SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended MARCH 31, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
Commission Registrant, State of Incorporation I.R. S. Employer
File Number Address, and Telephone Number Identification No.
- ----------- ----------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
40 Franklin Road, Roanoke, Virginia 24011
Telephone (540) 985-2300
0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
539 North Carancahua Street,
Corpus Christi, Texas 78401-2802 Telephone (361)
881-5300
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1 Riverside Plaza, Columbus,
Ohio 43215 Telephone (614) 223-1000
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
One Summit Square
P.O. Box 60, Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1701 Central Avenue, Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
301 Cleveland Avenue S.W., Canton, Ohio 44701
Telephone (330) 456-8173
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895
(An Oklahoma Corporation)
212 East 6th Street, Tulsa, Oklahoma 74119-1212
Telephone (918) 599-2000
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)
428 Travis Street, Shreveport, Louisiana 71156-0001
Telephone (318) 673-3000
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790
301 Cypress Street, Abilene, Texas
79601-5820 Telephone (915) 674-7000
AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company,
Public Service Company of Oklahoma and West Texas Utilities Company meet the
conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in
General Instruction H(2) to Form 10-Q.
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.
Yes X
--------
No --------
The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at April 30, 2001 was 322,151,975.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended March 31, 2001
CONTENTS
Page
Glossary of Terms i - iii
Forward-Looking Information iv
Part I. FINANCIAL INFORMATION
Items 1 and 2 Financial Statements and Management's Discussion and
Analysis of Results of Operations:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Discussion and Analysis of Results of Operations A-1
Consolidated Financial Statements A-2 - A-6
AEP Generating Company:
Management's Narrative Analysis of Results of Operations B-1
Financial Statements B-2 - B-5
Appalachian Power Company, Inc. and Subsidiaries:
Management's Discussion and Analysis of Results of Operations C-1 - C-2
Consolidated Financial Statements C-3 - C-7
Central Power and Light Company and Subsidiary:
Management's Discussion and Analysis of Results of Operations D-1
Consolidated Financial Statements D-2 - D-5
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Analysis of Results of Operations E-1 - E-2
Consolidated Financial Statements E-3 - E-6
Indiana Michigan Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations F-1
Consolidated Financial Statements F-2 - F-6
Kentucky Power Company
Management's Narrative Analysis of Results of Operations G-1
Financial Statements G-2 - G-6
Ohio Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations H-1 - H-2
Consolidated Financial Statements H-3 - H-7
Public Service Company of Oklahoma and Subsidiaries:
Management's Narrative Analysis of Results of Operations I-1
Consolidated Financial Statements I-2 - I-5
Southwestern Electric Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations J-1
Consolidated Financial Statements J-2 - J-5
West Texas Utilities Company:
Management's Narrative Analysis of Results of Operations K-1 - K-2
Financial Statements K-3 - K-6
Footnotes to Financial Statements L-1 - L-14
Item 2. Registrants' Combined Management Discussion and Analysis of
Financial Condition, Contingencies and Other Matters M-1 - M-8
Item 3. Quantitative and Qualitative Disclosures About Market Risk N-1
Part II. OTHER INFORMATION
Item 1. Legal Proceedings O-1
Item 6. Exhibits and Reports on Form 8-K O-1
(a) Exhibits
Exhibit 12
(b) Reports on Form 8-K
SIGNATURE P-1
This combined Form 10-Q is separately filed by 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 and West Texas Utilities Company.
Information contained herein relating to any individual registrant is filed by
such registrant on its own behalf. Each registrant makes no representation as to
information relating to the other registrants.
iii
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............................. South Texas Project 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 Restructuring 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.
iv
FORWARD-LOOKING INFORMATION
This report made by AEP and certain of its subsidiaries contains
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and each of its subsidiaries
believe that their expectations are based on reasonable assumptions, any
such statements may be influenced by factors that could cause actual
outcomes and results to be materially different from those projected. Among
the factors that could cause actual results to differ materially from those
in the forward-looking statements are:
o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to our power
generation business. o The structure and timing of a competitive market and its
impact on energy prices or fixed rates. o The ability to recover stranded costs
in connection with possible/proposed deregulation of generation. o New
legislation and government regulations.
o The ability of AEP to successfully control its costs.
o The success of new business ventures.
o International developments affecting AEP's foreign investments.
o The economic climate and growth in AEP's service territory.
Inflationary trends.
o Electricity and gas market prices.
o Interest rates
o Other risks and unforeseen events.
A-6
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased by $126 million or 90% due predominately to a
strong performance from the wholesale business inclusive of the favorable impact
of the return to service of the Cook Nuclear Plant. The wholesale business,
which consists of wholesale electric and gas sales in the United States, the
generation component of domestic retail electricity sales, worldwide electric
and gas trading and other related businesses, contributed $103 million to the
increase.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
-
Revenues $8,121 133
Fuel and Purchase Power
Expense 7,755 178
Maintenance and Other
Operation Expense 107 13
Income Taxes 93 121
Other Income, net (11) (26)
Interest and Preferred Dividends 16 6
Other 13 3
---------
Net Income $ 126 90
=======
The increase in revenues is due to a substantial increase in electric
and gas trading volumes and wholesale energy sales reflecting the return to
service of the Cook Nuclear units.
The major increase in fuel and purchased power expense was primarily
attributable to the increase in trading volume and an increase in generation.
Net generation increased 4% due mainly to the return to service in June and
December of 2000 of Cook Nuclear Plant's two generating units. STP Nuclear plant
increased its net generation by 4%.
Maintenance and other operation expense increased largely as a result of
material and labor costs associated with the development of Buckeye Power and
Dow Chemical gas-fired plants plus additional traders' incentive compensation.
These cost increases were partially offset by the cessation of restart
expenditures for the Cook Nuclear Plant units following an extended Nuclear
Regulatory Commission (NRC) monitored outage. Project fees received for the
Buckeye Power and Dow Chemical projects are recognized in revenues using the
percentage of completion method. Consequently, the charges to expense for
material and labor costs did not adversely affect net income.
The increase in income taxes is predominately due to an increase in
pre-tax income. Other income decreased in the quarter primarily due to a
reduction in equity earnings from investments. The increase in interest
and preferred dividends was primarily due to an increase in average
outstanding short-term debt
balances and an increase in average short-term debt interest rates reflecting
increased short-term cash demands and short-term market conditions.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
TOTAL REVENUES $14,238 $6,117
------- ------
EXPENSES:
Fuel and Purchased Power 12,102 4,347
Maintenance and Other Operation 958 851
Depreciation and Amortization 336 320
Taxes Other Than Income Taxes 168 171
--- ---
TOTAL EXPENSES 13,564 5,689
------ -----
OPERATING INCOME 674 428
OTHER INCOME, net 31 42
-- --
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES 705 470
INTEREST AND PREFERRED DIVIDENDS 269 253
--- ---
INCOME BEFORE INCOME TAXES 436 217
INCOME TAXES 170 77
--- --
NET INCOME $ 266 $ 140
========= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 322 322
=== ===
EARNINGS PER SHARE (Basic and Dilutive): $0.83 $0.43
===== =====
CASH DIVIDENDS PAID PER SHARE $0.60 $0.60
===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in millions)
ASSETS
- ------
CURRENT ASSETS:
Cash and Cash Equivalents $ 275 $ 437
Accounts Receivable (net) 3,158 3,699
Energy Trading Contracts 9,484 16,627
Other 1,317 1,268
----- -----
TOTAL CURRENT ASSETS 14,234 22,031
------ ------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 16,259 16,328
Transmission 5,804 5,609
Distribution 10,827 10,843
Other (including gas and coal mining
assets and nuclear fuel) 3,968 4,077
Construction Work in Progress 1,068 1,231
----- -----
Total Property, Plant and Equipment 37,926 38,088
Accumulated Depreciation and Amortization 15,823 15,695
------ ------
NET PROPERTY, PLANT AND EQUIPMENT 22,103 22,393
------ ------
REGULATORY ASSETS 3,868 3,698
----- -----
INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS 822 782
--- ---
GOODWILL (net of amortization) 1,310 1,382
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 2,271 1,620
----- -----
OTHER ASSETS 2,302 2,642
----- -----
TOTAL $46,910 $54,548
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $2,058 $2,627
Short-term Debt 4,108 4,333
Long-term Debt Due Within One Year 1,465 1,152
Energy Trading Contracts 9,379 16,801
Other 2,033 2,154
----- -----
TOTAL CURRENT LIABILITIES 19,043 27,067
------ ------
LONG-TERM DEBT 9,076 9,602
----- -----
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY
JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 333 334
--- ---
DEFERRED INCOME TAXES 4,865 4,875
----- -----
DEFERRED INVESTMENT TAX CREDITS 519 528
--- ---
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 201 203
--- ---
LONG-TERM ENERGY TRADING CONTRACTS 1,973 1,381
----- -----
DEFERRED CREDITS AND REGULATORY LIABILITIES 991 637
--- ---
OTHER NONCURRENT LIABILITIES 1,691 1,706
----- -----
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 161 161
--- ---
COMMITMENTS AND CONTINGENCIES (Note 8)
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2001 2000
---- ----
Shares Authorized. . . . . 600,000,000 600,000,000
Shares Issued. . . . . . . 331,095,028 331,019,146
(8,999,992 shares were held in treasury at March 31, 2001
and December 31, 2000) 2,152 2,152
Paid-in Capital 2,914 2,915
Accumulated Other Comprehensive Income (Loss) (172) (103)
Retained Earnings 3,163 3,090
----- -----
TOTAL COMMON SHAREHOLDERS' EQUITY 8,057 8,054
----- -----
TOTAL $46,910 $54,548
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in millions)
OPERATING ACTIVITIES:
Net Income $ 266 $ 140
Adjustments for Noncash Items:
Depreciation and Amortization 352 349
Deferred Federal Income Taxes 68 (34)
Deferred Investment Tax Credits (9) (9)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 615 34
Fuel, Materials and Supplies (13) 50
Accrued Utility Revenues 39 29
Prepayments and Other (68) (4)
Accounts Payable (499) (4)
Taxes Accrued 15 (23)
Interest Accrued 65 77
Rent Accrued - Rockport Plant Unit 2 37 37
Energy Trading Contracts (net) (279) (87)
Other (net) (5) 27
-- --
Net Cash Flows From Operating Activities 584 582
--- ---
INVESTING ACTIVITIES:
Construction Expenditures (315) (376)
Other 109 (20)
--- ---
Net Cash Flows Used For Investing Activities (206) (396)
---- ----
FINANCING ACTIVITIES:
Issuance of Common Stock 3 1
Issuance of Long-term Debt 132 331
Change in Short-term Debt (net) (266) (210)
Retirement of Long-term Debt (209) (253)
Special Deposit for Reacquisition of Long-term Debt - 50
Dividends Paid on Common Stock (193) (209)
---- ----
Net Cash Flows Used For Financing Activities (533) (290)
---- ----
Effect of Exchange Rate Change on Cash (7) (3)
-- --
Net Decrease in Cash and Cash Equivalents (162) (107)
Cash and Cash Equivalents at Beginning of Period 437 609
--- ---
Cash and Cash Equivalents at End of Period $ 275 $ 502
===== =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $115 million and $170
million and for income taxes was $178 million and $25 million in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $19 million and $17
million in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- -----
(in millions)
JANUARY 1, 2000 $2,149 $2,898 $3,630 $(4) $8,673
Issuance of Common Stock 1 1
Common Stock Dividends (209) (209)
----
8,465
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Currency Translation Adjustment (35) (35)
Unrealized Loss on Securities (7) (7)
Net Income 140 140
---
Total Comprehensive Income 98
-------- -------- -------- ----- --
MARCH 31, 2000 $2,149 $2,899 $3,561 $(46) $8,563
====== ====== ====== ==== ======
JANUARY 1, 2001 $2,152 $2,915 $3,090 $(103) $8,054
Issuance of Common Stock 4 4
Common Stock Dividends (193) (193)
Other (5) (5)
--
7,860
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Currency Translation Adjustment (82) (82)
Unrealized Gain on Hedged Derivatives 13 13
Net Income 266 266
---
Total Comprehensive Income 197
-------- -------- -------- ------- ------
MARCH 31, 2001 $2,152 $2,914 $3,163 $(172) $8,057
====== ====== ====== ===== ======
See Notes to Financial Statements beginning on page L-1.
B-5
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Operating revenues are derived from the sale of Rockport Plant energy
and capacity to two affiliated companies pursuant to FERC approved long-term
unit power agreements. 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 declined $0.5 million or 19% for first quarter primarily as a
result of a final true-up billing in January 2000 to an unaffiliated utility
whose unit power purchase contract expired on December 31, 1999.
Income statement line items which changed significantly were:
Increase (Decrease)
First Quarter
(in millions) %
------------- -
Operating Revenues $ 3.6 6
Fuel Expense 3.2 13
Maintenance Expense (0.6) (23)
Taxes Other Than Federal
Income Taxes 2.0 178
Federal Income Taxes (0.3) (46)
Interest Charges (0.1) (16)
The increase in operating revenues resulted primarily from an increase
in recoverable expenses as generation increased due to an increase in
Rockport Plant's availability. Shorter outages in 2001, reflecting
management's policy to maximize generating capacity availability, allowed
the Rockport Plant units to generate 19% more electricity than in 2000.
