings in
WV will subject AEP and APCo to the risk of fuel market price increases and
reductions in wholesale sales levels which could adversely affect results of
operations and cash flows.
Also, under the Joint Stipulation, APCo's share of any net savings from the
merger between AEP and CSW prior to December 31, 2004 shall be retained by APCo.
As a result, all costs incurred in the merger that were allocated to APCo shall
be fully charged to expense to partially offset merger savings through December
31, 2004 and shall not be included in any WV rate proceeding after that date.
After December 31, 2004, current distribution savings related to the merger will
be reflected in rates in any future rate proceeding before the WVPSC to
establish distribution rates or to adjust rate caps during the transition to
market based generation rates. When deregulation of generation occurs in WV, the
net retained generation-related merger savings shall be used to recover any
generation-related regulatory assets that are not recovered under the other
provisions of the Joint Stipulation and the mechanisms provided for in the
deregulation legislation and, to the extent possible, to recover any additional
costs or obligations that deregulation may impose on APCo. Regardless of whether
the net cumulative deferred ENEC overrecovery balance and the net merger savings
are sufficient to offset all of APCo's generation-related regulatory assets,
under the terms of the Joint Stipulation there will be no further explicit
adjustment to APCo's rates to provide for recovery of generation-related
regulatory assets beyond the above discussed specific adjustment provisions in
the Joint Stipulation and the 0.5 mills per KWH wires charge in the WV
Restructuring Plan (see Note 7 "Industry Restructuring" for discussion of WV
Restructuring Plan). On June 2, 2000, the WVPSC issued an order approving the
Joint Stipulation. Management expects that the stipulation agreement plus the
provisions of pending restructuring legislation will, if the legislation becomes
effective, provide for the recovery of existing regulatory assets, other
stranded costs and the cost of such deregulation in WV.
6. Effects of Regulation:
In accordance with SFAS 71 the consolidated financial statements include
regulatory assets (deferred expenses) and regulatory liabilities (deferred
revenues) recorded in accordance with regulatory actions in order to match
expenses and revenues from cost-based rates in the same accounting period.
Regulatory assets are expected to be recovered in future periods through the
rate-making process and regulatory liabilities are expected to reduce future
cost recoveries. Among other things, application of SFAS 71 requires that the
AEP System's regulated rates be cost-based and the recovery of regulatory assets
probable. Management has reviewed all the evidence currently available and
concluded that the requirements to apply SFAS 71 continue to be met for all
electric operations in Indiana, Kentucky, Louisiana, Michigan, Oklahoma and
Tennessee.
When the generation portion of the business in Arkansas, Ohio, Texas, Virginia
and WV no longer met the requirements to apply SFAS 71, net regulatory assets
were written off for that portion of the business unless they were determined to
be recoverable as a stranded cost through regulated distribution rates or wire
charges in accordance with SFAS 101 "Regulated Enterprises - Accounting for the
Discontinuation of FASB Statement No. 71" and EITF 97-4 "Deregulation of the
Pricing of Electricity - Issues Related to the Application of FASB No. 71,
Accounting for the Effects of Certain Types of Regulation, and No. 101,
Regulated Enterprises - Accounting for the Discontinuation of the Application of
FASB Statement No. 71." In the Ohio, Virginia and WV jurisdictions the
generation-related regulated assets that are recoverable through transition
rates have been transferred to the distribution portion of the business and are
being amortized as they are recovered through charges to regulated distribution
customers. In the Texas jurisdiction generation-related regulatory assets that
have been tentatively approved for recovery through securitization have been
classified as "regulatory assets designated for securitization." (See Note 7
"Industry Restructuring" for further details.)
AEP's recognized regulatory assets and liabilities are comprised of the
following at:
December 31,
2000 1999
(in millions)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $ 914 $1,450
Transition - Regulatory
Assets 963 -
Regulatory Assets
Designated for
Securitization 953 953
Deferred Fuel Costs 407 477
Unamortized Loss on
Reacquired Debt 113 154
Cook Plant Restart Costs 120 160
DOE Decontamination and
Decommissioning
Assessment 35 39
Other 193 231
------ ------
Total Regulatory Assets $3,698 $3,464
====== ======
Regulatory Liabilities:
Deferred Investment
Tax Credits $528 $580
Other 208 315
---- ----
Total Regulatory Liabilities $736 $895
==== ====
The recognized regulatory assets and liabilities for the registrant
subsidiaries are comprised of the following at:
AEGCo APCo CPL CSPCo I&M
---------------------------------------------------------
December 31, 2000 (in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $217,540 $ 206,930 $ 31,853 $229,466
Transition - Regulatory Assets 191,469 247,852
Excess Earnings (39,700)
Regulatory Assets Designated
For Securitization 953,249
Deferred Fuel Costs 14,669 127,295 112,503
Unamortized Loss on
Reacquired Debt $5,504 11,676 12,773 8,340 17,740
Deferred Storm Damage 1,244
Cook Plant Restart Costs 120,000
DOE Decontamination and
Decommissioning Assessment 3,622 31,744
Other 11,152 18,815 3,508 40,687
------ -------- ---------- -------- --------
Total Regulatory Assets $5,504 $447,750 $1,282,984 $291,553 $552,140
====== ======== ========== ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $59,718 $ 43,093 $128,100 $41,234 $113,773
Amounts Due To Customers
For Future Income Taxes 23,996
WV Rate Stabilization 75,601
Other 2,614 11,510 9,930
------- -------- -------- ------- --------
Total Regulatory Liabilities $83,714 $121,308 $128,100 $52,744 $123,703
======= ======== ======== ======= ========
KPCo OPCo PSO SWEPCo WTU
------------------------------------------------------
December 31, 2000 (in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $85,926 $180,602 $14,558
Transition - Regulatory Assets 517,851
Deferred Fuel Costs $43,267 35,469 $67,655
Unamortized Loss on
Reacquired Debt 459 6,106 13,600 22,626 11,204
Other 12,130 10,151 15,738 19,898 13,604
------- -------- ------- ------- -------
Total Regulatory Assets $98,515 $714,710 $72,605 $92,551 $92,463
======= ======== ======= ======= =======
Regulatory Liabilities:
Deferred Investment
Tax Credits $11,656 $25,214 $35,783 $53,167 $24,052
Excess Earnings 500 15,100
Amounts Due To Customers
For Future Income Taxes 28,652 13,493
Other 3,172 10,994 2,015 8,140
------- ------- ------- ------- --------
Total Regulatory Liabilities $14,828 $36,208 $66,450 $61,807 $52,645
======= ======= ======= ======= =======
AEGCo APCo CPL CSPCo I&M
------------------------------------------------------
December 31, 1999 (in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $389,922 $212,364 $243,031 $236,783
Excess Earnings (18,400)
Regulatory Assets -
Designated For Securitization 953,249
Deferred Fuel Costs 30,423 150,004
Unamortized Loss on
Reacquired Debt $5,744 20,828 13,983 23,307 14,780
Deferred Zimmer Plant
Carrying Charges 42,826
Deferred Storm Damage 6,619
Cook Plant Restart Costs 160,000
DOE Decontamination and
Decommissioning Assessment 4,022 35,238
Other 19,525 11,390 29,939 28,005
------ -------- ---------- -------- --------
Total Regulatory Assets $5,744 $436,894 $1,207,031 $339,103 $624,810
====== ======== ========== ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $63,114 $ 57,259 $ 133,306 $ 44,716 $121,627
Amounts Due To Customers
For Future Income Taxes 26,266
50% Share - Net WV ENEC 36,589
Over Recovery - Fuel Costs 34,676
Deferred Gains From Emission
Allowance Sales 1,867 13,539
Other 7,180 24,082 17,238
------- -------- --------- -------- --------
Total Regulatory Liabilities $89,380 $137,571 $ 133,306 $ 82,337 $138,865
======= ======== ========= ======== ========
KPCo OPCo PSO SWEPCo WTU
-----------------------------------------------------
December 31, 1999 (in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $88,764 $331,164 $ 7,128
Deferred Fuel Costs 197,631 $6,469 $14,652
Unamortized Loss on
Reacquired Debt 711 15,666 14,880 25,539 14,700
Other 6,821 49,924 1,837 14,513 15,045
------- -------- ------- ------- -------
Total Regulatory Assets $96,296 $594,385 $23,186 $47,180 $44,397
======= ======== ======= ======= =======
Regulatory Liabilities:
Deferred Investment
Tax Credits $12,908 $ 35,838 $37,574 $57,649 $25,323
Excess Earnings 6,500 6,000
Amounts Due To Customers
For Future Income Taxes 32,826 13,146
Deferred Gains From Emission
Allowance Sales 53,738
Other 2,792 13,043 2,480
------- -------- ------- ------- -------
Total Regulatory Liabilities $15,700 $102,619 $70,400 $66,629 $44,469
======= ======== ======= ======= =======
7. Industry Restructuring:
Restructuring legislation has been enacted in seven of the eleven state retail
jurisdictions in which AEP's domestic electric utility companies operate. The
legislation provides for a transition from cost-based regulation of bundled
electric service to unbundled cost-based rate regulation of transmission and
distribution service and customer choice market pricing for the supply of
electricity. The enactment of restructuring legislation and the ability to
determine transition rates, wires charges and any resultant extraordinary gain
or loss under restructuring legislation enabled APCo, CPL, CSPCo, OPCo, SWEPCo
and WTU to discontinue regulatory accounting for the generation portion of their
business in those jurisdictions. Prior to restructuring, the electric utility
companies accounted for their operations according to the cost-based regulatory
accounting principles of SFAS 71. Under the provisions of SFAS 71, regulatory
assets and regulatory liabilities are recorded to reflect the economic effects
of regulation to account for the difference between regulatory accounting and
GAAP and to match expenses with regulated revenues. The discontinuance of the
application of SFAS 71 is in accordance with the provisions of SFAS 101.
Pursuant to those provisions and further guidance provided in EITF Issue 97-4, a
company is required to write-off regulatory assets and liabilities related to
the deregulated operations, unless recovery of such amounts is provided through
cost-based regulated rates to be collected in the portion of operations which
continues to be rate regulated. Additionally, a company experiencing a
discontinuance of cost-based rate regulation is required to determine if any
plant assets are impaired under SFAS 121. A SFAS 121 accounting impairment
analysis involves estimating cumulative future non-discounted net cash flows
arising from the use of assets. If the cumulative undiscounted net cash flows
exceed the net book value of the assets,
then there is no impairment of the assets for accounting purposes. If there is
any accounting impairment, it would be recorded on a discounted basis.
As legislative and regulatory proceedings evolve, the electric operating
companies doing business in the seven states that have passed restructuring
legislation are applying the standards discussed above to discontinue SFAS 71
regulatory accounting. The following is a summary of the restructuring
legislation, the status of the transition plans and the status of the electric
utility operating companies' accounting to comply with the changes in each of
the seven state regulatory jurisdictions affected by restructuring legislation.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001, customer choice of electricity supplier began under
the Ohio Act. In February 2001, one supplier announced its plan to offer service
to CSPCo's residential customers. Currently for residential customers of OPCo,
no alternative suppliers have registered with the PUCO as required by the Ohio
Act. Two alternative suppliers have been approved to compete for CSPCo's and
OPCo's commercial and industrial customers. Presently, customers continue to be
served by CSPCo and OPCo with a legislatively required residential rate
reduction of 5% for the generation portion of rates and a freezing of generation
rates including fuel rates starting on January 1, 2001.
The Ohio Act provides for a five-year transition period to move from cost based
rates to market pricing for generation services. It granted the PUCO broad
oversight responsibility for promul-gation of rules for competitive retail
electric generation service, approval of a transition plan for each electric
utility company and addressing certain major transition issues including
unbund-ling of rates and the recovery of stranded costs including regulatory
assets and transition costs.
The Ohio Act also provides for a reduction in property tax assessments, the
imposition of replacement franchise and income taxes, and the replacement of a
gross receipts tax with a KWH based excise tax. The property tax assessment
percentage on generation property was lowered from 100% to 25% of value
effective January 1, 2001 and Ohio electric utilities will become subject to the
Ohio Corporate Franchise Tax and municipal income taxes on January 1, 2002. The
last year for which Ohio electric utilities will pay the excise tax based on
gross receipts is the tax year ending April 30, 2002. As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on KWH sold to
Ohio customers. The gross receipts tax is paid at the beginning of the tax year
(May 1), deferred by CSPCo and OPCo as a prepaid expense and amortized to
expense during the tax year pursuant to the tax law whereby the payment of the
tax results in the privilege to conduct business in the year following the
payment of the tax. As a result a duplicate tax will be expensed from May 1,
2001 through April 30, 2002 adding approximately $90 million ($40 million for
CSPCo and $50 million for OPCo) to tax expense during that period. Unless CSPCo
and OPCo can recover the duplicate amount from ratepayers it will negatively
impact results of operations.
On September 28, 2000, the PUCO approved, with minor modifications, a
stipulation agreement between CSPCo, OPCo, the PUCO staff, the Ohio Consumers'
Counsel and other concerned parties regarding transition plans filed by CSPCo
and OPCo. The key provisions of this stipulation agreement are:
o Recovery of generation-related regulatory assets at December 31, 2000 over
seven years for OPCo ($518 million) and over eight years for CSPCo ($248
million) through frozen transition rates for the first five years of the
recovery period and a wires charge for the remaining years.
o A shopping incentive (a price credit) of 2.5 mills per KWH for the first
25% of CSPCo residential customers that switch suppliers. There is no
shopping incentive for OPCo customers.
o The absorption of $40 million by CSPCo and OPCo ($20 million per company)
of consumer education, implementation and transition plan filing costs with
deferral of the remaining costs, plus a carrying charge, as a regulatory
asset for recovery in future distribution rates.
o CSPCo and OPCo will make available a fund of up to $10 million to reimburse
customers who choose to purchase their power from another company for
certain transmission charges imposed by PJM and/or a Midwest ISO on
generation originating in the Midwest ISO or PJM areas.
o The statutory 5% reduction in the generation component of residential
tariffs will remain in effect for the entire five year transition period.
o CSPCo's and OPCo's request for a $90 million gross receipts tax rider to
recover the duplicate gross receipts KWH based excise tax would be
considered separately by the PUCO.
The approved stipulation agreement also accepted the following provisions
contained in CSPCo's and OPCo's filed transition plans:
o a corporate separation plan to segregate generation, transmission and
distribution assets into separate legal entities, and o a plan for independent
operation of transmission facilities.
The gross receipts tax issue was considered by the PUCO in hearings held in June
2000. In the September 28, 2000 order approving the stipulation agreement, the
PUCO determined that there was no duplicate tax overlap period and denied the
request for a $90 million gross receipts tax rider. CSPCo's and OPCo's request
for rehearing of the gross receipts tax issue was denied. An appeal of this
issue to the Ohio Supreme Court has been filed. Unless this issue is resolved in
CSPCo's and OPCo's favor, it will have an adverse effect on future results of
operations and financial position.
One of the intervenors at the hearings for approval of the settlement agreement
(whose request for rehearing was denied by the PUCO) has filed with the Ohio
Supreme Court for review of the settlement agreement including recovery of
regulatory assets. Management is unable to predict the outcome of litigation but
the resolution of this matter could negatively impact results of operation.
Beginning January 1, 2001, CSPCo's and OPCo's fuel costs will not be subject to
PUCO fuel recovery proceedings. Deferred fuel costs at December 31, 2000 which
represent under or over recoveries were one of the items included in the PUCO's
final determination of net regulatory assets to be collected (recovered) during
the transition period. The elimination of fuel clause recoveries in 2001 in Ohio
will subject AEP, CSPCo and OPCo to the risk of fuel market price increases and
could adversely affect their future results of operations and cash flows.
CSPCo and OPCo Discontinue Application of SFAS 71 Regulatory Accounting for the
Ohio Jurisdiction
In September 2000 CSPCo and OPCo discontinued the application of SFAS 71 for
their Ohio retail jurisdictional generation business since generation is no
longer cost-based regulated in the Ohio jurisdiction and management was able to
determine their transition rates and wires charges. The discontinuance in the
Ohio jurisdiction was possible as a result of the PUCO's September 28, 2000
approval of the stipulation agreement which established rates, wires charges and
net regulatory asset recovery procedures during the transition to market rates.
CSPCo's and OPCo's discontinuance of SFAS 71 for generation resulted in after
tax extraordinary losses in the third quarter of 2000 of $25 million and $19
million, respectively, due to certain unrecoverable generation-related
regulatory assets and transition expenses. Management believes that
substantially all of the remaining net regulatory assets related to the Ohio
generation business will be recovered under the PUCO's September 28, 2000 order.
Therefore, under the provisions of EITF 97-4, CSPCo's and OPCo's
generation-related recoverable net regulatory assets were transferred to the
transmission and distribution portion of the business and will be amortized as
they are recovered through transition rates to customers. CSPCo and OPCo
performed an accounting impairment analysis on their generating assets under
SFAS 121 as required when discontinuing the application of SFAS 71 and concluded
there was no impairment of generation assets.
Virginia - Affecting AEP and APCo
In Virginia, a restructuring law provides for a transition to choice of
electricity supplier for retail customers beginning on January 1, 2002. In
February 2001 restructuring revision legislation was approved by the Virginia
Legislature which could modify the terms of restructuring. Presently, the
transition period is to be completed, subject to a finding by the Virginia SCC
that an effective competitive market exists by January 1, 2004 but no later than
January 1, 2005.
The restructuring law also provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
net stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the termination
of the rate cap. The restructuring law provides for the establishment of capped
rates prior to January 1, 2001 based either on a request by APCo for a change in
rates prior to January 1, 2001 or on the rates in effect at July 1, 1999 if no
rate change request is made and the establishment of a wires charge by the
fourth quarter of 2001. APCo did not request new rates; therefore, its current
rates are the capped rates. In the third quarter of 2000, the Virginia SCC
directed APCo to file a cost of service study using 1999 as a test year to
review the reasonableness of APCo's capped rates. The cost of service study was
filed on January 3, 2001. In the opinion of APCo's Virginia counsel, Virginia's
restructuring law does not permit the Virginia SCC to change rates for the
transition period except for changes in the fuel factor, changes in state gross
receipts taxes, or to address the utility's financial distress. However, if the
Virginia SCC were to reduce APCo's capped rates or deny recovery of regulatory
assets, it would adversely affect results of operations if such action is
ultimately determined to be legal.
The Virginia restructuring law also requires filings to be made that outline the
functional separation of generation from transmission and distribution and a
rate unbundling plan. On January 3, 2001, APCo filed its corporate separation
plan and rate unbundling plan with the Virginia SCC which is based on the most
recent rate case test year (1996). See the heading "Structural Separation" below
in this footnote for a discussion of AEP's corporate separation plan filed with
the SEC.
West Virginia - Affecting AEP and APCo
On January 28, 2000, the WVPSC issued an order approving an electricity
restructuring plan for WV. On March 11, 2000, the WV Legislature approved the
restructuring plan by joint resolution. The joint resolution provides that the
WVPSC cannot implement the plan until the legislature makes necessary tax law
changes to preserve the revenues of the state and local governments. The Joint
Committee on Government and Finance of the WV Legislature hired a consultant to
study and issue a report on the tax changes required to implement electric
restructuring. Moreover, the committee also hired a consultant to study and
issue a report on the electric restructuring plan in light of events occurring
in California. The WV Legislature is not expected to consider these reports
until the 2002 Legislative Session since the 2001 Legislative Session ends in
April 2001. Since the WV Legislature has not yet passed the required tax law
changes, the restructuring plan has not become effective. AEP subsidiaries, APCo
and WPCo, provide electric service in WV.
The provisions of the restructuring plan provide for customer choice to begin
after all necessary rules are in place (the "starting date"); deregulation of
generation assets on the starting date; functional separation of the generation,
transmission and distribution businesses on the starting date and their legal
corporate separation no later than January 1, 2005; a transition period of up to
13 years, during which the incumbent utility must provide default service for
customers who do not change suppliers unless an alternative default supplier is
selected through a WVPSC-sponsored bidding process; capped and fixed rates for
the 13 year transition period as discussed below; deregulation of metering and
billing; a 0.5 mills per KWH wires charge applicable to all retail customers for
a 10-year period commencing with the starting date intended to provide for
recovery of any stranded cost including net regulatory assets; establishment of
a rate stabilization deferred liability balance of $81 million ($76 million by
APCo and $5 million by WPCo) by the end of year ten of the transition period to
be used as determined by the WVPSC to offset market prices paid in the eleventh,
twelfth, and thirteenth year of the transition period by residential and small
commercial customers that do not choose an alternative supplier.
Default rates for residential and small commercial customers are capped for four
years after the starting date and then increase as specified in the plan for the
next six years. In years eleven, twelve and thirteen of the transition period,
the power supply rate shall equal the market price of comparable power. Default
rates for industrial and large commercial customers are discounted by 1% for
four and a half years, beginning July 1, 2000, and then increased at pre-defined
levels for the next three years. After seven years the power supply rate for
industrial and large commercial customers will be market based. APCo's Joint
Stipulation agreement, discussed in Note 5 "Rate Matters", which was approved by
the WVPSC on June 2, 2000 in connection with a base rate filing, also provides
additional mechanisms to recover regulatory assets.
APCo Discontinues Application of SFAS 71 Regulatory Accounting
In June 2000 APCo discontinued the application of SFAS 71 for its Virginia and
WV retail jurisdictional portions of its generation business since generation is
no longer considered to be cost-based regulated in those jurisdictions and
management was able to determine APCo's transition rates and wires charges. The
discontinuance in the WV jurisdiction was made possible by the June 2, 2000
approval of the Joint Stipulation which established rates, wires charges and
regulatory asset recovery procedures for the transition period to market rates
which was determined to be probable. APCo was also able to discontinue
application of SFAS 71 for the generation portion of its Virginia retail
jurisdiction after management decided that APCo would not request capped rates
different from its current rates. The existence of effective restructuring
legislation in Virginia and the probability that the WV legislation would become
effective with the expected probable passage of required enabling tax
legislation in 2001 supported management's decision in 2000 to discontinue SFAS
71 regulatory accounting for APCo's electricity generation and supply business.
APCo's discontinuance of SFAS 71 for generation resulted in an after tax
extraordinary gain, in the second quarter of 2000, of $9 million. Management
believes that it is probable that substantially all net regulatory assets
related to the Virginia and WV generation business will be recovered. Therefore,
under the provisions of EITF 97-4, APCo's generation-related net regulatory
assets were transferred to the distribution portion of the business and are
being amortized as they are recovered through charges to regulated distribution
customers. As required by SFAS 101 when discontinuing SFAS 71 regulatory
accounting, APCo performed an accounting impairment analysis on its generating
assets under SFAS 121 and concluded that there was no accounting impairment of
generation assets.
The studies requested by the WV Legislature, discussed above, could result in
the WV Legislature deciding not to enact the required tax changes, thereby,
effectively continuing cost based rate regulation in West Virginia or it could
modify the restructuring plan. Modifications in the restructuring plan could
adversely affect future results of operations if they were to occur. Management
is carefully monitoring the situation in West Virginia and continues to work
with all concerned parties to get approval to successfully transition APCo's
generation business in West Virginia. Failure to pass the required enabling tax
changes could ultimately require APCo to reinstate regulatory accounting
principles under SFAS 71 for its generation operations in West Virginia.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 legislation was enacted in Arkansas that will ultimately restructure the
electric utility industry. Its major provisions are:
o retail competition begins January 1, 2002 but can be delayed until as late as
June 30, 2003 by the Arkansas Commission; o transmission facilities must be
operated by an ISO if owned by a company which also owns generation assets; o
rates will be frozen for one to three years; o market power issues will be
addressed by the Arkansas Commission; and o an annual progress report to the
Arkansas General Assembly on the development of competition in electric markets
and its
impact on retail customers is required.
In November 2000 the Arkansas Commission filed its annual progress report with
the Arkansas General Assembly recommending a delay in the start date of retail
competition to a date between October 1, 2003 and October 1, 2005. The report
also asks the Arkansas General Assembly to delegate authority to the Arkansas
Commission to determine the appropriate retail competition start date within the
approved time frame. In February 2001 the Arkansas General Assembly passed
legislation that was signed into law by the Governor that changes the date of
electric retail competition to October 1, 2003, and provided the Arkansas
Commission with the authority to delay that date for up to two years.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
In June 1999 Texas restructuring legislation was signed into law which, among
other things:
o gives Texas customers of investor-owned utilities the opportunity to
choose their electricity provider beginning January 1, 2002;
o provides for the recovery of regulatory assets and of other stranded
costs through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o provides for a rate freeze until January 1, 2002 followed by a 6%
rate reduction for residential and small commercial customers and
a number of customer protections;
o provides for an earnings test for each of the three years of the rate
freeze period (1999 through 2001) which will reduce stranded cost
recoveries or if there is no stranded cost provides for a refund or their
use to fund certain capital expenditures in the amount of the excess
earnings;
o requires each utility to structurally unbundle into a retail
electric provider, a power generation company and a
transmission and distribution utility;
o provides for certain limits for ownership and control of generating
capacity by companies;
o provides for elimination of the fuel clause reconciliation
process beginning January 1, 2002; and
o provides for a 2004 true-up proceeding to determine recovery of stranded
costs including final fuel recovery balances, net regulatory assets,
certain environmental costs, accumulated excess earnings and other issues.
Under the Texas Legislation, delivery of electricity will continue to be the
responsibility of the local electric transmission and distribution utility
company at regulated prices. Each electric utility was required to submit a plan
to structurally unbundle its business activities into a retail electric
provider, a power generation company, and a transmission and distribution
utility. In May 2000 CPL, SWEPCo and WTU filed a revised business separation
plan that the PUCT approved on July 7, 2000 in an interim order. The revised
business separation plans provided for CPL and WTU, which operate in Texas only,
to establish separate companies and divide their integrated utility operations
and assets into a power generation company, a transmission and distribution
utility and a retail electric provider. SWEPCo will separate its Texas
jurisdictional transmission and distribution assets and operations into a new
Texas regulated transmission and distribution subsidiary. In addition, a retail
electric provider will be formed by SWEPCo to provide retail electric service to
SWEPCo's Texas jurisdictional customers.
Under the Texas Legislation, electric utilities are allowed, with the approval
of the PUCT, to recover stranded generation costs including generation-related
regulatory assets that may not be recoverable in a future competitive market.
The approved stranded costs can be refinanced through securitization, which is a
financing structure designed to provide lower financing costs than are available
through conventional financings. Lower financing costs are achieved through the
issuance of securitization bonds at a lower interest rate to finance 100% of the
costs pursuant to a state pledge to ensure recovery of the bond principal and
financing costs through a non-bypassable rate surcharge by the regulated
transmission and distribution utility over the life of the securitization bonds.
In 1999 CPL filed an application with the PUCT to securitize approximately $1.27
billion of its retail generation-related regulatory assets and approximately $47
million in other qualified restructuring costs. On March 27, 2000, the PUCT
issued an order permitting CPL to securitize approximately $764 million of net
regulatory assets. The PUCT's order authorized issuance of up to $797 million of
securitization bonds including the $764 million for recovery of net
generation-related regulatory assets and $33 million for other qualified
refinancing costs. The $764 million for recovery of net generation-related
regulatory assets reflects the recovery of $949 million of generation-related
regulatory assets offset by $185 million of customer benefits associated with
accumulated deferred income taxes. CPL had previously proposed in its filing to
flow these benefits back to customers over the 14-year term of the
securitization bonds. On April 11, 2000, four parties appealed the PUCT's
securitization order to the Travis County District Court. In July 2000 the
Travis County District Court upheld the PUCT's securitization order. The
securitization order is being appealed to the Supreme Court of Texas. One of
these appeals challenges CPL's ability to recover securitization charges under
the Texas Constitution. CPL will not be able to issue the securitization bonds
until these appeals are resolved.
The remaining regulatory assets of $206 million originally included by CPL in
its 1999 securitization request were included in a March 2000 filing with the
PUCT, requesting recovery of an additional $1.1 billion of stranded costs. The
March 2000 filing of $1.1 billion included recovery of approximately $800
million of STP costs included in property, plant and equipment-electric on AEP's
Consolidated Balance Sheets and in electric utility plant-production on CPL's
Consolidated Balance Sheets. These STP costs had previously been identified as
excess cost over market (ECOM) by the PUCT for regulatory purposes and were
earning a lower return and were being amortized on an accelerated basis for
rate-making purposes in Texas. The March 2000 filing will determine the initial
amount of stranded costs in addition to the securitized regulatory assets to be
recovered beginning January 1, 2002.
CPL submitted a revised estimate of stranded costs on October 2, 2000 using
assumptions developed in generic proceedings by the PUCT and an administrative
model developed by the PUCT staff that reduced the amount of the initial
stranded cost estimate to $361 million from the $1.1 billion requested by CPL.