Fuel expense increased due to the increase in generation.
The reduction in the number of outages and the shorter length of
planned outages also accounted for the decrease in maintenance expense.
Taxes other than federal income taxes increased due to the accrual of
state income taxes based on an estimate of higher taxable income for 2001.
The decrease in federal income taxes attributable to operations is
primarily due to a decrease in pre-tax income. Reductions in variable
interest rates, reflecting market conditions, were the primary reason for
the decline in interest charges.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $60,507 $56,866
------- -------
OPERATING EXPENSES:
Fuel 27,645 24,435
Rent - Rockport Plant Unit 2 17,071 17,071
Other Operation 2,958 3,098
Maintenance 1,926 2,515
Depreciation 5,586 5,505
Taxes Other Than Federal Income Taxes 3,128 1,126
Federal Income Taxes 386 721
--- ---
TOTAL OPERATING EXPENSES 58,700 54,471
------ ------
OPERATING INCOME 1,807 2,395
NONOPERATING INCOME 862 869
--- ---
INCOME BEFORE INTEREST CHARGES 2,669 3,264
INTEREST CHARGES 689 819
--- ---
NET INCOME $1,980 $2,445
====== ======
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 9,722 $ 3,673
NET INCOME 1,980 2,445
CASH DIVIDENDS DECLARED 959 1,935
--- -----
BALANCE AT END OF PERIOD $10,743 $4,183
======= ======
The common stock of AEGCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $635,945 $635,215
General 2,973 2,795
Construction Work in Progress 3,676 4,292
----- -----
Total Electric Utility Plant 642,594 642,302
Accumulated Depreciation 320,991 315,566
------- -------
NET ELECTRIC UTILITY PLANT 321,603 326,736
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 4,768 2,757
Accounts Receivable:
Affiliated Companies 21,105 21,374
Miscellaneous 2,110 2,341
Fuel - at average cost 10,375 11,006
Materials and Supplies - at average cost 3,949 3,979
Prepayments 105 145
--- ---
TOTAL CURRENT ASSETS 42,412 41,602
------ ------
REGULATORY ASSETS 5,444 5,504
----- -----
DEFERRED CHARGES 3,379 760
----- ---
TOTAL ASSETS $372,838 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(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 23,434
Retained Earnings 10,743 9,722
------ -----
TOTAL CAPITALIZATION AND COMMON SHAREHOLDER'S EQUITY 35,177 34,156
------ ------
OTHER NONCURRENT LIABILITIES 358
---
358
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 44,810 44,808
Advances from Affiliates 28,068
219
Accounts Payable:
General 7,879 6,109
Affiliated Companies 9,737 7,724
Taxes Accrued 11,124 4,993
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Other 4,818 4,443
----- -----
TOTAL CURRENT LIABILITIES 102,014 101,108
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 120,796 122,188
------- -------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 58,881 59,718
Amounts Due to Customers for Income Taxes 23,329 23,996
------ ------
TOTAL REGULATORY LIABILITIES 82,210 83,714
------ ------
DEFERRED INCOME TAXES 32,133 32,928
------ ------
DEFERRED CREDITS 150 150
--- ---
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $372,838 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 1,980 $ 2,445
Adjustment for Noncash Items:
Depreciation 5,586 5,505
Deferred Federal Income Taxes (1,462) (1,374)
Deferred Investment Tax Credits (837) (837)
Amortization of Deferred Gain
on Sale and Leaseback - Rockport Plant Unit 2 (1,392) (1,393)
Deferred Property Taxes (2,737) (2,489)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable 500 5,681
Fuel, Materials and Supplies 661 461
Accounts Payable 3,783 (4,686)
Taxes Accrued 6,131 4,198
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Other (net) 574 (1,735)
--- ------
Net Cash Flow From Operating Activities 31,251 24,240
------ ------
INVESTING ACTIVITIES - Construction Expenditures (432) (1,266)
---- ------
FINANCING ACTIVITIES:
Return of Capital to Parent Company - (2,000)
Change in Short-term Debt (net) - (17,650)
Change in Advances from Affiliates (net) (27,849) -
Dividends Paid (959) (1,935)
---- ------
Net Cash Flows Used For Financing Activities (28,808) (21,585)
------- -------
Net Increase in Cash and Cash Equivalents 2,011 1,389
Cash and Cash Equivalents at Beginning of Period 2,757 317
----- ---
Cash and Cash Equivalents at End of Period $ 4,768 $1,706
======== ======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $644,000 and $732,000 and
for income taxes was $1,349,000 and $678,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
C-7
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $14.1 million or 30% mainly due to growth in and
strong performance by the trading operation. APCo, as a member of the AEP Power
Pool, shares in the revenues and costs of wholesale marketing and trading
activities conducted on its behalf by the AEP Power Pool.
Income statement line items which changed significantly were:
Increase (Decrease)
First Quarter
(in millions) %
------------- -
Operating Revenues $952 93
Fuel Expense (3) (3)
Purchased Power Expense 927 141
Other Operation Expense 5 9
Maintenance Expense 5 17
Depreciation and
Amortization 5 14
Nonoperating Income 4 547
The significant increase in revenues is due to a 60% increase in
electric trading volume. In the first quarter of 2001 the AEP Power Pool
grew its trading business resulting in an increase in the number of forward
electricity purchase and sales contracts made in AEP's traditional
marketing area (up to two transmission systems from AEP's service
territory).
Fuel expense decreased due to a decline in generation as a result of
scheduled plant maintenance. The increase in purchased power expense was
primarily attributable to the increase in trading volume.
Other operation expense increased as a result of the growth in AEP's
electricity marketing and trading operations. The increase in maintenance
expense is due to the effect of performing generating plant boiler
maintenance repairs to the Amos, Mountaineer and Glen Lyn Plants.
Depreciation and amortization expense increased due to the accelerated
amortization beginning in July 2000 of transition regulatory assets in
connection with the June 2000 discontinuance of SFAS 71 in the Company's
Virginia and West Virginia jurisdictions whereby net generation-related
regulatory assets were transferred to the distribution portion of the
business commensurate with their recovery through regulated rates (see Note
5 for further discussion of the effects of restructuring). Additional
investments in distribution and transmission plant also contributed to the
increase in depreciation and amortization expense.
The increase in nonoperating income was due to an increase in net
gains from AEP Power Pool trading transactions outside of the AEP System's
traditional marketing area and speculative financial transactions (options,
futures, swaps). The AEP Power Pool enters into power trading transactions
for the forward purchase and sale of electricity and electricity 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.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $1,974,127 $1,021,678
---------- ----------
OPERATING EXPENSES:
Fuel 95,476 98,557
Purchased Power 1,585,202 658,647
Other Operation 65,889 60,641
Maintenance 33,009 28,325
Depreciation and Amortization 43,717 38,338
Taxes Other Than Federal Income Taxes 31,868 30,645
Federal Income Taxes 30,814 28,279
------ ------
TOTAL OPERATING EXPENSES 1,885,975 943,432
--------- -------
OPERATING INCOME 88,152 78,246
NONOPERATING INCOME 5,051 781
----- ---
INCOME BEFORE INTEREST CHARGES 93,203 79,027
INTEREST CHARGES 31,416 31,363
------ ------
NET INCOME 61,787 47,664
PREFERRED STOCK DIVIDEND REQUIREMENTS 503 633
--- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 61,284 $ 47,031
============ ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
NET INCOME $61,787 $47,644
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (417) -
---- --
COMPREHENSIVE INCOME $61,370 $47,664
======= =======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $120,584 $175,854
NET INCOME 61,787 47,664
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 32,399 31,653
Cumulative Preferred Stock 361 525
Capital Stock Expense 142 108
--- ---
BALANCE AT END OF PERIOD $149,469 $191,232
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,058,100 $2,058,952
Transmission 1,193,606 1,177,079
Distribution 1,836,856 1,816,925
General 256,265 254,371
Construction Work in Progress 100,046 110,951
------- -------
Total Electric Utility Plant 5,444,873 5,418,278
Accumulated Depreciation and Amortization 2,218,992 2,188,796
--------- ---------
NET ELECTRIC UTILITY PLANT 3,225,881 3,229,482
--------- ---------
OTHER PROPERTY AND INVESTMENTS 51,879 56,967
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 572,406 322,688
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 7,571 5,847
Advances to Affiliates - 8,387
Accounts Receivable:
Customers 166,360 243,298
Affiliated Companies 58,465 63,919
Miscellaneous 15,907 16,179
Allowance for Uncollectible Accounts (1,995) (2,588)
Fuel - at average cost 32,994 39,076
Materials and Supplies - at average cost 60,506 57,515
Accrued Utility Revenues 15,207 66,499
Energy Trading Contracts 1,875,174 2,036,001
Prepayments 14,356 6,307
------ -----
TOTAL CURRENT ASSETS 2,244,545 2,540,440
--------- ---------
REGULATORY ASSETS 450,773 447,750
------- -------
DEFERRED CHARGES 45,921 48,826
------ ------
TOTAL ASSETS $6,591,405 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(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 715,359 715,218
Accumulated Other Comprehensive Income (Loss) (417) -
Retained Earnings 149,469 120,584
------- -------
Total Common Shareowner's Equity 1,124,869 1,096,260
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,431,088 1,430,812
--------- ---------
TOTAL CAPITALIZATION 2,584,607 2,555,722
--------- ---------
OTHER NONCURRENT LIABILITIES 97,674 105,883
------ -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 75,006 175,006
Short-term Debt - 191,495
Advances from Affiliates 145,185 -
Accounts Payable - General 148,743 153,422
Accounts Payable - Affiliated Companies 118,321 107,556
Taxes Accrued 68,675 63,258
Customer Deposits 12,366 12,612
Interest Accrued 39,173 21,555
Energy Trading Contracts 1,889,898 2,091,804
Other 70,090 85,378
------ ------
TOTAL CURRENT LIABILITIES 2,567,457 2,902,086
--------- ---------
DEFERRED INCOME TAXES 710,796 682,474
------- -------
DEFERRED INVESTMENT TAX CREDITS 41,987 43,093
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 491,369 259,438
------- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 97,515 97,457
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $6,591,405 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 61,787 $47,664
Adjustments for Noncash Items:
Depreciation and Amortization 43,745 38,366
Deferred Federal Income Taxes 19,438 8,180
Deferred Investment Tax Credits (1,106) (1,166)
Deferred Power Supply Costs (net) 121 (8,157)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 82,071 7,003
Fuel, Materials and Supplies 3,091 9,557
Accrued Utility Revenues 51,292 15,298
Accounts Payable 6,086 (13,123)
Taxes Accrued 5,417 16,443
Interest Accrued 17,618 10,815
Net Change in Energy Trading Contracts (58,864) (9,253)
Other (net) (19,549) (25,046)
------- -------
Net Cash Flows From Operating Activities 211,147 96,581
------- ------
INVESTING ACTIVITIES:
Construction Expenditures (39,922) (39,901)
Proceeds from Sale of Property 1,182 16
----- --
Net Cash Flows Used For Investing Activities (38,740) (39,885)
------- -------
FINANCING ACTIVITIES:
Change in Short-term Debt (net) (191,495) 4,945
Change in Advance from Affiliates (net) 153,572 -
Retirement of Cumulative Preferred Stock - (164)
Retirement of Long-term Debt (100,000) (83,201)
Dividends Paid on Common Stock (32,399) (31,653)
Dividends Paid on Cumulative Preferred Stock (361) (528)
---- ----
Net Cash Flows Used For Financing Activities (170,683) (110,601)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 1,724 (53,905)
Cash and Cash Equivalents at Beginning of Period 5,847 64,828
----- ------
Cash and Cash Equivalents at End of Period $ 7,571 $ 10,923
============= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,156,000 and
$19,610,000 and for income taxes was $13,543,000 and $6,693,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $1,512,000
and $3,361,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
D-5
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $27 million, or 330%, primarily from
participation in AEP's power marketing and trading operations subsequent to
the AEP CSW merger and a reduction in depreciation and amortization
expense. CPL shares in the results of power marketing and trading
activities conducted on its behalf by the AEP System. Income statement line
items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $287 91
Fuel Expense 62 70
Purchased Power Expense 194 N.M.
Depreciation and Amortization (12) (22)
Taxes Other Than Federal
Income Taxes 2 11
Federal Income Taxes 14 322
N.M. = Not Meaningful
The significant increase in operating revenues resulted from higher
fuel related revenues due to increased fuel and purchased power expense,
increased energy sales to residential and commercial customers and the post
merger favorable impact of AEP's power marketing and trading operations,
which added new wholesale revenues.
Fuel expense increased due primarily to an increase in the average
unit cost of fuel as a result of higher spot market natural gas prices.
The rise in purchased power expense was primarily attributable to
participation in AEP's trading operation. The decrease in depreciation and
amortization is due primarily to a decrease in depreciation associated with
the cessation in July 2000 of accelerated ECOM depreciation on STP and
reduced accruals for excess earnings.
Taxes other than federal income taxes increased due to a favorable
accrual adjustment in 2000 for ad valorem taxes. The increase in federal
income tax expense attributable to operations in 2001 was primarily due to
an increase in pre-tax operating income.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $603,412 $316,328
-------- --------
OPERATING EXPENSES:
Fuel 151,853 89,397
Purchased Power 214,566 20,420
Other Operation 75,071 75,301
Maintenance 17,287 16,422
Depreciation and Amortization 42,391 54,198
Taxes Other Than Federal Income Taxes 19,488 17,534
Federal Income Taxes 18,604 4,406
------ -----
TOTAL OPERATING EXPENSES 539,260 277,678
------- -------
OPERATING INCOME 64,152 38,650
NONOPERATING INCOME 1,639 547
----- ---
INCOME BEFORE INTEREST CHARGES 65,791 39,197
INTEREST CHARGES 30,760 31,058
------ ------
NET INCOME 35,031 8,139
PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60
-- --
EARNINGS APPLICABLE TO COMMON STOCK $ 34,971 $ 8,079
======== =======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $792,219 $758,894
NET INCOME 35,031 8,139
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 37,014 39,000
Preferred Stock 60 60
Other 1 2
--- ------
BALANCE AT END OF PERIOD $790,175 $727,971
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,161,904 $3,175,867
Transmission 585,157 581,931
Distribution 1,234,153 1,221,750
General 239,473 237,764
Construction Work in Progress 168,726 138,273
Nuclear Fuel 237,499 236,859
-------- -------
Total Electric Utility Plant 5,626,912 5,592,444
Accumulated Depreciation and Amortization 2,316,202 2,297,189
--------- ---------
NET ELECTRIC UTILITY PLANT 3,310,710 3,295,255
---------- ---------
OTHER PROPERTY AND INVESTMENTS 45,357 44,225
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 19,908 66,231
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 4,849 14,253
Accounts Receivable:
Customers 54,545 66,112
Affiliated Companies 34,636 31,272
Fuel Inventory - at LIFO cost 38,423 22,842
Materials and Supplies - at average cost 52,994 53,108
Under-recovered Fuel Costs 125,223 127,295
Energy Trading Contracts 40,155 481,206
Prepayments and Other Current Assets 2,910 3,014
----- -----
TOTAL CURRENT ASSETS 353,735 799,102
------- -------
REGULATORY ASSETS 197,711 202,440
------- -------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249
-------- -------
NUCLEAR DECOMMISSIONING TRUST FUND 90,563 93,592
------- ------
DEFERRED CHARGES 47,251 18,402
------ ------
TOTAL ASSETS $5,018,484 $5,472,496
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(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 790,175 792,219
------- -------
Total Common Shareowner's Equity 1,364,063 1,366,107
Preferred Stock 5,967 5,967
CPL - Obligated, Mandatorily
Redeemable Preferred Securities of
Subsidiary Trust Holding Solely Junior
Subordinated Debentures of CPL 148,000 148,500
Long-term Debt 942,861 1,254,559
------- ---------
TOTAL CAPITALIZATION 2,460,891 2,775,133
--------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 511,700 200,000
Advances from Affiliates 312,868 269,712
Accounts Payable - General 108,821 128,957
Accounts Payable - Affiliated Companies 42,982 40,962
Taxes Accrued 83,097 55,526
Interest Accrued 23,189 26,217
Energy Trading Contracts 39,500 489,888
Other 36,439 40,630
------ ------
TOTAL CURRENT LIABILITIES 1,158,596 1,251,892
--------- ---------
DEFERRED INCOME TAXES 1,243,439 1,242,797
--------- ---------
DEFERRED INVESTMENT TAX CREDITS 126,798 128,100
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 19,493 65,740
------- ------
DEFERRED CREDITS 9,267 8,834
----- -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,018,484 $5,472,496
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $35,031 $ 8,139
Adjustments for Noncash Items:
Depreciation and Amortization 42,391 54,198
Deferred Federal Income Taxes 2,579 (15,670)
Deferred Investment Tax Credits (1,302) (1,302)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 8,203 1,847
Fuel, Materials and Supplies (15,468) 3,448
Fuel Recovery 2,073 (616)
Accounts Payable (18,115) 9,969
Taxes Accrued 27,571 (2,807)
Transmission Coordination Agreement Settlement - 15,519
Deferred Property Taxes (29,292) -
Other (net) (29,779) 22,658
------- ------
Net Cash Flows From Operating Activities 23,892 95,383
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (38,873) (44,406)
Other - (1,721)
------ ------
Net Cash Flows Used For Investing Activities (38,873) (46,127)
------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 149,426
Retirement of Long-term Debt (505) (50,000)
Change in Advances from Affiliates (net) 43,156 (162,266)
Special Deposit for Reacquisitions 50,000
-
Dividends Paid on Common Stock (37,014) (39,000)
Dividends Paid on Cumulative Preferred Stock (60)
---
(60)
Net Cash Flows From (Used For) Financing Activities 5,577 (51,900)
----- -------
Net Decrease in Cash and Cash Equivalents (9,404) (2,644)
Cash and Cash Equivalents at Beginning of Period 14,253 7,995
------ -----
Cash and Cash Equivalents at End of Period $ 4,849 $ 5,351
======== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $24,938,000 and
$15,348,000 and for income taxes was $6,071,000 and $-0- in 2001 and 2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
E-6
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $10.2 million or 37% due to increased trading
volume and improved performance of the wholesale marketing and trading
operations. CSPCo, as a member of the AEP Power Pool, shares in the revenues and
costs of wholesale marketing and trading activities conducted on its behalf by
the AEP Power Pool
Income statement line items which changed significantly were:
Increase
(in millions) %
------------- -
Operating Revenues $492 78
Fuel Expense 6 15
Purchased Power Expense 457 110
Other Operation Expense 9 20
Maintenance Expense 4 28
Depreciation and
Amortization 7 28
Federal Income Taxes 4 23
Nonoperating Income 6 N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to a 47% increase in
electric trading volume. In the first quarter of 2001 the AEP Power Pool
was able to expand the number of forward electricity contracts made in
AEP's traditional marketing area (up to two transmission systems from AEP's
service territory) resulting in the increase in trading volume.
Fuel expense increased in the first quarter of 2001 due to the
discontinuance of deferred fuel accounting on January 1, 2001 as a result
of the restructuring of the electric utility industry in Ohio to provide
customers with choice of generation supplier. Under deferred fuel
accounting, changes in fuel costs were deferred until they were reflected
in rates. In the three months ended March 31, 2000, the Company amortized
over collections of fuel costs thereby reducing fuel expense commensurate
with refunds of the over-collection to customers.
The substantial increase in purchased power expense is primarily
attributable to the increase in trading volume. Other operation expense
increased due to power trading expenses and incentives, factored customer
accounts receivable expenses and the cessation of amortizing deferred gains
from sales of emission allowances to income as a result of the
discontinuations of SFAS 71.
Maintenance expenses increased in the first quarter of 2001 due to
planned outages at two plants for steam boiler overhaul and inspections.
The commencement of the amortization of transition regulatory assets
in connection with the transition to customer choice and market-based
pricing of electricity accounted for the increase in depreciation and
amortization expense.
An increase in pre-tax operating income caused the Federal income
taxes attributable to operations to increase. The increase in nonoperating
income was due to an increase in net gains from 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 reflects growth in and improved
performance of the trading operations.
The decline in interest charges was due to a decrease in the
outstanding balance of long-term debt.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $1,125,573 $633,305
---------- --------
OPERATING EXPENSES:
Fuel 47,030 40,748
Purchased Power 871,911 414,702
Other Operation 54,548 45,289
Maintenance 18,780 14,696
Depreciation and Amortization 31,482 24,544
Taxes Other Than Federal Income Taxes 31,907 31,477
Federal Income Taxes 21,800 17,725
------ ------
TOTAL OPERATING EXPENSES 1,077,458 589,181
--------- -------
OPERATING INCOME 48,115 44,124
NONOPERATING INCOME 7,289 1,684
----- -----
INCOME BEFORE INTEREST CHARGES 55,404 45,808
INTEREST CHARGES 17,733 18,337
------ ------
NET INCOME 37,671 27,471
PREFERRED STOCK DIVIDEND REQUIREMENTS 302 533
--- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 37,369 $ 26,938
============ ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 99,069 $246,584
NET INCOME 37,671 27,471
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 20,738 23,650
Cumulative Preferred Stock 262 437
Capital Stock Expense 254 96
--- --
BALANCE AT END OF PERIOD $115,486 $249,872
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,571,778 $1,564,254
Transmission 368,817 360,302
Distribution 1,110,006 1,096,365
General 150,267 156,534
Construction Work in Progress 93,941 89,339
------ ------
Total Electric Utility Plant 3,294,809 3,266,794
Accumulated Depreciation and Amortization 1,325,156 1,299,697
--------- ---------
NET ELECTRIC UTILITY PLANT 1,969,653 1,967,097
--------- ---------
OTHER PROPERTY AND INVESTMENTS 42,304 39,848
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 312,852 172,167
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 8,297 11,600
Accounts Receivable:
Customers 64,264 73,711
Affiliated Companies 60,792 49,591
Miscellaneous 27,120 18,807
Allowance for Uncollectible Accounts (659) (659)
Fuel - at average cost 16,532 13,126
Materials and Supplies - at average cost 39,036 38,097
Accrued Utility Revenues - 9,638
Energy Trading Contracts 1,021,733 1,085,989
Prepayments and Other Current Assets 57,311 46,735
------ ------
TOTAL CURRENT ASSETS 1,294,426 1,346,635
--------- ---------
REGULATORY ASSETS 280,975 291,553
------- -------
DEFERRED CHARGES 58,117 77,634
------ ------
TOTAL ASSETS $3,958,327 $3,894,934
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(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 573,607 573,354
Retained Earnings 115,486 99,069
------- ------
Total Common Shareowner's Equity 730,119 713,449
Cumulative Preferred Stock - Subject
to Mandatory Redemption 15,000 15,000
Long-term Debt 899,745 899,615
------- -------
TOTAL CAPITALIZATION 1,644,864 1,628,064
--------- ---------
OTHER NONCURRENT LIABILITIES 44,061 47,584
------ ------
CURRENT LIABILITIES:
Advances from Affiliates 102,209 88,732
Accounts Payable - General 88,530 89,846
Accounts Payable - Affiliated Companies 91,414 72,493
Taxes Accrued 124,400 162,904
Interest Accrued 24,491 13,369
Energy Trading Contracts 1,032,236 1,115,967
Other 55,625 60,701
------ ------
TOTAL CURRENT LIABILITIES 1,518,905 1,604,012
--------- ---------
DEFERRED INCOME TAXES 427,368 422,759
------- -------
DEFERRED INVESTMENT TAX CREDITS 40,398 41,234
------ ------
DEFERRED CREDITS 14,170 12,861
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 268,561 138,420
------- -------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $3,958,327 $3,894,934
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
(in thousands)
2001 2000
---- ----
OPERATING ACTIVITIES:
Net Income $ 37,671 $27,471
Adjustments for Noncash Items:
Depreciation and Amortization 25,835 24,669
Amortization Regulatory Assets 5,803 -
Deferred Federal Income Taxes 6,957 5,072
Deferred Investment Tax Credits (836) (847)
Deferred Fuel Cost (net) - (5,408)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (10,067) 24,057
Fuel, Materials and Supplies (4,345) 89
Accrued Utility Revenues 9,638 7,390
Accounts Payable 17,605 (10,440)
Taxes Accrued (38,504) (29,554)
Interest Accrued 11,122 8,700
Other (net) (23,652) 9,925
------- -----
Net Cash Flows From Operating Activities 37,227 61,124
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (33,007) (27,022)
Proceeds from Sale of Property - 330
----- ---
Net Cash Flows Used For Investing Activities (33,007) (26,692)
------- -------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 13,477 -
Change in Short-term Debt (net) - (6,025)
Retirement of Long-term Debt - (1,976)
Dividends Paid on Common Stock (20,738) (23,650)
Dividends Paid on Cumulative Preferred Stock (262) (437)
---- ----
Net Cash Flows Used For Financing Activities (7,523) (32,088)
------ -------
Net Increase (Decrease) in Cash and Cash Equivalents (3,303) 2,344
Cash and Cash Equivalents at Beginning of Period 11,600 5,107
------ -----
Cash and Cash Equivalents at End of Period $ 8,297 $ 7,451
=========== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $6,127,000 and $8,684,000
and for income taxes was $17,485,000 and $6,607,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $84,000 and
$1,377,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
F-6
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $69 million primarily due to the return to
service of both of I&M's Cook Plant nuclear units which were on an extended
outage throughout 1999 and for a significant portion of 2000 because of
questions regarding the operability of certain safety systems. Unit 2 and
Unit 1 returned to service in June and December 2000, respectively.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $583 82
Fuel Expense 16 34
Purchased Power Expense 522 116
Other Operation Expense (36) (27)
Maintenance Expense (27) (49)
Federal Income Taxes 35 N.M.
N.M. = Not Meaningful
The significant increase in operating revenues resulted from increased
wholesale sales as sales to the AEP Power Pool increased by a multiple of
13 and I&M's share of sales to and forward trades with other utility
systems and power marketers by the AEP Power Pool increased 53%. As a
member of the AEP Power Pool, I&M shares in the revenues and costs of the
AEP Power Pool's wholesale sales and forward trades. In the first quarter
of 2001 the AEP Power Pool grew its trading operations resulting in an
increase in the number of forward electricity contracts made in AEP's
traditional marketing area (up to two transmission systems from AEP's
service territory) resulting in the increase in trading volume. 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. With the return to service of the nuclear units in 2000,
I&M's available generation increased resulting in additional power being
delivered to the AEP Power Pool in 2001.