CPL subsequently agreed to accept adjustments proposed by intervenors that
reduced ECOM to approximately $230 million. Hearings on CPL's requested ECOM
were held in October 2000. In February 2001 the PUCT issued an interim decision
determining an initial amount of CPL ECOM or stranded costs of negative $580
million. The decision indicated that CPL's costs were below market after
securitization of regulatory assets. Management does not agree with the critical
inputs to this model. Management believes CPL has a positive stranded cost
exclusive of securitized regulatory assets. The final amount of CPL's stranded
costs including regulatory assets and ECOM will be established by the PUCT in
the legislatively required 2004 true-up proceeding. If CPL's total stranded
costs determined in the 2004 true-up are less than the amount of securitized
regulatory assets, the PUCT can implement an offsetting credit to transmission
and distribution rates.
The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would
be made to the amount of regulatory costs authorized by the PUCT to be
securitized. However, the PUCT also ruled that excess earnings for the period
1999-2001 should be refunded through transmission and distribution rates to the
extent of any over-mitigation of stranded costs represented by negative ECOM. In
the event that CPL will be required to refund excess earnings in the future
instead of applying them to reduce ECOM or regulatory assets, it will adversely
affect future cash flow but not results of operations since excess earnings for
1999 and 2000 were accrued and expensed in 1999 and 2000. The Texas Legislation
allows for several alternative methods to be used to value stranded costs in the
final 2004 true-up proceeding including the sale or exchange of generation
assets, the issuance of power generation company stock to the public or the use
of PUCT staff's ECOM model. To the extent that the final 2004 true-up proceeding
determines that CPL should recover additional stranded costs, the total amount
recoverable can be securitized.
The Texas Legislation provides that each year during the 1999 through 2001 rate
freeze period, electric utilities are subject to an earnings test. For electric
utilities with stranded costs, such as CPL, any earnings in excess of the most
recently approved cost of capital in its last rate case must be applied to
reduce stranded costs. Utilities without stranded costs, such as SWEPCo and WTU,
must either flow such excess earnings amounts back to customers or make capital
expenditures to improve transmission or distribution facilities or to improve
air quality. The Texas Legislation requires PUCT approval of the annual earnings
test calculation.
The 1999 earnings test reports filed by CPL, SWEPCo and WTU showed excess
earnings of $21 million, $1 million and zero, respectively. The PUCT staff
issued its report on the excess earnings calculations filed by CPL, SWEPCo and
WTU and calculated the excess earnings amounts to be $41 million, $3 million and
$11 million for CPL, SWEPCo and WTU, respectively. The Office of Public Utility
Counsel also filed exceptions to the companies' earnings reports. Several issues
were resolved via settlement and the remaining open issues were submitted to the
PUCT. A final order was issued by the PUCT in February 2001 and adjustments to
the accrued 1999 and 2000 excess earnings were recorded in results of operations
in the fourth quarter of 2000. After adjustments the accruals for 1999 excess
earnings for CPL and WTU were $24 million and $1 million, respectively. CPL and
WTU also recorded an estimated provision for excess 2000 earnings of $16 million
and $14 million, respectively.
A Texas settlement agreement in connection with the AEP and CSW merger permits
CPL to apply for regulatory purposes up to $20 million of STP ECOM plant assets
a year in 2000 and 2001 to reduce excess earnings, if any. For book and
financial reporting purposes, STP ECOM plant assets will be depreciated in
accordance with GAAP, on a systematic and rational basis unless impaired. CPL
will establish a regulatory liability or reduce regulatory assets by a charge to
earnings to the extent excess earnings exceed $20 million in 2000 and 2001.
Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel
reconciliation proceedings. Consequently, CPL, SWEPCo and WTU will file a final
fuel reconciliation with the PUCT to reconcile their fuel costs through the
period ending December 31, 2001. Fuel costs have been reconciled by CPL, SWEPCo
and WTU through June 30, 1998, December 31, 1999 and June 30, 1997,
respectively. WTU is currently reconciling its fuel through June 2000. See
discussion in Note 5 "Rate Matters". At December 31, 2000, CPL's, SWEPCo's and
WTU's Texas jurisdictional unrecovered deferred fuel balances were $127 million,
$20 million and $59 million, respectively. Final unrecovered deferred fuel
balances at December 31, 2001 will be included in each company's 2004 true-up
proceeding. If the final fuel balances or any amount incurred but not yet
reconciled were not recovered, they could have a negative impact on results of
operations. The elimination of the fuel clause recoveries in 2002 in Texas will
subject AEP, CPL, SWEPCo and WTU to greater risks of fuel market price increases
and could adversely affect future results of operations beginning in 2002.
The affiliated retail electric provider of CPL, SWEPCo and WTU will be required
to offer residential and small commercial customers (with a peak usage of less
than 1000 KW) a rate 6% below rates in effect on January 1, 1999 adjusted for
any changes in fuel cost recovery factors since January 1, 1999 (price to beat).
The price to beat must be offered to residential and small commercial customers
until January 1, 2007. Customers with a peak usage of more than 1000 KW are
subject to market rates. The Texas restructuring legislation provides for the
price to beat to be adjusted up to two times annually to reflect significant
changes in fuel and purchased energy costs.
Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas
and Texas
The financial statements of CPL, SWEPCo and WTU have historically reflected the
economic effects of regulation by applying the requirements of SFAS 71. As a
result of the scheduled deregulation of generation in Arkansas and Texas, the
application of SFAS 71 for the generation portion of the business in those
states was discontinued in the third quarter of 1999. Under the provisions of
EITF 97-4, CPL's generation-related net regulatory assets were transferred to
the distribution portion of the business and will be amortized as they are
recovered through wires charges to customers. Management believes that
substantially all of CPL's generation-related regulatory assets will be
recovered under the Texas Legislation. CPL's recovery of generation-related
regulatory assets and stranded costs are subject to a final determination by the
PUCT in 2004. If future events were to make the recovery through securitization
of CPL's generation-related regulatory assets no longer probable, CPL would
write-off the portion of such regulatory assets deemed unrecoverable as a
non-cash extraordinary charge to earnings.
The Texas Legislation provides that all finally determined stranded costs will
be recovered. Since SWEPCo and WTU are not expected to have net stranded costs,
all Arkansas and Texas jurisdictional generation-related net regulatory assets
were written off as non-recoverable in 1999 when SWEPCo and WTU discontinued the
application of SFAS 71 regulatory accounting. As required by SFAS 101 when SFAS
71 is discontinued, an accounting impairment analysis for generation assets
under SFAS 121 was completed for CPL, SWEPCo and WTU. The analysis showed that
there was no accounting impairment of generation assets when the application of
SFAS 71 was discontinued. CPL, SWEPCo and WTU will test their generation assets
for impairment under SFAS 121 if circumstances change. Management believes that
on a discounted basis CPL's generation business net cash flows will likely be
less than its generating assets' net book value and together with its
generation-related regulatory assets should create a recoverable stranded cost
for regulatory purposes under the Texas Legislation. Therefore, management
continues to carry on the balance sheet at December 31, 2000, $953 million of
generation-related regulatory assets already approved for securitization and
$195 million of net generation-related regulatory assets pending approval for
securitization in Texas. A final determination of whether they will be
securitized and recovered will be made as part of the 2004 true-up proceeding.
CPL, SWEPCo, and WTU continue to analyze the impact of electric utility industry
restructuring legislation on their Arkansas and Texas electric operations.
Although management believes that the Texas Legislation provides for full
recovery of stranded costs and that the companies do not have a recordable
accounting impairment, a final determination of whether CPL will experience an
accounting loss or whether SWEPCo and WTU will experience any additional
accounting loss from an inability to recover generation-related regulatory
assets and other restructuring related costs in Texas and Arkansas cannot be
made until such time as the regulatory process is complete following the 2004
true-up proceeding in Texas and a determination by the Arkansas Commission. In
the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding and
after the Arkansas Commission proceedings to recover all or a portion of their
generation-related regulatory assets, stranded costs and other restructuring
related costs, it could have a material adverse effect on results of operations,
cash flows and possibly financial condition.
Although Arkansas' delay of retail competition may be having a negative effect
on the progress of efforts to transition SWEPCo's generation in Arkansas to
market based pricing of electricity, it appears that Texas is moving forward as
planned. Management is carefully monitoring the situation in Arkansas and is
working with all concerned parties to prudently quicken the pace of the
transition. However, changes could occur due to concerns stemming from the
California energy crisis and other events which could adversely affect future
results of operations in Arkansas and possibly Texas.
Michigan Restructuring - Affecting AEP and I&M
On June 5, 2000, the Michigan Legislation became law. Its major provisions,
which were effective immediately, applied only to electric utilities with one
million or more retail customers. I&M, AEP's electric operating subsidiary doing
business in Michigan, has less than one million customers in Michigan.
Consequently, I&M was not immediately required to comply with the Michigan
Legislation.
The Michigan Legislation gives the MPSC broad power to issue orders to implement
retail customer choice of electric supplier no later than January 1, 2002
including recovery of regulatory assets and stranded costs. On October 2, 2000,
I&M filed a restructuring implementation plan as required by a MPSC order. The
plan identifies I&M's proposal to file with the MPSC on June 5, 2001 its
unbundled rates, open access tariffs, terms of service and supporting schedules.
Described in the plan are I&M's intentions and preparation for competition
related to supplier transactions, customer transactions, rate unbundling,
education programs, and regional transmission organization. The plan contains a
proposed methodology to determine stranded costs and implementation costs and
requests the continuation of a wires charge for recovery of nuclear
decommissioning costs. Approval of the restructuring implementation plan is
pending before the MPSC.
Management has concluded that as of December 31, 2000 the requirements to apply
SFAS 71 continue to be met since I&M's rates for generation in Michigan will
continue to be cost-based regulated until the MPSC approves rates and wires
charges in 2001. The establishment of rates and wires charges under a MPSC
approved transition plan will enable management to determine the ability to
recover stranded costs including regulatory assets and other implementation
costs, a requirement of EITF 97-4 to discontinue the application of SFAS 71.
Upon the discontinuance of SFAS 71, I&M will, if necessary, have to write off
its Michigan jurisdictional generation-related regulatory assets and record its
unrecorded Michigan jurisdictional liability for decommissioning the Cook Plant
to the extent that they cannot be recovered under the transition rates and wires
charges. As required by SFAS 101 when discontinuing SFAS 71 regulatory
accounting, I&M will have to perform an accounting impairment analysis under
SFAS 121 to determine if the Michigan jurisdictional portion of its generating
assets are impaired for accounting purposes.
The amount of regulatory assets recorded on the books at December 31, 2000
applicable to I&M's Michigan retail jurisdictional generation business is
approximately $45 million before related tax effects. The estimated unrecorded
liability for the Michigan jurisdiction to decommission the Cook Plant ranges
from $114 million to $215 million in 2000 non-discounted dollars based upon
studies completed during 2000. For the Michigan jurisdiction, I&M has
accumulated approximately $100 million in trust funds to decommission the Cook
Plant. Based on the current information available, management does not
anticipate that I&M will experience any material tangible asset accounting
impairment or regulatory asset write-offs. Ultimately, however, whether I&M will
experience material regulatory asset write-offs will depend on whether the MPSC
approves their recovery in future restructuring proceedings.
A determination of whether I&M will experience any asset impairment loss
regarding its Michigan retail jurisdictional generating assets and any loss from
a possible inability to recover Michigan generation-related regulatory assets,
de-commissioning obligations and transition costs cannot be made until such time
as the rates and the wires charges are determined through the regulatory
process. In the event I&M is unable to recover all or a portion of its
generation-related regulatory assets, unrecorded decommissioning obligation,
stranded costs and other implementation costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.
Oklahoma Restructuring - Affecting AEP and PSO
In 1997, the Oklahoma Legislature passed restructuring legislation providing for
retail open access by July 1, 2002. That legislation called for a number of
studies to be completed on a variety of restructuring issues, including an
independent system operator, technical, financial, transition and consumer
issues. During 1998 and 1999 several of the studies were completed.
The information from the studies was expected to be used in the development of
additional industry restructuring legislation during the 2000 legislative
session. Several additional electric industry restructuring bills were filed in
the 2000 Oklahoma legislative session. The proposed bills generally supplemented
the industry restructuring legislation previously enacted in Oklahoma which
lacked specific procedures for a transition to market based competitive prices.
The industry restructuring legislation previously passed did not delegate the
establishment of transition procedures to the Oklahoma Corporation Commission.
The 2000 Oklahoma legislative session adjourned in May without passing further
restructuring legislation.
The 2001 Oklahoma legislative session convened in early February. No further
electric restructuring legislation has passed and proposals have been made to
delay the implementation of the transition to customer choice and market based
pricing under the restructuring legislation. If the necessary legislation is not
passed, PSO's generation and retail electric supply business will remain
regulated in Oklahoma. If implementation legislation were to modify the original
restructuring legislation in Oklahoma it could have a adverse effect on results
of operations.
Management has concluded that as of December 31, 2000 the requirements to apply
SFAS 71 continue to be met since PSO's rates for generation in Oklahoma will
continue to be cost-based regulated until the Oklahoma Legislature approves
further restructuring legislation and transition rates and wires charges are
established under an approved transition plan. Until management is able to
determine the ability to recover stranded costs which includes regulatory assets
and other implementation costs, PSO cannot discontinue application of SFAS 71
accounting under GAAP.
When PSO discontinues application of SFAS 71, it will be necessary to write off
Oklahoma jurisdictional generation-related regulatory assets to the extent that
they cannot be recovered under the transition rates and wires charges, when
determined, and record any asset accounting impairments in accordance with SFAS
121.
A determination of whether PSO will experience any asset impairment loss
regarding its Oklahoma retail jurisdictional generating assets and any loss from
a possible inability to recover Oklahoma generation-related regulatory assets
and other transition costs cannot be made until such time as the rates and the
wires charges are determined through the legislative and/or regulatory process.
In the event PSO is unable to recover all or a portion of its generation-related
regulatory assets and implementation costs, Oklahoma restructuring could have a
material adverse effect on results of operations and cash flows.
Structural Separation
On November 1, 2000, AEP, AEPSC, APCo, CPL, CSPCo, OPCo, SWEPCo and WTU filed
with the SEC for approval to form two separate legal holding company
subsidiaries of AEP, the parent company. The purpose of these entities is to
legally and functionally separate the competitive market business activities and
the subsidiaries performing those competitive activities from the business
activities which are cost-based regulated and the subsidiaries that perform
those regulated activities. Corporate separation plans have also been filed with
regulatory commissions in Arkansas, Ohio, Texas and Virginia to comply with
requirements specified in their restructuring legislation. The Texas Legislation
requires separate legal entities for generation and distribution assets by
January 1, 2002. AEP, APCo, CPL, CSPCo, OPCo, SWEPCo and WTU will need approval
from the SEC under PUHCA, FERC and certain state regulatory commissions to make
these organization changes.
8. Commitments and Contingencies:
Construction and Other Commitments - The AEP System has substantial construction
commitments to support its operations. Aggregate construction expenditures for
2001-2003 for consolidated domestic and foreign operations are estimated to be
$7 billion.
The following table shows the estimated construction expenditures of the
subsidiary registrants for 2001 - 2003:
(in millions)
AEGCo $ 9.1
APCo 1,164.3
CPL 770.2
CSPCo 422.2
I&M 439.6
KPCo 215.6
OPCo 1,085.2
PSO 310.8
SWEPCo 413.1
WTU 259.3
Long-term contracts to acquire fuel for electric generation have been entered
into for various terms, the longest of which extends to the year 2014 for the
AEP System. The expiration date of the longest fuel contract for APCo is 2006,
CSPCo is 2007, I&M is 2014, KPCo is 2003, OPCo is 2012, PSO is 2014, SWEPCo is
2006 and WTU is 2006. The contracts provide for periodic price adjustments and
contain various clauses that would release the subsidiaries from their
obligations under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,174 MW of capacity
domestically on a long-term basis to unaffiliated utilities. Certain of these
contracts totaling 250 mw of capacity are unit power agreements requiring the
delivery of energy only if the unit capacity is available. The power sales
contracts expire from 2001 to 2010.
Nuclear Plants - Affecting AEP, CPL and I&M
I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by
the NRC. CPL owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on
behalf of the joint owners under licenses granted by the NRC. The operation of a
nuclear facility involves special risks, potential liabilities, and specific
regulatory and safety requirements. Should a nuclear incident occur at any
nuclear power plant facility in the U.S., the resultant liability could be
substantial. By agreement I&M and CPL are partially liable together with all
other electric utility companies that own nuclear generating units for a nuclear
power plant incident at any nuclear plant in the U.S. In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds and recovery
in rates is not possible, results of operations, cash flows and financial
condition would be adversely affected.
Nuclear Incident Liability - Affecting AEP, CPL and I&M
The Price-Anderson Act establishes insurance protection for public liability
arising from a nuclear incident at $9.5 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $200
million of coverage. In the event of a nuclear incident at any nuclear plant in
the U.S. the remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor in the U.S. payable in annual
installments of $10 million. As a result, I&M could be assessed $176 million per
nuclear incident payable in annual installments of $20 million. CPL could be
assessed $44 million per nuclear incident payable in annual installments of $5
million as its share of a STPNOC assessment. The number of incidents for which
payments could be required is not limited.
Insurance coverage for property damage, decommissioning and decontamination at
the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8
billion each. Cook Plant and STPNOC jointly purchase $1 billion of excess
coverage for property damage, de-commissioning and decontamination. Additional
insurance provides coverage for extra costs resulting from a prolonged
accidental outage.
SNF Disposal - Affecting AEP, CPL, and I&M
Federal law provides for government responsibility for permanent SNF disposal
and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per
KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being
collected from customers and remitted to the U.S. Treasury. Fees and related
interest of $211 million for fuel consumed prior to April 7, 1983 at Cook Plant
have been recorded as long-term debt. I&M has not paid the government the Cook
Plant related pre-April 1983 fees due to continued delays and uncertainties
related to the federal disposal program. At December 31, 2000, funds collected
from customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and approximate the liability. CPL is not liable
for any assessments for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.
Decommissioning and Low Level Waste Accumulation Disposal - Affecting AEP, CPL
and I&M
Decommissioning costs are accrued over the service lives of the Cook Plant and
STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014
and 2017. After expiration of the licenses, Cook Plant is expected to be
decommissioned through dismantlement. The estimated cost of decommissioning and
low level radioactive waste accumulation disposal costs for Cook Plant ranges
from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide
range is caused by variables in assumptions including the estimated length of
time SNF may need to be stored at the plant site subsequent to ceasing
operations. This, in turn, depends on future developments in the federal
government's SNF disposal program. Continued delays in the federal fuel disposal
program can result in increased decommissioning costs. I&M is re-covering
estimated Cook Plant decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The amount
recovered in rates for decommissioning the Cook Plant and deposited in the
external fund was $28 million in 2000, $28 million in 1999 and $29 million in
1998.
The licenses to operate the two nuclear units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
decontamination method. CPL estimates its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. CPL is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of $8 million per year.
Decommissioning costs recovered from customers are deposited in external trusts.
In 2000 and 1999 I&M deposited in its decommissioning trust an additional $6
million and $4 million, respectively, related to special regulatory commission
approved funding for decommissioning of the Cook Plant. Trust fund earnings
increase the fund assets and the recorded liability and decrease the amount
needed to be recovered from ratepayers. Decommissioning costs including
interest, unrealized gains and losses and expenses of the trust funds are
recorded in other operation expense for Cook Plant. For STP, nuclear
decommissioning costs are recorded in other operation expense, interest income
of the trusts are recorded in nonoperating income and interest expense of the
trust funds are included in interest charges. During 1999 and 1998 I&M withdrew
$8 million and $3 million, respectively, from the trust funds for
decommissioning of the original steam generators removed from Cook Plant Unit 2.
On the AEP Consolidated Balance Sheets, nuclear decommissioning trust assets are
included in other assets and a corresponding nuclear decommissioning liability
is included in other noncurrent liabilities. On CPL's balance sheets, the
nuclear decommissioning liability is included in electric utility
plant-accumulated depreciation and amortization. At December 31, 2000 and 1999,
the decommissioning liability for Cook Plant and STP combined totals $654
million and $587 million, respectively.
Shareholders' Litigation - Affecting AEP
On June 23, 2000, a complaint was filed in the U.S. District Court for the
Eastern District of New York seeking unspecified compensatory damages against
AEP and four former or present officers. The individual plaintiff also seeks
certification as the representative of a class consisting of all persons and
entities who purchased or otherwise acquired AEP common stock between July 25,
1997, and June 25, 1999. The complaint alleges that the defendants knowingly
violated federal securities laws by disseminating materially false and
misleading statements concerning, among other things, the undisclosed materially
impaired condition of the Cook Plant, AEP's inability to properly monitor,
manage, repair, supervise and report on operations at the Cook Plant and the
materially adverse conditions these problems were having, and would continue to
have, on AEP's deteriorating financial condition, and ultimately on AEP's
operations, liquidity and stock price. Four other similar class action
complaints have been filed and the court has consolidated the five cases. The
plaintiffs filed a consolidated complaint pursuant to this court order. This
case has been transferred to the U.S. District Court for the Southern District
of Ohio. Although management believes these shareholder actions are without
merit and intends to oppose them vigorously, management cannot predict the
outcome of this litigation or its impact on results of operations, cash flows or
financial condition.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
CPL has been involved in litigation regarding municipal franchise fees in Texas
as a result of a class action suit filed by the City of San Juan, Texas in 1996.
The City of San Juan claims CPL underpaid municipal franchise fees and seeks
damage of up to $300 million plus attorney's fees. CPL filed a counterclaim for
overpayment of franchise fees.
During 1997, 1998 and 1999 the litigation moved procedurally through the Texas
Court System and was sent to mediation without resolution.
In 1999 a class notice was mailed to each of the cities served by CPL. Over 90
of the 128 cities declined to participate in the lawsuit. However, CPL has
pledged that if any final, non-appealable court decision in the litigation
awards a judgement against CPL for a franchise underpayment, CPL will extend the
principles of that decision, with regard to any franchise underpayment, to the
cities that declined to participate in the litigation. In December 1999, the
court ruled that the class of plaintiffs would consist of approximately 30
cities. A trial date for June 2001 has been set.
Although management believes that it has substantial defenses to the cities'
claims and intends to defend itself against the cities' claims and pursue its
counterclaims vigorously, management cannot predict the outcome of this
litigation or its impact on results of operations, cash flows or financial
condition.
Texas Base Rate Litigation - Affecting AEP and CPL
In November 1995 CPL filed with the PUCT a request to increase its retail base
rates by $71 million. In October 1997 the PUCT issued a final order which
lowered CPL's annual retail base rates by $19 million from the rate level which
existed prior to May 1996. The PUCT also included a "glide path" rate
methodology in the final order pursuant to which annual rates were reduced by
$13 million beginning May 1, 1998 with an additional annual reduction of $13
million commencing on May 1, 1999.
CPL appealed the final order to the Travis District Court. The primary issues
being appealed include: the classification of $800 million of invested capital
in STP as ECOM and assigning it a lower return on equity than other generation
property; the use of the "glide path" rate reduction methodology; and an $18
million disallowance of service billings from an affiliate, CSW Services. As
part of the appeal, CPL sought a temporary injunction to prohibit the PUCT from
implementing the "glide path" rate reduction methodology. The temporary
injunction was denied and the "glide path" rate reduction was implemented. In
February 1999 the Travis District Court affirmed the PUCT order in regard to the
three major items discussed above.
CPL appealed the Travis District Court's findings to the Texas Appeals Court
which in July 2000, issued its opinion upholding the Travis District Court
except for the disallowance of affiliated service company billings. Under Texas
law, specific findings regarding affiliate transactions must be made by PUCT. In
regards to the affiliate service billing issue, the findings were not complete
in the opinion of the Texas Appeals Court who remanded the issue back to PUCT.
CPL has sought a rehearing of the Texas Appeals Court's opinion. The Texas
Appeals Court has requested briefs related to CPL's rehearing request from
interested parties. Management is unable to predict the final resolution of its
appeal. If the appeal is unsuccessful the PUCT's 1997 order will continue to
adversely affect results of operations and cash flows.
As part of the AEP/CSW merger approval process in Texas, a stipulation agreement
was approved which resulted in the withdrawal of the appeal related to the
"glide path" rate methodology. CPL will continue its appeal of the ECOM
classification for STP property and the disallowed affiliated service billings.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo
SWEPCo and CLECO are each a 50% owner of Dolet Hills Power Station Unit 1 and
jointly own lignite reserves in the Dolet Hills area of northwestern Louisiana.
In 1982, SWEPCo and CLECO entered into a lignite mining agreement with DHMV, a
partnership for the mining and delivery of lignite from a portion of these
reserves.
In April 1997, SWEPCo and CLECO sued DHMV and its partners in U.S. District
Court for the Western District of Louisiana seeking to enforce various
obligations of DHMV under the lignite mining agreement, including provisions
relating to the quality of delivered lignite, pricing, and mine reclamation
practices. In June 1997, DHMV filed an answer denying the allegations in the
suit and filed a counterclaim asserting various contract-related claims against
SWEPCo and CLECO. SWEPCo and CLECO have denied the allegations contained in the
counterclaims. In January 1999, SWEPCo and CLECO amended the claims against DHMV
to include a request that the lignite mining agreement be terminated.
In April 2000, the parties agreed to settle the litigation. As part of the
settlement, DHMV's interest in the mining operations and related debt and other
obligations will be purchased by SWEPCo and CLECO. The closing date for the
settlement has been extended from December 31, 2000 to March 31, 2001. The
litigation has been stayed until April 2001 to give the parties time to
consummate the settlement agreement.
Management believes that the resolution of this matter will not have a material
effect on results of operations, cash flows or financial condition.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M,
and OPCo
Under the Clean Air Act, if a plant undertakes a major modification that
directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant.
AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding
generating plant emissions under the Clean Air Act. In 1999 Notices of Violation
were issued and complaints were filed by Federal EPA in various U.S. District
Courts alleging APCo, CSPCo, I&M, OPCo and a number of unaffiliated utilities
made modifications to generating units at certain of their coal-fired generating
plants over the course of the past 25 years that extended unit operating lives
or increased unit generating capacity without a preconstruction permit in
violation of the Clean Air Act. The complaint was amended in March 2000 to add
allegations for certain generating units previously named in the complaint and
to include additional generating units previously named only in the Notices of
Violation in the complaint.
A number of northeastern and eastern states were granted leave to intervene in
the Federal EPA's action against the AEP System under the Clean Air Act. A
lawsuit against power plants owned by certain AEP System operating companies
alleging similar violations to those in the Federal EPA complaint and Notices of
Violation was filed by a number of special interest groups and has been
consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit ($25,000 per day prior to January 30, 1997).
Civil penalties, if ultimately imposed by the court, and the cost of any
required new pollution control equipment, if the court accepts Federal EPA's
contentions, could be substantial.
On May 10, 2000, the AEP System companies filed motions to dismiss all or
portions of the complaints. Briefing on these motions was completed on August 2,
2000. On February 23, 2001, the government filed a motion for partial summary
judgement seeking a determination that four projects undertaken on units at
Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance,
repair and replacement" as used in the Clean Air Act. Management believes its
maintenance, repair and replacement activities were in conformity with the Clean
Air Act and intends to vigorously pursue its defense.
In the event the AEP System companies do not prevail, any capital and operating
costs of additional pollution control equipment that may be required as well as
any penalties imposed would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates, and where states are deregulating generation, unbundled
transition period generation rates, stranded cost wires charges and future
market prices for electricity.
In December 2000 Cinergy Corp., an unaffiliated utility, which operates certain
plants jointly owned by CSPCo reached a tentative agreement with Federal EPA and
other parties to settle litigation regarding generating plant emissions under
the Clean Air Act. Negotiations are continuing between the parties in an attempt
to reach final settlement terms. Cinergy's settlement could impact the operation
of Zimmer Plant and W.C. Beckjord Generating Station Unit 6 which are owned
25.4% and 12.5%, respectively, by CSPCo. Until a final settlement is reached,
CSPCo will be unable to determine the settlement's impact on its jointly owned
facilities and its future earnings and cash flows.
NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and
SWEPCo
Federal EPA issued a NOx rule that required substantial reductions in NOx
emissions in a number of eastern states, including certain states in which the
AEP System's generating plants are located. A number of utilities, including
several AEP System companies, filed petitions seeking a review of the final rule
in the D.C. Circuit Court. In March 2000, the D.C. Circuit Court issued a
decision generally upholding the NOx rule. The D.C. Circuit Court issued an
order in August 2000 which extends the final compliance date to May 31, 2004. In
September 2000 following denial by the D.C. Circuit Court of a request for
rehearing, the industry petitioners, including the AEP System companies,
petitioned the U.S. Supreme Court for review, which was denied.