Fuel expense increased primarily due to increased generation
reflecting the return to service of the nuclear units following the
extended outage.
The increase in purchased power expense resulted mainly from the
increase in wholesale sales and trading volume. Other operation and
maintenance expenses decreased primarily due to the cessation of expenses
related to work to restart the Cook Plant units.
The significant increase in federal income tax expense attributable to
operations was primarily due to a major increase in pre-tax operating
income.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $1,291,538 $708,150
---------- --------
OPERATING EXPENSES:
Fuel 63,973 47,860
Purchased Power 971,587 449,270
Other Operation 97,363 133,551
Maintenance 28,175 55,384
Depreciation and Amortization 40,723 38,211
Taxes Other Than Federal Income Taxes 20,332 17,209
Federal Income Tax Expense (Credit) 16,687 (18,084)
------ -------
TOTAL OPERATING EXPENSES 1,238,840 723,401
--------- -------
OPERATING INCOME (LOSS) 52,698 (15,251)
NONOPERATING INCOME 4,445 565
----- ---
INCOME (LOSS) BEFORE INTEREST CHARGES 57,143 (14,686)
INTEREST CHARGES 24,780 21,867
------ ------
NET INCOME (LOSS) 32,363 (36,553)
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,155 1,160
----- -----
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 31,208 $ (37,713)
============ =========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
NET INCOME (LOSS) $32,363 $(36,553)
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (1,919) -
------ ------
COMPREHENSIVE INCOME (LOSS) $30,444 $(36,553)
======= ========
The common stock of I&M is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 3,443 $166,389
NET INCOME (LOSS) 32,363 (36,553)
DEDUCTIONS:
Cash Dividends Declared:
Common Stock - 26,290
Cumulative Preferred Stock 1,122 1,125
Capital Stock Expense 33 57
-- --
BALANCE AT END OF PERIOD $34,651 $102,364
======= ========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,733,347 $2,708,436
Transmission 947,946 945,709
Distribution 873,271 863,736
General (including nuclear fuel) 246,591 257,152
Construction Work in Progress 97,959 96,440
------ ------
Total Electric Utility Plant 4,899,114 4,871,473
Accumulated Depreciation and Amortization 2,341,947 2,280,521
--------- ---------
NET ELECTRIC UTILITY PLANT 2,557,167 2,590,952
--------- ---------
NUCLEAR DECOMMISSIONING AND
SPENT NUCLEAR FUEL DISPOSAL TRAUST FUNDS 792,140 778,720
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 354,629 194,947
------- -------
OTHER PROPERTY AND INVESTMENTS 129,246 131,417
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 13,922 14,835
Accounts Receivable:
Customers 73,876 106,832
Affiliated Companies 43,807 48,706
Miscellaneous 21,518 27,491
Allowance for Uncollectible Accounts (734) (759)
Fuel - at average cost 19,417 16,532
Materials and Supplies - at average cost 87,684 84,471
Energy Trading Contracts 1,203,262 1,229,683
Prepayments 11,974 6,424
------ -----
TOTAL CURRENT ASSETS 1,474,726 1,534,215
--------- ---------
REGULATORY ASSETS 528,340 552,140
------- -------
DEFERRED CHARGES 40,032 36,156
------ ------
TOTAL ASSETS $5,876,280 $5,818,547
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
arch 31, 2001 December 31, 2000
------------- -----------------
(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 733,106 733,072
Accumulated Other Comprehensive Income (Loss) (1,919) -
Retained Earnings 34,651 3,443
------ -----
Total Common Shareowner's Equity 822,422 793,099
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,302,308 1,298,939
--------- ---------
TOTAL CAPITALIZATION 2,198,411 2,165,719
--------- ---------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 568,432 560,628
Other 104,977 108,600
------- -------
TOTAL OTHER NONCURRENT LIABILITIES 673,409 669,228
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 90,000 90,000
Advances from Affiliates 258,460 253,582
Accounts Payable:
General 94,006 119,472
Affiliated Companies 79,314 75,486
Taxes Accrued 96,582 68,416
Interest Accrued 23,993 21,639
Obligations Under Capital Leases 10,341 100,848
Energy Trading Contracts 1,195,172 1,275,097
Other 90,477 97,070
------ ------
TOTAL CURRENT LIABILITIES 1,938,345 2,101,610
--------- ---------
DEFERRED INCOME TAXES 479,679 487,945
------- -------
DEFERRED INVESTMENT TAX CREDITS 111,905 113,773
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK
- ROCKPORT PLANT UNIT 2 80,372 81,299
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 304,482 156,736
------- -------
DEFERRED CREDITS 89,677 42,237
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,876,280 $5,818,547
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $32,363 $ (36,553)
Adjustments for Noncash Items:
Depreciation and Amortization 41,589 39,191
Amortization of Incremental Nuclear
Refueling Outage Expenses (net) 316 2,035
Unrecovered Fuel and Purchased Power Costs (net) 9,375 9,375
Amortization of Nuclear Outage Costs 10,000 10,000
Deferred Federal Income Taxes (2,462) (7,801)
Deferred Investment Tax Credits (1,868) (1,887)
Deferred Property Taxes (9,731) (10,241)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 43,803 12,710
Fuel, Materials and Supplies (6,098) 4,609
Accrued Utility Revenues - 2,436
Accounts Payable (21,638) (18,932)
Taxes Accrued 28,166 3,794
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Energy Trading Contracts - Current (net) (53,504) (12,638)
Other (net) 17,413 (8,688)
------ ------
Net Cash Flows From Operating Activities 106,188 5,874
------- -----
INVESTING ACTIVITIES:
Construction Expenditures (18,241) (51,435)
Buyout of Nuclear Fuel Leases (92,616) -
Other - 250
------ ---
Net Cash Flows Used For Investing Activities (110,857) (51,185)
-------- -------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 4,878 -
Change in Short-term Debt (net) - 124,131
Retirement of Long-term Debt - (48,000)
Retirement of Cumulative Preferred Stock - (149)
Dividends Paid on Common Stock - (26,290)
Dividends Paid on Cumulative Preferred Stock (1,122) -
------ ------
Net Cash Flows From Financing Activities 3,756 49,692
----- ------
Net Increase (Decrease) in Cash and Cash Equivalents (913) 4,381
Cash and Cash Equivalents at Beginning of Period 14,835 3,863
------ -----
Cash and Cash Equivalents at End of Period $ 13,922 $ 8,244
======== =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $21,610,000 and
$17,965,000 and for income taxes was $7,471,000 and $(8,966,000) in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $991,000 and
$1,184,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
G-6
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Although revenues rose 98% for the quarter, net income declined by $1.0
million or 12%, as increases in operating expenses more than offset the revenue
increase. Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $228 98
Fuel Expense 1 7
Purchased Power
Expense 226 135
Other Operation
Expense 4 42
Maintenance Expense (1) (15)
Nonoperating Income 3 N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to a 64% increase in
electric trading volume. In the first quarter of 2001 the AEP Power Pool
grew its electric trading business resulting in a significant increase in
the number of forward electricity contracts made in AEP's traditional
marketing area (up to two transmission systems from AEP's service
territory). The Company, as a member of the AEP Power Pool, shares with
other Pool members in the revenues and costs of the AEP Power Pool's
wholesale sales to and forward trades with other utility systems and power
marketers.
Fuel expense increased in the quarter due to increased generation from
the Company's generating facilities as planned outages were reduced in 2001
compared with 2000. The Big Sandy Plant Unit 2 began a planned outage on
March 11, 2000 for boiler inspections and repairs and returned to service
late in April in 2000.
The increase in purchased power expense was primarily attributable to
the increase in trading volume.
Other operation expense increased due to an increase in trading
overhead expense and the cost of factoring of accounts receivable.
The effect of the costs of the outages at Big Sandy Plant in 2000
caused maintenance expense to decrease in the quarter. The increase in
nonoperating income 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 and speculative financial transactions (options, futures,
swaps). The AEP Power Pool enters into power trading transactions including
the forward purchase and sale of electricity and electricity 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.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
(in thousands)
OPERATING REVENUES: $459,157 $231,454
-------- --------
OPERATING EXPENSES:
Fuel 17,956 16,802
Purchased Power 393,865 167,732
Other Operation 14,728 10,384
Maintenance 5,429 6,367
Depreciation and Amortization 8,027 7,603
Taxes Other Than Federal Income Taxes 3,734 2,834
Federal Income Taxes 4,149 4,175
----- -----
TOTAL OPERATING EXPENSES 447,888 215,897
------- -------
OPERATING INCOME 11,269 15,557
NONOPERATING INCOME (LOSS) net 2,810 (46)
----- ----
INCOME BEFORE INTEREST CHARGES 14,079 15,511
INTEREST CHARGES 7,004 7,459
----- -----
NET INCOME $ 7,075 $ 8,052
========== =======
STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
NET INCOME $ 7,075 $8,052
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (1,354) -
------ --
COMPREHENSIVE INCOME $ 5,721 $8,052
======= ======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
(in thousands)
BALANCE AT BEGINNING OF PERIOD $57,513 $67,110
NET INCOME 7,075 8,052
CASH DIVIDENDS DECLARED:
Common Stock 7,561 7,590
----- -----
BALANCE AT END OF PERIOD $57,027 $67,572
======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- ----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 270,651 $ 271,107
Transmission 364,356 360,563
Distribution 391,261 387,499
General 67,857 67,476
Construction Work in Progress 12,481 16,419
------ ------
Total Electric Utility Plant 1,106,606 1,103,064
Accumulated Depreciation and Amortization 365,951 360,648
------- -------
NET ELECTRIC UTILITY PLANT 740,655 742,416
------- -------
OTHER PROPERTY AND INVESTMENTS 6,300 6,559
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 141,170 76,657
------- ------
CURRENT ASSETS:
Cash and Cash Equivalents 1,291 2,270
Accounts Receivable:
Customers 27,918 34,555
Affiliated Companies 20,181 22,119
Miscellaneous 4,763 6,419
Allowance for Uncollectible Accounts (278) (282)
Fuel - at average cost 4,425 4,760
Materials and Supplies - at average cost 16,093 15,408
Accrued Utility Revenues 3,257 6,500
Energy Trading Contracts 465,526 483,537
Prepayments 901 766
--- ---
TOTAL CURRENT ASSETS 544,077 576,052
------- -------
REGULATORY ASSETS 99,474 98,515
------ ------
DEFERRED CHARGES 9,835 11,817
----- ------
TOTAL ASSETS $1,541,511 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- ----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $50,450
Paid-in Capital 158,750 158,750
Accumulated Other Comprehensive Income (Loss) (1,354) -
Retained Earnings 57,027 57,513
------ ------
Total Common Shareowner's Equity 264,873 266,713
Long-term Debt 270,941 270,880
------- -------
TOTAL CAPITALIZATION 535,814 537,593
------- -------
OTHER NONCURRENT LIABILITIES 17,065 18,348
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 60,000 60,000
Advances from Affiliates 39,603 47,636
Accounts Payable:
General 34,389 32,043
Affiliated Companies 38,338 37,506
Customer Deposits 4,153 4,389
Taxes Accrued 8,194 11,885
Interest Accrued 7,976 5,610
Energy Trading Contracts 466,993 496,884
Other 10,415 14,517
------ ------
TOTAL CURRENT LIABILITIES 670,061 710,470
------- -------
DEFERRED INCOME TAXES 169,453 165,935
------- -------
DEFERRED INVESTMENT TAX CREDITS 11,360 11,656
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 122,250 61,632
------- ------
DEFERRED CREDITS 15,508 6,382
------ -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,541,511 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
(in thousands)
OPERATING ACTIVITIES:
Net Income $7,075 $8,052
Adjustments for Noncash Items:
Depreciation and Amortization 8,029 7,605
Deferred Federal Income Taxes 4,194 1,961
Deferred Investment Tax Credits (297) (298)
Deferred Fuel Costs (net) (1,271) (1,580)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 10,227 (105)
Fuel, Materials and Supplies (350) (797)
Accrued Utility Revenues 3,243 3,274
Accounts Payable 3,177 (2,334)
Taxes Accrued (3,691) 713
Interest Accrued 2,366 2,356
Change in Energy Trading Contracts (net) (15,775) 5,041
Other 3,218 (5,950)
----- ------
Net Cash Flows From Operating Activities 20,145 17,938
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (5,746) (7,573)
Proceeds from Sales of Property 216 -
--- ------
Net Cash Flow Used for Investing Activities (5,530) (7,573)
------ ------
FINANCING ACTIVITIES:
Change in Short-term Debt (net) - (2,065)
Change in Advances from Affiliates (net) (8,033) -
Dividends Paid (7,561) (7,590)
------ ------
Net Cash Flows Used For Financing Activities (15,594) (9,655)
------- ------
Net Increase (Decrease) in Cash and Cash Equivalents (979) 710
Cash and Cash Equivalents at Beginning of Period 2,270 674
----- ---
Cash and Cash Equivalents at End of Period $1,291 $ 1,384
====== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $4,529,000 and $5,029,000
and for income taxes was $4,354,000 and $2,001,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $661,000 and
$374,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
H-7
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $7.2 million or 16% in the first quarter of 2001
mainly due to strong performance by the trading operation offset in part by
the commencement of accelerated amortization of transition regulatory
assets. OPCo, as a member of the AEP Power Pool, shares in the revenues and
costs of wholesale marketing and trading activities conducted on its behalf
by the AEP Power Pool.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $652 62
Fuel Expense (15) (7)
Purchased Power Expense 641 119
Maintenance Expense 7 26
Depreciation and
Amortization 22 56
Taxes Other Than Federal
Income taxes (3) (7)
Federal Income Taxes 3 7
Nonoperating Income 15 N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to a 41% increase in
electric trading volume. In the first quarter of 2001 the AEP Power Pool
grew its trading operations resulting in the expension of the number of
forward electricity contracts made in AEP's traditional marketing area (up
to two transmission systems from AEP's service territory).