In December 2000 Federal EPA ruled that eleven states, including states in which
AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating units are located,
failed to submit plans to comply with the mandates of the NOx rule. This
determination means that those states could face stringent sanctions within the
next 24 months including limits on construction of new sources of air emissions,
loss of federal highway funding and possible Federal EPA takeover of state air
quality management programs.
In January 2000 Federal EPA adopted a revised rule granting petitions filed by
certain northeastern states under Section 126 of the Clean Air Act seeking
significant reductions in nitrogen oxide emissions from utility and industrial
sources. The rule imposes emissions reduction requirements comparable to the NOx
rule beginning May 1, 2003, for most of AEP's coal-fired generating units.
Certain AEP operating companies and other utilities filed petitions for review
in the D.C. Circuit Court. Briefing has been completed and oral argument was
held in December 2000.
In a related matter, on April 19, 2000, the Texas Natural Resource Conservation
Commission adopted rules requiring significant reductions in NOx emissions from
utility sources, including CPL and SWEPCo. The rule's compliance date is May
2003 for CPL and May 2005 for SWEPCo.
In June 2000 OPCo announced that it was beginning a $175 million installation of
selective catalytic reduction technology (expected to be operational in 2001) to
reduce NOx emissions on its two-unit 2,600 MW Gavin Plant. Construction of
selective catalytic reduction technology on Amos Plant Unit 3, which is jointly
owned by OPCo and APCo, and APCo's Mountaineer Plant is scheduled to begin in
2001. The Amos and Mountaineer projects (expected to be completed in 2002) are
estimated to cost a total of $230 million ($145 million for APCo and $85 million
for OPCo).
Preliminary estimates indicate that compliance with the NOx rule upheld by the
D.C. Circuit Court as well as compliance with the Texas Natural Resource
Conservation Commission rule and the Section 126 petitions could result in
required capital expenditures of approximately $1.6 billion, including the
amounts discussed in the previous paragraph, for AEP Consolidated. Estimated
compliance costs by registrant subsidiaries are as follows:
(in millions)
AEGCo $125
APCo 365
CPL 57
CSPCo 106
I&M 202
KPCo 140
OPCo 606
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the preliminary estimates depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital and operating costs of additional pollution
control equipment are recovered from customers through regulated rates and/or
future market prices for electricity where generation is deregulated, they will
have an adverse effect on future results of operations, cash flows and possibly
financial condition.
COLI Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
On February 20, 2001, the U.S. District Court for the Southern District of Ohio
ruled against the AEP System companies in their suit against the United States
over deductibility of interest claimed in their consolidated federal income tax
return related to a COLI program. The suit was filed to resolve the IRS'
assertion that interest deductions for the COLI program should not be allowed.
In 1998 and 1999 APCo, CSPCo, I&M, KPCo and OPCo paid the disputed taxes and
interest attributable to COLI interest deductions for taxable years 1991-98 for
APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment
by the IRS of additional interest on the contested tax. The payments were
included in other assets on AEP's Consolidated Balance Sheet and in Other
Property and Investment on the subsidiaries' balance sheets pending the
resolution of this matter. As a result of the U.S. District Court's decision to
deny the COLI interest deductions, net income was reduced for AEP Consolidated
by $319 million in 2000. The appeal of this decision is planned.
The earnings reductions for affected registrant subsidiaries are as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
Other - AEP and its registrant subsidiaries are involved in a number of other
legal proceedings and claims. While management is unable to predict the ultimate
outcome of these matters, it is not expected that their resolution will have a
material adverse effect on results of operations, cash flows or financial
condition.
9. Acquisitions:
AEP completed two energy related acquisitions in 1998 through a subsidiary,
AEPR. Both acquisitions have been accounted for using the purchase method. On
December 31, 1998 CitiPower, an Australian distribution utility, that serves
approximately 250,000 customers in Melbourne with 3,100 miles of distribution
lines in a service area of approximately 100 square miles was acquired. All of
the stock of CitiPower was acquired for approximately $1.1 billion. The
acquisition of CitiPower had no effect on the results of operations for 1998 and
a full year of CitiPower's results of operations are included in the
consolidated statements of income for 1999 and 2000. Assets acquired and
liabilities assumed have been recorded at their fair values. Based on an
independent appraisal, $616 million of the purchase price was allocated to
retail and wholesale distribution licenses which are being amortized on a
straight-line basis over 20 years and 40 years, respectively. The excess of cost
over fair value of the net assets acquired was approximately $34 million and is
recorded as goodwill and is being amortized on a straight-line basis over 40
years. On December 1, 1998 AEPR acquired Louisiana Intrastate Gas (LIG) with
midstream gas operations that include a fully integrated natural gas gathering,
processing, storage and transportation operation in Louisiana and a gas trading
and marketing operation. LIG was acquired for approximately $340 million,
including working capital funds with one month of earnings reflected in AEP's
consolidated results of operations for the year ended December 31, 1998. A full
year of LIG's results of operations is included in AEP's consolidated statements
of income for 1999 and 2000. Assets acquired and liabilities assumed have been
recorded at their fair values. The excess of cost over fair value of the net
assets acquired was approximately $158 million for the midstream gas storage
operations and $17 million for the gas trading and marketing operation. The
goodwill is being amortized on a straight-line basis over 40 years and 10 years,
respectively.
10. International Investments:
CSW International owns a 44% equity interest in Vale, a Brazilian electric
operating company which it had purchased for a total of $149 million. The
investment is covered by a put option, which, if exercised, requires CSW
International's partners in Vale to purchase CSW International's Vale shares at
a minimum price equal to the U.S. dollar equivalent of CSW International's
purchase price. As a result, management has concluded that CSW International's
investment carrying amount will not be reduced below the put option value unless
it is deemed to be a permanent impairment and CSW International's partners in
Vale are deemed unable to fulfill their responsibilities under the put option.
Vale has experienced losses from operations and CSW International's investment
has been affected by the devaluation of the Brazilian Real. CSW International's
cumulative equity share of these operating and foreign currency translation
losses through December 31, 2000 is approximately $33 million, net of tax, and
$49 million, net of tax, respectively. Pursuant to the put option arrangement,
these losses have not been applied to reduce the carrying value of the Vale
investment. As a result, CSW International will not recognize any future
earnings from Vale until the operating losses are recovered. In December 2000,
CSW International sold its investment in a Chilean electric company for $67
million. A net loss on the sale of $13 million ($9 million after tax) is
included in worldwide electric and gas expenses and includes $26 million ($17
million net of tax) of losses from foreign exchange rate changes that were
previously reflected in other comprehensive income. In the second quarter of
2000 management determined that the then existing decline in market value of the
shares was other than temporary. As a result the investment was written down by
$33 million ($21 million after tax) in June 2000. The total loss from both the
write down of the Chilean investment to market in the second quarter and from
the sale in the fourth quarter was $46 million ($30 million net of tax).
In December 2000 AEPR entered into negotiations to sell its 50% investment in
Yorkshire, a U.K. electricity supply and distribution company. On February 26,
2001 an agreement to sell AEPR's 50% interest in Yorkshire was signed. As a
result a $43 million impairment writedown ($30 million after tax) was recorded
in the fourth quarter of 2000 to reflect the net loss from the expected sale in
the first quarter of 2001. The impairment writedown is included in other income
(net) on AEP's Consolidated Statements of Income.
11. Staff Reductions:
During 1998 an internal evaluation of the power generation organization was
conducted with a goal of developing an optimum organizational structure for a
competitive generation market. The study was completed in October 1998 and
called for the elimination of approximately 450 positions across the AEP System.
In addition, a review of energy delivery staffing levels in 1998 identified 65
AEP System positions for elimination.
A provision for severance costs totaling $26 million was recorded in December
1998 for reductions in power generation and energy delivery staffs and was
charged to maintenance and other operation expense. The power generation and
energy delivery staff reductions were made in the first quarter of 1999. The
amount of severance benefits paid was not significantly different from the
amount accrued.
The following table shows the staff reductions information for the applicable
registrant companies:
Total Number Severance Accrual
Company of Employees Amount
- ------- ------------- ------------------
(in millions)
APCo 180 $7.6
CSPCo 70 3.4
I&M 80 3.7
KPCo 35 1.9
OPCo 150 8.6
12. Benefit Plans:
In the U.S. the AEP System sponsors two qualified pension plans and two
nonqualified pension plans. All employees in the U.S., except participants in
the UMWA pension plans are covered by one or both of the pension plans. OPEB
plans are sponsored by the AEP System to provide medical and death benefits for
retired employees in the U.S.
The foreign pension plans are for employees of SEEBOARD in the U.K. and
CitiPower in Australia. The majority of SEEBOARD's employees joined a pension
plan that is administered for the U.K.'s electricity industry. The assets of
this plan are actuarially valued every three years. SEEBOARD and its
participating employees both contribute to the plan. Subsequent to July 1, 1995,
new employees were no longer able to participate in that plan and two new
pension plans were made available to new employees of SEEBOARD. CitiPower
sponsors a defined benefit pension plan that covers all employees.
The following tables provide a reconciliation of the changes in the plans'
benefit obligations and fair value of assets over the two-year period ending
December 31, 2000, and a statement of the funded status as of December 31 for
both years:
U.S. Foreign U.S.
Pension Plans Pension Plans OPEB Plans
------------------ ---------------- -------------------
2000 1999 2000 1999 2000 1999
---- ---- ---- ---- ---- ----
(in millions)
Reconciliation of benefit
obligation:
Obligation at January 1 $2,934 $3,117 $1,176 $1,147 $1,365 $1,297
Service Cost 60 71 13 15 29 33
Interest Cost 227 211 64 59 106 90
Participant Contributions - - 5 4 7 9
Plan Amendments (71)(a) 7 (b) - 7 (c) (67) (d) -
Foreign Currency Translation
Adjustment - - (95) (26) - -
Actuarial (Gain) Loss 218 (300) 80 37 262 -
Benefit Payments (207) (172) (64) (67) (85) (74)
Curtailments - - - - 51 (e) 10 (e)
------ ------ ------ ------ ------ ------
Obligation at December 31 $3,161 $2,934 $1,179 $1,176 $1,668 $1,365
====== ====== ====== ====== ====== ======
Reconciliation of fair value
of plan assets:
Fair value of plan assets at
January 1 $3,866 $3,665 $1,405 $1,338 $668 $560
Actual Return on Plan Assets 250 370 55 156 2 71
Company Contributions 2 2 - 7 112 103
Participant Contributions - - 5 4 7 9
Foreign Currency Translation
Adjustment - - (111) (33) - -
Benefit Payments (207) (172) (64) (67) (85) (74)
------ ------ ------ ------ ---- ----
Fair value of plan assets at
December 31 $3,911 $3,865 $1,290 $1,405 $704 $669
====== ====== ====== ====== ==== ====
Funded status:
Funded status at December 31 $ 750 $ 931 $111 $ 229 $(964) $(696)
Unrecognized Net Transition
(Asset) Obligation (23) (31) - - 298 434
Unrecognized Prior-Service Cost (12) 71 10 11 - -
Unrecognized Actuarial
(Gain) Loss (628) (954) (67) (177) 448 135
----- ----- ---- ----- ----- -----
Prepaid Benefit (Accrued
Liability) $ 87 $ 17 $ 54 $ 63 $(218) $(127)
===== ===== ==== ===== ===== =====
(a) One of the qualified pension plans converted to the cash balance pension
formula from a final average pay formula. (b) Early retirement factors for one
of the pension plans was changed to provide more generous benefits to
participants retiring between ages 55 and 60.
(c) SEEBOARD made a one-time payment to all retired participants.
(d) Change to a service-related formula for retirement health care costs and a
50% of pay life insurance benefit for retiree life insurance. (e) Related to the
shutdown of OPCo's affiliated coal mine operations.
The following table provides the amounts recognized in AEP's consolidated balance sheets as of December 31 of both years:
U.S. Foreign U.S.
Pension Plan Pension Plans OPEB Plans
------------------- ---------------- -------------------
2000 1999 2000 1999 2000 1999
---- ---- ---- ---- ---- ----
(in millions)
Prepaid Benefit Costs $ 159 $ 145 $54 $63 $ - $ -
Accrued Benefit Liability (72) (128) - - (218) (127)
Additional Minimum Liability (24) (14) - - N/A N/A
Intangible Asset 14 8 - - N/A N/A
Accumulated Other
Comprehensive Income 10 6 - - N/A N/A
----- ----- --- --- ----- ------
Net Amount Recognized $ 87 $ 17 $54 $63 $(218) $(127)
===== ===== === === ===== =====
Other Comprehensive (Income)
Expense Attributable to
Change in Additional Pension
Liability Recognition $4 $(2) - - N/A N/A
== ==== === === === ====
N/A = Not Applicable
The AEP System's nonqualified pension plans had accumulated benefit obligations
in excess of plan assets of $41 million and $26 million at December 31, 2000 and
$29 million and $23 million at December 31, 1999. There are no plan assets in
the nonqualified plans.
The AEP System's OPEB plans had accumulated benefit obligations in excess of
plan assets of $964 million and $696 million at December 31, 2000 and 1999,
respectively.
The following table provides the components of AEP's net periodic benefit cost for the plans for fiscal years 2000, 1999 and 1998:
U.S. Foreign U.S.
Pension Plans Pension Plans OPEB Plans
-------------------- -------------------- -------------------
2000 1999 1998 2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ---- ---- ---- ----
(in millions)
Service cost $ 60 $ 71 $ 67 $ 13 $ 15 $ 14 $ 29 $ 33 $ 26
Interest cost 227 211 202 64 59 68 106 90 76
Expected return on plan assets (321) (299) (269) (75) (71) (77) (57) (49) (40)
Amortization of
transition (asset) obligation (8) (8) (8) - - - 41 43 41
Amortization of prior-service
cost 13 12 9 1 - - - - -
Amortization of net actuarial
(gain) loss (39) (15) (3) - - - 4 5 (2)
---- ----- ----- ---- ---- ---- ---- ---- ----
Net periodic benefit cost (68) (28) (2) 3 3 5 123 122 101
Curtailment loss(a) - - - - - - 79 18 24
---- ----- ----- ---- ---- ---- ---- ---- -----
Net periodic benefit
cost after curtailments $(68) $ (28) $ (2) $ 3 $ 3 $ 5 $202 $140 $125
==== ===== ===== ==== ==== ==== ==== ==== ====
(a) Curtailment charges were recognized during 2000, 1999 and 1998 for the
shutdown of affiliated coal mine operations.
The following table provides the net periodic benefit cost (credit) for the
plans by the following AEP registrant subsidiaries for fiscal years 2000, 1999
and 1998:
U.S. U.S
Pension Plans OPEB Plans
---------------------------- ---------------------------
2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ----
(in thousands)
APCo $(14,047) $(3,925) $ 778 $ 22,139 $19,431 $16,569
CPL (2,986) (4,270) (2,850) 6,656 7,595 6,599
CSPCo (10,905) (4,893) (1,410) 9,643 8,623 7,467
I&M (8,565) (1,259) 2,104 14,155 13,664 11,994
KPCo (2,075) (393) 322 2,364 2,652 2,113
OPCo (15,041) (4,979) 26 116,205 52,518 54,578
PSO (2,196) (3,129) (2,190) 4,277 5,516 4,369
SWEPCo (2,606) (3,734) (2,581) 4,152 4,913 3,673
WTU (1,585) (2,221) (1,478) 2,929 3,377 3,002
The assumptions used in the measurement of the AEP System's benefit obligations
are shown in the following tables:
U.S. Foreign
Pension Plans Pension Plans U.S. OPEB Plans
----------------------- ------------------------- --------------------
2000 1999 1998 2000 1999 1998 2000 1999 1998
---- ---- ---- ---- ---- ---- ---- ---- ----
% % % % % % % % %
Weighted-average assumptions as of December 31:
Discount rate 7.50 8.00 6.75 5-5.5 5.5-6 5-5.5 7.50 8.00 6.75
Expected return on
plan assets 9.00 9.00 9.00 6-7.5 6.5-7.5 6.25-7 8.75 8.75 8.75
Rate of compensation
increase 3.2 3.8 3.8 3.5-4.0 4-4.5 3.5-4 N/A N/A N/A
For measurement purposes, a 6.0% annual rate of increase in the per capita cost
of covered health care benefits was assumed for 2001. The rate was assumed to
decrease gradually each year to a rate of 5.1% through 2005 and remain at that
level thereafter.
Assumed health care cost trend rates have a significant effect on the amounts
reported for the OPEB health care plans. A 1% change in assumed health care cost
trend rates would have the following effects:
1% Increase 1% Decrease
----------- ------------
(in millions)
Effect on total
service and interest
cost components of
net periodic
postretirement
health care benefit cost $ 15 $ (13)
Effect on the health care
component of the
accumulated
postretirement
benefit obligation 197 (162)
AEP System Savings Plans - The AEP System Savings Plans are defined contribution
plans offered to non-UMWA U.S. employees. The cost for contributions to these
plans totaled $37 million in 2000, $36 million in 1999 and $35 million in 1998.
Beginning in 2001 AEP's contributions to the plans will increase to 4.5% of the
initial 6% of employee pay contributed from the current 3% of the initial 6% of
employee base pay contributed.
The following table provides the cost for contributions to the savings plans by
the following AEP registrant subsidiaries for fiscal years 2000, 1999 and 1998:
2000 1999 1998
---- ---- ----
(in thousands)
APCo $3,988 $4,091 $4,276
CPL 3,161 3,284 3,078
CSPCo 1,638 1,679 1,830
I&M 4,231 3,996 4,017
KPCo 544 561 714
OPCo 3,713 3,744 3,978
PSO 2,306 2,435 2,230
SWEPCo 2,880 2,961 2,728
WTU 1,708 1,766 1,594
Other UMWA Benefits - AEP and OPCo provide UMWA pension, health and welfare
benefits for certain unionized mining employees, retirees, and their survivors
who meet eligibility requirements. The benefits are administered by UMWA
trustees and contributions are made to their trust funds. Contributions are
based on hours worked and are expensed as paid as part of the cost of active
mining operations and were not material in 2000, 1999 and 1998.
13. Stock-Based Compensation:
In 2000, AEP adopted a Long-term Incentive Plan under which a maximum of
15,700,000 shares of common stock can be issued to key employees. Under the
plan, the exercise price of each option granted equals the market price of AEP's
common stock on the date of grant. These options will vest in equal increments,
annually, over a three-year period beginning on January 1, 2002 with a maximum
exercise term of ten years.
CSW maintained a stock option plan prior to the merger with AEP. Effective with
the merger, all CSW stock options outstanding were converted into AEP stock
options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock
option. The exercise price for each CSW stock option was adjusted for the
exchange ratio. The provisions of the CSW stock option plan will continue in
effect until all options expire or there are no longer options outstanding.
Under the CSW stock option plan, the option exercise price was equal to the
stock's market price on the date of grant. The grant vested over three years,
one-third on each of the first three anniversary dates of the grant, and expires
10 years after the original grant date. All CSW stock options were fully vested
at December 31, 2000.
The following table summarizes share activity in the above plans, and the
weighted-average exercise price:
2000 1999 1998
---- ---- ----
Weighted Weighted Weighted
Average Average Average
Options Exercise Options Exercise Options Exercise
(in thousands) Price (in thousands) Price (in thousands) Price
-------------- ----- -------------- ----- -------------- ------
Outstanding at
beginning of year 825 $40 866 $40 1,141 $40
Granted 6,046 $36 - $ - - $ -
Exercised (26) $36 (22) $38 (202) $40
Forfeited (235) $39 (19) $43 (73) $40
----- --- -----
Outstanding at
end of year 6,610 $36 825 $40 866 $40
===== === =====
Options Exercisable
at end of year 588 $41 707 $42 606 $43
=== === ===
The weighted-average fair value of options granted in 2000 is $36 per share. No
options were granted in 1999 or 1998. Shares outstanding under the stock option
plan have exercise prices ranging from $35 to $49 and a weighted-average
remaining contractual life of 9.2 years.
If compensation expense for stock options had been determined based on the fair
value at the grant date, net income and earnings per share would have been the
pro forma amounts shown below:
2000 1999 1998
---- ---- ----
Pro forma net income
(in millions) $264 $972 $975
Pro forma earnings per
share (basic and diluted) $0.82 $3.03 $3.06
The pro forma amounts are not representative of the effects on reported net
income for future years.
The fair value of each option award is estimated on the date of grant using the
Black-Scholes option-pricing model with the following assumptions used to
estimate the fair value of options granted in 2000: dividend yield of 6.02%;
expected stock price volatility of 24.75%; risk-free interest rate of 5.02% and
expected life of option of 7 years.
14. Business Segments:
AEP's principal business segment is its cost-based rate regulated Domestic
Electric Utility business consisting of eleven regulated utility operating
companies providing generation, distribution and transmission electric services
in eleven states. Also included in this segment are AEP's electric power
wholesale marketing and trading activities conducted within two transmission
systems of the AEP System.
The AEP consolidated income statement caption "Revenues-Domestic Electric
Utility Operations" includes both the retail and wholesale domestic electricity
supply businesses which are cost-based rate regulated on a bundled basis with
transmission and distribution services in Kentucky, Indiana, Michigan,
Louisiana, Oklahoma and Tennessee and are in the process of transitioning to
customer choice market based pricing in Arkansas, Ohio, Texas, WV and Virginia.
Since the domestic electric utility companies have not yet functionally or
structurally separated their retail and wholesale electricity supply business
from their regulated transmission and distribution service business, separate
financial data is not available and the Domestic Electric Utilities business
will continue to be reported as one business segment which is the only
reportable segment for the domestic electric
operating subsidiaries. Therefore all registrant subsidiaries have one
reportable segment, a regulated vertically integrated electricity generation and
energy delivery business. All other activities for these registrant subsidiaries
are insignificant. In 2000, 1999 and 1998 all the registrant subsidiaries
revenues are derived from the generation, sale and delivery of electricity in
the U.S.
The AEP consolidated income statement caption "Revenues-Worldwide Electric and
Gas Operations" includes three segments: Foreign Energy Delivery, Worldwide
Energy Investments and other. The Foreign Energy Delivery segment includes
investments in overseas electric distribution and supply companies (SEEBOARD and
Yorkshire in the U.K. and CitiPower in Australia).
The Worldwide Energy Investments segment represents domestic and international
investments in energy-related gas and electric projects including the
development and management of those projects. Such investment activities include
electric generation in Florida, Texas, Colorado, Brazil and Mexico, and natural
gas pipeline, storage and other natural gas services in the U.S.
The other segment which is included in the AEP consolidated income statement as
part of Worldwide Electric and Gas Operations includes non-regulated electric
marketing and trading activities outside of AEP's marketing area (beyond two
transmission systems from the AEP System) gas marketing and trading activities,
telecommunication services, and the marketing of various energy related products
and services.
In the fourth quarter of 2000, management announced its intent to functionally
and structurally separate its operations into two main business segments, a
non-regulated business and a regulated business. Separation of AEP's regulated
bundled generation, distribution and transmission businesses into an unbundled
non-regulated generation business and regulated unbundled distribution and
transmission business will not be completed until the required regulatory
approvals are obtained and the electric operating subsidiaries operating in
states that are deregulating the generation business are structurally separated
and the remaining subsidiaries functionally separated and the necessary changes
are made to their accounting software, books, and records. Management expects to
begin reporting certain segmented information by the new business segments in
the near future.
Domestic* Foreign Worldwide
Electric Energy Energy Reconciling AEP
Year Utilities Delivery Investments Other Adjustments Consolidated
- ---- --------- -------- ----------- ----- ----------- ------------
(in millions)
2000
Revenues from:
External unaffiliated
customers $10,827 $1,934 $ 836 $ 97 - $13,694
Transactions with other
operating segments - - 147 391 $(538) -
Interest expense 734 163 129 91 (60) 1,057
Depreciation, depletion and
amortization expense 1,062 149 25 13 (187) 1,062
Income tax expense (benefit) 641 (16) (19) (9) - 597
Segment net income (loss) 211 125 (56) (13) - 267
Total assets 35,741 4,446 2,089 12,272 - 54,548
Investments in equity method
subsidiaries - 427 360 77 - 864
Gross property additions 1,386 177 149 61 - 1,773
1999
Revenues from:
External unaffiliated
customers $ 9,838 $2,023 $ 583 $ (37) - $12,407
Transactions with other
operating segments - - 70 246 $(316) -
Interest expense 688 172 109 55 (47) 977
Depreciation, depletion and
amortization expense 1,011 166 26 9 (201) 1,011
Income tax expense (benefit) 490 18 (10) (16) - 482
Segment net income (loss) 794 170 34 (26) - 972
Total assets 27,288 4,739 1,669 2,023 - 35,719
Investments in equity method
subsidiaries - 412 420 57 - 889
Gross property additions 1,215 206 205 54 - 1,680
1998
Revenues from:
External unaffiliated
customers $ 9,834 $1,769 $ 183 $ 54 - $11,840
Transactions with other
operating segments - - - 49 $ (49) -
Interest expense 682 116 68 51 (38) 879
Depreciation, depletion and
amortization expense 989 95 13 7 (115) 989
Income tax expense (benefit) 532 4 (14) (20) - 502
Segment net income (loss) 884 155 (26) (38) - 975
Total assets 25,546 4,504 1,672 1,543 - 33,265
Investments in equity method
subsidiaries - 352 287 59 - 698
Gross property additions 729 1,259 712 90 - 2,790
*Includes the domestic generation retail and wholesale supply businesses a
significant portion of which is undergoing a transition from regulated cost
based bundled rates to open access market pricing but which have not yet been
unbundled i.e., structurally separated from the distribution and transmission
portions of the vertically integrated electric utility business.
Geographic Areas Revenues
- ---------------- ----------------------------------------------------------------------
United AEP
United States Kingdom Other Foreign Consolidated
---------------------------------------------------------------------
(in millions)
2000 $11,663 $1,632 $399 $13,694
1999 10,353 1,705 349 12,407
1998 10,063 1,769 8 11,840
Long-Lived Assets
----------------------------------------------------------------------
United AEP
United States Kingdom Other Foreign Consolidated
---------------------------------------------------------------------
(in millions)
2000 $20,463 $1,220 $710 $22,393
1999 19,958 1,124 783 21,865
1998 19,752 1,102 665 21,519
15. Financial Instruments, Credit and
Risk Management:
AEP and its subsidiaries are subject to market risk as a result of changes in
commodity prices, foreign currency exchange rates, and interest rates. AEP has
wholesale electricity and gas trading and marketing operations that manage the
exposure to commodity price movements using physical forward purchase and sale
contracts at fixed and variable prices, and financial derivative instruments
including exchange traded futures and options, over-the-counter options, swaps
and other financial derivative contracts at both fixed and variable prices.
In the first quarter of 1999 AEP adopted the Financial Accounting Standards
Board's EITF 98-10, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities". The EITF requires that all open energy trading
contracts be marked-to-market. The effect on the Consolidated Statements of
Income of marking open trading contracts to market in the AEP System's regulated
jurisdictions are deferred as regulatory assets or liabilities in accordance
with SFAS 71 for the portion of those open electricity trading transactions
within AEP's marketing area that are included in cost of service on a settlement
basis for ratemaking purposes. Open electricity trading transactions within
AEP's marketing area allocated to non-regulated jurisdictions are
marked-to-market and included in revenues from domestic electric utility
operations. Open electricity trading contracts outside AEP's marketing area are
accounted for on a mark-to-market basis and included in revenues from worldwide
electric and gas operations. Open gas trading contracts are accounted for on a
mark-to-market basis and included in revenues from worldwide electric and gas
operations. Unrealized mark-to-market gains and losses from trading of financial
instruments are reported as assets and liabilities, respectively.
The amounts of net revenues recorded in 2000 and 1999 for electric and gas
trading activities were:
Revenues - Net Gain (Loss) 2000 1999
- -------------------------- ---- ----
(in millions)
Domestic Electric Utility
Operations $ 43 $27
Worldwide Electric and
Gas Operations 213 14
The amounts of net revenues recorded in 2000 and 1999 for the registrant
subsidiaries were:
2000 1999
---- ----
(in thousands)
APCo $23,712 $14,640
CPL (3,809) -
CSPCo 22,032 5,819
I&M 29,344 6,384
KPCo 11,792 2,182
OPCo 34,582 10,921
PSO 3,553 -
SWEPCo (441) -
WTU (453) -
Investment in foreign energy companies and projects exposes AEP to risk of
foreign currency fluctuations. AEP is also exposed to changes in interest rates
primarily due to short- and long-term borrowings used to fund its business
operations. AEP does not presently utilize derivatives to manage its exposures
to foreign currency exchange rate movements.
Market Valuation - The book values of cash and cash equivalents, accounts
receivable, short-term debt and accounts payable approximate fair value because
of the short-term maturity of these instruments. The book value of the pre-April
1983 spent nuclear fuel disposal liability approximates AEP and I&M's best
estimate of its fair value.
The book values and fair values of AEP's and the registrant subsidiaries'
significant financial instruments at December 31, 2000 and 1999 are summarized
in the following table. The fair values of long-term debt and preferred stock
subject to mandatory redemption are based on quoted market prices for the same
or similar issues and the current dividend or interest rates offered for
instruments of the
same remaining maturities. The fair value of those financial instruments that
are marked-to-market are based on management's best estimates using
over-the-counter quotations, exchange prices, volatility factors and a
valuation methodology. The estimates presented herein are not necessarily
indicative of the amounts that AEP and the registrant subsidiaries could realize
in a current market exchange.
2000 1999
Book Value Fair Value Book Value Fair Value
---------- ---------- ---------- ----------
(in thousands) (in thousands)
Non-Derivatives
AEP Consolidated
Long-term Debt $10,754,000 $10,812,000 $11,524,000 $11,037,000
Preferred Stock 100,000 98,000 119,000 117,000
Trust Preferred Securities 334,000 326,000 335,000 290,000
AEGCo
Long-term Debt $45 $45 $45 $45
APCo
Long-term Debt $1,605,818 $1,601,313 $1,665,307 $1,580,600
Preferred Stock 10,860 10,725 20,310 19,700
CPL
Long-term Debt $1,454,559 $1,463,690 $1,454,541 $1,435,083
Trust Preferred Securities 148,500 147,431 150,000 129,360
CSPCo
Long-term Debt $899,615 $908,620 $925,000 $889,000
Preferred Stock 15,000 14,892 25,000 25,438
I&M
Long-term Debt $1,388,939 $1,377,230 $1,324,326 $1,283,300
Preferred Stock 64,945 63,941 64,945 63,500
KPCo
Long-term Debt $330,880 $335,408 $365,782 $359,100
OPCo
Long-term Debt $1,195,493 $1,176,367 $1,151,511 $1,027,000
Preferred Stock 8,850 8,780 8,850 8,500
PSO
Long-term Debt $470,822 $476,964 $384,516 $378,437
Trust Preferred Securities 75,000 72,180 75,000 63,390
SWEPCo
Long-term Debt $645,963 $651,586 $541,568 $537,354
Trust Preferred Securities 110,000 106,700 110,000 97,372
WTU
Long-term Debt $255,843 $261,315 $303,686 $298,220
Derivatives
2000 1999
--------------------------- ----------------------------
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
-------- ----- ---------- -------- ----- ----------
GWH (in millions) GWH (in millions)
AEP Consolidated
Trading Assets
Electric
Futures and
Options-NYMEX (net) - $ - $ - 224 $ 2 $ 1
Physicals 247,330 8,845 2,758 69,509 577 517
Options - OTC 8,981 215 99 6,203 39 62
Swaps 11,575 164 60 177 1 1
MMMBTU MMMBTU
Gas
Futures and
Options-NYMEX (net) - $ - $ - - $ - $ -
Physicals 597,251 455 97 345,830 37 39
Options - OTC 698,392 1,266 355 192,593 54 40
Swaps 4,677,142 7,328 1,730 2,682,033 410 312
Trading Liabilities
GWH (in millions) GWH (in millions)
Electric
Futures and
Options-NYMEX (net) - $ - $ - - $ - $ -
Physicals 246,729 (8,906) (2,712) 74,764 (536) (498)
Options - OTC 10,368 (133) (69) 8,907 (43) (56)
Swaps 11,289 (144) (47) 180 (2) (2)
MMMBTU MMMBTU
Gas
Futures and
Options-
NYMEX (net) 23,110 $ (81) $ (11) 69,840 $ (8) $ (5)
Physicals 442,309 (420) (91) 301,271 (32) (26)
Options - OTC 666,304 (934) (306) 227,225 (55) (37)
Swaps 4,616,178 (7,592) (1,762) 2,601,644 (379) (303)
2000 1999
--------------------------- ----------------------------
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
-------- ----- ---------- -------- ----- ----------
GWH (in thousands) GWH (in thousands)
APCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) - $ - $ - 64 $ 535 $ 254
Physicals 45,406 2,246,952 757,757 19,953 165,624 150,377
Options - OTC 1,924 59,814 25,015 1,781 11,766 18,461
Swaps 3,652 51,470 18,387 51 112 90
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) - $ - $ - - $ - $ -
Physicals 45,994 (2,271,026) (747,567) 21,461 (154,364)(144,876)
Options - OTC 3,130 (35,955) (18,872) 2,557 (12,375) (16,811)
Swaps 3,562 (44,855) (14,103) 52 (103) (85)
KPCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) - $ - $ - 15 $ 114 $ 49
Physicals 10,779 533,781 179,999 4,707 39,074 35,477
Options - OTC 456 14,207 5,938 420 2,773 4,353
Swaps 867 12,227 4,368 12 26 21
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) - $ - $ - - $ - $ -
Physicals 10,919 (539,465) (177,581) 5,063 (36,422)(34,180)
Options - OTC 743 (8,521) (4,461) 603 (2,900) (3,949)
Swaps 846 (10,656) (3,350) 12 (24) (20)
2000 1999
--------------------------- ----------------------------
Notional Fair Average Notional Fair Average
Amount Value Fair Value Amount Value Fair Value
-------- ----- ---------- -------- ----- ----------
GWH (in thousands) GWH (in thousands)
I&M
Trading Assets
Electric
Futures and
Options-NYMEX (net) - $ - $ - 43 $ 340 $ 171
Physicals 27,431 1,357,459 466,140 13,592 112,830 99,621
Options - OTC 1,162 36,139 15,464 1,213 8,010 12,125
Swaps 2,206 31,095 11,144 35 76 61
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) - $ - $ - - $ - $ -
Physicals 27,786 (1,379,302) (460,348) 14,620 (105,169)(95,948)
Options - OTC 1,891 (25,807) (13,031) 1,742 (8,391)(11,010)
Swaps 2,152 (27,099) (8,552) 35 (70) (58)
OPCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) - $ - $ - 61 $ 583 $ 286
Physicals 36,080 1,786,137 639,632 18,753 155,507 146,395
Options - OTC 1,529 46,731 20,403 1,673 9,672 9,936
Swaps 2,902 41,788 16,172 48 987 967
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) - $ - $ - - $ - $ -
Physicals 36,547 (1,802,295) (627,137) 20,171 (143,440)(135,015)
Options - OTC 2,487 (29,350) (16,571) 2,403 (11,506) (7,084)
Swaps 2,830 (37,398) (13,447) 49 (1,846) (1,829)
CSPCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) - $ - $ - 40 $ 312 $ 159
Physicals 24,221 1,198,835 420,090 12,503 103,794 91,570
Options - OTC 1,026 31,918 13,961 1,116 7,369 11,140
Swaps 1,948 27,461 9,914 32 70 56
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) - $ - $ - - $ - $ -
Physicals 24,535 (1,211,580) (414,198) 13,449 (96,748)(88,194)
Options - OTC 1,669 (19,220) (10,629) 1,602 (7,717)(10,114)
Swaps 1,900 (23,932) (7,599) 32 (64) (53)
2000
Notional Fair Average
Amount Value Fair Value
-------- ----- ----------
GWH (in thousands)
CPL
Trading Assets
Electric
Physicals 31,040 $547,437 $ 210,189
Trading
Liabilities
Electric
Physicals 31,442 (555,628) (211,482)
PSO
Trading Assets
Electric
Physicals 24,670 435,009 232,198
Trading
Liabilities
Electric
Physicals 24,990 (441,517) (234,082)
SWEPCo
Trading Assets
Electric
Physicals 29,538 520,964 217,444
Trading
Liabilities
Electric
Physicals 29,920 (528,759) (220,171)
WTU
Trading Assets
Electric
Physicals 9,821 173,118 58,048
Trading
Liabilities
Electric
Physicals 9,948 (175,708) (58,071)
There were no trading activities for CPL, PSO, SWEPCo, and WTU for the year
ended 1999.
AEP routinely enters into exchange traded futures and options transactions for
electricity and natural gas as part of its wholesale trading operations. These
transactions are executed through brokerage accounts with brokers who are
registered with the Commodity Futures Trading Commission. Brokers require cash
or cash related instruments to be deposited on these accounts as margin calls
against the customer's open position. The amount of these deposits at December
31, 2000 and 1999 was $95 million and $25 million, respectively.
Credit and Risk Management - In addition to market risk associated with price
movements, AEP is also subject to the credit risk inherent in its risk
management activities. Credit risk refers to the financial risk arising from
commercial transactions and/or the intrinsic financial value of contractual
agreements with trading counter parties, by which there exists a potential risk
of non-performance. The AEP System has established and enforced credit policies
that minimize or eliminate this risk. AEP accepts as counter parties to
forwards, futures, and other derivative contracts primarily those entities that
are classified as Investment Grade, or those that can be considered as such due
to the effective placement of credit enhancements and/or collateral agreements.
Investment Grade is the designation given to the four highest debt rating
categories (i.e., AAA, AA, A, BBB) of the major rating services, e.g., ratings
BBB- and above at Standard & Poor's and Baa3 and above at Moody's. When adverse
market conditions have the potential to negatively affect a counter party's
credit position, AEP will require further enhancements to mitigate risk. Since
the formation of the trading business in July of 1997, AEP has not experienced a
significant loss due to the credit risk; furthermore, AEP does not anticipate
any future material effect on its results of operations, cash flow or financial
condition as a result of counter party non-performance.
Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The
trust investments for decommission and SNF disposal, reported in other assets,
are recorded at market value. At December 31, 2000 and 1999 the fair values of
the trust investments were $873 million and $795 million, respectively, and had
a cost basis of $768 million and $696 million, respectively. The change in
market value in 2000, 1999, and 1998 was a net unrealized holding gain of $6
million, $18 million, and $32 million, respectively.
At December 31, 2000 and 1999 the fair value of CPL's trust investments for
decommissioning were $94 million and $86 million, respectively, and had a cost
basis of $70 million and $60 million, respectively. The change in market value
for CPL was a net unrealized holding loss of $3 million in 2000 and a net
unrealized holding gain of $10 million and $8 million in 1999 and 1998,
respectively. At December 31, 2000 and 1999 the fair value of I&M's trust
investments for decommissioning and SNF disposal were $779 million and $708
million, respectively, and had a cost basis of $698 million and $636 million,
respectively. The change in market value for I&M in 2000, 1999, and 1998 was a
net unrealized holding gain of $9 million, $8 million and $24 million,
respectively.
CitiPower entered into several interest rate swap agreements for $425 million of
borrowings under a credit facility. The swap agreements involve the exchange of
floating-rate for fixed-rate interest payments. Interest is recognized currently
based on the fixed rate of interest resulting from use of these swap agreements.
Market risks arise from the movements in interest rates. If counter parties to
an interest rate swap agreement were to default on contractual payments,
CitiPower could be exposed to increased costs related to replacing the original
agreement. However, CitiPower does not anticipate non-performance by any counter
party to any interest rate swap in effect as of December 31, 2000. As of
December 31, 2000, CitiPower was a party to interest rate swaps having an
aggregate notional amount of $626 million, with $224 million maturing on
December 31, 2003, and $201 million maturing on December 29, 2003, $201 million
commencing on December 29, 2003 and maturing on December 30, 2005. The average
fixed interest rate payable on the aggregate of the interest rate swaps is
5.84%. The average floating rate for interest rate swaps was 6.04% at December
31, 2000. The estimated fair value of the interest rate swaps, which represents
the estimated amount CitiPower would receive to terminate the swaps at December
31, 2000, based on quoted interest rates, is a net receivable of less than a
million dollars.
CitiPower entered into interest rate swap agreement for $112 million in January
2000, for the purpose of hedging a capital markets bond issue. The interest rate
swap agreement exchanges a fixed-rate for a floating interest rate up to January
15, 2007. The $112 million interest rate swap agreement was terminated on
December 18, 2000. The gain of $9 million earned upon termination of the swap
agreement has been deferred and will be amortized through January 15, 2007.
The CSW UK Holdings Group (Group) entered into two currency swaps in 1996 in
respect of two tranches of $200 million notes ("Yankee Bonds") repayable on
August 1, 2001 and August 1, 2006. The swaps convert fixed rate semi-annual U.S.
Dollar interest payments at 6.95% and 7.45% to fixed rate sterling. As a result
of the swaps the effective fixed sterling interest rates, including fees, are
7.98% and 8.75%. The estimated fair value of these swaps at December 31, 2000 is
a net payable of $1 million.
The Group also has an interest in two interest rate swaps entered into by its
joint venture associate Power Asset Development Company Limited in 1998. The
swaps convert floating rate interest payable on a $157 million bank project
finance borrowing, maturing in 2021, to 6.00% fixed rate. The estimated fair
value of these swaps at December 31, 2000 is a net payable of $3 million of
which the Group's interest is $1 million.
In addition, at December 31, 2000, the Group has an interest in a currency swap
and an interest rate swap entered into by another joint venture associate, South
Coast Power Limited. The estimated fair value of these swaps is a net receivable
of $3 million of which the Group's share is $1 million.
In accordance with the debt covenants included in the financing provisions of
its credit facility, CitiPower must hedge at least 80% of its energy purchase
requirements through energy trading derivative instruments entered into with
market participants, predominantly generators. As of December 31, 2000,
CitiPower had outstanding energy trading derivatives with a total contracted
load of 10,144 GWH's. The maturities for these contracts range from three months
to six years. Management's estimate of the fair value of these derivatives as of
December 31, 2000 is $7 million in excess of net contract value.
SEEBOARD manages its energy purchase costs through energy trading derivative
instruments entered into with market participants. The Company buys derivative
instruments to hedge purchase costs only and does not enter into any speculative
trades. As of December 31, 2000, SEEBOARD had outstanding energy trading
derivatives with a total contracted volume of 14,059 GWH's excluding Medway
Power Limited. These contracts have maturities in the range of 1 to 27 months.
In addition SEEBOARD has a 15 year contract with Medway Power Limited which owns
and operates a 675 MW combined cycle gas generating station. SEEBOARD also has a
37.5% equity interest in Medway Power Limited. There are 29,025 GWH remaining
under the contract which has 10 years and 9 months to run.
Management's estimate of the fair value of these derivatives as of December 31,
2000 is $132 million below net contract value.
16. Income Taxes:
The details of AEP's consolidated income taxes as reported are as follows:
Year Ended December 31,
------------------------------
2000 1999 1998
---- ---- ----
(in millions)
Federal:
Current $ 766 $308 $492
Deferred (237) 129 (43)
----- ---- ----
Total 529 437 449
----- ---- ----
State:
Current 50 25 30
Deferred (9) - -
----- ---- ----
Total 41 25 30
----- ---- ----
International:
Current 6 3 14
Deferred 21 17 9
----- ---- -----
Total 27 20 23
----- ---- -----
Total Income Tax
as Reported $ 597 $482 $502
===== ==== ====
The details of the registrant subsidiaries income taxes as reported are as
follows:
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 8,746 $129,165 $ 89,403 $120,494 $ 134,796
Deferred (5,842) 3,838 16,263 (7,746) (126,748)
Deferred Investment Tax Credits - (2,947) (5,207) (3,379) (7,524)
------- -------- -------- -------- ---------
Total 2,904 130,056 100,459 109,369 524
------- -------- -------- -------- ---------
Charged (Credited) to
Nonoperating Income (net):
Current (44) 327 (5,073) 3,777 2,950
Deferred - 4,764 - 3,683 1,569
Deferred Investment Tax Credits (3,396) (1,968) - (103) (330)
------- -------- ------- -------- ---------
Total (3,440) 3,123 (5,073) 7,357 4,189
------- -------- ------- -------- ---------
Total Income Tax as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713
======= ======== ======= ======== =========
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $17,878 $259,608 $11,597 $16,073 $ 6,774
Deferred 2,521 (70,263) 25,453 14,653 9,401
Deferred Investment Tax Credits (1,187) (1,824) (1,791) (4,482) (1,271)
------- -------- ------- ------- -------
Total 19,212 187,521 35,259 26,244 14,904
------- -------- ------- ------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (50) 15,426 (1,306) (1,476) (222)
Deferred 1,244 4,307 - - (1,237)
Deferred Investment Tax Credits (65) (1,575) - - -
------- ------- ------- ------- --------
Total 1,129 18,158 (1,306) (1,476) (1,459)
------- ------- ------- ------- -------
Total Income Tax as Reported $20,341 $205,679 $33,953 $24,768 $13,445
======= ======== ======= ======= =======
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 1999 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 7,713 $69,522 $ 89,112 $79,410 $(67,368)
Deferred (5,282) 8,981 19,620 9,737 85,345
Deferred Investment Tax Credits - (2,659) (5,207) (3,432) (7,547)
------- ------- -------- ------- --------
Total 2,431 75,844 103,525 85,715 10,430
------- ------- -------- ------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (146) (1,548) (5,604) (3,122) 1,529
Deferred - 4,052 318 744 382
Deferred Investment Tax Credits (3,448) (2,313) - (562) (605)
------- ------- -------- ------- --------
Total (3,594) 191 (5,286) (2,940) 1,306
------- ------- -------- ------- --------
Total Income Taxes as Reported $(1,163) $76,035 $ 98,239 $82,775 $ 11,736
======= ======= ======== ======= ========
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 1999 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $14,897 $135,540 $20,777 $ 60,169 $ 3,328
Deferred 2,239 4,205 14,521 (17,347) 12,026
Deferred Investment Tax Credits (1,193) (1,825) (1,791) (4,565) (1,275)
------- -------- ------- -------- -------
Total 15,943 137,920 33,507 38,257 14,079
------- -------- ------- -------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (424) (3,256) (2,215) (4,826) 858
Deferred 357 (539) - - -
Deferred Investment Tax Credits (99) (1,633) - - -
------- -------- ------- -------- -------
Total (166) (5,428) (2,215) (4,826) 858
------- -------- ------- -------- -------
Total Income Taxes as Reported $15,777 $132,492 $31,292 $ 33,431 $14,937
======= ======== ======= ======== =======
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 1998 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $(2,556) $63,291 $128,942 $62,123 $43,103
Deferred 5,544 (143) (8,328) 17,612 21,073
Deferred Investment Tax Credits - (2,671) (3,858) (3,498) (7,593)
------- ------- -------- ------- -------
Total 2,988 60,477 116,756 76,237 56,583
------- ------- -------- ------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (45) (4,902) (2,204) (3,795) (594)
Deferred - (2,195) - (511) (3,168)
Deferred Investment Tax Credits (3,454) (2,594) - (726) (673)
------- ------- -------- ------- -------
Total (3,499) (9,691) (2,204) (5,032) (4,435)
------- ------- -------- ------- -------
Total Income Taxes as Reported $ (511) $50,786 $114,552 $71,205 $52,148
======= ======= ======== ======= =======
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 1998 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $10,788 $120,932 $52,587 $ 64,463 $28,542
Deferred 3,967 3,907 (1,651) (11,909) (6,626)
Deferred Investment Tax Credits (1,202) (1,827) (1,795) (4,631) (1,321)
------- -------- ------- -------- -------
Total 13,553 123,012 49,141 47,923 20,595
------- -------- ------- -------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (794) (5,619) (93) (1,868) (454)
Deferred (360) (865) - - -
Deferred Investment Tax Credits (213) (1,698) - - -
------- -------- ------- -------- --------
Total (1,367) (8,182) (93) (1,868) (454)
------- -------- ------- -------- -------
Total Income Taxes as Reported $12,186 $114,830 $49,048 $ 46,055 $20,141
======= ======== ======= ======== =======
The following is a reconciliation for AEP Consolidated of the difference between
the amount of federal income taxes computed by multiplying book income before
federal income taxes by the statutory tax rate, and the amount of income taxes
reported.
Year Ended December 31,
---------------------------------
2000 1999 1998
---- ---- ----
(in millions)
Net Income $267 $ 972 $ 975
Extraordinary Items
(net of income tax $44 million in 2000 and
$8 million in 1999) 35 14 -
Preferred Stock Dividends 11 19 19
---- ------ ------
Income Before Preferred Stock Dividends
of Subsidiaries 313 1,005 994
Income Taxes 597 482 502
---- ------ ------
Pre-Tax Income $910 $1,487 $1,496
==== ====== ======
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $319 $520 $524
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 77 71 67
Corporate Owned Life Insurance 247 2 (16)
Foreign Tax Credits (31) (63) (49)
Investment Tax Credits (net) (36) (38) (37)
Merger Transaction Costs 49 - -
State Income Taxes 26 16 19
International 18 13 15
Other (72) (39) (21)
---- ---- ----
Total Income Taxes as Reported $597 $482 $502
==== ==== ====
Effective Income Tax Rate 65.5% 32.5% 33.6%
==== ==== ====
Shown below is a reconciliation for each AEP registrant subsidiary of the
difference between the amount of federal income taxes computed by multiplying
book income before federal income taxes by the statutory rate, and the amount of
income taxes reported.
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 2000 (in thousands)
Net Income (Loss) $7,984 $ 73,844 $189,567 $ 94,966 $(132,032)
Extraordinary (Gains) Loss (1,066) 39,384
Income Tax Benefit - (7,872) - (14,148) -
Income Taxes (536) 133,179 95,386 116,726 4,713
------ -------- -------- -------- ---------
Pre-Tax Income (Loss) $7,448 $198,085 $284,953 $236,928 $(127,319)
====== ======== ======== ======== =========
Income Tax on Pre-Tax Income (Loss)
at Statutory Rate (35%) $ 2,607 $ 69,330 $99,733 $ 82,925 $(44,561)
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 452 7,606 7,556 10,529 20,378
Corporate Owned Life Insurance - 54,824 - 29,259 42,587
Nuclear Fuel Disposal Costs - - - - (3,957)
Allowance for Funds Used
During Construction (1,070) - - - (2,211)
Rockport Plant Unit 2 Investment
Tax Credit 374 - - - -
Removal Costs - (1,197) - - -
Investment Tax Credits (net) (3,396) (4,915) (5,207) (3,482) (7,854)
State Income Taxes 784 9,950 2,296 89 6,004
Other (287) (2,419) (8,992) (2,594) (5,673)
------- -------- ------- -------- --------
Total Income Taxes as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713
======= ======== ======= ======== ========
Effective Income Tax Rate N.M. 67.2% 33.5% 49.3% N.M.
==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 2000 (in thousands)
Net Income $20,763 $ 83,737 $ 66,663 $72,672 $27,450
Extraordinary Loss 40,157
Income Tax Benefit - (21,281) - - -
Income Taxes 20,342 205,679 33,953 24,768 13,445
------- -------- -------- ------- -------
Pre-Tax Income $41,105 $308,292 $100,616 $97,440 $40,895
======= ======== ======== ======= =======
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $14,387 $107,903 $35,216 $ 34,104 $14,313
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 1,827 27,577 - - 1,204
Corporate Owned Life Insurance 5,149 84,453 - - -
Nuclear Fuel Disposal Costs - - - - -
Allowance for Funds Used
During Construction - - - - -
Rockport Plant Unit 2 Investment
Tax Credit - - - - -
Removal Costs (420) - - - -
Investment Tax Credits (net) (1,252) (3,398) (1,791) (4,482) (1,271)
State Income Taxes 1,597 (1,988) 3,037 1,650 -
Other (946) (8,868) (2,509) (6,504) (801)
------- -------- ------- -------- ------- -
Total Income Taxes as Reported $20,342 $205,679 $33,953 $ 24,768 $13,445
======= ======== ======= ======== =======
Effective Income Tax Rate 49.5% 66.8% 33.8% 25.4% 32.9%
==== ==== ==== ==== ====
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 1999 (in thousands)
Net Income $ 6,195 $120,492 $182,201 $150,270 $32,776
Extraordinary Loss 8,488
Income Tax Benefit - - (2,971) - -
Income Taxes (1,163) 76,035 98,239 82,775 11,736
------- -------- -------- -------- -------
Pre-Tax Income $ 5,032 $196,527 $285,957 $233,045 $44,512
======= ======== ======== ======== =======
Income Tax on Pre-Tax
Income at Statutory Rate (35%) $ 1,762 $ 68,785 $100,085 $ 81,566 $15,580
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 446 12,593 7,981 8,846 19,966
Corporate Owned Life Insurance - - - - 594
Nuclear Fuel Disposal Costs - - - - (3,347)
Allowance for Funds Used
During Construction (1,069) - - - (2,174)
Rockport Plant Unit 2
Investment Tax Credit 374 - - - -
Removal Costs - (3,220) - - -
Investment Tax Credits (net) (3,448) (4,972) (5,207) (3,994) (8,152)
State Income Taxes 467 3,305 6,965 58 (4,635)
Other 305 (456) (11,585) (3,701) (6,096)
------- -------- -------- -------- -------
Total Income Taxes as Reported $(1,163) $ 76,035 $ 98,239 $ 82,775 $11,736
======= ======== ======== ======== =======
Effective Income Tax Rate N.M. 38.7% 34.4% 35.6% 26.4%
==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 1999 (in thousands)
Net Income $25,430 $212,157 $61,508 $83,194 $26,406
Extraordinary Loss 4,632 8,402
Income Tax Benefit - - - (1,621) (2,941)
Income Taxes 15,777 132,492 31,292 33,431 14,937
------- -------- ------- -------- -------
Pre-Tax Income $41,207 $344,649 $92,800 $119,636 $46,804
======= ======== ======= ======== =======
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $14,423 $120,628 $ 32,480 $ 41,873 $16,382
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 1,843 17,517 - - 1,120
Corporate Owned Life Insurance - 198 - - -
Removal Costs (420) - - - -
Investment Tax Credits (net) (1,292) (3,458) (1,791) (4,565) (1,275)
State Income Taxes 1,809 1,090 3,054 2,924 -
Other (586) (3,483) (2,451) (6,801) (1,290)
------- -------- -------- -------- -------
Total Income Taxes as Reported $15,777 $132,492 $ 31,292 $ 33,431 $14,937
======= ======== ======== ======== =======
Effective Income Tax Rate 38.3% 38.5% 33.8% 28.0% 32.0%
==== ==== ==== ==== ====
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 1998 (in thousands)
Net Income $ 8,946 $ 93,330 $161,511 $133,044 $ 96,628
Income Taxes (511) 50,786 114,552 71,205 52,148
------- -------- -------- -------- --------
Pre-Tax Income $ 8,435 $144,116 $276,063 $204,249 $148,776
======= ======== ======== ======== ========
Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $ 2,953 $ 50,441 $ 96,623 $ 71,488 $ 52,072
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 1,105 11,667 8,170 8,604 17,257
Corporate Owned Life Insurance - (4,212) - - (3,263)
Allowance for Funds Used
During Construction (1,070) - - - (2,184)
Rockport Plant Unit 2
Investment Tax Credits 374 - - - -
Nuclear Fuel Disposal Costs - - - - (3,397)
Removal Costs - (4,200) - - -
Investment Tax Credits (net) (3,454) (5,265) (3,858) (4,224) (8,266)
State Income Taxes (203) 4,449 - 1 3,209
Mirror CWIP - - 10,055 - -
Other (216) (2,094) 3,562 (4,664) (3,280)
------- -------- -------- -------- -------
Total Income Taxes as Reported $ (511) $ 50,786 $114,552 $ 71,205 $52,148
======= ======== ======== ======== =======
Effective Income Tax Rate N.M. 35.3% 41.5% 34.9% 35.1%
==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 1998 (in thousands)
Net Income $21,676 $209,925 $ 76,909 $ 97,994 $37,725
Income Taxes 12,186 114,830 49,048 46,055 20,141
------- -------- -------- -------- -------
Pre-Tax Income $33,862 $324,755 $125,957 $144,049 $57,866
======= ======== ======== ======== =======
Income Tax on Pre-Tax Book Income
at Statutory Rate (35%) $11,852 $113,665 $ 44,085 $ 50,418 $20,253
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 1,633 16,693 - - 964
Corporate Owned Life Insurance - (5,238) - - -
Removal Costs (840) - - - -
Investment Tax Credits (net) (1,415) (3,525) (1,795) (4,631) (1,321)
State Income Taxes 1,560 1,782 4,478 3,308 -
Other (604) (8,547) 2,280 (3,040) 245
------- -------- -------- -------- -------
Total Income Taxes as Reported $12,186 $114,830 $ 49,048 $ 46,055 $20,141
======= ======== ======== ======== =======
Effective Income Tax Rate 36.0% 35.4% 39.0% 32.0% 34.9%
==== ==== ==== ==== ====
The following tables show the elements of the net deferred tax liability and the
significant temporary differences for AEP Consolidated and each registrant
subsidiary:
December 31,
--------------------------
2000 1999
---- ----
(in millions)
Deferred Tax Assets $ 1,248 $ 1,241
Deferred Tax Liabilities (6,123) (6,391)
------- -------
Net Deferred Tax Liabilities $(4,875) $(5,150)
=======- =======
Property Related Temporary Differences $(3,935) $(4,109)
Amounts Due From Customers For Future
Federal Income Taxes (415) (437)
Deferred State Income Taxes (251) (220)
Regulatory Assets Designated for Securitization (332) (332)
All Other (net) 58 (52)
------- -------
Net Deferred Tax Liabilities $(4,875) $(5,150)
======= =======
AEGCo APCo CPL CSPCo I&M
December 31, 2000 (in thousands)
Deferred Tax Assets $ 81,480 $ 178,487 $ 67,184 $ 88,198 $ 342,900
Deferred Tax Liabilities (114,408) (860,961) (1,309,981) (510,957) (830,845)
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945)
========= ========= =========== ========= =========
Property Related Temporary Differences $ (78,113) $(510,950) $ (773,454) $(343,045) $(324,198)
Amounts Due From Customers For
Future Federal Income Taxes 10,317 (95,639) (72,426) (79,959) (55,218)
Deferred State Income Taxes (5,478) (86,351) - - (69,982)
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 42,766 - - - 28,454
Accrued Nuclear Decommissioning Expense - - - - 34,702
Deferred Fuel and Purchased Power - - - - (39,395)
Deferred Cook Plant Restart Costs - - - - (42,000)
Nuclear Fuel - - - - (28,319)
Regulatory Assets Designated
for Securitization - - (332,198) - -
All Other (net) (2,420) 10,466 (64,719) 245 8,011
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945)
========= ========= =========== ========= =========
KPCo OPCo PSO SWEPCo WTU
December 31, 2000 (in thousands)
Deferred Tax Assets $ 32,807 $ 330,878 $ 60,010 $ 47,615 $ 16,604
Deferred Tax Liabilities (198,742) (952,819) (372,070) (446,819) (173,642)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038)
========= ========= ========= ========= =========
Property Related Temporary Differences $(116,109) $(586,039) $(313,248) $(375,427) $(150,264)
Amounts Due From Customers For
Future Federal Income Taxes (19,680) (110,908) 11,082 (6,015) 4,723
Deferred State Income Taxes (29,695) (14,282) (36,487) - -
Deferred Fuel and Purchased Power - (116,224) - - -
Provision for Mine Shutdown Costs - 63,995 - - -
Postretirement Benefits - 93,306 - - -
All Other (net) (451) 48,211 26,593 (17,762) (11,497)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038)
========= ========= ========= ========= =========
AEGCo APCo CPL CSPCo I&M
December 31, 1999 (in thousands)
Deferred Tax Assets $ 85,392 $ 173,038 $ 99,426 $ 79,510 $ 231,329
Deferred Tax Liabilities (121,892) (844,955) (1,334,601) (527,117) (853,486)
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (36,500) $(671,917) $(1,234,175) $(447,607) $(622,157)
========= ========= =========== ========= =========
Property Related Temporary Differences $ (84,149) $(510,143) $ (798,381) $(352,805) $(436,162)
Amounts Due From Customers For
Future Federal Income Taxes 11,283 (109,846) (74,328) (85,078) (61,311)
Deferred State Income Taxes (5,970) (76,073) - - (61,700)
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 44,716 - - - 29,752
Accrued Nuclear Decommissioning Expense - - - - 32,097
Deferred Fuel and Purchased Power - - - - (52,713)
Deferred Cook Plant Restart Costs - - - - (56,000)
Nuclear Fuel - - - - (27,512)
Regulatory Assets Designated
for Securitization - - (332,198) - -
All Other (net) (2,380) 24,145 (29,268) (9,724) 11,392
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (36,500) $(671,917) $(1,234,175) $(447,607) $(622,157)
========= ========= =========== ========= =========
KPCo OPCo PSO SWEPCo WTU
December 31, 1999 (in thousands)
Deferred Tax Assets $ 32,186 $ 234,826 $ 68,488 $ 79,056 $ 26,916
Deferred Tax Liabilities (197,193) (911,286) (350,404) (455,560) (175,908)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(165,007) $(676,460) $(281,916) $(376,504) $(148,992)
========= ========= ========= ========= =========
Property Related Temporary Differences $(114,903) $(599,863) $(308,497) $(389,680) $(153,027)
Amounts Due From Customers For Future
-
Federal Income Taxes (19,616) (108,185) 12,697 (3,366) 4,569
Deferred State Income Taxes (32,715) (22,124) (13,001) - -
Deferred Fuel and Purchase Power - (62,832) - - -
Provision for Mine Shutdown Costs - 33,105 - - -
Postretirement Benefits - 44,483 - - -
All Other (net) 2,227 38,956 26,885 16,542 (534)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(165,007) $(676,460) $(281,916) $(376,504) $(148,992)
========= ========= ========= ========= =========
The AEP System has settled with the IRS all issues from the audits of its
consolidated federal income tax returns for the years prior to 1991. Returns for
the years 1991 through 1999 are presently being audited by the IRS. Management
is not aware of any issues for open tax years that upon final resolution are
expected to have a material adverse effect on results of operations.