Fuel expense decreased in the first quarter of 2001 due mainly to a
drop in the cost per ton of fuel and decreased shutdown costs for
affiliated mining operations. The Company discontinued the practice of
deferred fuel accounting due to the deregulation of the electric utility
industry on January 1, 2001 as a result of the restructuring the electric
utility industry in Ohio to provide customers with a choice of generation
supplier. Under deferred fuel accounting, changes in fuel costs were
deferred until they were reflected in rates. As a result of the cessation
of deferred fuel cost accounting commensurate with the termination of the
Ohio fuel clause, the Company is subject to the effect of changes in the
price of fuel it uses to generate electricity.
The increase in purchased power expense was primarily attributable to
the increase in trading volume. Maintenance expenses increased due to steam
boiler inspections and overhauls at various plants. The commencement of
accelerated amortization of transition regulatory assets in connection with
the transition to customer choice and market-based pricing of electricity
accounted for the increase in depreciation and amortization expense.
A decline in the gross receipts tax caused taxes other than federal
income taxes to decrease. The gross receipts tax decreased due to an
increase from $1 per ton to $3 per ton in a state tax credit for the use of
Ohio coal. The increase in Federal income taxes attributable to operations
was primarily due to changes in certain book/tax timing differences
accounted for on a flow-through basis offset in part by a decrease in
pre-tax operating book income.
The increase in nonoperating income was due to an increase in net
gains from AEP Power Pool trading transactions outside of the AEP System's
traditional marketing area and speculative financial transactions (options,
futures, swaps). The AEP Power Pool enters into power trading transactions
including the forward purchase and sale of electricity and electricity
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's traditional marketing area and for speculative financial
transactions (options, futures, swaps) is included in nonoperating income.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $1,699,665 $1,047,837
---------- ----------
OPERATING EXPENSES:
Fuel 200,561 215,248
Purchased Power 1,178,906 537,728
Other Operation 88,406 84,452
Maintenance 35,400 28,030
Depreciation and Amortization 60,059 38,489
Taxes Other Than Federal Income Taxes 40,861 43,732
Federal Income Taxes 37,608 35,045
------ ------
TOTAL OPERATING EXPENSES 1,641,801 982,724
--------- -------
OPERATING INCOME 57,864 65,113
NONOPERATING INCOME 18,000 2,900
------ -----
INCOME BEFORE INTEREST CHARGES 75,864 68,013
INTEREST CHARGES 22,467 21,797
------ ------
NET INCOME 53,397 46,216
PREFERRED STOCK DIVIDEND REQUIREMENTS 314 321
--- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 53,083 $ 45,895
============ ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
NET INCOME $53,397 $46,216
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (220) -
--- ------
COMPREHENSIVE INCOME $53,177 $46,216
======= =======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $398,086 $587,424
NET INCOME 53,397 46,216
CASH DIVIDENDS DECLARED:
Common Stock 35,744 37,703
Cumulative Preferred Stock 314 317
--- ---
BALANCE AT END OF PERIOD $415,425 $595,620
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
arch 31, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,774,742 $2,764,155
Transmission 875,190 870,033
Distribution 1,053,030 1,040,940
General (including mining assets) 604,638 707,417
Construction Work in Progress 212,401 195,086
------- -------
Total Electric Utility Plant 5,520,001 5,577,631
Accumulated Depreciation and Amortization 2,708,332 2,764,130
--------- ---------
NET ELECTRIC UTILITY PLANT 2,811,669 2,813,501
--------- ---------
OTHER PROPERTY AND INVESTMENTS 106,925 109,124
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 449,630 256,455
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 21,378 31,393
Advances to Affiliates 16,536 92,486
Accounts Receivable:
Customers 128,106 139,732
Affiliated Companies 135,780 126,203
Miscellaneous 39,792 39,046
Allowance for Uncollectible Accounts (1,025) (1,054)
Fuel - at average cost 88,505 82,291
Materials and Supplies - at average cost 106,970 96,053
Energy Trading Contracts 1,471,335 1,617,660
Prepayments and Other 55,419 33,146
------ ------
TOTAL CURRENT ASSETS 2,062,796 2,256,956
--------- ---------
REGULATORY ASSETS 703,119 714,710
------- -------
DEFERRED CHARGES 79,105 101,690
------ -------
TOTAL ASSETS $6,213,244 $6,252,436
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(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 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (220) -
Retained Earnings 415,425 398,086
------- -------
Total Common Shareholder's Equity 1,198,889 1,181,770
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 1,078,171 1,077,987
--------- ---------
TOTAL CAPITALIZATION 2,302,558 2,285,255
--------- ---------
OTHER NONCURRENT LIABILITIES 537,423 542,017
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 75,000 117,506
Accounts Payable - General 151,028 179,691
Accounts Payable - Affiliated Companies 115,081 121,360
Customer Deposits 129,358 39,736
Taxes Accrued 171,681 223,101
Interest Accrued 31,564 20,458
Obligations Under Capital Leases 29,189 32,716
Energy Trading Contracts 1,483,865 1,662,315
Other 136,314 151,934
------- -------
TOTAL CURRENT LIABILITIES 2,323,080 2,548,817
--------- ---------
DEFERRED INCOME TAXES 617,096 621,941
------- -------
DEFERRED INVESTMENT TAX CREDITS 24,413 25,214
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 385,975 206,187
------- -------
DEFERRED CREDITS 22,699 23,005
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $6,213,244 $6,252,436
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 53,397 $46,216
Adjustments for Noncash Items:
Depreciation 52,853 60,294
Amortization of Transition Assets 19,256 -
Deferred Federal Income Taxes (1,068) (14,957)
Deferred Fuel Costs (net) - (3,961)
Amortization of Deferred Property Taxes 19,992 19,666
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 1,274 (64,270)
Fuel, Materials and Supplies (17,131) 13,714
Accrued Utility Revenues 264 12,519
Prepayments (22,537) (4,941)
Accounts Payable (34,942) 19,615
Taxes Accrued (51,420) (18,324)
Interest Accrued 11,106 6,549
Operating Reserves (1,042) 22,694
Other (net) 21,815 16,082
------ ------
Net Cash Flows From Operating Activities 51,817 110,896
------ -------
INVESTING ACTIVITIES:
Construction Expenditures (65,103) (40,684)
Proceeds from Sale of Property and Other 5,885 -
----- -------
Net Cash Flows Used For Investing Activities (59,218) (40,684)
------- -------
FINANCING ACTIVITIES:
Change in Advances to Affiliates (net) 75,950 -
Change in Short-term Debt (net) - 46,506
Retirement of Cumulative Preferred Stock - (46)
Retirement of Long-term Debt (42,506) (8,883)
Dividends Paid on Common Stock (35,744) (37,733)
Dividends Paid on Cumulative Preferred Stock (314) (317)
---- ----
Net Cash Flows Used For Financing Activities (2,614) (473)
------ ----
Net Increase (Decrease) in Cash and Cash Equivalents (10,015) 69,739
Cash and Cash Equivalents at Beginning of Period 31,393 157,138
------ -------
Cash and Cash Equivalents at End of Period $ 21,378 $ 226,877
=========== =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $10,887,000 and
$15,043,000 and for income taxes was $50,242,000 and $20,652,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $319,000 and
$2,791,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
I-5
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
The Company had a loss of $1.6 million for the first quarter of 2001
compared with net income of $1.2 million for the first quarter of 2000. The
loss was primarily a result of increased maintenance expense due to damage
caused by a large winter ice storm and increased interest costs.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $195 121
Fuel Expense 40 56
Purchased Power Expense 146 706
Other Operation Expense 11 45
Maintenance Expense 1 14
Federal Income Taxes (2) 542
Interest Charges 1 6
The significant increase in operating revenues was due to
participation in power marketing and trading activities conducted on its
behalf by the AEP System. Revenues were also impacted by the absence of a
2000 adjustment of the Company's portion of a FERC-approved Transmission
Coordination Agreement, which had decreased revenues in 2000 and decreased
other operation expenses in 2000. The transmission coordination agreement
provides the means by which the AEP West electric operating companies plan,
operate and maintain their four separate transmission systems as a single
unit. The agreement also established the method by which these companies
allocate revenues and costs received under open access transmission
tariffs.
Fuel expense increased due primarily to a rise in the average unit
fuel cost reflecting an increase in natural gas prices. The increase in
purchased power expense was primarily attributable to the increase in
trading volume. Other operation expenses increased due mainly to the
absence of a 2000 favorable adjustment for the FERC-approved Transmission
Coordination Agreement mentioned above, along with increased power trading
and transmission expenses.
Maintenance expense increased for the quarter due primarily to
increased expenses to repair damage to overhead lines caused by a winter
storm.
Income tax expense associated with utility operations decreased as a
result of a decrease in pre-tax book income. Interest charges increased
reflecting the issuance of one year floating rate notes in November 2000
and additional short-term borrowings.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $356,139 $161,329
-------- --------
OPERATING EXPENSES:
Fuel 111,801 71,586
Purchased Power 166,546 20,666
Other Operation 34,557 23,757
Maintenance 9,830 8,586
Depreciation and Amortization 19,471 18,913
Taxes Other Than Federal Income Taxes 7,373 7,239
Federal Income Taxes (1,779) (277)
------ ----
TOTAL OPERATING EXPENSES 347,799 150,470
------- -------
OPERATING INCOME 8,340 10,859
NONOPERATING INCOME 603 223
--- ---
INCOME BEFORE INTEREST CHARGES 8,943 11,082
INTEREST CHARGES 10,503 9,917
------ -----
NET INCOME (LOSS) (1,560) 1,165
PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53
-- --
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $(1,613) $1,112
======= ======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $137,688 $139,237
NET INCOME (LOSS) (1,560) 1,165
CASH DIVIDENDS DECLARED:
Common Stock 13,060 17,000
Preferred Stock 53 53
-- --
BALANCE AT END OF PERIOD $123,015 $123,349
======== ========
The common stock of PSO is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 914,325 $914,096
Transmission 399,558 396,695
Distribution 946,944 938,053
General 208,536 206,731
Construction Work in Progress 160,620 149,095
------- -------
Total Electric Utility Plant 2,629,983 2,604,670
Accumulated Depreciation and Amortization 1,162,740 1,150,253
--------- ---------
NET ELECTRIC UTILITY PLANT 1,467,243 1,454,417
--------- ---------
OTHER PROPERTY AND INVESTMENTS 39,141 38,211
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 16,463 52,629
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 14,092 11,301
Accounts Receivable:
Customers 60,705 59,957
Affiliated Companies 6,723 3,453
Fuel - at LIFO costs 21,300 28,113
Materials and Supplies - at average costs 30,591 29,642
Under-recovered Fuel Costs 45,991 43,267
Energy Trading Contracts 33,207 382,380
Prepayments 3,890 1,559
----- -----
TOTAL CURRENT ASSETS 216,499 559,672
------- -------
REGULATORY ASSETS 23,150 29,338
------ ------
DEFERRED CHARGES 28,411 7,889
------ -----
TOTAL ASSETS $1,790,907 $2,142,156
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
rch 31, 2001 December 31, 2000
------------ -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000 Shares
Issued Shares: 10,482,000 shares and
Outstanding Shares: 9,013,000 Shares $ 157,230 $157,230
Paid-in Capital 180,000 180,000
Retained Earnings 123,015 137,688
------- -------
Total Common Shareholder's Equity 460,245 474,918
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,283 5,283
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 450,899 450,822
------- -------
TOTAL CAPITALIZATION 991,427 1,006,023
------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 20,000
Advances from Affiliates 178,993 81,120
Accounts Payable - General 67,306 104,379
Accounts Payable - Affiliated Companies 66,205 64,556
Customers Deposits 18,800 19,294
Taxes Accrued 6,397 1,659
Interest Accrued 11,085 8,336
Energy Trading Contracts 32,665 389,279
Other 10,169 12,137
------ ------
TOTAL CURRENT LIABILITIES 391,620 700,760
------- -------
DEFERRED INCOME TAXES 318,754 312,060
------- -------
DEFERRED INVESTMENT TAX CREDITS 35,335 35,783
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 37,651 35,292
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 16,120 52,238
------ ------
TOTAL CAPITALIZATION AND LIABILITIES $1,790,907 $2,142,156
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $ (1,560) $ 1,165
Adjustments for Noncash Items:
Depreciation and Amortization 19,471 18,913
Deferred Income Taxes 5,750 2,137
Deferred Investment Tax Credits (448) (448)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (4,018) 6,859
Fuel, Materials and Supplies 5,864 657
Accounts Payable (35,424) 14,359
Taxes Accrued 4,738 (11,953)
Other Property and Investments (930) 2,998
Transmission Coordination Agreement Settlement - (15,063)
Deferred Property Taxes (20,730) -
Fuel Recovery (2,724) 9,267
Other (net) (3,362) 6,062
------ -----
Net Cash Flows From (Used For) Operating Activities (33,373) 34,953
------- ------
INVESTING ACTIVITIES:
Construction Expenditures (28,595) (34,760)
Other - (3,543)
------ ------
Net Cash Flows Used For Investing Activities (28,595) (38,303)
------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (20,000) (10,000)
Change in Advances from Affiliates (net) 97,872 31,034
Dividends Paid on Common Stock (13,060) (17,000)
Dividends Paid on Cumulative Preferred Stock (53) (53)
--- ---
Net Cash Flows From Financing Activities 64,759 3,981
------ -----
Net Increase in Cash and Cash Equivalents 2,791 631
Cash and Cash Equivalents at Beginning of Period 11,301 3,173
------ -----
Cash and Cash Equivalents at End of Period $ 14,092 $3,804
========= ======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $5,736,000 and $4,238,000
and for income taxes was $1,978,000 and $2,850,000 in 2001 and 2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
J-5
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $12.2 million, or 159%, for the first quarter of
2001. The increase for the quarter resulted primarily from increased
average wholesale prices and the favorable impact of AEP's power marketing
and trading operations. SWEPCo participates in power marketing and trading
activities conducted on its behalf by the AEP System. Income statement line
items which changed significantly were:
Increase
(in millions) %
------------- -
Operating Revenues $214 101
Fuel Expense 29 32
Purchased Power Expense 157 N.M.