17. Supplementary Information:
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in millions)
AEP Consolidated Purchased Power -
Ohio Valley Electric Corporation $86 $64 $43
(44.2% owned by AEP System)
Cash was paid for:
Interest (net of capitalized amounts) $842 $979 $859
Income Taxes $449 $270 $540
Noncash Investing and Financing Activities:
Acquisitions under Capital Leases $118 $80 $119
Assumption of Liabilities Related to Acquisitions - - $152
The amounts of power purchased by the registrant subsidiaries from Ohio Valley
Electric Corporation, which is 44.2% owned by the AEP System, for the years
ended December 31, 2000, 1999, and 1998 were:
Year Ended
December 31, APCo CSPCo I&M OPCo
------------ ---- ----- --- ----
(in thousands)
2000 $30,998 $8,706 $15,204 $31,134
1999 21,774 6,006 10,227 25,623
1998 10,388 5,947 14,271 12,006
18. Leases:
Leases of property, plant and equipment are for periods up to 35 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have purchase or renewal options and will be renewed or
replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment. The components of
rental costs are as follows:
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2000 (in thousands)
Lease Payments on
Operating Leases $216,000 $73,858 $ 7,128 $ 7,683 $ 81,446 $1,978 $51,981
Amortization of Capital Leases 121,000 281 13,900 7,776 26,341 3,931 37,280
Interest on Capital Leases 38,000 55 3,930 2,690 10,908 1,054 9,584
-------- ------- ------- ------- -------- ------ -------
Total Lease Rental Costs $375,000 $74,194 $24,958 $18,149 $118,695 $6,963 $98,845
======== ======= ======= ======= ======== ====== =======
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 1999 (in thousands)
Lease Payments on
Operating Leases $247,000 $74,269 $ 5,647 $ 5,687 $ 81,611 $ 199 $ 60,026
Amortization of Capital Leases 97,000 364 13,749 7,427 11,320 4,299 35,622
Interest on Capital Leases 35,000 64 4,267 2,720 9,338 1,162 9,552
-------- ------- ------- ------- -------- ------ --------
Total Lease Rental Costs $379,000 $74,697 $23,663 $15,834 $102,269 $5,660 $105,200
======== ======= ======= ======= ======== ====== ========
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 1998 (in thousands)
Lease Payments on
Operating Leases $257,000 $76,387 $ 7,047 $ 8,107 $ 88,297 $ 931 $ 59,141
Amortization of Capital Leases 91,000 560 13,561 6,530 10,717 4,265 36,585
Interest on Capital Leases 37,000 97 3,541 2,626 10,302 1,173 14,309
-------- ------- ------- ------- -------- ------ --------
Total Lease Rental Costs $385,000 $77,044 $24,149 $17,263 $109,316 $6,369 $110,035
======== ======= ======= ======= ======== ====== ========
CPL, PSO, SWEPCo and WTU do not have any operating leases.
Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2000 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 42,000 $2,017 $ 6,276 $ 2 $ 7,023 $ 1,730 $ 24,709
Distribution 151,000 14,595
Other:
Nuclear Fuel
(net of amortization) 90,000 89,872
Mining Assets and Other 619,000 177 93,437 $68,352 97,383 22,072 200,308
-------- ------ ------- ------- -------- ------- ---------
Total Property, Plant
and Equipment 902,000 2,194 99,713 68,354 208,873 23,802 225,017
Accumulated Amortization 288,000 1,603 36,553 25,422 45,700 9,618 108,436
-------- ------ ------- ------- -------- ------- ---------
Net Property, Plant and
Equipment Under
Capital Leases $614,000 $ 591 $63,160 $42,932 $163,173 $14,184 $116,581
======== ====== ======= ======= ======== ======= ========
Obligations Under Capital Leases:
Noncurrent Liability $419,000 $ 358 $50,350 $35,199 $ 62,325 $11,091 $ 83,866
Liability Due Within One Year 195,000 233 12,810 7,733 100,848 3,093 32,715
-------- ------ ------- ------- -------- ------- ---------
Total Obligations Under
Capital Leases $614,000 $ 591 $63,160 $42,932 $163,173 $14,184 $116,581
======== ====== ======= ======= ======== ======= =========
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 1999 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $ 46,000 $2,350 $ 8,354 $ 8,348 $ 2,022 $ 24,428
Distribution 106,000 14,645
Other:
Nuclear Fuel
(net of amortization) 108,000 108,140
Mining Assets and Other 612,000 226 93,053 $63,386 99,367 24,225 205,209
-------- ------ -------- ------- -------- ------- --------
Total Property, Plant
and Equipment 872,000 2,576 101,407 63,386 230,500 26,247 229,637
Accumulated Amortization 262,000 1,708 36,762 23,116 42,535 11,106 93,094
-------- ------ -------- ------- -------- ------- --------
Net Property, Plant and
Equipment Under
Capital Leases $610,000 $ 868 $ 64,645 $40,270 $187,965 $15,141 $136,543
======== ====== ======== ======= ======== ======= ========
Obligations Under Capital Leases:
Noncurrent Liability $510,000 $ 592 $ 52,009 $33,031 $176,893 $11,830 $102,259
Liability Due Within One Year 100,000 276 12,636 7,239 11,072 3,311 34,284
-------- ------ -------- ------- -------- ------- --------
Total Obligations Under
Capital Leases $610,000 $ 868 $ 64,645 $40,270 $187,965 $15,141 $136,543
======== ====== ======== ======= ======== ======= ========
Properties under operating leases and related obligations are not included in
the Consolidated Balance Sheets.
CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under
capital leases.
Future minimum lease payments consisted of the following at December 31, 2000:
AEP AEGCo APCo CSPCo I&M KPCo OPCo
Capital (a) (in thousands)
- -----------
2001 $129,000 $255 $16,528 $10,480 $ 14,620 $ 3,929 $ 39,733
2002 99,000 217 15,526 9,426 13,535 3,501 21,332
2003 81,000 133 12,872 7,677 11,336 2,661 19,004
2004 63,000 20 10,336 6,331 9,397 2,004 15,445
2005 48,000 6 7,027 5,397 7,053 1,609 11,746
Later Years 397,000 1 13,748 15,376 25,427 3,417 38,710
-------- ---- ------- ------- -------- ------- ---------
Total Future Minimum
Lease Payments 817,000(a) 632 76,037 54,687 81,368 17,121 145,970
Less Estimated Interest Element 293,000 41 12,876 11,755 8,067 2,937 29,389
-------- ---- ------- ------- -------- ------- --------
Estimated Present Value of
Future Minimum Lease Payments 524,000 $591 $63,161 $42,932 73,301 $14,184 $116,581
==== ======= ======= ======= ========
Unamortized Nuclear Fuel 90,000 89,872
-------- -------- -
Total $614,000 $163,173
======== ========
(a) Minimum lease payments do not include nuclear fuel payments. The payments
are paid in proportion to heat produced and carrying charges on the
unamortized nuclear fuel balance. There are no minimum lease payment
requirements for leased nuclear fuel.
AEP AEGCo APCo CSPCo I&M KPCo OPCo
(in thousands)
Noncancellable Operating Leases
2001 $ 244,000 $ 73,854 $ 726 $ 4,314 $ 99,249 $ 29 $ 62,560
2002 236,000 73,854 425 774 97,551 26 61,787
2003 235,000 73,854 412 735 97,385 23 61,109
2004 235,000 73,854 412 735 96,467 21 61,229
2005 243,000 73,854 412 735 95,201 21 71,304
Later Years 3,090,000 1,255,518 2,888 2,820 1,434,570 232 386,629
---------- ---------- ------ ------- ---------- ---- ---------
Total Future Minimum
Lease Payments $4,283,000 $1,624,788 $5,275 $10,113 $1,920,423 $352 $704,618
========== ========== ====== ======= ========== ==== =========
19. Lines of Credit and Factoring of
Receivables:
The AEP System uses short-term debt, primarily commercial paper, to meet
fluctuations in working capital requirements and other interim capital needs.
AEP has established a money pool to coordinate short-term borrowings for certain
subsidiaries, including AEGCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU,
and also incurs borrowings outside the money pool for other subsidiaries. As of
December 31, 2000, AEP had revolving credit facilities totaling $3.5 billion to
backup its commercial paper program. At December 31, 2000, AEP had $2.7 billion
outstanding in short-term borrowings. The maximum amount of such short-term
borrowings outstanding during the year, which had a weighted average interest
rate for the year of 7.5%, was $2.7 billion during December 2000.
The registrant subsidiaries incurred interest expense for amounts borrowed from
the AEP money pool as follows
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in millions)
CPL $16.9 $14.1 $8.8
CSPCo 1.4 - -
I&M 0.8 - -
KPCo - - -
OPCo 9.2 - -
PSO 7.5 2.0 1.0
SWEPCo 4.2 4.7 1.8
WTU 2.7 0.6 0.3
Interest income earned from amounts advanced to the AEP money pool by the
registrant subsidiaries were:
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in millions)
CSPCo $ 1.1 $ - $ -
I&M 9.0 - -
KPCo 1.8 - -
OPCo 3.4 - -
PSO - - 0.6
SWEPCo - 0.1 0.1
WTU - 0.2 0.4
AEP Credit, which does not participate in the money pool, issues commercial
paper on a stand-alone basis. At December 31, 2000, AEP Credit had a $2.0
billion unsecured revolving credit agreement to back up its commercial paper
program, which had $1.2 billion outstanding. The maximum amount of such
commercial paper outstanding during the year, which had a weighted average
interest rate for the year of 6.6% was $1.5 billion during September 2000.
Outstanding short-term debt for AEP Consolidated consisted of:
December 31,
2000 1999
---- ----
(in millions)
Balance Outstanding:
Notes Payable $ 193 $ 232
Commercial Paper 4,140 2,780
------ ------
Total $4,333 $3,012
====== ======
In 2000 APCo did not participate in AEP's money pool. At December 31, 2000 and
1999, APCo had issued commercial paper in the amounts of $191.5 million and
$123.5 million, respectively. At December 31, 2000, the weighted average
interest rate for APCo's commercial paper borrowings was 8.24%. In January 2001
APCo became a participant in AEP's money pool and retired all outstanding
short-term debt.
AEP Credit factors electric customer accounts receivable for affiliated
operating companies and unaffiliated companies. AEP Credit issues commercial
paper on a stand alone basis and does not participate in the money pool. In June
2000 the factoring of customer accounts receivable for affiliated companies was
expanded as a result of the merger.
Under the factoring arrangement the registrant subsidiaries (excluding AEGCo and
APCo) sell without recourse certain of their customer accounts receivable and
accrued utility revenue balances to AEP Credit and are charged a fee based on
AEP Credit financing costs, uncollectible accounts experience for each company's
receivables and administrative costs. The costs of factoring customer accounts
receivable is reported as an operating expense. At December 31, 2000, the amount
of factored accounts receivable and accrued utility revenues for each registrant
subsidiary was as follows:
Company (in millions)
- -------
CPL $153
CSPCo 116
I&M 103
KPCo 30
OPCo 104
PSO 108
SWEPCo 91
WTU 52
The fees paid by the registrant subsidiaries to AEP Credit for factoring
customer accounts receivable were:
Year Ended December 31,
2000 1999 1998
---- ---- ----
(in millions)
CPL $15.7 $14.7 $12.8
CSPCo 10.8 - -
I&M 6.8 - -
KPCo 1.9 - -
OPCo 8.4 - -
PSO 8.3 6.5 7.7
SWEPCo 9.2 9.3 9.1
WTU 4.0 3.5 3.7
20. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for AEP Consolidated follows:
2000 Quarterly Periods Ended
-------------------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
---------- ---------- ---------- ----------
(In Millions - Except
Per Share Amounts)
- -----------------------
Operating Revenues $3,021 $3,169 $3,915 $3,589
Operating Income 428 308 873 417
Income (Loss) Before
Extraordinary Items 140 (18) 403 (223)
Net Income (Loss) 140 (9) 359 (223)
Earnings (Loss)
per Share 0.43 (0.03) 1.11 (0.68)
Fourth quarter 2000 earnings decreased $415 million from the prior year. The
decrease was primarily due to various unfavorable items including: a ruling
disallowing interest deductions claimed by AEP relating to its COLI program of
$319 million; $35 million of the Cook Plant restart costs; and a $30 million
writedown for the proposed sale of Yorkshire. Additionally, the fourth quarter
of 1999 includes a $33 million gain on the sale of Sweeney in October.
1999 Quarterly Periods Ended
-------------------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
---------- ---------- ---------- ----------
(In Millions - Except
Per Share Amounts)
- -----------------------
Operating Revenues $2,902 $2,963 $3,528 $3,014
Operating Income 525 552 802 446
Income Before
Extraordinary Items 195 190 403 198
Net Income 195 190 395 192
Earnings per Share 0.61 0.59 1.23 0.60
The unaudited quarterly financial information for each AEP registrant subsidiary
follows:
Quarterly Periods
Ended AEGCo APCo CPL CSPCo I&M
----------------- ----- ---- --- ----- ---
(in thousands)
2000
March 31
Operating Revenues $56,866 $455,595 $316,328 $298,306 $343,986
Operating Income 2,395 78,246 38,650 44,124 (15,251)
Income (Loss) Before
Extraordinary Items 2,445 47,664 8,139 27,471 (36,553)
Net Income (Loss) 2,445 47,664 8,139 27,471 (36,553)
June 30
Operating Revenues $56,928 $430,000 $437,911 $330,914 $362,272
Operating Income 1,746 58,208 95,717 50,798 (18,599)
Income (Loss) Before
Extraordinary Items 1,653 30,240 67,553 35,335 (39,181)
Net Income (Loss) 1,653 39,178 67,553 35,335 (39,181)
September 30
Operating Revenues $55,658 $475,092 $601,369 $386,583 $423,217
Operating Income 2,209 65,750 120,653 83,562 36,056
Income Before Extraordinary Items 1,972 36,112 89,974 65,542 15,190
Net Income 1,972 36,112 89,974 40,306 15,190
December 31
Operating Revenues $59,064 $499,478 $415,569 $340,605 $419,001
Operating Income 2,074 (1,050) 52,078 17,393 (36,908)
Income (Loss) Before
Extraordinary Items 1,914 (49,110) 23,901 (8,146) (71,488)
Net Income (Loss) 1,914 (49,110) 23,901 (8,146) (71,488)
Quarterly Periods
Ended KPCo OPCo PSO SWEPCo WTU
----------------- ---- ---- --- ------ ---
(in thousands)
2000
March 31
Operating Revenues $ 97,204 $545,411 $161,329 $212,156 $ 96,535
Operating Income 15,557 65,113 10,860 22,731 9,781
Income Before Extraordinary Items 8,052 46,216 1,165 7,663 3,833
Net Income 8,052 46,216 1,165 7,663 3,833
June 30
Operating Revenues $ 97,759 $540,321 $209,172 $272,409 $130,742
Operating Income 9,456 79,968 24,502 33,296 16,938
Income Before Extraordinary Items 2,449 58,233 14,700 18,786 8,070
Net Income 2,449 58,233 14,700 18,786 8,070
September 30
Operating Revenues $106,698 $582,702 $358,710 $377,442 $201,191
Operating Income 13,790 96,652 56,437 61,312 16,565
Income Before Extraordinary Items 6,761 77,061 54,329 47,537 10,670
Net Income 6,761 58,185 54,329 47,537 10,670
December 31
Operating Revenues $108,742 $559,468 $233,398 $262,203 $144,326
Operating Income 10,935 (14,906) 4,870 10,939 9,057
Income (Loss) Before
Extraordinary Items 3,501 (78,897) (3,531) (1,314) 4,877
Net Income (Loss) 3,501 (78,897) (3,531) (1,314) 4,877
In the fourth quarter of 2000 earnings for APCo, CSPCo, I&M, and OPCo were
effected by a ruling disallowing interest deductions claimed by AEP relating to
its COLI program. The unfavorable amounts are $82 million for APCo, $41 million
for CSPCo, $66 million for I&M, $8 million for KPCo and $118 million for OPCo.
Additionally I&M incurred costs in the fourth quarter of 2000 for the Cook Plant
restart of $35 million.
Quarterly Periods
Ended AEGCo APCo CPL CSPCo I&M
----------------- ----- ---- --- ----- ---
(in thousands)
1999
March 31
Operating Revenues $52,827 $427,702 $282,278 $279,067 $334,113
Operating Income 2,360 71,607 46,091 46,047 38,838
Income Before Extraordinary Items 2,614 39,261 17,020 27,418 20,070
Net Income 2,614 39,261 17,020 27,418 20,070
June 30
Operating Revenues $51,612 $373,766 $383,783 $301,419 $336,553
Operating Income 1,002 43,099 79,679 54,473 26,966
Income Before Extraordinary Items 1,222 11,036 51,024 34,559 9,745
Net Income 1,222 11,036 51,024 34,559 9,745
September 30
Operating Revenues $57,235 $441,435 $495,653 $368,946 $411,248
Operating Income 921 66,309 127,499 83,478 26,085
Income Before Extraordinary Items 958 35,661 103,989 63,719 8,084
Net Income 958 35,661 103,989 63,719 8,084
December 31
Operating Revenues $55,515 $408,034 $320,761 $280,562 $312,205
Operating Income 1,057 60,221 40,716 38,792 16,763
Income (Loss) Before
Extraordinary Items 1,401 34,534 15,685 24,574 (5,123)
Net Income (Loss) 1,401 34,534 10,168 24,574 (5,123)
Quarterly Periods
Ended KPCo OPCo PSO SWEPCo WTU
----------------- ---- ---- --- ------ ---
(in thousands)
1999
March 31
Operating Revenues $ 90,741 $518,221 $151,030 $197,064 $ 81,052
Operating Income 15,360 78,956 12,031 25,810 6,922
Income Before Extraordinary Items 8,209 60,821 2,423 12,095 932
Net Income 8,209 60,821 2,423 12,095 932
June 30
Operating Revenues $ 86,231 $498,587 $178,699 $242,888 $107,782
Operating Income 10,233 73,328 23,172 35,269 16,361
Income Before Extraordinary Items 2,995 51,865 13,955 21,411 10,116
Net Income 2,995 51,865 13,955 21,411 10,116
September 30
Operating Revenues $ 94,939 $544,451 $258,656 $312,035 $164,104
Operating Income 14,244 72,858 57,720 61,541 27,030
Income Before Extraordinary Items 7,197 56,233 50,257 44,908 21,413
Net Income 7,197 56,233 50,257 41,897 15,952
December 31
Operating Revenues $102,071 $478,004 $161,005 $219,540 $ 92,771
Operating Income 14,838 63,687 5,790 24,442 3,486
Income (Loss) Before
Extraordinary Items 7,029 43,238 (5,127) 7,791 (594)
Net Income (Loss) 7,029 43,238 (5,127) 7,791 (594)
21. Trust Preferred Securities:
The following Trust Preferred Securities issued by the wholly-owned statutory
business trusts of CPL, PSO and SWEPCo were outstanding at December 31, 2000 and
December 31, 1999. They are classified on the balance sheets as certain
subsidiaries Obligated, Mandatorily Redeemable Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of such
subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. CPL
reacquired 60,000 trust preferred units during 2000.
Units issued/ 2000 1999 Description of
outstanding Amount Amount Underlying
Business Trust Security at 12/31/00 (millions) (millions) Debentures of Registrant
- ---------------------------------------------------------------------------------------------
CPL Capital I 8.00%, Series A 5,940,000 $149 $150 CPL, $153 million,
8.00%, Series A
PSO Capital I 8.00%, Series A 3,000,000 75 75 PSO, $77 million,
8.00%, Series A
SWEPCo Capital I 7.875%, Series A 4,400,000 110 110 SWEPCO, $113 million,
---------- ---- ----
13,340,000 $334 $335 7.875%, Series A
========== ==== ====
Each of the business trusts is treated as a subsidiary of its parent company.
The only assets of the business trusts are the subordinated debentures issued by
their parent company as specified above. In addition to the obligations under
their subordinated debentures, each of the parent companies has also agreed to a
security obligation which represents a full and unconditional guarantee of its
capital trust obligation.
22. Jointly Owned Electric Utility Plant:
CPL, CSP, PSO, SWEPCo and WTU have generating units that are jointly owned with
unaffiliated companies. Each of the participating companies is obligated to pay
its share of the costs of any such jointly owned facilities in the same
proportion as its ownership interest. Each AEP registrant subsidiary's
proportionate share of the operating costs associated with such facilities is
included in its statements of income and the investments are reflected in its
balance sheets under utility plant as follows:
Company's Share
December 31,
2000 1999
-------------------------- ---------------------------
Percent Utility Construction Utility Construction
of Plant Work Plant Work
Ownership in Service in Progress in Service in Progress
--------- ------------ ------------- ------------ ------------
(in thousands) (in thousands)
CPL:
Oklaunion Generating Station
(Unit No. 1) 7.8 $ 37,236 $ 395 $ 37,236 $ -
South Texas Project Generating
Station (Units No. 1 and 2) 25.2 2,373,575 19,292 2,351,795 56,021
---------- ------- ---------- -------
$2,410,811 $19,687 $2,389,031 $56,021
========== ======= ========== ========
CSP:
W.C. Beckjord Generating Station
(Unit No. 6) 12.5 $ 14,108 $ 178 $ 13,919 $ 390
Conesville Generating Station
(Unit No. 4) 43.5 80,103 261 80,433 80
J.M. Stuart Generating Station 26.0 191,875 10,086 184,168 3,620
Wm. H. Zimmer Generating Station 25.4 706,549 5,265 701,054 6,030
Transmission (a) 61,820 451 60,333 1,210
---------- ------- ---------- -------
$1,054,455 $16,241 $1,039,907 $11,330
========== ======= ========== =======
PSO:
Oklaunion Generating Station
(Unit No. 1) 15.6 $ 81,185 $ 817 $ 81,185 $ -
========== ======= ========== ========
SWEPCo:
Dolet Hills Generating Station
(Unit No. 1) 40.2 $ 231,442 $ 1,984 $ 230,971 $ 1,771
Flint Creek Generating Station
(Unit No. 1) 50.0 82,899 852 81,895 286
Pirkey Generating Station
(Unit No. 1) 85.9 437,069 435 434,960 1,777
---------- ------- ---------- -------
$ 751,410 $ 3,271 $ 747,826 $ 3,834
========== ======= ========== ========
WTU:
Oklaunion Generating Station
(Unit No. 1) 54.7 $ 277,624 $ 3,295 $ 281,777 $ -
========== ======= ========== ========
(a) Varying percentages of ownership.
The accumulated depreciation with respect to each AEP registrant subsidiary's
share of jointly owned facilities is shown below:
December 31,
2000 1999
---- ----
(in thousands)
CPL $834,722 $758,460
CSPCo 389,558 361,113
PSO 33,669 36,374
SWEPCo 367,558 354,360
WTU 98,045 93,807
23. Related Party Transactions
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 their 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.
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.
CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Restated and
Amended Operating Agreement originally dated as of January 1, 1997 (CSW
Operating Agreement). The CSW Operating Agreement requires the operating
companies of the west zone to maintain specified annual planning reserve margins
and requires the subsidiaries that have capacity in excess of the required
margins to make such capacity available for sale to other AEP subsidiaries as
capacity commitments. The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition, disposition, planning,
design and construction of generating units and to supervise the operation and
maintenance of a central control center. The CSW Operating Agreement has been
accepted for filing and allowed to become effective by FERC.
AEP's System Integration Agreement provides for the integration and coordination
of AEP's east and west zone operating subsidiaries, joint dispatch of generation
within the AEP System, and the distribution, between the two operating zones, of
costs and benefits associated with the System's generating plants. It is
designed to function as an umbrella agreement in addition to the AEP
Interconnection Agreement and the CSW Operating Agreement, each of which will
continue to control the distribution of costs and benefits within each zone.
The following table shows the revenues derived from sales to the Pools and
direct sales to affiliates for years ended December 31, 2000, 1999 and 1998:
APCo CSPCo I&M KPCo OPCo AEGCo
Related Party Revenues (in thousands)
2000 Sales to East System Pool $ 81,013 $36,884 $200,474 $36,554 $502,140 $ -
Sales to West System Pool 7,697 4,095 4,614 1,829 6,356 -
Direct Sales To East Affiliates 59,106 - - - 66,487 227,983
Direct Sales To West Affiliates 4,092 2,262 2,510 972 3,421 -
-------- ------- -------- ------- -------- ---------
Total Revenues $151,908 $43,241 $207,598 $39,355 $578,404 $227,983
======== ======= ======== ======= ======== ========
1999 Sales to East System Pool $41,869 $15,136 $50,624 $43,157 $337,699 $ -
Direct Sales To East Affiliates 57,201 - - - 50,968 152,559
------- ------- ------- ------- -------- --------
Total Revenues $99,070 $15,136 $50,624 $43,157 $388,667 $152,559
======= ======= ======= ======= ======== ========
1998 Sales to East System Pool $36,930 $20,128 $37,561 $43,543 $363,343 $ -
Direct Sales To East Affiliates 56,753 - - - 55,167 153,537
------- ------- ------- ------- -------- --------
Total Revenues $93,683 $20,128 $37,561 $43,543 $418,510 $153,537
======= ======= ======= ======= ======== ========
CPL PSO SWEPCo WTU
Related Party Revenues (in thousands)
2000 Sales to East System Pool $ - $ - $ - $ -
Sales to West System Pool 23,421 7,323 5,546 194
Direct Sales To East Affiliates (3,348) (1,990) (3,008) (1,116)
Direct Sales To West Affiliates 12,516 21,995 62,178 7,645
------- ------- ------- -------
Total Revenues $32,589 $27,328 $64,716 $ 6,723
======= ======= ======= =======
1999 Sales to West System Pool $ 6,124 $ 3,097 $ 4,527 $ 401
Direct Sales To West Affiliates 7,470 7,968 49,542 2,576
------- ------- ------- ------
Total Revenues $13,594 $11,065 $54,069 $2,977
======= ======= ======= ======
1998 Sales to West System Pool $ 7,853 $ 3,223 $ 5,660 $ 270
Direct Sales To West Affiliates 9,798 10,196 29,811 2,190
------- ------- ------- ------
Total Revenues $17,651 $13,419 $35,471 $2,460
======= ======= ======= ======
The following table shows the purchased power expense incurred from purchases
from the Pools and affiliates for the years ended December 31, 2000, 1999, and
1998:
APCo CSPCo I&M KPCo OPCo
Related Party Purchases (in thousands)
2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 $50,339
Purchases from West System Pool 455 260 285 108 390
Direct Purchases from East Affiliates - - 158,537 69,446 -
Direct Purchases from West Affiliates 14 8 9 3 12
-------- -------- -------- -------- -------
Total Purchases $355,774 $287,750 $265,475 $127,707 $50,741
======== ======== ======== ======== =======
1999 Purchases from East System Pool $130,991 $199,574 $112,350 $19,502 $ 20,864
Direct Purchases from East Affiliates - - 88,022 64,498 -
-------- -------- -------- ------- ---------
Total Purchases $130,991 $199,574 $200,372 $84,000 $ 20,864
======== ======== ======== ======= ========
1998 Purchases from East System Pool $180,762 $167,619 $125,240 $ 9,673 $ 18,211
Direct Purchases from East Affiliates - - 86,246 67,291 -
-------- -------- -------- ------- ---------
Total Purchases $180,762 $167,619 $211,486 $76,964 $ 18,211
======== ======== ======== ======= ========
CPL PSO SWEPCo WTU
Related Party Purchases (in thousands)
2000 Purchases from East System Pool $ - $20,100 $ - $ -
Purchases from West System Pool 1,696 5,386 4,379 18,444
Direct Purchases from East Affiliates 251 2,117 - 71
Direct Purchases from West Affiliates 30,644 33,185 8,264 39,258
------- ------- ------- -------
Total Purchases $32,591 $60,788 $12,643 $57,773
======= ======= ======= =======
1999 Purchases from West System Pool $ 895 $ 6,992 $1,295 $ 7,266
Direct Purchases from West Affiliates 15,778 27,627 6,256 19,325
------- ------- ------ -------
Total Purchases $16,673 $34,619 $7,551 $26,591
======= ======= ====== =======
1998 Purchases from West System Pool $1,091 $ 5,022 $ 2,579 $ 8,314
Direct Purchases from West Affiliates 8,636 15,970 7,576 20,935
------ ------- ------- -------
Total Purchases $9,727 $20,992 $10,155 $29,249
====== ======= ======= =======
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 kw 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."
The following table shows the net (credits) or charges allocated among the
parties to the Transmission Agreement during the years ended December 31, 1998,
1999 and 2000:
1998 1999 2000
---- ---- ----
(in thousands)
APCo $ (2,400) $ (8,300) $ (3,400)
CSPCo 35,600 39,000 38,300
I&M (44,100) (43,900) (43,800)
KEPCo (6,000) (4,300) (6,000)
OPCo 16,900 17,500 14,900
CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Transmission
Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA
established a coordinating committee, which is charged with the responsibility
of overseeing the coordinated planning of the transmission facilities of the
west zone operating subsidiaries, including the performance of transmission
planning studies, the interaction of such subsidiaries with independent system
operators (ISO) and other regional bodies interested in transmission planning
and compliance with the terms of the Open Access Transmission Tariff (OATT)
filed with the FERC and the rules of the FERC relating to such tariff.
Under the TCA, the west zone operating subsidiaries have delegated to AEP
Service Corporation the responsibility of monitoring the reliability of their
transmission systems and administering the OATT on their behalf. The TCA also
provides for the allocation among the west zone operating subsidiaries of
revenues collected for transmission and ancillary services provided under the
OATT. In December 1999, the FERC approved the TCA filing based on the revised
revenue allocation ratios effective as of January 1, 1997. In January 2000, the
west zone operating companies settled among themselves, including interest,
under the revised TCA.
The following table shows the net (credits) or charges, excluding interest,
allocated among the west zone operating companies during the years ended
December 31, 1998, 1999 and 2000:
1998 1999 2000
---- ---- ----
(in thousands)
CPL $ - $ - $(15,498)
WTU 1,139 (28) (23,443)
SWEPCo 3,572 1,058 22,115
PSO (4,711) (1,030) 16,826
AEP's System Transmission Integration Agreement provides for the integration and
coordination of the planning, operation and maintenance of the transmission
facilities of AEP's east and west zone operating subsidiaries. Like the System
Integration Agreement, the System Transmission Integration Agreement functions
as an umbrella agreement in addition to the AEP Transmission Agreement and the
Transmission Coordination Agreement. The System Transmission Integration
Agreement contains two service schedules that govern:
o The allocation of transmission costs and revenues.
o The allocation of third-party transmission costs and revenues and System
dispatch costs.
The Transmission Integration Agreement anticipates that additional service
schedules may be added as circumstances warrant.
Unit Power Agreements and Other
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 expiration of the lease term of Unit 2 of the Rockport Plant
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.
APCo and OPCo, jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership interests. Each
company's share of these costs is included in the appropriate expense accounts
on each company's consolidated statements of income. Each company's investment
in these plants is included in electric utility plant on its consolidated
balance sheets.
I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from
barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid
to I&M for barging services as fuel expense. The amount of affiliated revenues
and affiliated expenses were:
Year Ended December 31,
2000 1999 1998
---- ---- ----
Company (in millions)
I&M - revenues $23.5 $28.1 $24.8
AEGCo - expense 8.8 8.5 8.8
APCo - expense 7.8 10.5 8.5
OPCo - expense 6.9 9.1 7.5
American Electric Power Service Corporation (AEPSC) provides certain managerial
and professional services to AEP System companies. The costs of the services are
billed to its affiliated companies by AEPSC on a direct-charge basis, whenever
possible, and on reasonable bases of proration for shared services. The billings
for services are made at cost and include no compensation for the use of equity
capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are
capitalized or expensed depending on the nature of the services rendered. AEPSC
and its billings are subject to the regulation of the SEC under the 1935 Act.
M-26
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS
- ----------------------------------------------------------------------------
The following is a combined presentation of management's discussion and
analysis of financial condition, contingencies and other matters for AEP and
certain of its registrant subsidiaries. Management's discussion and analysis of
results of operations for AEP and each of its subsidiary registrants is
presented with their financial statements earlier in this document. The
following is a list of sections of management's discussion and analysis of
financial condition, contingencies and other matters and the registrant to which
they apply:
Financial Condition AEP, APCo, CPL,
I&M, OPCo, SWEPCo
Market Risks AEP, AEGCo, APCo,
CPL, CSPCo, I&M,
KPCo, OPCo, PSO,
SWEPCo, WTU
Industry Restructuring AEP, APCo, CPL,
CSPCo, I&M, OPCo,
PSO, SWEPCo, WTU
Litigation AEP, APCo, CPL,
CSPCo, I&M, KPCo,
OPCo, SWEPCo, WTU
Environmental Concerns
and Issues AEP, APCo, CPL,
CSPCo, I&M, OPCo,
SWEPCo
Foreign Energy Delivery, AEP
Worldwide Energy
Investments and Other
Business Operations
Other Matters AEP, AEGCo, APCo,
CPL, CSPCo, I&M,
KPCo, OPCo, PSO,
SWEPCo, WTU
Financial Condition - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo
The Cook Plant extended outage and related restart expenditures
negatively affected AEP's 2000 earnings and cash flows and the write-off related
to COLI and non-regulated subsidiaries further depressed earnings. Although the
2000 dividend payout ratio was 289%, it is expected that the ratio will improve
significantly as a result of earnings growth in 2001. It has been a
management objective to reduce the payout ratio by increasing earnings.
Management expects to grow future earnings by growing the wholesale business and
by controlling operations and maintenance costs.
AEP's common equity to total capitalization, including long-term debt
due within one year and short-term debt, decreased from 37% in 1999 to 34% in
2000. Preferred stock at 1% remained unchanged. Long-term debt decreased from
50% to 47%, while short-term debt increased from 12% to 18%. AEP's intention is
to maintain flexibility during corporate separation by issuing floating rate
debt. In 2000, AEP did not issue any shares of common stock to meet the
requirements of the Dividend Reinvestment and Direct Stock Purchase Plan and the
Employee Savings Plan. Sales of common stock and/or equity linked securities may
be necessary in the future to support AEP's plan to grow the business.
Expenditures by the AEP System for domestic electric utility
construction are estimated to be $6 billion for the next three years.
Approximately 70% of those construction expenditures are expected to be financed
by internally generated funds.
Construction expenditures for the registrant subsidiaries for the next
three years excluding AFUDC are:
Construction
Projected Expenditures
Construction Financed with
Expenditures Internal Funds
(in millions)
APCo $1,122.8 79%
I&M 427.2 ALL
OPCo 1,044.5 ALL
CPL 745.1 NONE
SWEPCo 405.6 70%
The year-end ratings of the subsidiaries' first mortgage bonds are
listed in the following table:
Company Moody's S&P Fitch
APCo A3 A A-
CSPCo A3 A- A
I&M Baa1 A- BBB+
KPCo Baa1 A- BBB+
OPCo A3 A- A-
CPL A3 A- A
PSO A1 A A+
SWEPCo A1 A A+
WTU A2 A- A
The ratings at the end of the year for senior unsecured debt issued by
the subsidiaries are listed in the following table:
Company Moody's S&P Fitch
AEP Resources* Baa2 BBB+ BBB+
APCo Baa1 BBB+ BBB+
CSPCo Baa1 BBB+ A-
I&M Baa2 BBB+ BBB
KPCo Baa2 BBB+ BBB
OPCo Baa1 BBB+ BBB+
CPL Baa1 BBB+ A-
PSO A2 BBB+ A
SWEPCo A2 BBB+ A
WTU A3 BBB+ -
o The rating is for a series of senior notes issued with a Support Agreement
from AEP.
Financing Activity
Debt was issued in 2000 for the funding of debt maturities, for
construction programs and for the growth of the wholesale business. AEP and its
subsidiaries issued $1.1 billion principal amount of long-term obligations in
2000 at variable interest rates with due dates ranging from 2001 to 2007. The
principal amount of long-term debt retirements, including maturities, totaled
$1.6 billion with interest rates ranging from 5.25% to 9.6%.
The principal amount of long-term obligations issued and retired in 2000
by the registrant subsidiaries was:
Issuance Retirements
(in thousands)
APCo $ 75,000 $136,000
I&M 200,000 148,000
OPCo 75,000 32,102
CPL 150,000 150,000
SWEPCo 150,000 45,595
The domestic electric utility subsidiaries generally issue short-term
debt to provide for interim financing of capital expenditures that exceed
internally generated funds. They periodically reduce their outstanding
short-term debt through issuances of long-term debt and additional capital
contributions by the parent company. The sources of funds available to the
parent company, AEP, are dividends from its subsidiaries, short-term and
long-term borrowings and proceeds from the issuance of common stock.
The subsidiaries formed to pursue worldwide electric and gas
opportunities use short-term debt and capital contributions from the parent
company for interim financing of working capital and acquisitions. Short-term
debt is replaced with long-term debt when financial market conditions are
favorable. Some acquisitions of existing business entities include the
assumption of their outstanding debt.
The AEP System uses short-term debt, primarily commercial paper, to meet
fluctuations in working capital requirements and other interim capital needs.
AEP has established a system money pool to meet the short-term borrowings for
certain of its subsidiaries, including AEGCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU. In January 2001 APCo became a participant in AEP's money pool
and retired all outstanding short-term debt. In addition, AEP also funds the
short-term debt requirements of other subsidiaries that are not included in the
money pool. As of December 31, 2000, AEP had back up credit facilities totaling
$3.5 billion to support its commercial paper program. At December 31, 2000, AEP
had $2.7 billion outstanding in short-term borrowings. The maximum amount of
short-term borrowings outstanding during the year, which had a weighted average
interest rate for the year of 7.5%, was $2.7 billion during December 2000.
AEP Credit purchases, without recourse, the accounts receivable of most of the
domestic utility operating companies and certain non-affiliated electric utility
companies. The sale of accounts receivable provides the domestic electric
utility operating companies with cash immediately, thereby reducing working
capital needs and revenue requirements. In addition, AEP Credit's capital
structure contains greater leverage than that of the domestic electric utility
operating companies, so cost of capital is lowered. AEP Credit issues commercial
paper to meet its financing needs. At December 31, 2000, AEP Credit had a $2.0
billion unsecured back up credit facility to support its commercial paper
program, which had $1.2 billion outstanding. The maximum amount of such
commercial paper outstanding during the year, which had a weighted average
interest rate of 6.6%, was $1.5 billion during September 2000.
Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU
AEP as a major power producer and a trader of wholesale electricity and
natural gas has certain market risks inherent in its business activities. The
trading of electricity and natural gas and related financial derivative
instruments exposes AEP to market risk. Market risk represents the risk of loss
that may impact due to changes in commodity market prices and rates. Policies
and procedures have been established to identify, assess, and manage market risk
exposures including the use of a risk measurement model which calculates Value
at Risk (VaR). The VaR is based on the variance - covariance method using
historical prices to estimate volatilities and correlations and assuming a 95%
confidence level and a one-day holding period. Throughout the year ending
December 31, 2000 the average, high, and low VaRs in the wholesale electricity
and gas trading portfolio were $10 million, $32 million, and $1 million,
respectively. The average, high, and low VaRs for the year ending December 31,
1999 were $4 million, $8 million, and $1 million, respectively. Based on this
VaR analysis, at December 31, 2000 a near term typical change in commodity
prices is not expected to have a material effect on AEP's results of operations,
cash flows or financial condition. The following table shows the high and
average U.S. electricity market risk as measured by VaR allocated to the AEP
registrant subsidiaries based upon the AEP System's trading activities in the
U.S. Low VaR is excluded because all companies are under $1 million.
VaR for Registrant Subsidiaries:
December 31,
2000 1999
---- ----
High Average High Average
(in millions)
APCo $2 $6 $1 $2
CPL 1 4 - -
CSPCo 1 3 1 1
I&M 1 4 1 2
KPCo - 1 - 1
OPCo 2 5 1 2
PSO 1 3 - -
SWEPCo 1 4 - -
WTU - 1 - -
Investments in foreign ventures expose AEP to risk of foreign currency
fluctuations. AEP's exposure to changes in foreign currency exchange rates
related to these foreign ventures and investments is not expected to be
significant for the foreseeable future.
AEP is exposed to changes in interest rates primarily due to short-and
long-term borrowings to fund its business operations. AEP measures interest rate
market risk exposure utilizing a VaR model. The interest rate VaR model is based
on a Monte Carlo simulation with a 95% confidence level and a one year holding
period. The volatilities and correlations were based on three years of weekly
prices. The risk of potential loss in fair value attributable to AEP's exposure
to interest rates, primarily related to long-term debt with fixed interest
rates, was $998 million at December 31, 2000 and $966 million at December 31,
1999. The following table shows the potential loss in fair value as measured by
VaR allocated to the AEP registrant subsidiaries based upon debt outstanding:
VaR for Registrant Subsidiaries:
December 31,
2000 1999
---- ----
(in millions)
Company
AEGCo $ 4 $ 4
APCo 149 144
CPL 135 131
CSPCo 84 81
I&M 129 125
KPCo 31 30
OPCo 112 109
PSO 44 42
SWEPCo 60 58
WTU 24 23
AEP and its registrant subsidiaries would not expect to liquidate its
entire debt portfolio in a one year holding period. Therefore, a near term
change in interest rates should not materially affect results of operations or
the consolidated financial position of AEP and its registrant subsidiaries. AEP
is currently utilizing interest rate swaps as a hedge to manage its exposure to
interest rate fluctuations in the U.K. and Australia.
AEP has investments in debt and equity securities which are held in
nuclear trust funds. The trust investments and their fair value are discussed in
Note 15 of the Notes to Consolidated Financial Statements. Instruments in the
trust funds have not been included in the market risk calculation for interest
rates as these instruments are marked-to-market and changes in market value are
reflected in a corresponding decommissioning liability. Any differences between
the trust fund assets and the ultimate liability should be recoverable from
ratepayers.
AEGCo is not exposed to risk from changes in interest rates on
short-term and long-term borrowings used to finance oper-ations since financing
costs are recovered through the unit power agreements.
Inflation affects the AEP's System's cost of replacing utility plant and
the cost of operating and maintaining its plant. The rate-making process limits
recovery to the historical cost of assets, resulting in economic losses when the
effects of inflation are not recovered from customers on a timely basis.
However, economic gains that result from the repayment of long-term debt with
inflated dollars partly offset such losses.
Industry Restructuring
In 2000 California's deregulated energy market suffered problems
including high energy prices, short energy supply, and financial difficulties
for retail energy suppliers whose prices to customers are controlled. This
energy crisis has highlighted the importance of risk management and has
contributed to certain state regulatory and legislative actions which could
delay the start of customer choice and the transition to competitive, market
based pricing for retail electricity supply in some of the states in which the
AEP System companies operate. Seven of the eleven state retail jurisdictions in
which the domestic electric utility companies operate have enacted restructuring
legislation. In general, the legislation provides for a transition from
cost-based regulation of bundled electric service to customer choice and market
pricing for the supply of electricity. As legislative and regulatory proceedings
evolve, six of the electric operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo
and WTU) doing business in five of the seven states that have passed
restructuring legislation have discontinued the application of SFAS 71
regulatory accounting for generation. The seven states in various stages of
restructuring to transition generation to market based pricing are Arkansas,
Michigan, Ohio, Oklahoma, Texas, Virginia, and West Virginia. PSO and I&M have
not discontinued regulatory accounting for their generation business in Oklahoma
and Michigan, respectively, pending the implementation of the legislation. The
following is a summary of restructuring legislation, the status of the
transition plans and the status of the electric utility companies' accounting to
comply with the changes in each of the AEP System's seven state regulatory
jurisdictions affected by restructuring legislation.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001, customer choice of electricity supplier
began under the Ohio Act. In February 2001, one supplier announced its plan to
offer service to CSPCo's residential customers. Currently for residential
customers of OPCo, no alternative suppliers have registered with the PUCO as
required by the Ohio Act. Two alternative suppliers have been approved to
compete for CSPCo's and OPCo's commercial and industrial customers. Presently,
customers continue to be served by CSPCo and OPCo with a legislatively required
residential rate reduction of 5% for the generation portion of rates and a
freezing of generation rates including fuel rates starting on January 1, 2001.
The Ohio Act provides for a five-year transition period to move from
cost based rates to market pricing for generation services. It granted the PUCO
broad oversight responsibility for promulgation of rules for competitive retail
electric generation service, approval of a transition plan for each electric
utility company and addressing certain major transition issues including
unbundling of rates and the recovery of stranded costs including regulatory
assets and transition costs.
The Ohio Act also provides for a reduction in property tax
assessments, the imposition of replacement franchise and income taxes, and the
replacement of a gross receipts tax with a KWH based excise tax. The property
tax assessment percentage on generation property was lowered from 100% to 25% of
value effective January 1, 2001 and Ohio electric utilities will become subject
to the Ohio Corporate Franchise Tax and municipal income taxes on January 1,
2002. The last year for which Ohio electric utilities will pay the excise tax
based on gross receipts is the tax year ending April 30, 2002. As of May 1, 2001
electric distribution companies will be subject to an excise tax based on KWH
sold to Ohio customers. The gross receipts tax is paid at the beginning of the
tax year (May 1), deferred by CSPCo and OPCo as a prepaid expense and amortized
to expense during the tax year pursuant to the tax law whereby the payment of
the tax results in the privilege to conduct business in the year following the
payment of the tax. As a result a duplicate tax will be expensed from May 1,
2001 through April 30, 2002 adding approximately $90 million to AEP consolidated
tax expense ($40 million for CSPCo and $50 million for OPCo) during that period.
Unless the companies can recover the duplicate amount from ratepayers it will
negatively impact results of operations.
On September 28, 2000, the PUCO approved, with minor modifications, a
stipulation agreement between CSPCo, OPCo, the PUCO staff, the Ohio Consumers'
Counsel and other concerned parties regarding transition plans filed by CSPCo
and OPCo. The key provisions of this stipulation agreement are:
o Recovery of generation-related regulatory assets at December 31, 2000 over
seven years for OPCo ($518 million) and over eight years for CSPCo ($248
million) through frozen transition rates for the first five years of the
recovery period and a wires charge for the remaining years.
o A shopping incentive (a price credit) of 2.5 mills per KWH for the first
25% of CSPCo residential customers that switch suppliers. There is no
shopping incentive for OPCo customers.
o The absorption of $40 million by CSPCo and OPCo ($20 million per company)
of consumer education, implementation and transition plan filing costs with
deferral of the remaining costs, plus a carrying charge, as a regulatory
asset for recovery in future distribution rates.
o CSPCo and OPCo will make available a fund of up to $10 million to reimburse
customers who choose to purchase their power from another company for
certain transmission charges imposed by PJM and/or a Midwest ISO on
generation originating in the Midwest ISO or PJM areas.
o The statutory 5% reduction in the generation component of residential
tariffs will remain in effect for the entire five year transition period.
o The companies' request for a $90 million ($40 million for CSPCo and $50
million for OPCo) gross receipts tax rider to recover the duplicate gross
receipts KWH based excise tax would be considered separately by the PUCO.
The approved stipulation agreement also accepted the following
provisions contained in CSPCo's and OPCo's filed transition plans:
o a corporate separation plan to segregate generation, transmission and
distribution assets into separate legal entities, and o a plan for independent
operation of transmission facilities.
The gross receipts tax issue was considered by the PUCO in hearings held
in June 2000. In the September 28, 2000 order approving the stipulation
agreement, the PUCO determined that there was no duplicate tax overlap period
and denied the request for a $90 million ($40 million for CSPCo and $50 million
for OPCo) gross receipts tax rider. CSPCo's and OPCo's request for rehearing of
the gross receipts tax issue was denied. An appeal of this issue to the Ohio
Supreme Court has been filed. Unless this issue is resolved in the companies'
favor, it will have an adverse effect on future results of operations and
financial position.
One of the intervenors at the hearings for approval of the settlement
agreement (whose request for rehearing was denied by the PUCO) has filed with
the Ohio Supreme Court for review of the settlement agreement including recovery
of regulatory assets. Management is unable to predict the outcome of litigation
but the resolution of this matter could negatively impact results of operations.
Beginning January 1, 2001, CSPCo's and OPCo's fuel costs will not be
subject to PUCO fuel recovery proceedings. Deferred fuel costs at December 31,
2000 which represent under or over recoveries were one of the items included in
the PUCO's final determination of net regulatory assets to be collected
(recovered) during the transition period. The elimination of fuel clause
recoveries in 2001 in Ohio will subject AEP, CSPCo and OPCo to the risk of fuel
market price increases and could adversely affect their future results of
operations and cash flows.
CSPCo and OPCo Discontinue Application of SFAS 71 Regulatory Accounting for the
Ohio Jurisdiction
In September 2000 CSPCo and OPCo discontinued the application of SFAS 71
for their Ohio retail jurisdictional generation business since generation is no
longer cost-based regulated in the Ohio jurisdiction and management was able to
determine their transition rates and wires charges. The discontinuance in the
Ohio jurisdiction was possible as a result of the PUCO's September 28, 2000
approval of the stipulation agreement which established rates, wires charges and
net regulatory asset recovery procedures during the transition to market rates.
CSPCo's and OPCo's discontinuance of SFAS 71 for generation resulted in
after tax extraordinary losses in the third quarter of 2000 of $25 million and
$19 million, respectively, due to certain unrecoverable generation-related
regulatory assets and transition expenses. Management believes that
substantially all of the remaining net regulatory assets related to the Ohio
generation business will be recovered under the PUCO's September 28, 2000 order.
Therefore, under the provisions of EITF 97-4, CSPCo's and OPCo's
generation-related recoverable net regulatory assets were transferred to the
transmission and distribution portion of the business and will be amortized as
they are recovered through transition rates to customers. CSPCo and OPCo
performed an accounting impairment analysis on their generating assets under
SFAS 121 as required when discontinuing the application of SFAS 71 and concluded
there was no impairment of generation assets.
Virginia Restructuring - Affecting AEP and APCo
In Virginia, a restructuring law provides for a transition to choice of
electricity supplier for retail customers beginning on January 1, 2002. In
February 2001, restructuring revision legislation was approved by the Virginia
Legislature which could modify the terms of restructuring. Presently, the
transition period is to be completed, subject to a finding by the Virginia SCC
that an effective competitive market exists by January 1, 2004 but no later than
January 1, 2005.
The restructuring law also provides an opportunity for recovery of just
and reasonable net stranded generation costs. The mechanisms in the Virginia law
for net stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the termination
of the rate cap. The restructuring law provides for the establishment of capped
rates prior to January 1, 2001 based either on a request by APCo for a change in
rates prior to January 1, 2001 or on the rates in effect at July 1, 1999 if no
rate change request is made and the establishment of a wires charge by the
fourth quarter of 2001. APCo did not request new rates; therefore, its current
rates are the capped rates. In the third quarter of 2000, the Virginia SCC
directed APCo to file a cost of service study using 1999 as a test year to
review the reasonableness of APCo's capped rates. The cost of service study was
filed on January 3, 2001. In the opinion of APCo's Virginia counsel, Virginia's
restructuring law does not permit the Virginia SCC to change rates for the
transition period except for changes in the fuel factor, changes in state gross
receipts taxes, or to address the utility's financial distress. However, if the
Virginia SCC were to reduce APCo's capped rates or deny recovery of regulatory
assets, it would adversely affect results of operations if such action is
ultimately determined to be legal.
The Virginia restructuring law also requires filings to be made that
outline the functional separation of generation from transmission and
distribution and a rate unbundling plan. On January 3, 2001, APCo filed its
corporate separation plan and rate unbundling plan with the Virginia SCC which
is based on the most recent rate case test year (1996). See Note 7 of the Notes
to Consolidated Financial Statements for a discussion of AEP's corporate
separation plan filed with the SEC.
West Virginia Restructuring - Affecting AEP and APCo
On January 28, 2000, the WVPSC issued an order approving an electricity
restructuring plan for WV. On March 11, 2000, the WV Legislature approved the
restructuring plan by joint resolution. The joint resolution provides that the
WVPSC cannot implement the plan until the legislature makes necessary tax law
changes to preserve the revenues of the state and local governments. The Joint
Committee on Government and Finance of the WV Legislature hired a consultant to
study and issue a report on the tax changes required to implement electric
restructuring. Moreover, the committee also hired a consultant to study and
issue a report on the electric restructuring plan in light of events occurring
in California. The WV Legislature is not expected to consider these reports
until the 2002 Legislative Session since the 2001 Legislative Session ends in
April 2001. Since the WV Legislature has not yet passed the required tax law
changes, the restructuring plan has not become effective. AEP subsidiaries, APCo
and WPCo, provide electric service in WV.