Other Operation Expense 5 13
Maintenance Expense 1 7
Taxes Other Than Federal
Income Taxes 4 34
Federal Income Taxes 6 N.M.
N.M. = Not Meaningful
The increase in operating revenues resulted from higher fuel related
revenues due to increased fuel and purchased power expense due to the fuel
clause mechanism, increased retail energy sales due to increased usage and
the post merger favorable impact of AEP's power marketing and trading
operations, which added new wholesale revenues.
Fuel expense increased due primarily to an increase in the average
unit cost of fuel as a result of higher spot market natural gas prices.
The increase in purchased power expense was primarily caused by the
participation in AEP's trading operation, an increase in economy energy
purchases and increased firm energy contract purchases.
Other operation expense increased for the quarter as a result of an
unfavorable accounts receivable write-off, SWEPCo's share of power trading
expenses that did not exist prior to the merger and increased transmission
services expense.
Maintenance expense for the first quarter of 2001 increased as a
result of severe ice storms, offset in part by reduced overhead line
maintenance and tree-trimmings.
The increase in taxes other than federal income taxes was due to a
favorable adjustment of ad valorem taxes recorded in the first quarter of
2000.
The increase in federal income tax expense attributable to operations
was primarily due to an increase in pre-tax operating income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $425,689 $212,156
-------- --------
OPERATING EXPENSES:
Fuel 118,246 89,352
Purchased Power 168,857 11,698
Other Operation 39,268 34,698
Maintenance 15,236 14,306
Depreciation and Amortization 28,130 27,357
Taxes Other Than Federal Income Taxes 14,266 10,661
Federal Income Taxes 7,700 1,353
----- -----
TOTAL OPERATING EXPENSES 391,703 189,425
------- -------
OPERATING INCOME 33,986 22,731
NONOPERATING INCOME (LOSS) 247 (233)
--- ----
INCOME BEFORE INTEREST CHARGES 34,233 22,498
INTEREST CHARGES 14,364 14,835
------ ------
NET INCOME 19,869 7,663
PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57
-- --
EARNINGS APPLICABLE TO COMMON STOCK $ 19,812 $ 7,606
========= =======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $293,989 $283,546
NET INCOME 19,869 7,663
CASH DIVIDENDS DECLARED:
Common Stock 18,553 15,501
Preferred Stock 57 57
-- --
BALANCE AT END OF PERIOD $295,248 $275,651
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,425,061 $1,414,527
Transmission 523,948 519,317
Distribution 1,007,999 1,001,237
General 326,967 325,948
Construction Work in Progress 49,587 57,995
------ ------
Total Electric Utility Plant 3,333,562 3,319,024
Accumulated Depreciation and Amortization 1,474,266 1,457,005
--------- ---------
NET ELECTRIC UTILITY PLANT 1,859,296 1,862,019
--------- ---------
OTHER PROPERTY AND INVESTMENTS 40,731 39,627
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 19,916 63,028
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 2,515 1,907
Accounts Receivable:
Customers 10,507 41,399
Affiliated Companies 20,642 11,419
Fuel Inventory - at average cost 39,677 40,024
Under-recovered Fuel 42,106 35,469
Materials and Supplies - at average cost 26,146 25,137
Energy Trading Contracts 40,171 457,936
Prepayments 15,730 16,780
------ ------
TOTAL CURRENT ASSETS 197,494 630,071
------- -------
REGULATORY ASSETS 53,503 57,082
------ ------
DEFERRED CHARGES 34,511 10,707
------ ------
TOTAL ASSETS $2,205,451 $2,662,534
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(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 295,248 293,989
------- -------
Total Common Shareowner's Equity 675,908 674,649
Preferred Stock 4,704 4,704
SWEPCO-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
SUBORDINATED DEBENTURES OF SWEPCO 110,000 110,000
Long-term Debt 494,897 645,368
------- -------
TOTAL CAPITALIZATION 1,285,509 1,434,721
--------- ---------
OTHER NONCURRENT LIABILITIES 11,824 11,290
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 150,595 595
Advances from Affiliates 60,305 16,823
Accounts Payable - General 65,562 107,747
Accounts Payable - Affiliated Companies 28,884 36,021
Customer Deposits 16,868 16,433
Taxes Accrued 43,343 11,224
Interest Accrued 11,834 13,198
Energy Trading Contracts 39,518 466,198
Other 12,419 15,064
------ ------
TOTAL CURRENT LIABILITIES 429,328 683,303
------- -------
DEFERRED INCOME TAXES 398,258 399,204
------- -------
DEFERRED INVESTMENT TAX CREDITS 52,054 53,167
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 8,977 18,288
----- ------
LONG-TERM ENERGY TRADING CONTRACTS 19,501 62,561
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $2,205,451 $2,662,534
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 19,869 $ 7,663
Adjustments for Noncash Items:
Depreciation and Amortization 28,130 27,357
Deferred Income Taxes (1,930) 5,544
Deferred Investment Tax Credits (1,113) (1,121)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 21,669 7,972
Fuel, Materials and Supplies (662) 1,488
Accounts Payable (49,324) 1,507
Taxes Accrued 32,119 (7,719)
Transmission Coordination Agreement Settlement - (24,406)
Deferred Property Taxes (24,531) -
Fuel Recovery (6,637) -
Other (20,092) 6,983
------- -----
Net Cash Flows From (Used For) Operating Activities (2,502) 25,268
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (21,638) (28,062)
Other 326 (2,645)
--- ------
Net Cash Flows Used For Investing Activities (21,312) (30,707)
------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 149,515
Retirement of Long-term Debt (450) (450)
Change in Advances from Affiliates (net) 43,482 (127,608)
Dividends Paid on Common Stock (18,553) (15,501)
Dividends Paid on Cumulative Preferred Stock (57) (57)
--- ---
Net Cash Flows From Financing Activities 24,422 5,899
------ -----
Net Increase in Cash and Cash Equivalents 608 460
Cash and Cash Equivalents at Beginning of Period 1,907 3,043
----- -----
Cash and Cash Equivalents at End of Period $ 2,515 $ 3,503
========= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,877,000 and $7,172,000
and for income taxes was $3,164,000 and $1,205,000 in 2001 and 2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
K-6
WEST TEXAS UTILITIES COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
--------------------------------------------------------
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income decreased $2.9 million or 77% for the quarter. This
decrease was primarily due to the absence of an excess earnings adjustment
made in 2000 which had increased net income by $2.1 million in 2000. This
adjustment was made to true up the 1999 excess earnings accrual to the
actual report filed in March 2000. No such adjustment was required in 2001.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $98 102
Fuel Expense 31 110
Purchased Power Expense 67 449
Other Operation Expense 5 27
Taxes Other Than Federal
Income Taxes 1 22
Federal Income Taxes (2) (106)
Nonoperating Income 2 N.M.
N.M. = Not Meaningful
The significant increase in operating revenues was due mostly to the
post merger favorable impact of AEP's power marketing and trading
operations, which added new wholesale revenues. Revenues were also impacted
by the absence of a 2000 adjustment of the Company's portion of a
FERC-approved Transmission Coordination Agreement, which had decreased
revenues in 2000 and decreased other operation expenses in 2000. The
transmission coordination agreement provides the means by which the AEP
West electric operating companies plan, operate and maintain their four
separate transmission systems as a single unit. The agreement also
established the method by which these companies allocate revenues and costs
received under open access transmission tariffs.
The increase in fuel expense was due primarily to an increase in the
average unit cost of fuel as a result of higher spot market natural gas
prices.
The significant rise in purchased power expense was primarily
attributable to participation in AEP's trading operation and the impact of
natural gas prices on wholesale purchased power prices.
The increase in other operation expense was due mainly to the absence
in 2001 of a favorable adjustment made in 2000 related to the FERC-approved
Transmission Coordination Agreement.
The increase in taxes other than federal income taxes for the quarter
was primarily due to higher ad valorem taxes.
Federal income taxes attributable to operations decreased due
primarily to a decrease in pre-tax income.
The increase in nonoperating income was due primarily from interest
income on under-recovered fuel. WTU has been experiencing 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 including
accumulated interest on under-recovered balances. On January 1, 2002 the
fuel recovery mechanism will cease in Texas subjecting WTU to the risk of
changes in the market price of gas used to generate electricity.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
ree Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $195,006 $96,535
-------- -------
OPERATING EXPENSES:
Fuel 59,905 28,580
Purchased Power 81,692 14,893
Other Operation 25,756 20,304
Maintenance 4,562 4,862
Depreciation and Amortization 11,771 11,241
Taxes Other Than Federal Income Taxes 6,038 4,963
Federal Income Taxes 1,911
-----
(110)
TOTAL OPERATING EXPENSES 189,614 86,754
------- ------
OPERATING INCOME 5,392 9,781
NONOPERATING INCOME (LOSS) 1,431 (91)
----- ---
INCOME BEFORE INTEREST CHARGES 6,823 9,690
INTEREST CHARGES 5,932 5,857
----- -----
NET INCOME 891 3,833
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26
--- --
EARNINGS APPLICABLE TO COMMON STOCK $ 865 $ 3,807
========= =======
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $122,588 $113,242
NET INCOME 891 3,833
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 7,206 4,500
Preferred Stock 26 26
--- --
BALANCE AT END OF PERIOD $116,247 $112,549
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 436,816 $ 431,793
Transmission 236,149 235,303
Distribution 419,923 416,587
General 111,852 110,832
Construction Work in Progress 33,811 34,824
------ ------
Total Electric Utility Plant 1,238,551 1,229,339
Accumulated Depreciation and Amortization 523,888 515,041
------- -------
NET ELECTRIC UTILITY PLANT 714,663 714,298
------- -------
OTHER PROPERTY AND INVESTMENTS 23,681 23,154
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 20,944
------
6,619
CURRENT ASSETS:
Cash and Cash Equivalents 6,941
3,744
Accounts Receivable:
Customers 25,929 36,217
Affiliated Companies 13,822 16,095
Allowance for Uncollectible Accounts (108) (288)
Fuel Inventory - at average cost 12,607 12,174
Materials and Supplies - at average cost 11,128 10,510
Underrecovered Fuel 69,883 67,655
Energy Trading Contracts 13,351 152,174
Prepayments and Other Current Assets 851
---
232
TOTAL CURRENT ASSETS 150,588 302,329
------- -------
REGULATORY ASSETS 21,647 24,808
------ ------
DEFERRED CHARGES 11,521 3,399
------ -----
TOTAL ASSETS $ 928,719 $1,088,932
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(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 116,247 122,588
------- -------
Total Common Shareowner's Equity 255,697 262,038
Cumulative Preferred Stock Not Subject to
Mandatory Redemption
2,482 2,482
Long-term Debt 255,874 255,843
------- -------
TOTAL CAPITZALIZATION 514,053 520,363
------- -------
CURRENT LIABILITIES:
Advances from Affiliates 67,816 58,578
Accounts Payable - General 41,104 45,562
Accounts Payable - Affiliated Companies 30,684 42,212
Customer Deposits 2,659
4,321
Taxes Accrued 23,945 18,901
Interest Accrued 3,717
6,015
Energy Trading Contracts 13,133 154,919
Other 7,906
-----
7,269
TOTAL CURRENT LIABILITIES 194,287 334,454
------- -------
DEFERRED INCOME TAXES 157,090 157,038
------- -------
DEFERRED INVESTMENT TAX CREDITS 23,734 24,052
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 6,481 20,789
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 33,074 32,236
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $ 928,719 $1,088,932
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 891 $ 3,833
Adjustments for Noncash Items:
Depreciation and Amortization 11,771 11,241
Deferred Income Taxes 85 (5,946)
Deferred Investment Tax Credits (318) (318)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 12,381 7,431
Fuel, Materials and Supplies (1,051) (720)
Accounts Payable (15,986) (4,277)
Taxes Accrued 5,044 189
Transmission Coordination Agreement Settlement - 15,465
Deferred Property Taxes (8,616) -
Fuel Recovery (2,228) 5,361
Other (net) 3,586 4,722
----- -----
Net Cash Flows From Operating Activities 5,559 36,981
----- ------
INVESTING ACTIVITIES:
Construction Expenditures (10,762) (15,284)
Other - (982)
--- ----
Net Cash Flows Used For Investing Activities (10,762) (16,266)
------- -------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 9,238 (16,806)
Dividends Paid on Common Stock (7,206) (4,500)
Dividends Paid on Cumulative Preferred Stock (26)
---
(26)
Net Cash Flows From (Used For) Financing Activities 2,006 (21,332)
----- -------
Net Decrease in Cash and Cash Equivalents (3,197) (617)
Cash and Cash Equivalents at Beginning of Period 6,941 6,074
----- -----
Cash and Cash Equivalents at End of Period $ 3,744 $ 5,457
======= =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,162,000 and
$1,214,000 and for income taxes was ($2,957,000) and $-0- in 2001 and 2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
L-14
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 2001
(UNAUDITED)
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. General AEP, AEGCo, APCo, CSPCo, CPL, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
2. Financial Instruments,
Credit and Risk
Management AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
3. Sales of Assets AEP, OPCo
4. Rate Matters AEP, CPL, SWEPCo, WTU
5. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU
6. Business Segments AEP
7. Financing and Related
Activities AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
8. Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 2000 Annual Report as incorporated in and filed
with the Form 10-K.