The provisions of the restructuring plan provide for customer choice to
begin after all necessary rules are in place (the "starting date"); deregulation
of generation assets on the starting date; functional separation of the
generation, transmission and distribution businesses on the starting date and
their legal corporate separation no later than January 1, 2005; a transition
period of up to 13 years, during which the incumbent utility must provide
default service for customers who do not change suppliers unless an alternative
default supplier is selected through a WVPSC-sponsored bidding process; capped
and fixed rates for the 13 year transition period as discussed below;
deregulation of metering and billing; a 0.5 mills per KWH wires charge
applicable to all retail customers for a 10-year period commencing with the
starting date intended to provide for recovery of any stranded cost including
net regulatory assets; establishment of a rate stabilization deferred liability
balance of $81 million ($76 million by APCo and $5 million by WPCo) by the end
of year ten of the transition period to be used as determined by the WVPSC to
offset market prices paid in the eleventh, twelfth, and thirteenth year of the
transition period by residential and small commercial customers that do not
choose an alternative supplier.
Default rates for residential and small commercial customers are capped
for four years after the starting date and then increase as specified in the
plan for the next six years. In years eleven, twelve and thirteen of the
transition period, the power supply rate shall equal the market price of
comparable power. Default rates for industrial and large commercial customers
are discounted by 1% for four and a half years, beginning July 1, 2000, and then
increased at pre-defined levels for the next three years. After seven years the
power supply rate for industrial and large commercial customers will be market
based. APCo's Joint Stipulation agreement, discussed in Note 5 of the Notes to
Consolidated Financial Statements, which was approved by the WVPSC on June 2,
2000 in connection with a base rate filing, also provides additional mechanisms
to recover regulatory assets.
APCo Discontinues Application of SFAS 71 Regulatory Accounting
In June 2000 APCo discontinued the application of SFAS 71 for its
Virginia and WV retail jurisdictional portions of its generation business since
generation is no longer considered to be cost-based regulated in those
jurisdictions and management was able to determine APCo's transition rates and
wires charges. The discontinuance in the WV jurisdiction was made possible by
the June 2, 2000 approval of the Joint Stipulation which established rates,
wires charges and regulatory asset recovery procedures for the transition period
to market rates which was determined to be probable. APCo was also able to
discontinue application of SFAS 71 for the generation portion of its Virginia
retail jurisdiction after management decided that APCo would not request capped
rates different from its current rates. The existence of effective restructuring
legislation in Virginia and the probability that the WV legislation would become
effective with the expected probable passage of required enabling tax
legislation in 2001 supported management's decision in 2000 to discontinue SFAS
71 regulatory accounting for APCo's electricity generation and supply business.
APCo's discontinuance of SFAS 71 for generation resulted in an after tax
extraordinary gain, in the second quarter of 2000, of $9 million. Management
believes that it is probable that substantially all net regulatory assets
related to the Virginia and WV generation business will be recovered. Therefore,
under the provisions of EITF 97-4, APCo's generation-related net regulatory
assets were transferred to the distribution portion of the business and are
being amortized as they are recovered through charges to regulated distribution
customers. As required by SFAS 101 when discontinuing SFAS 71 regulatory
accounting, APCo performed an accounting impairment analysis on its generating
assets under SFAS 121 and concluded that there was no accounting impairment of
generation assets.
The recent energy crisis in California, discussed above, may be having a
chilling effect on efforts to enact the required tax change legislation in West
Virginia. The WV Legislature could decide not to enact the required tax changes,
thereby, effectively continuing cost based rate regulation in West Virginia or
it could modify the restructuring plan. Modifications in the restructuring plan
could adversely affect future results of operations if they were to occur.
Management is carefully monitoring the situation in West Virginia and continues
to work with all concerned parties to get approval to successfully transition
our generation business in West Virginia. Failure to pass the required enabling
tax changes could ultimately require APCo to re-instate regulatory accounting
principles under SFAS 71 for its generation operations in West Virginia.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry. Its major provisions are:
o retail competition begins January 1, 2002 but can be delayed until as late as
June 30, 2003 by the Arkansas Commission; o transmission facilities must be
operated by an ISO if owned by a company which also owns generation assets; o
rates will be frozen for one to three years; o market power issues will be
addressed by the Arkansas Commission; and o an annual progress report to the
Arkansas General Assembly on the development of competition in electric markets
and its
impact on retail customers is required.
In November 2000 the Arkansas Commission filed its annual progress
report with the Arkansas General Assembly recommending a delay in the start date
of retail competition to a date between October 1, 2003 and October 1, 2005. The
report also asks the Arkansas General Assembly to delegate authority to the
Arkansas Commission to determine the appropriate retail competition start date
within the approved time frame. In February 2001 the Arkansas General Assembly
passed legislation that was signed into law by the Governor that changes the
date of electric retail competition to October 1, 2003, and provides the
Arkansas Commission with the authority to delay that date for up to two years.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
In June 1999 Texas restructuring legislation was signed into law which,
among other things:
o gives Texas customers of investor-owned utilities the opportunity to
choose their electricity provider beginning January 1, 2002;
o provides for the recovery of regulatory assets and of other stranded costs
through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o provides for a rate freeze until January 1, 2002 followed by a 6% rate
reduction for residential and small commercial customers and a number
of customer protections;
o provides for an earnings test for each of the three years of the rate
freeze period (1999 through 2001) which will reduce stranded cost
recoveries or if there is no stranded cost provides for a refund or their
use to fund certain capital expenditures in the amount of the excess
earnings;
o requires each utility to structurally unbundle into a retail
electric provider, a power generation company and a transmission and
distribution utility;
o provides for certain limits for ownership and control of generating
capacity by companies;
o provides for elimination of the fuel clause reconciliation
process beginning January 1, 2002; and o provides for a 2004 true-up
proceeding to determine recovery of stranded costs including final fuel
recovery balances, net regulatory assets, certain environmental costs,
accumulated excess earnings and other issues.
Under the Texas Legislation, delivery of electricity will continue to
be the responsibility of the local electric transmission and distribution
utility company at regulated prices. Each electric utility was required to
submit a plan to structurally unbundle its business activities into a retail
electric provider, a power generation company, and a transmission and
distribution utility. In May 2000 CPL, SWEPCo and WTU filed a revised business
separation plan that the PUCT approved on July 7, 2000 in an interim order. The
revised business separation plans provided for CPL and WTU, which operate in
Texas only, to establish separate companies and divide their integrated utility
operations and assets into a power generation company, a transmission and
distribution utility and a retail electric provider. SWEPCo will separate its
Texas jurisdictional transmission and distribution assets and operations into a
new Texas regulated transmission and distribution subsidiary. In addition, a
retail electric provider will be formed by SWEPCo to provide retail electric
service to SWEPCo's Texas jurisdictional customers.
Under the Texas Legislation, electric utilities are allowed, with the
approval of the PUCT, to recover stranded generation costs including
generation-related regulatory assets that may not be recoverable in a future
competitive market. The approved stranded costs can be refinanced through
securitization, which is a financing structure designed to provide lower
financing costs than are available through conventional financings. Lower
financing costs are achieved through the issuance of securitization bonds at a
lower interest rate to finance 100% of the costs pursuant to a state pledge to
ensure recovery of the bond principal and financing costs through a
non-bypassable rate surcharge by the regulated transmission and distribution
utility over the life of the securitization bonds.
In 1999 CPL filed an application with the PUCT to securitize
approximately $1.27 billion of its retail generation-related regulatory assets
and approximately $47 million in other qualified restructuring costs. On March
27, 2000, the PUCT issued an order permitting CPL to securitize approximately
$764 million of net regulatory assets. The PUCT's order authorized issuance of
up to $797 million of securitization bonds including the $764 million for
recovery of net generation-related regulatory assets and $33 million for other
qualified refinancing costs. The $764 million for recovery of net
generation-related regulatory assets reflects the recovery of $949 million of
generation-related regulatory assets offset by $185 million of customer benefits
associated with accumulated deferred income taxes. CPL had previously proposed
in its filing to flow these benefits back to customers over the 14-year term of
the securitization bonds. On April 11, 2000, four parties appealed the PUCT's
securitization order to the Travis County District Court. In July 2000 the
Travis County District Court upheld the PUCT's securitization order. The
securitization order is being appealed to the Supreme Court of Texas. One of
these appeals challenges CPL's ability to recover securitization charges under
the Texas Constitution. CPL will not be able to issue the securitization bonds
until these appeals are resolved.
The remaining regulatory assets of $206 million originally included by
CPL in its 1999 securitization request were included in a March 2000 filing with
the PUCT, requesting recovery of an additional $1.1 billion of stranded costs.
The March 2000 filing of $1.1 billion included recovery of approximately $800
million of STP costs included in property, plant and equipment-electric on AEP's
Consolidated Balance Sheets and in electric utility plant-production on CPL's
Consolidated Balance Sheets. These STP costs had previously been identified as
excess cost over market (ECOM) by the PUCT for regulatory purposes and were
earning a lower return and were being amortized on an accelerated basis for
rate-making purposes in Texas. The March 2000 filing will determine the initial
amount of stranded costs in addition to the securitized regulatory assets to be
recovered beginning January 1, 2002.
CPL submitted a revised estimate of stranded costs on October 2, 2000
using assumptions developed in generic proceedings by the PUCT and an
administrative model developed by the PUCT staff that reduced the amount of the
initial stranded cost estimate to $361 million from the $1.1 billion requested
by CPL. CPL subsequently agreed to accept adjustments proposed by intervenors
that reduced ECOM to approximately $230 million. Hearings on CPL's requested
ECOM were held in October 2000. In February 2001 the PUCT issued an interim
decision determining an initial amount of CPL ECOM or stranded costs of negative
$580 million. The decision indicated that CPL's costs were below market after
securitization of regulatory assets. Management does not agree with the critical
inputs to this model. Management believes CPL has a positive stranded cost
exclusive of securitized regulatory assets. The final amount of CPL's stranded
costs including regulatory assets and ECOM will be established by the PUCT in
the legislatively required 2004 true-up proceeding. If CPL's total stranded
costs determined in the 2004 true-up are less than the amount of securitized
regulatory assets, the PUCT can implement an offsetting credit to transmission
and distribution rates.
The PUCT ruled that prior to the 2004 true-up proceeding, no
adjustments would be made to the amount of regulatory costs authorized by the
PUCT to be securitized. However, the PUCT also ruled that excess earnings for
the period 1999-2001 should be refunded through transmission and distribution
rates to the extent of any over-mitigation of stranded costs represented by
negative ECOM. In the event that CPL will be required to refund excess earnings
in the future instead of applying them to reduce ECOM or regulatory assets, it
will adversely affect future cash flow but not results of operations since
excess earnings for 1999 and 2000 were accrued and expensed in 1999 and 2000.
The Texas Legislation allows for several alternative methods to be used to value
stranded costs in the final 2004 true-up proceeding including the sale or
exchange of generation assets, the issuance of power generation company stock to
the public or the use of PUCT staff's ECOM model. To the extent that the final
2004 true-up proceeding determines that CPL should recover additional stranded
costs, the total amount recoverable can be securitized.
The Texas Legislation provides that each year during the 1999 through
2001 rate freeze period, electric utilities are subject to an earnings test. For
electric utilities with stranded costs, such as CPL, any earnings in excess of
the most recently approved cost of capital in its last rate case must be applied
to reduce stranded costs. Utilities without stranded costs, such as SWEPCo and
WTU, must either flow such excess earnings amounts back to customers or make
capital expenditures to improve transmission or distribution facilities or to
improve air quality. The Texas Legislation requires PUCT approval of the annual
earnings test calculation.
The 1999 earnings test reports filed by CPL, SWEPCo and WTU showed
excess earnings of $21 million, $1 million and zero, respectively. The PUCT
staff issued its report on the excess earnings calculations filed by CPL, SWEPCo
and WTU and calculated the excess earnings amounts to be $41 million, $3 million
and $11 million for CPL, SWEPCo and WTU, respectively. The Office of Public
Utility Counsel also filed exceptions to the companies' earnings reports.
Several issues were resolved via settlement and the remaining open issues were
submitted to the PUCT. A final order was issued by the PUCT in February 2001 and
adjustments to the accrued 1999 and 2000 excess earnings were recorded in
results of operations in the fourth quarter of 2000. After adjustments the
accruals for 1999 excess earnings for CPL and WTU were $24 million and $1
million, respectively. CPL and WTU also recorded an estimated provision for
excess 2000 earnings of $16 million and $14 million, respectively.
A Texas settlement agreement in connection with the AEP and CSW merger
permits CPL to apply for regulatory purposes up to $20 million of STP ECOM plant
assets a year in 2000 and 2001 to reduce excess earnings, if any. For book and
financial reporting purposes, STP ECOM plant assets will be depreciated in
accordance with GAAP, on a systematic and rational basis unless impaired. CPL
will establish a regulatory liability or reduce regulatory assets by a charge to
earnings to the extent excess earnings exceed $20 million in 2000 and 2001.
Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel
reconciliation proceedings. Consequently, CPL, SWEPCo and WTU will file a final
fuel reconciliation with the PUCT to reconcile their fuel costs through the
period ending December 31, 2001. Fuel costs have been reconciled by CPL, SWEPCo
and WTU through June 30, 1998, December 31, 1999 and June 30, 1997,
respectively. WTU is currently reconciling its fuel through June 2000. See
discussion in Note 5 of the Notes to Consolidated Financial Statements. At
December 31, 2000, CPL's, SWEPCo's and WTU's Texas jurisdictional unrecovered
deferred fuel balances were $127 million, $20 million and $59 million,
respectively. Final unrecovered deferred fuel balances at December 31, 2001 will
be included in each company's 2004 true-up proceeding. If the final fuel
balances or any amount incurred but not yet reconciled were not recovered, they
could have a negative impact on results of operations. The elimination of the
fuel clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to
greater risks of fuel market price increases and could adversely affect future
results of operations beginning in 2002.
The affiliated retail electric provider of CPL, SWEPCo and WTU will be
required to offer residential and small commercial customers (with a peak usage
of less than 1000 KW) a rate 6% below rates in effect on January 1, 1999
adjusted for any changes in fuel cost recovery factors since January 1, 1999
(price to beat). The price to beat must be offered to residential and small
commercial customers until January 1, 2007. Customers with a peak usage of more
than 1000 KW are subject to market rates. The Texas restructuring legislation
provides for the price to beat to be adjusted up to two times annually to
reflect significant changes in fuel and purchased energy costs.
CPL, SWEPCo and WTU Discontinue Application of SFAS 71 Regulatory Accounting in
Arkansas and Texas
The financial statements of CPL, SWEPCo and WTU have historically
reflected the economic effects of regulation by applying the requirements of
SFAS 71. As a result of the scheduled deregulation of generation in Arkansas and
Texas, the application of SFAS 71 for the generation portion of the business in
those states was discontinued in the third quarter of 1999. Under the provisions
of EITF 97-4, CPL's generation-related net regulatory assets were transferred to
the distribution portion of the business and will be amortized as they are
recovered through wires charges to customers. Management believes that
substantially all of CPL's generation-related regulatory assets will be
recovered under the Texas Legislation. CPL's recovery of generation-related
regulatory assets and stranded costs are subject to a final determination by the
PUCT in 2004. If future events were to make the recovery through securitization
of CPL's generation-related regulatory assets no longer probable, CPL would
write-off the portion of such regulatory assets deemed unrecoverable as a
non-cash extraordinary charge to earnings.
The Texas Legislation provides that all finally determined stranded
costs will be recovered. Since SWEPCo and WTU are not expected to have net
stranded costs, all Arkansas and Texas jurisdictional generation-related net
regulatory assets were written off as non-recoverable in 1999 when they
discontinued application of SFAS 71 regulatory accounting. As required by SFAS
101 when SFAS 71 is discontinued, an accounting impairment analysis for
generation assets under SFAS 121 was completed for CPL, SWEPCo and WTU. The
analysis showed that there was no accounting impairment of generation assets
when the application of SFAS 71 was discontinued. CPL, SWEPCo and WTU will test
their generation assets for impairment under SFAS 121 if circumstances change.
Management believes that on a discounted basis CPL's generation business net
cash flows will likely be less than its generating assets' net book value and
together with its generation-related regulatory assets should create a
recoverable stranded cost for regulatory purposes under the Texas Legislation.
Therefore, management continues to carry on the balance sheet at December 31,
2000, $953 million of generation-related regulatory assets already approved for
securitization and $195 million of net generation-related regulatory assets
pending approval for securitization in Texas. A final determination of whether
they will be securitized and recovered will be made as part of the 2004 true-up
proceeding.
CPL, SWEPCo, and WTU continue to analyze the impact of electric utility
industry restructuring legislation on their Arkansas and Texas electric
operations. Although management believes that the Texas Legislation provides for
full recovery of stranded costs and that the companies do not have a recordable
accounting impairment, a final determination of whether CPL will experience an
accounting loss or whether SWEPCo and WTU will experience any additional
accounting loss from an inability to recover generation-related regulatory
assets and other restructuring related costs in Texas and Arkansas cannot be
made until such time as the regulatory process is complete following the 2004
true-up proceeding in Texas and a determination by the Arkansas Commission. In
the event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding and
after the Arkansas Commission proceedings to recover all or a portion of their
generation-related regulatory assets, stranded costs and other restructuring
related costs, it could have a material adverse effect on results of operations,
cash flows and possibly financial condition.
Although Arkansas' delay of retail competition may be having a negative
effect on the progress of efforts to transition SWEPCo's generation in Arkansas
to market based pricing of electricity, it appears that Texas is moving forward
as planned. Management is carefully monitoring the situation in Arkansas and is
working with all concerned parties to prudently quicken the pace of the
transition. However, changes could occur due to concerns stemming from the
California energy crisis and other events which could adversely affect future
results of operations in Arkansas and possibly Texas.
Michigan Restructuring - Affecting AEP and I&M
On June 5, 2000, the Michigan Legislation became law. Its major
provisions, which were effective immediately, applied only to electric utilities
with one million or more retail customers. I&M, AEP's electric operating
subsidiary doing business in Michigan, has less than one million customers in
Michigan. Consequently, I&M was not immediately required to comply with the
Michigan Legislation.
The Michigan Legislation gives the MPSC broad power to issue orders to
implement retail customer choice of electric supplier no later than January 1,
2002 including recovery of regulatory assets and stranded costs. On October 2,
2000, I&M filed a restructuring implementation plan as required by a MPSC order.
The plan identifies I&M's proposal to file with the MPSC on June 5, 2001 its
unbundled rates, open access tariffs, terms of service and supporting schedules.
Described in the plan are I&M's intentions and preparation for competition
related to supplier transactions, customer transactions, rate unbundling,
education programs, and regional transmission organization. The plan contains a
proposed methodology to determine stranded costs and implementation costs and
requests the continuation of a wires charge for recovery of nuclear
decommissioning costs. Approval of the restructuring implementation plan is
pending before the MPSC.
Management has concluded that as of December 31, 2000 the requirements
to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan
will continue to be cost-based regulated until the MPSC approves rates and wires
charges in 2001. The establishment of rates and wires charges under a MPSC
approved transition plan will enable management to determine the ability to
recover stranded costs including regulatory assets and other implementation
costs, a requirement of EITF 97-4 to discontinue the application of SFAS 71.
Upon the discontinuance of SFAS 71, I&M will, if necessary, have to
write off its Michigan jurisdictional generation-related regulatory assets and
record its unrecorded Michigan jurisdictional liability for decommissioning the
Cook Plant to the extent that they cannot be recovered under the transition
rates and wires charges. As required by SFAS 101 when discontinuing SFAS 71
regulatory accounting, I&M will have to perform an accounting impairment
analysis under SFAS 121 to determine if the Michigan jurisdictional portion of
its generating assets are impaired for accounting purposes.
The amount of regulatory assets recorded on the books at December 31,
2000 applicable to I&M's Michigan retail jurisdictional generation business is
approximately $45 million before related tax effects. The estimated unrecorded
liability for the Michigan jurisdiction to decommission the Cook Plant ranges
from $114 million to $215 million in 2000 non-discounted dollars based upon
studies completed during 2000. For the Michigan jurisdiction, I&M has
accumulated approximately $100 million in trust funds to decommission the Cook
Plant. Based on the current information available, management does not
anticipate that I&M will experience any material tangible asset accounting
impairment or regulatory asset write-offs. Ultimately, however, whether I&M will
experience material regulatory asset write-offs will depend on whether the MPSC
approves their recovery in future restructuring proceedings.
A determination of whether I&M will experience any asset impairment
loss regarding its Michigan retail jurisdictional generating assets and any loss
from a possible inability to recover Michigan generation-related regulatory
assets, decommissioning obligations and transition costs cannot be made until
such time as the rates and the wires charges are determined through the
regulatory process. In the event I&M is unable to recover all or a portion of
its generation-related regulatory assets, unrecorded decommissioning obligation,
stranded costs and other implementation costs, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.
Oklahoma Restructuring - Affecting AEP and PSO
In 1997, the Oklahoma Legislature passed restructuring legislation
providing for retail open access by July 1, 2002. That legislation called for a
number of studies to be completed on a variety of restructuring issues,
including an independent system operator, technical, financial, transition and
consumer issues. During 1998 and 1999 several of the studies were completed.
The information from the studies was expected to be used in the
development of additional industry restructuring legislation during the 2000
legislative session. Several additional electric industry restructuring bills
were filed in the 2000 Oklahoma legislative session. The proposed bills
generally supple-mented the industry restructuring legislation previously
enacted in Oklahoma which lacked specific procedures for a transition to market
based competitive prices. The industry restructuring legislation previously
passed did not delegate the establishment of transition procedures to the
Oklahoma Corporation Commission. The 2000 Oklahoma legislative session adjourned
in May without passing further restructuring legislation.
The 2001 Oklahoma legislative session convened in early February. No
further electric restructuring legislation has passed and proposals have been
made to delay the implementation of the transition to customer choice and market
based pricing under the restructuring legislation. These proposals are a
reaction to California's recent energy crisis. Management is working with all
concerned parties to reassure them that what happened in California will not
occur in Oklahoma. If the necessary legislation is not passed, PSO's generation
and retail electric supply business will remain regulated in Oklahoma. If
implementation legislation were to modify the original restructuring legislation
in Oklahoma it could have a adverse effect on results of operations.
Management has concluded that as of December 31, 2000 the requirements
to apply SFAS 71 continue to be met since PSO's rates for generation in Oklahoma
will continue to be cost-based regulated until the Oklahoma Legislature approves
further restructuring legislation and transition rates and wires charges are
established under an approved transition plan. Until management is able to
determine the ability to recover stranded costs which includes regulatory assets
and other implementation costs, PSO cannot discontinue application of SFAS 71
accounting under GAAP.
When PSO discontinues application of SFAS 71, it will be necessary to
write off Oklahoma jurisdictional generation-related regulatory assets to the
extent that they cannot be recovered under the transition rates and wires
charges, when determined, and record any asset accounting impairments in
accordance with SFAS 121.
A determination of whether PSO will experience any asset impairment loss
regarding its Oklahoma retail jurisdictional generating assets and any loss from
a possible inability to recover Oklahoma generation-related regulatory assets
and other transition costs cannot be made until such time as the rates and the
wires charges are determined through the legislative and/or regulatory process.
In the event PSO is unable to recover all or a portion of its generation-related
regulatory assets and implementation costs, Oklahoma restructuring could have a
material adverse effect on results of operations and cash flows.
Restructuring In Other Jurisdictions
The remaining four states (Indiana, Kentucky, Louisiana and Tennessee)
making up AEP's service territory have initiatives to implement or review
customer choice, although the timing of any implementation is uncertain and may
be further delayed due to the California situation. AEP supports customer choice
and deregulation of generation and is proactively involved in discussions
regarding the best competitive market structure and transition method to arrive
at a fair, competitive marketplace. As the pricing of generation in these
markets evolves from regulated cost-of-service rates to market-based pricing,
the recovery of stranded costs including net regulatory assets and other
transition costs must be addressed. The amount of stranded costs the AEP
subsidiaries could experience when and if restructuring occurs in their state
jurisdictions depends on the timing and extent to which competition is
introduced to their business and the future market prices of electricity. The
recovery of stranded cost is dependent on the terms of future legislation and,
if required, related regulatory proceedings.
Customer choice and the transition to market based competition if
restructuring is implemented in Indiana, Kentucky, Louisiana and Tennessee could
also ultimately result in adverse impacts on results of operations and cash
flows depending on the future market prices of electricity and the ability of
the subsidiaries to recover their stranded costs including net regulatory assets
during a transition or subsequent period through a wires charge or other
recovery mechanism. Management believes that state restructuring legislation and
the regulatory process should provide for full recovery of generation-related
net regulatory assets and other reasonable stranded costs if these states decide
to deregulate generation. However, if in the future any portion of the
generation business in these other jurisdictions were to no longer be cost-based
regulated and if it were not possible to demonstrate probability of recovery of
resultant stranded costs including regulatory assets, results of operations,
cash flows and financial condition would be adversely affected.
Amortization of Transition Regulatory Assets and Other Deferred Costs -
Affecting AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Future earnings will be negatively impacted by amortization of certain
deferred costs and regulatory assets related to I&M's Cook Plant extended
outage, transition plans to discontinue SFAS 71 regulatory accounting for
generation with the beginning of customer choice in certain states and the
merger of AEP and CSW.
During 1999, the IURC and MPSC approved settlement agreements which
provided for the deferral in 1999 and amortization of restart costs and
fuel-related revenues from the extended Cook Plant outage. The amortization
period is for five years ending in December 2003. Annual amortization is $78
million for I&M. See Note 4 of the Notes to Consolidated Financial Statements.
Beginning in 2001 under the Ohio Act, CSPCo and OPCo began amortizing
their transition regulatory assets over eight and seven years, respectively. The
annual amortization in 2001 for CSPCo and OPCo is estimated to be $20 million
and $74 million, respectively. The amount of amortization is based upon KWH
sold.
APCo began amortization of its West Virginia jurisdictional regulatory
assets over an eleven year period in July 2000. In the Virginia jurisdiction,
APCo started straight line amortization of regulatory assets over a seven year
period in July 2000. The annual amortization for 2001 is $9 million for APCo's
West Virginia jurisdiction and $9 million for APCo's Virginia jurisdiction.
In June 2000 AEP merged with CSW. In connection with securing approval
for the merger, AEP and certain of its subsidiaries signed agreements, approved
by regulatory authorities, which included rate reductions to share estimated
merger savings with customers. The agreements provide for rate reductions for
periods up to eight years beginning in the third quarter of 2000.
Certain merger related costs recover-able from ratepayers were deferred
pursuant to the settlement agreements and will be amortized over five to eight
years depending upon the terms of the respective agreements. The annual
amortization of the deferred merger costs for the AEP System is estimated to
total $8 million in 2001. The merger amortization will be recorded as follows:
$2.6 million by CPL, $1.7 million by I&M, $600,000 by KPCo, $1.2 million by PSO,
$1.1 million by SWEPCo and $800,000 by WTU. If actual merger savings are
significantly less than the merger savings rate reductions required by the
merger settlement agreements and the amortization of deferred merger-related
costs, future results of operations, cash flows and possibly financial condition
could be adversely affected. See Note 3 of the Notes to Consolidated Financial
Statements for further discussion of the merger.
Amortization of the above described deferred costs and regulatory assets
could negatively affect future earnings to the extent that they exceed cost
savings or revenues growth.
Litigation
COLI - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
On February 20, 2001, the U.S. District Court for the Southern District
of Ohio ruled against AEP in its suit against the United States over
deductibility of interest claimed by AEP in its consolidated federal income tax
return related to its COLI program. AEP had filed suit to resolve the IRS'
assertion that interest deductions for AEP's COLI program should not be allowed.
In 1998 and 1999 AEP and the impacted subsidiaries paid the disputed taxes and
interest attributable to COLI interest deductions for taxable years 1991-98 for
APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment
by the IRS of additional interest on the contested tax. The payments were
included in other assets on AEP Consolidated Balance Sheet and Other Property
and Investments on the subsidiaries' balance sheets pending the resolution of
this matter. As a result of the U.S. District Court's decision to deny the COLI
interest deductions, net income was reduced by $319 million for the AEP System
in 2000. Management plans to appeal the decision.
The earnings reductions for affected registrant subsidiaries are as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
Shareholders' Litigation - Affecting AEP
On June 23, 2000, a complaint was filed in the U.S. District Court for
the Eastern District of New York seeking unspecified compensatory damages
against AEP and four former or present officers. The individual plaintiff also
seeks certification as the representative of a class consisting of all persons
and entities who purchased or otherwise acquired AEP common stock between July
25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly
violated federal securities laws by disseminating materially false and
misleading statements concerning, among other things, the undisclosed materially
impaired condition of the Cook Plant, AEP's inability to properly monitor,
manage, repair, supervise and report on operations at the Cook Plant and the
materially adverse conditions these problems were having, and would continue to
have, on AEP's deteriorating financial condition, and ultimately on AEP's
operations, liquidity and stock price. Four other similar class action
complaints have been filed and the court has consolidated the five cases. The
plaintiffs filed a consolidated complaint pursuant to this court order. This
case has been transferred to the U.S. District Court for the Southern District
of Ohio. Although, management believes these shareholder actions are without
merit and intends to oppose them vigorously, management cannot predict the
outcome of this litigation or its impact on results of operations, cash flows or
financial condition.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
CPL has been involved in litigation regarding municipal franchise fees
in Texas as a result of a class action suit filed by the City of San Juan, Texas
in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and
seeks damages of up to $300 million plus attorney's fees. CPL filed a
counterclaim for overpayment of franchise fees.
During 1997, 1998 and 1999 the litigation moved procedurally through the
Texas Court System and was sent to mediation without resolution.
In 1999 a class notice was mailed to each of the cities served by CPL.
Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL
has pledged that if any final, non-appealable court decision awards a judgement
against CPL for a franchise underpayment, CPL will extend the principles of that
decision, with regard to any franchise underpayment, to the cities that declined
to participate in the litigation. In December 1999, the court ruled that the
class of plaintiffs would consist of approximately 30 cities. A trial date for
June 2001 has been set.
Although management believes that it has substantial defenses to the
cities' claims and intends to defend itself against the cities' claims and
pursue its counterclaim vigorously, management cannot predict the outcome of
this litigation or its impact on results of operations, cash flows or financial
condition.
Texas Base Rate Litigation - Affecting AEP and CPL
In November 1995 CPL filed with the PUCT a request to increase its
retail base rates by $71 million. In October 1997 the PUCT issued a final order
which lowered CPL's annual retail base rates by $19 million from the rate level
which existed prior to May 1996. The PUCT also included a "glide path" rate
methodology in the final order pursuant to which annual rates were reduced by
$13 million beginning May 1, 1998 with an additional annual reduction of $13
million commencing on May 1, 1999.
CPL appealed the final order to the Travis District Court. The primary
issues being appealed include: the classification of $800 million of invested
capital in STP as ECOM and assigning it a lower return on equity than other
generation property; the use of the "glide path" rate reduction methodology; and
an $18 million disallowance of service billings from an affiliate, CSW Services.
As part of the appeal, CPL sought a temporary injunction to prohibit the PUCT
from implementing the "glide path" rate reduction methodology. The temporary
injunction was denied and the "glide path" rate reduction was implemented. In
February 1999 the Travis District Court affirmed the PUCT order in regard to the
three major items discussed above.
CPL appealed the Travis District Court's findings to the Texas Appeals
Court which in July 2000, issued its opinion upholding the Travis District Court
except for the disallowance of affiliated service company billings. Under Texas
law, specific findings regarding affiliate transactions must be made by PUCT. In
regards to the affiliate service billing issue, the findings were not complete
in the opinion of the Texas Appeals Court who remanded the issue back to PUCT.
CPL has sought a rehearing of the Texas Appeals Court's opinion. The
Texas Appeals Court has requested briefs related to CPL's rehearing request from
interested parties. Management is unable to predict the final resolution of its
appeal. If the appeal is unsuccessful the PUCT's 1997 order will continue to
adversely affect results of operations and cash flows.
As part of the AEP/CSW merger approval process in Texas, a stipulation
agreement was approved which resulted in the withdrawal of the appeal related to
the "glide path" rate methodology. CPL will continue its appeal of the ECOM
classification for STP property and the related loss of return on equity and the
disallowed affiliated service billings.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo
SWEPCo and CLECO are each a 50% owner of Dolet Hills Power Station Unit
1 and jointly own lignite reserves in the Dolet Hills area of northwestern
Louisiana. In 1982, SWEPCo and CLECO entered into a lignite mining agreement
with DHMV, a partnership for the mining and delivery of lignite from a portion
of these reserves.
In April 1997, SWEPCo and CLECO sued DHMV and its partners in U.S.
District Court for the Western District of Louisiana seeking to enforce various
obligations of DHMV under the lignite mining agreement, including provisions
relating to the quality of delivered lignite, pricing, and mine reclamation
practices. In June 1997, DHMV filed an answer denying the allegations in the
suit and filed a counterclaim asserting various contract-related claims against
SWEPCo and CLECO. SWEPCo and CLECO have denied the allegations contained in the
counterclaims. In January 1999, SWEPCo and CLECO amended the claims against DHMV
to include a request that the lignite mining agreement be terminated.
In April 2000, the parties agreed to settle the litigation. As part of
the settlement, DHMV's interest in the mining operations and related debt and
other obligations will be purchased by SWEPCo and CLECO. The closing date for
the settlement has been extended from December 31, 2000 to March 31, 2001. The
litigation has been stayed until April 2001 to give the parties time to
consummate the settlement agreement.
Management believes that the resolution of this matter will not have a
material effect on results of operations, cash flows or financial condition.
AEP and its registrant subsidiaries are involved in a number of other
legal proceedings and claims. While management is unable to predict the outcome
of such litigation, it is not expected that the ultimate resolution of these
matters will have a material adverse effect on the results of operations, cash
flows or financial condition.
Environmental Concerns and Issues
As 2001 begins, the U.S. continues to debate an array of environmental
issues affecting the electric utility industry. Most of the policies are aimed
at reducing air emissions citing alleged impacts of such emissions on public
health, sensitive ecosystems or the global climate.
AEP and its subsidiaries' policy on the environment continues to be the
development and application of long-term economically feasible measures to
improve air and water quality, limit emissions and protect the health of
employees, customers, neighbors and others impacted by their operations. In
support of this policy, AEP and its subsidiaries continue to invest in research
through groups like the Electric Power Research Institute and directly through
demonstration projects for new technology for the capture and storage of carbon
dioxide, mercury, NOx and other emissions. The AEP System intends to continue in
a leadership role to protect and preserve the environment while providing vital
energy commodities and services to customers at fair prices.
AEP and its subsidiaries have a proven record of efficiently producing
and delivering electricity and gas while minimizing the impact on the
environment. AEP and its subsidiaries have spent billions of dollars to equip
their facilities with the latest cost effective clean air and water technologies
and to research new technologies. Award winning efforts to reclaim our mining
properties is a proud accomplishment.
The introduction of multi-pollutant control legislation is being
discussed by members of Congress and the Bush Administration. The legislation
being considered may regulate carbon dioxide, NOx, sulfur dioxide, mercury and
other emissions from electric generating plants. Management will continue to
support solutions which are based on sound science, economics and demonstrated
control technologies. Management is unable to predict the timing or magnitude of
additional pollution control laws or regulations. If additional control
technology is required on facilities owned by the electric utility companies and
their costs were not recoverable from ratepayers or through market based prices
or volumes of product sold, they could adversely affect future results of
operations and cash flows. The following discussions explains existing control
efforts, litigation and other pending matters related to environmental issues
for AEP System companies.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, CSPCo, I&M
and OPCo
Under the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting requirements might be
triggered and the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed components, or other
repairs needed for the reliable, safe and efficient operation of the plant.
AEP, APCo, CSPCo, I&M and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. In 1999 Notices of
Violation were issued and complaints were filed by Federal EPA in various U.S.
District Courts alleging APCo, CSPCo, I&M and OPCo and a number of unaffiliated
utilities made modifications to generating units at certain of their coal-fired
generating plants over the course of the past 25 years that extended unit
operating lives or increased unit generating capacity without a preconstruction
permit in violation of the Clean Air Act. The complaint was amended in March
2000 to add allegations for certain generating units previously named in the
complaint and to include additional generating units previously named only in
the Notices of Violation in the complaint.
A number of northeastern and eastern states were granted leave to
intervene in the Federal EPA's action against the AEP System under the Clean Air
Act. A lawsuit against power plants owned by certain AEP System operating
companies alleging similar violations to those in the Federal EPA complaint and
Notices of Violation was filed by a number of special interest groups and has
been consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per day
per violation at each generating unit ($25,000 per day prior to January 30,
1997). Civil penalties, if ultimately imposed by the court, and the cost of any
required new pollution control equipment, if the court accepts Federal EPA's
contentions, could be substantial.
On May 10, 2000, the AEP System companies filed motions to dismiss all
or portions of the complaints. Briefing on these motions was completed on August
2, 2000. On February 23, 2001, the government filed a motion for partial summary
judgement seeking a determination that four projects undertaken on units at
Sporn, Cardinal and Clinch River plants do not constitute "routine maintenance,
repair and replacement" as used in the Clear Air Act. Management believes its
maintenance, repair and replacement activities were in conformity with the Clean
Air Act and intends to vigorously pursue its defense.
In the event the AEP System companies do not prevail, any capital and
operating costs of additional pollution control equipment that may be required
as well as any penalties imposed would adversely affect future results of
operations, cash flows and possibly financial condition unless such costs can be
recovered through regulated rates, and where states are deregulating generation,
unbundled transition period generation rates, stranded cost wires charges and
future market prices for electricity.
In December 2000 Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by AEP's subsidiary, CSPCo, reached a tentative
agreement with Federal EPA and other parties to settle litigation regarding
generating plant emissions under the Clean Air Act. Negotiations are continuing
between the parties in an attempt to reach final settlement terms. Cinergy's
settlement could impact the operation of Zimmer Plant and W.C. Beckjord
Generating Station Unit 6 which are owned 25.4% and 12.5%, respectively, by
CSPCo. Until a final settlement is reached, CSPCo will be unable to determine
the settlement's impact on its jointly owned facilities and its future earnings
and cash flows.
NOx Reduction - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo
Federal EPA issued a NOx rule that required substantial reductions in
NOx emissions in a number of eastern states, including certain states in which
the AEP System's generating plants are located. A number of utilities, including
several AEP System companies, filed petitions seeking a review of the final rule
in the D.C. Circuit Court. In March 2000, the D.C. Circuit Court issued a
decision generally upholding the NOx rule. The D.C. Circuit Court issued an
order in August 2000 which extends the final compliance date to May 31, 2004. In
September 2000 following denial by the D.C. Circuit Court of a request for
rehearing, the industry petitioners, including the AEP System companies,
petitioned the U.S. Supreme Court for review, which was denied.
In December 2000 Federal EPA ruled that eleven states, including certain
states in which the AEP System's generating units are located, failed to submit
plans to comply with the mandates of the NOx rule. This deter-mination means
that those states could face stringent sanctions within the next 24 months
including limits on construction of new sources of air emissions, loss of
federal high-way funding and possible Federal EPA take-over of state air quality
management programs.
In January 2000 Federal EPA adopted a revised rule granting petitions
filed by certain northeastern states under Section 126 of the Clean Air Act
seeking significant reductions in nitrogen oxide emissions from utility and
industrial sources. The rule im-poses emissions reduction requirements
com-parable to the NOx rule beginning May 1, 2003, for most of AEP's coal-fired
generating units. Certain AEP companies and other utili-ties filed petitions for
review in the D.C. Circuit Court. Briefing has been completed and oral argument
was held in December 2000.
In a related matter, on April 19, 2000, the Texas Natural Resource
Conservation Commission adopted rules requiring significant reductions in NOx
emissions from utility sources, including CPL and SWEPCo. The rule's compliance
date is May 2003 for CPL and May 2005 for SWEPCo.
In June 2000 OPCo announced that it was beginning a $175 million
installation of selective catalytic reduction technology (expected to be
operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin
Plant. Construction of selective catalytic reduction technology on Amos Plant
Unit 3, which is jointly owned by OPCo and APCo, and APCo's Mountaineer Plant is
scheduled to begin in 2001. The Amos and Mountaineer projects (expected to be
completed in 2002) are estimated to cost a total of $230 million ($145 million
for APCo and $85 million for OPCo).
Preliminary estimates indicate that compliance with the NOx rule upheld
by the D.C. Circuit Court as well as compliance with the Texas Natural Resource
Conservation Commission rule and the Section 126 petitions could result in
required capital expenditures of approximately $1.6 billion including the
amounts discussed in the previous paragraph for the AEP System.
The following table shows the estimated compliance cost for certain of
AEP's registrant subsidiaries.
Company Amount
- ------- ------
(in millions)
APCo $365
CPL 57
I&M 202
OPCo 606
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the preliminary estimates
depending upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital and operating costs of additional pollution
control equipment are recovered from customers through regulated rates and/or
future market prices for electricity where generation is deregulated, they will
have an adverse effect on future results of operations, cash flows and possibly
financial condition.
Superfund - Affecting AEP, APCo, CPL, CSPCo, I&M, OPCo and SWEPCo
By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion
by-products, which constitute the overwhelming percentage of these materials,
are typically disposed of or treated in captive disposal facilities or are
beneficially utilized. In addition, the AEP System's generating plants and
transmission and distribution facilities have used asbestos, PCBs and other
hazardous and non-hazardous materials. The AEP System companies are currently
incurring costs to safely dispose of these substances. Additional costs could be
incurred to comply with new laws and regulations if enacted.
Superfund addresses clean-up of hazardous substances at disposal sites
and authorized Federal EPA to administer the clean-up programs. As of year-end
2000, subsidiaries of AEP have been named by the Federal EPA as a PRP for five
sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has two PRP sites.
There are five additional sites for which AEP, APCo, CSPCo, I&M, OPCo and SWEPCo
have received information requests which could lead to PRP designation. CPL,
OPCo and SWEPCo have also been named a PRP at three sites under state law.
Liability has been resolved for a number of sites with no significant effect on
the AEP subsidiaries' results of operations. In those instances where AEP or its
subsidiaries have been named a PRP or defendant, their disposal or recycling
activities were in accordance with the then-applicable laws and regulations.
Unfortunately, Superfund does not recognize compliance as a defense, but imposes
strict liability on parties who fall within its broad statutory categories.
While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding AEP's and its
subsidiaries' potential future liability. Disposal of materials at a particular
site is often unsubstantiated and the quantity of materials deposited at a site
was small and often nonhazardous. Although liability is joint and several,
typically many parties are named as PRPs for each site and several of the
parties are financially sound enterprises. Therefore, management's present
estimates do not anticipate material cleanup costs for identified sites for
which AEP System companies have been declared PRPs. If significant cleanup costs
are attributed to AEP or its subsidiaries in the future under Superfund, results
of operations, cash flows and possibly financial condition would be adversely
affected unless the costs can be recovered from customers.
Global Climate Change
At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160
countries, including the U.S., negotiated a treaty requiring legally-binding
reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change. The treaty, which
requires the advice and consent of the U.S. Senate for ratification, would
require the U.S. to reduce greenhouse gas emissions seven percent below 1990
levels in the years 2008-2012. Although the U.S. has agreed to the treaty and
signed it on November 12, 1998, the treaty has not been submitted to the Senate
for consideration as it does not contain requirements for "meaningful
participation by key developing countries" and the rules, procedures,
methodologies and guidelines of the treaty's emissions trading and joint
implementation programs and compliance enforcement provisions have not been
negotiated. At the Fourth Conference of the Parties in November 1998, the
parties agreed to a work plan to complete negotiations on outstanding issues
with a view toward approving them at the Sixth Conference of the Parties to be
held in November 2000. During the Sixth Conference of the Parties agreement was
not reached on any of the outstanding issues requiring resolution in order to
faciliate ratification of the Kyoto Protocol. There are several contentious
issues and literally hundreds of pages of detailed, complex rules that remain to
be negotiated. Discussions are expected to resume in July 2001. While a
candidate for the presidency, George Bush had stated his opposition to U.S.
ratification of the Kyoto Protocol. The Seventh Conference of the Parties is
scheduled for October 2001 in Morocco. AEP does not support the Kyoto Treaty as
presently drafted. Management will continue to work with the Administration and
Congress to develop responsible public policy on this issue.
If the Kyoto treaty is approved by Congress as presently drafted, the
costs for the AEP System to comply with the required emission reductions
required by the treaty are expected to be substantial and would have a material
adverse impact on results of operations, cash flows and possibly financial
condition if not recovered from customers. It is management's belief that the
Kyoto Protocol is unlikely to be ratified and implemented in the U.S. in its
current form.
Costs for Spent Nuclear Fuel and Decommissioning - Affecting AEP, CPL and I&M
I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP,
have a significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of SNF
and high-level radioactive waste. By law CPL and I&M participate in the DOE's
SNF disposal program which is described in Note 8 of the Notes to Consolidated
Financial Statements. Since 1983 I&M has collected $275 million from customers
for the disposal of nuclear fuel consumed at the Cook Plant. $116 million of
these funds have been deposited in external trust funds to provide for the
future disposal of SNF and $159 million has been remitted to the DOE. CPL has
collected and remitted to the DOE, $44 million for the future disposal of SNF
since STP began operation in the late 1980s. Under the provisions of the Nuclear
Waste Policy Act, collections from customers are to provide the DOE with money
to build a permanent repository for spent fuel. However, in 1996, the DOE
notified the companies that it would be unable to begin accepting SNF by the
January 1998 deadline required by law. To date DOE has failed to comply with the
requirements of the Nuclear Waste Policy Act.
As a result of DOE's failure to make sufficient progress toward a
permanent repository or otherwise assume responsibility for SNF, AEP on behalf
of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number
of unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S.
Court of Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. AEP's and I&M suit
has been stayed pending further action by the U.S. Court of Federal Claims. As
long as the delay in the availability of a government approved storage
repository for SNF continues, the cost of both temporary and permanent storage
and the cost of decommissioning will continue to increase.
In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined
a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related
to DOE's nuclear waste fund cost recovery settlement with PECO Energy
Corporation. The settlement allows PECO to skip two payments to the DOE for
disposal of SNF due to the lack of progress towards development of a permanent
repository for SNF. The companies believe the settlement is unlawful as the
settlement would force other utilities to make up any shortfall in DOE's SNF
disposal funds.
The cost to decommission nuclear plants is affected by both NRC
regulations and the delayed SNF disposal program. Studies completed in 2000
estimate the cost to decommission the Cook Plant ranges from $783 million to
$1,481 million in 2000 non-discounted dollars. External trust funds have been
established with amounts collected from customers to decommission the plant. At
December 31, 2000, the total decommissioning trust fund balance for Cook Plant
was $558 million which includes earnings on the trust investments. Studies
completed in 1999 for STP estimate CPL's share of decommissioning cost to be
$289 million in 1999 non-discounted dollars. Amounts collected from customers to
decommission STP have been placed in an external trust. At December 31, 2000,
the total decommissioning trust fund for CPL's share of STP was $94 million
which includes earnings on the trust investments. Estimates from the
decommissioning studies could continue to escalate due to the uncertainty in the
SNF disposal program and the length of time that SNF may need to be stored at
the plant site. We will work with regulators and customers to recover the
remaining estimated costs of decommissioning Cook Plant and STP through
regulated rates and, where generation has been deregulated, through wires
charges. However, AEP's, CPL's and I&M's future results of operations, cash
flows and possibly their financial conditions would be adversely affected if the
cost of SNF disposal and decommissioning continues to increase and cannot be
recovered.
Foreign Energy Delivery, Worldwide Energy Investments and Other Business
Operations
Worldwide electric and gas operations on AEP's Consolidated Statements
of Income include the foreign energy delivery, worldwide energy investments, and
other segments of AEP's business. See Note 14 of the Notes to Consolidated
Financial Statements for a discussion of segments.
AEP's investment in certain types of activities is limited by PUHCA. SEC
authorization under PUHCA limits AEP to issuing and selling securities in an
amount up to 100% of its average quarterly consolidated retained earnings
balance for investment in EWGs and FUCOs. At December 31, 2000, AEP's investment
in EWGs and FUCOs was $1.8 billion compared to AEP's limit of $3.4 billion by
law.
SEC rules under PUHCA permit AEP to invest up to 15% of consolidated
capitalization (such amount was $3.5 billion at December 31, 2000) in
energy-related companies that engage in marketing and/or trading of electricity,
gas and other energy commodities. AEP's gas trading business and its interests
in domestic cogeneration projects are reported as investments under this rule
and at December 31, 2000, AEP's investment was less than one million dollars.
Management continues to evaluate the U.S. and international energy
markets for investment opportunities that complement AEP's wholesale operations.
Management expects to continue to pursue new and existing energy supply projects
and to provide energy related services worldwide. AEP's future consolidated
earnings will be impacted by the performance of existing and any future
investments.
The major business activities and subsidiaries of AEP's worldwide
electric and gas operations are SEEBOARD, CitiPower, Yorkshire, European energy
trading operations, U.S. power trading more than two transmission systems
removed from the AEP transmission system and gas trading operations in the U.S.,
domestic and foreign generating facilities in China, Mexico and the U.S.,
electric distribution in South America and power plant construction. SEEBOARD's
principal business is the distribution and supply of electricity in southeast
England. CitiPower provides electricity and electric distribution service in the
city of Melbourne, Australia. AEP owns 100% of SEEBOARD and CitiPower. The
revenues and operating expenses for SEEBOARD and CitiPower are included in
worldwide revenues and expenses on AEP's Consolidated Statements of Income.
Interest, taxes and other nonoperating items for SEEBOARD and CitiPower are
included in the appropriate income statement lines.
In 1998 SEEBOARD's 80% owned subsidiary, SEEBOARD Powerlink, signed a
30-year contract for $1.6 billion to operate, maintain, finance and renew the
high-voltage power distribution network of the London Underground transportation
system. SEEBOARD Powerlink will be responsible for distributing high voltage
electricity to supply 270 London Underground stations and 250 miles of the rail
system's track. SEEBOARD's partners in Powerlink are an international electrical
engineering group and an international cable and construction group.
AEP has a 50% investment in Yorkshire, another U.K. regional electricity
distribution and supply company. The investment is accounted for using the
equity method of accounting with equity earnings included in other income (net)
on the AEP Consolidated Statements of Income. In December 2000 AEP entered into
negotiations to sell its investment in Yorkshire. On February 26, 2001, an
agreement to sell AEP's 50% interest in Yorkshire was signed. The sale is
expected to close by March 31, 2001. See Note 10 of the Notes to Consolidated
Financial Statements.
In the U.K. all residential and commercial customers have been allowed
to choose their electricity supplier since May 1999. Margins on retail electric
sales have been generally declining due to competition. In April 2000 final
proposals from the regulatory commission reduced distribution rates and
electricity supply price caps. The distribution rate reductions and reduced
price caps are expected to reduce AEP's earnings from SEEBOARD and its Yorkshire
investment. In response to these final proposals and increasing competition,
SEEBOARD and Yorkshire adopted an aggressive program of reducing controllable
costs. Significant features of this program include staff reductions,
outsourcing of certain functions and consolidation of facilities. Management
intends to aggressively pursue this cost reduction program and continues to
evaluate additional cost reduction measures to further mitigate the effects of
the final proposals and increasing competition in the U.K. electricity supply
business. Management expects that, despite the cost control measures, the rate
reductions will negatively impact AEP's earnings.
The Utilities Act which became law in the U.K. in July 2000 includes a
requirement for separate licensing of electricity supply and distribution and
the introduction of a prohibition of electricity supply and distribution
licenses being held by the same legal entity. This requirement effectively means
that the electricity supply and distribution businesses of SEEBOARD and
Yorkshire must be held by separate companies. However, AEP will not be required
to divest its interest in either the supply entity or the distribution entity.
The separation of the supply and distribution business into two entities each
for SEEBOARD and Yorkshire is not expected to have a material impact on future
results of operations or cash flows.
Beginning January 1, 2001 price reductions on the supply and
distribution of electricity are being implemented in Victoria, Australia. The
effect of these price reductions is expected to reduce CitiPower's results of
operations to the extent that they cannot be offset by reduced expenses,
improved efficiencies or increased sales.
A new, higher tariff rate for the electricity from two 250 MW coal-fired
generating units located in Henan Province, China was approved by the Central
Chinese government in January 2000. AEP owns 70% of these units, with the
remaining 30% owned by two Chinese partners. As a result of the new tariff the
units contributed positively to AEP's results of operations for 2000 after
incurring a loss in 1999.
Other foreign generating facilities include a 37.5% interest in 675 MW
of capacity in the U.K. and a 50% interest in 118 MW of capacity in Mexico. AEP
also has a 50% ownership interest in two generating plants under construction; a
600 MW facility in Mexico and a 400 MW facility in the U.K. All of these
facilities sell their capacity under long-term contracts. The investment in
these facilities is accounted for using the equity method.
AEP, through its CSW Energy subsidiary, has an ownership interest in
seven operational domestic generation facilities in Colorado, Florida and Texas
with one 440 MW facility under construction. These plants are EWGs or qualifying
facilities (QF) as defined by law and not subject to cost-based rate regulation
or the application of SFAS 71 regulatory accounting. The combined installed
capacity of the operational facilities is 1,508 MW at December 31, 2000. The
power from these QF facilities is sold under long-term power purchase agreements
with the local host facility. Any merchant power is sold in the wholesale market
generally under short-term contract. As a result, increases in the market price
of natural gas used to generate electricity at these facilities may adversely
impact results of operations.
In 1999 a 50% equity interest in one of the above facilities was sold to
an unaffiliated company. The after-tax gain from the sale was approximately $33
million. An additional unit is under construction at this facility. Pursuant to
the terms of the sale agreement, the unaffiliated company will make additional
payments to CSW Energy upon completion of the additional unit.
Under terms of the FERC and Texas settlement agreements that approved
the merger, the divestiture of certain generating units is required. The
Frontera power plant, one of CSW Energy's facilities, is specifically identified
as one of the plants where the entire ownership interest must be sold. On
February 8, 2001, AEP announced that it had reached agreement with an
unaffiliated company to sell the 500 MW Frontera power plant for $265 million in
cash.
In 2000 an electricity and gas trading operation in Europe was added.
This business requires minimal capital investment and offers an opportunity to
employ our expertise in energy marketing and trading to a new market.
The domestic gas trading operation grew substantially in 2000 and is
expected to benefit from the planned acquisition of the Houston Pipe Line
Company which was announced in January 2001. The acquisition of Houston Pipe
Line Company, which has more than 4,400 miles of natural gas transmission
pipeline and operates one of the largest storage facilities, is expected to
complement our intra-state gas transmission and storage facilities in Louisiana
and extends AEP's strategy of linking physical energy asset operations with
trading and marketing operations.
AEP's Louisiana gas operation is LIG, a midstream natural gas operation,
that was purchased in December 1998 for approximately $340 million including
working capital funds. LIG includes a fully integrated natural gas gathering,
processing, storage and transportation operation in Louisiana and a gas trading
and marketing operation. Assets include an intrastate pipeline system, natural
gas liquids processing plants and natural gas storage facilities.
AEP's subsidiaries are engaged in the engineering and construction for
third parties of three power plants in the U.S. with a capacity of 1,910 MW.
These plants will be natural gas-fired facilities that are scheduled to be
completed from 2001 to 2003. AEP intends to use its engineering, trading and
marketing expertise on these projects some of which also include power purchase
and power sale agreements to enhance its results of operations.
Other Matters - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU
New Accounting Standards - SFAS 133, "Accounting for Derivative Instruments and
Hedging Activities", as amended by SFAS 137 and SFAS 138, is effective for the
AEP System beginning January 1, 2001. SFAS 133 requires that entities recognize
all derivatives as either assets or liabilities and measure them at fair value.
Changes in the fair value of derivative assets and liabilities must be
recognized currently in net income. Changes in the derivatives that are
effective cash flow hedges are recorded in other comprehensive income.
Pending the resolution of certain industry issues presently before the
FASB's Derivatives Implementation Group (DIG), the effect of adoption of SFAS
133 will result in transition adjustment amounts which will have an immaterial
effect on both net income and other comprehensive income.
The FASB's DIG, has issued tentative guidance, which has not yet been
approved by the FASB, that option contracts cannot qualify as normal purchases
and sales. In addition there are two industry issues pending resolution by the
DIG related to whether electric capacity contracts that may have some
characteristics of purchased and written options can qualify as normal sales,
and whether contracts which do not result in physical delivery of power because
of transmission constraints are derivatives.
While the Company believes the majority of the its fuel supply
agreements should qualify as normal purchases and that the majority of its power
sales agreements qualify as normal sales, the ultimate resolution of the above
issues may result in accounting for certain power sales and fuel supply
agreements as derivatives which may have a material effect on reported net
income under SFAS 133. Whether the impact will be favorable or adverse will
depend on the market prices compared to the contractual prices at the time of
valuation.
INVESTOR INQUIRIES
Investors should direct inquiries to Investor Relations using the toll free
number, 1-800-237-2667 or by writing to: Bette Jo Rozsa Managing Director of
Investor Relations American Electric Power Service Corporation 28th Floor 1
Riverside Plaza Columbus, OH 43215-2373
FORM 10-K ANNUAL REPORT
The Annual Report (Form 10-K) to the Securities and Exchange Commission
will be available in April 2001 at no cost to shareholders.
Please address requests for copies to:
Geoffrey C. Dean
Director of Financial Reporting
American Electric Power Service Corporation
26th Floor
1 Riverside Plaza
Columbus, OH 43215-2373
TRANSFER AGENT AND REGISTRAR OF CUMULATIVE PREFERRED STOCK
Equiserve, First Chicago Division
P.O. Box 2500
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Phone number: 1-800-328-6955