The AEP System operating companies have reclassified certain
settled forward energy transactions of their trading operation from a
net to a gross basis of presentation in order to better reflect the
scope and nature of the AEP System's energy sales and purchases. All
financially net settled trading transactions, such as swaps, futures,
and unexercised options, continue to be reported on a net basis,
reflecting the financial nature of these transactions. The following
expense amounts were reclassified from revenues to purchased power
expense to present the prior period on a comparable basis.
Three Months Ended
March 31, 2000
Company (in thousands)
AEP $3,100,000
APCo 566,083
CSPCo 334,999
I&M 364,164
KPCo 134,250
OPCo 502,426
In the opinion of management, the unaudited financial statements
reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
2. RISK MANAGEMENT AND RELATED ACCOUNTING
Risk Management
AEP and its registrant 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 while entering into 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 to create shareholder value.
Risks of foreign currency fluctuations arise from investments in
foreign energy companies and projects and equipment purchases
denominated in foreign currencies. AEP does not presently utilize
derivatives to manage its exposures to foreign currency exchange rate
movements for its investments in foreign energy companies and projects.
For equipment purchases and energy trading transactions denominated in
foreign currencies, forward contracts have been utilized to manage the
exposure to fluctuations in foreign currency exchange rates. AEP, APCo,
and OPCo have entered into foreign currency hedge contracts to manage
the exposure to changes in foreign currency rates on assets purchased.
Short and long-term borrowings used to fund business operations
expose AEP and its registrant subsidiaries to risk from changes in
interest rates. AEP, KPCo, and I&M have entered into cash flow hedge
contracts to manage the exposure to changes in interest rates on
variable interest rate debt and the changes in interest rates on fixed
rate debt issuances.
Certain of AEP's foreign subsidiaries employ hedging transactions
in order to mitigate the risks of commodity market prices, foreign
currency and interest rate fluctuations. CitiPower utilizes interest
rate swaps and forward commodity contracts to hedge the risks of market
price and interest rate fluctuations. Certain of CitiPower's commodity
contracts are not designated as hedges and are marked-to-market.
Currency swaps are used by CSW International to hedge debt transactions
issued in foreign currencies. The majority of SEEBOARD's power and gas
contracts are considered as normal purchases and sales.
Accounting
In the first quarter of 2001, AEP adopted Statement of Financial
Accounting Standard No. 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS 137 and SFAS 138. SFAS 133
requires that entities recognize all derivatives as either assets or
liabilities and measure such derivatives at fair value. Changes in the
fair value of derivatives that are effective cash flow hedges are
included in other comprehensive income. AEP recorded a favorable
transition adjustment to accumulated other comprehensive income of $27
million at January 1, 2001 in connection with the adoption of SFAS 133.
AEP and its registrant subsidiaries have significant domestic
energy trading contracts that have been marked-to-market and accounted
for under EITF 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities". Therefore, the adoption of SFAS
133 did not require transition adjustments for AEP and its registrant
subsidiaries' open energy trading contracts.
AEP contracts identified in the SFAS 133 transition adjustment,
include interest rate swaps, foreign currency swaps, and commodity
swaps, options and futures, the vast majority of which were designated
as cash flow hedges and relate to foreign operations.
Subsequent to recording the transition adjustment FASB approved
guidance indicating that contracts with option features cannot qualify
for the normal purchases and normal sales exception under SFAS 133, as
amended. This guidance, which is effective in the third quarter of 2001,
is expected to have a favorable effect on earnings assuming that market
prices do not decline.
The FASB recently issued tentative guidance on two issues with
significant impacts on the electric industry. Such tentative guidance
states that energy capacity contracts that include certain
characteristics of purchased and written options and that derivative
contracts which do not result in physical delivery of power because of
transmission scheduling, referred to as bookouts, cannot meet the normal
purchases and normal sales exception. While AEP believes that the
majority of its electricity capacity contracts qualify as normal
purchases and sales and that bookouts result in simultaneous delivery,
passage of title, and settlement on a gross basis and are, therefore,
physical normal purchase and sale transactions, the ultimate resolution
of these electric industry issues could have a material effect on
reported earnings. The electric industry and AEP are activity working
with the FASB to resolve these issues.
Contracts that qualify as derivatives under SFAS 133 are reported
on the consolidated balance sheets at fair value. Open derivative
contracts are fair valued with unrealized gains reported as assets and
unrealized losses reported as liabilities.
Cash flows from both derivative instruments and trading activities
are included in net cash flows from operating activities.
Certain derivatives may be designated for accounting purposes as a
hedge of either the fair value of an asset, liability or firm
commitment, or a hedge of the variability of cash flows related to a
variable-priced asset, liability, commitment or forecasted transaction.
To qualify for hedge accounting, the relationship between the hedging
instrument and the hedged item must be documented to include the risk
management objective and strategy for use of the hedge instrument. At
the inception of the hedge and on an ongoing basis, the effectiveness of
the hedge is assessed as to whether the hedge is highly effective in
offsetting changes in fair value or cash flows. Changes in the fair
value that result from ineffectiveness under SFAS 133 are recognized
currently in earnings.
Changes in the fair value of fair value hedges offset changes in
the fair value of the hedged items to the extent the hedge is effective.
Changes in the fair value of effective cash flows hedges are reported in
accumulated other comprehensive income if documented at inception. Gains
and losses from cash flow hedges in other comprehensive income are
reclassified to earnings in periods in which the variability of cash
flows of the hedged items affect earnings.
The following chart represents the various cash flow hedge
derivative positions of AEP and its registrant companies at March 31,
2001:
Hedging Assets Hedging Liabilities Other Comprehensive
Income (Loss) After Tax
-----------------------
(in thousands)
AEP Consolidated
Power $33,185 $ (1,058) $ 36,527
Gas 20 (10,193) (7,111)
Interest Rate 394 (32,330) (14,866)
Foreign Currency (1,471) (1,128)
--------
$ 13,422
APCo
Foreign Currency - (642) (417)
KPCo
Interest Rate - (2,083) (1,354)
I&M
Interest Rate 394 (3,346) (1,919)
OPCo
Foreign Currency - (338) (220)
The following table represents the activity in Other Comprehensive
Income related to the effect of adopting SFAS 133 for derivative
contracts that qualify as cash flow hedges during the first quarter of
2001 (in thousands):
AEP consolidated
Transition Adjustment, January 1, 2001 $26,795
Effective portion of change in fair value 9,462
Reclass from OCI to net income (22,835)
-------
Accumulated OCI derivative gain $13,422
=======
APCo
Transition Adjustment, January 1, 2001 $ -
Effective portion of change in fair value (417)
Reclass from OCI to net income -
-----
Accumulated OCI derivative loss $(417)
=====
KPCo
Transition Adjustment, January 1, 2001 $ (557)
Effective portion of change in fair value (764)
Reclass from OCI to net income (33)
-------
Accumulated OCI derivative loss $(1,354)
=======
I&M
Transition Adjustment, January 1, 2001 $ (317)
Effective portion of change in fair value (1,405)
Reclass from OCI to net income (197)
-------
Accumulated OCI derivative loss $(1,919)
=======
OPCo
Transition Adjustment, January 1, 2001 $ -
Effective portion of change in fair value (220)
Reclass from OCI to net income -
-----
Accumulated OCI derivative loss $(220)
=====
Approximately $2 million of net gains from hedge derivatives in
accumulated other comprehensive income at March 31, 2001 is expected to
be reclassified to net income in the next twelve months by AEP. KPCo and
I&M estimate that approximately $0.6 million and $1.9 million,
respectively, of net losses in accumulated other comprehensive income
will be reclassified to net income in the next twelve months. The actual
amounts reclassified from accumulated other comprehensive income to net
income can differ as a result of market price changes. The maximum term
for which the exposure to the variability of future cash flows is being
hedged is up to 5 years for AEP and up to one year for APCo and OPCo.
3. SALES OF ASSETS
Sale of Generating Assets - Affecting AEP
As discussed in Note 3 of the Notes to Financial Statements in
the 2000 Annual Report, the divestiture of 1,904 MW of generating
capacity was required by the FERC and the PUCT as part of the approval
of the merger. In March 2001, AEP completed the sale of Frontera, one of
the generating plants required to be divested under the settlement
agreements approved by the FERC. The sale proceeds were $265 million and
resulted in an after tax gain of $46 million.
Sale of Yorkshire Investment - Affecting AEP
In December 2000 AEP 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 AEP's interest in
Yorkshire was signed and resulted in a $30 million after tax net loss
from the expected sale being recorded in 2000. On April 2, 2001,
following the approval of the buyer's shareholders, the sale was
completed without further impact on AEP's consolidated earnings.
Proposed Sale of Affiliated Coal Mines - Affecting AEP and OPCo
On April 30, 2001, AEP announced that it had entered into a
memorandum of understanding regarding a proposed sale of OPCo's
affiliated coal mines in Ohio and West Virginia. In addition, OPCo would
enter into coal supply agreements to purchase approximately 34 million
tons of coal through 2008. The terms of the sale are being negotiated
and management will continue to evaluate the transaction. Management is
unable to estimate the impact of the proposed sale on results of
operations.
4. RATE MATTERS
As discussed in Note 5 of the Notes to Financial Statements in the
2000 Annual Report, AEP's Texas electric operating companies have been
experiencing 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 amounts.
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. In
March 2001, pursuant to an interim order of an Administrative Law Judge
adopting a settlement of the fixed fuel factor portion of the application,
CPL implemented a $170.5 million increase in fixed fuel factors. In April
2001 the PUCT approved the settlement fixed fuel factors. In addition, in
April 2001 the PUCT voted to defer implementation of the requested fuel
surcharge until CPL's final fuel reconciliation as part of a 2004 true-up
proceeding. CPL has requested a rehearing on the surcharge denial.
In January 2001 WTU filed an application with the PUCT to implement
an increase in fuel factors of $46.5 million effective with the March 2001
billing month. In March 2001 pursuant to an interim order of an
Administrative Law Judge adopting a settlement of the fixed fuel factor
portion of the application, WTU implemented the increase in fixed fuel
factors. In April 2001, the PUCT approved the new WTU fixed fuel factors.
In March 2001 WTU filed a request with the PUCT for authority to
implement a surcharge of fuel cost under-recoveries totaling $59.5 million
including interest. The under-recoveries were incurred during the period
July 2000 through January 2001. The request is seeking to surcharge the
under-recovered fuel costs during the period May 2001 through December
2001. A decision on the WTU fuel surcharge request is pending. Based upon
the decision in the CPL fuel surcharge proceeding, management expects the
PUCT may defer recovery of the WTU fuel surcharge until the 2004 true-up
proceeding when WTU would have a final fuel reconciliation.
In June 2000 SWEPCo had filed with the PUCT an application to
reconcile fuel costs and to request authorization to carry the unrecovered
balance forward into the next reconciliation period. As discussed in the
2000 Annual Report, a settlement was reached in December 2000 and approved
by the PUCT in February 2001 which did not have a material effect on
results of operations.
In November 2000 SWEPCo filed an application with the PUCT 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.
The PUCT approved SWEPCo's application in January 2001. The order allows
an increase in fuel factors of $12 million on an annual basis beginning in
January 2001 and a surcharge of $11.8 million including accumulated
interest for the billing months of February through July 2001.
In May 2001 SWEPCo filed to increase fixed fuel factors by $4.3
million and to surcharge fuel under-recoveries for the period October 2000
through March 2001 of $18.3 million, including interest. Based upon the
decision in the CPL fuel surcharge proceeding, management expects the PUCT
may defer recovery of the SWEPCo fuel surcharge until the 2004 true-up
proceeding when SWEPCo would have a final fuel reconciliation.
Beginning January 1, 2002, fuel costs will no longer be subject to
PUCT fuel reconciliation proceedings under the Texas Restructuring
Legislation. 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. At
March 31, 2001, CPL's, SWEPCo's and WTU's Texas jurisdictional unrecovered
deferred fuel balances were $125 million, $25.4 million and $66.8 million,
respectively. As discussed above, the remaining balances on CPL, SWEPCo,
and WTU current fuel surcharges at March 31, 2001 are $45 million, $6.5
million and $9.5 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 are not recovered, it would have a negative impact on
results of operations.
5. INDUSTRY RESTRUCTURING
As discussed in the 2000 Annual Report, restructuring legislation
has been enacted in seven of the eleven state retail jurisdictions in
which the AEP domestic electric utility companies operate. 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. The following paragraphs discuss significant
events occurring in 2001 related to industry restructuring.
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 under the Ohio Act. Alternative suppliers
have been approved to compete for CSPCo's and OPCo's commercial and
industrial customers. Presently, virtually all 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 frozen
transition generation rates including fuel rates from January 1, 2001
to December 31, 2005 for all classes of customers.
As discussed in Note 7 of the Notes to Financial Statements in the
2000 Annual Report, CSPCo and OPCo filed an appeal with the Ohio Supreme
Court related to a tax expense issue which would result in duplicate
expense of $40 million and $50 million, respectively, for a twelve month
period beginning on May 1, 2001. One of the items CSPCo and OPCo
requested was a stay of the PUCO ordered implementation date (May 1,
2001) for an excise tax credit rider. On April 13, 2001, the Ohio
Supreme Court denied the companies' stay request. Management does not
expect the Ohio Supreme Court to hear arguments on the merits of this
case until the fourth quarter of 2001.
One of the intervenors at the hearings for approval of a
transition 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 CSPCo's and OPCo's recovery of their
transition generation-related regulatory assets. Management is unable to
predict the outcome of litigation. The resolution of this matter could
negatively impact future results of operation.
Virginia Restructuring - Affecting AEP and APCo
In connection with a Virginia law that provides for a transition
to choice of electricity supplier for retail customers beginning on
January 1, 2002 (which is described in Note 7 of the Notes to Financial
Statements in the 2000 Annual Report), APCo was required to make a
filing with the Virginia SCC to unbundle rates and separate generation
from transmission and distribution. On January 3, 2001, APCo filed its
corporate separation plan and rate unbundling plan with the Virginia
SCC, which included a 1999 cost of service study required by the
Virginia SCC's regulations. That filing indicated that additional
information about APCo's proposed corporate separation plan would be
filed at a later date.
On April 11, 2001, the Virginia SCC directed APCo to file the
additional information required to complete its corporate separation
filing when that information becomes available. APCo was also directed
to file, by May 15, 2001, all information necessary for the Virginia SCC
to fully consider a functional separation of APCo, by divisions. If in
connection with the transition process, the Virginia SCC were to reduce
APCo's rates or deny recovery of generation-related regulatory assets,
it would have an adverse effect on results of operations.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry. In February 2001 the Arkansas
General Assembly passed legislation that was signed into law by the
Governor that extended the date for electric retail competition to
October 1, 2003, and provided the Arkansas Commission with the authority
to delay that date for up to two additional years.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
The Texas Restructuring Legislation gives Texas customers of
investor-owned utilities the opportunity to choose their electric
provider and eliminates the fuel clause reconciliation process beginning
January 1, 2002. A 2004 true-up proceeding will determine the amount of
stranded costs, if any, including the final fuel recovery, net
regulatory asset recovery, certain environmental costs, accumulated
excess earnings offsets and other issues.
As discussed in the 2000 Annual Report, the method used to
determine initial stranded costs to be recovered beginning on January 1,
2002 has been controversial. During 2000 CPL submitted estimates of
stranded costs and the PUCT held hearings. In February 2001 the PUCT
issued an interim decision determining an initial amount of stranded
costs for CPL of negative $580 million. In April 2001 the PUCT ruled
that its current estimate of CPL's stranded costs was negative $615
million. CPL disagrees with the ruling that it has a stranded benefit
and has requested a rehearing.
In April 2001 the PUCT issued an order requiring CPL to reduce
future distribution rates by $54.8 million over a five-year period in
order to return estimated excess earnings for 1999, 2000 and 2001. The
Texas Restructuring Legislation intended that excess earnings would be
used to reduce stranded cost. Final stranded cost amounts and the
treatment of excess earnings will be determined in the 2004 true-up
proceeding. The PUCT currently estimates that CPL will have no stranded
cost and has ordered the rate reduction to return excess earnings,
pending the outcome of the 2004 true-up proceeding. Management believes
that CPL will have stranded costs in 2004, and that the current
treatment of excess earnings will be amended at that time. CPL expensed
excess earnings amounts in 1999 and 2000. Consequently, the April order
has no effect on reported net income.
A Texas settlement agreement in connection with the AEP and
CSW merger permits CPL to apply for regulatory purposes up to $20
million of previously identified STP ECOM plant assets a year in 2000
and 2001 to reduce excess earnings, if any. For book purposes, STP ECOM
plant assets will be depreciated in accordance with GAAP, on a
systematic and rational basis unless impaired. To the extent excess
earnings exceed $20 million in 2001, CPL will establish a regulatory
liability or reduce regulatory assets by a charge to earnings.
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 which reconciles
their fuel costs through the period ending December 31, 2001. These
final fuel balances will be included in each company's 2004 true-up
proceeding. The elimination of the fuel clause recoveries in 2002 in
Texas will subject AEP, CPL, SWEPCo and WTU to the risk of fuel market
price increases and could adversely affect future results of operations
beginning in 2002.
In the event CPL, SWEPCo, and WTU are unable after the 2004
true-up proceeding to recover all or a portion of their
generation-related regulatory assets, unrecovered fuel balances,
stranded costs and other restructuring related costs, it could have a
material adverse effect on results of operations, cash flows and
possibly financial condition.
6. BUSINESS SEGMENTS
AEP has three principal business segments: wholesale, energy
delivery, and other investments. The wholesale segment is comprised of
the generation component of electricity sales to domestic retail and
wholesale customers, worldwide electric and gas trading and other energy
supply related businesses. Energy delivery includes the electric
transmission and distribution operations of the domestic electric
operating companies. Investments in foreign electric distribution and
supply companies, generation facilities outside of the United States and
telecommunication services make up the other investments segment.
All of the registrant subsidiaries except AEGCo have two business
segments, wholesale and energy delivery. AEGCo has one segment, a
wholesale generation business.
The presentation of wholesale and energy delivery segments
reflects management intention, announced in the fourth quarter of 2000,
to functionally and structurally separate its operations into
non-regulated and regulated businesses. Separation of AEP's regulated
bundled generation, transmission and distribution operations into an
unbundled non-regulated wholesale business and a regulated unbundled
energy delivery business will not be completed until the required
regulatory approvals are obtained. The electric operating subsidiaries
operating in states that are deregulating the supply business will be
structurally separated and the remaining subsidiaries will be
functionally separated. The amounts reported for 2000 have been
reclassified to conform to the current period's presentation.
The amounts shown for the three business segments reported by AEP
include certain estimates and allocations where necessary.
Energy Other Reconciling
Wholesale Delivery Investments Adjustments Consolidated
March 31, 2001 (in millions)
Revenues from:
External customers $12,879 $ 788 $ 571 $- $14,238
Transactions with other operating segments 192 (192)
Segment EBIT 352 245 113 (5) 705
Total assets 25,392 13,405 8,113 46,910
March 31, 2000 Revenues from:
External customers 4,776 724 617 6,117
Transactions with other operating segments 92 (92)
Segment EBIT 126 233 87 24 470
Total assets 17,802 10,717 7,283 35,802
The following tables present the business segments being reported
for APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU:
Wholesale
Segment March 31, 2001 March 31, 2000
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $1,822,030 $62,766 $3,684,595 $874,876 $ 43,019 $2,476,298
CPL 493,082 52,080 2,945,850 217,387 30,832 2,794,274
CSPCo 1,026,577 60,163 2,624,371 543,028 46,830 1,890,628
I&M 1,213,601 39,733 4,172,159 633,819 (66,008) 3,316,250
KPCo 422,830 1,021 840,123 198,183 2,500 556,073
OPCo 1,567,816 69,236 4,193,940 932,886 59,264 3,296,050
PSO 307,722 713 845,308 120,664 3,102 729,950
SWEPCo 347,632 17,220 1,146,835 139,869 (1,071) 1,093,677
WTU 156,364 (2,546) 442,070 59,808 (582) 398,227
Energy
Delivery March 31, 2001 March 31, 2000
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $152,097 $63,189 $2,906,810 $146,802 $63,481 $1,953,573
CPL 110,330 32,372 2,072,634 98,941 12,527 1,965,988
CSPCo 98,996 14,762 1,333,956 90,277 16,778 960,998
I&M 77,937 36,114 1,704,121 74,331 33,450 1,354,524
KPCo 36,327 16,636 701,388 33,271 17,176 464,245
OPCo 131,849 34,077 2,019,304 114,951 36,532 1,586,987
PSO 48,417 6,344 945,599 40,665 7,602 816,554
SWEPCo 78,057 24,660 1,058,616 72,287 24,874 1,009,548
WTU 38,642 9,540 486,649 36,727 12,100 438,384
Registrant
Subsidiaries
Company Total March 31, 2001 March 31, 2000
Revenues Revenues
From From
External Total Assets External
Customers EBIT Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $1,974,127 $125,955 $6,591,405 $1,021,678 $106,500 $4,429,871
CPL 603,412 84,452 5,018,484 43,359 4,760,262
316,328
CSPCo 1,125,573 74,925 3,958,327 63,608 2,851,626
633,305
I&M 1,291,538 75,847 5,876,280 (32,558) 4,670,774
708,150
KPCo 459,157 17,657 1,541,511 19,676 1,020,318
231,454
OPCo 1,699,665 103,313 6,213,244 1,047,837 95,796 4,883,037
PSO 356,139 7,057 1,790,907 10,704 1,546,504
161,329
SWEPCo 425,689 41,880 2,205,451 23,803 2,103,225
212,156
WTU 195,006 6,994 928,719 11,518 836,611
96,535
7. FINANCING AND RELATED ACTIVITIES
In the first quarter of 2001, the AEP System issued $40 million
of notes payable due in 2004 with an interest rate of 6.73% and
increased the level of borrowing under the SEEBOARD Revolving Credit
Facility by $89 million. Retirements of debt were: first mortgage bonds
totaling $120 million with interest rates ranging from 5.91% to 6-3/8%
due in 2001 and $61 million notes payable with interest rates ranging
from 6.20% to 7.5625% due in 2001.
The following table lists long-term debt retirements during the
first quarter of 2001 by the registrant subsidiaries:
Principal
Type Amount Interest Due
Company of Debt Retired Rate Date
------- ------- ----------- -------- ----
(in millions) (%)
APCo FMB $100 6-3/8 March 1, 2001
OPCo NP 30 6.20 January 31, 2001
PSO FMB 6 5.91 March 1, 2001
PSO FMB 5 6.02 March 1, 2001
PSO FMB 9 6.02 March 1, 2001
In March 2001 I&M paid $92.6 million to purchase leased nuclear
fuel from an unaffiliated company reflecting management's decision to
discontinue its policy of leasing all nuclear fuel for the Cook Plant.
The purchase was financed with funds from operations.
CPL redeemed $500,000 of its 8.00% trust preferred securities on
February 1, 2001.
On May 10, 2001, AEP issued $1.25 billion of debt consisting of
$1 billion of senior notes and $250 million of putable callable notes.
The interest rate on the senior notes is 6.125% and they are due in May
2006. The putable callable notes (Series B notes) have a fixed interest
rate of 5.5% until May 2003. At that date the Series B notes may be
subject to call by a third party for purchase and remarketing, in which
case the maturity would extend until May 2013. In the event the Series B
notes are not called for remarketing, AEP must redeem them.
In January 2001 APCo became a participant in AEP's money pool and
retired all outstanding short-term debt. The Money Pool coordinates
short-term borrowings for certain AEP System subsidiaries, primarily the
domestic electric utility operating companies. The operation of the
Money Pool is designed to match on a daily basis the available cash and
borrowing requirements of the participants, thereby minimizing the need
for short-term borrowings from external sources and increasing the
interest income for participants with available cash. Participants with
excess cash loan funds to the Money Pool reducing the amount of external
funds AEP needs to borrow to meet the short-term cash requirements of
other participants whose short-term cash requirements are met through
advances from the Money Pool. AEP borrows the funds on a daily basis,
when necessary, to meet the net cash requirements of the Money Pool
participants. A weighted average daily interest rate which is calculated
based on the outstanding short-term debt borrowings made by AEP is
applied to each Money Pool participant's daily outstanding investment or
debt position to determine interest income or interest expense. Money
Pool participants include interest income in nonoperating income and
interest expense in interest charges. APCo reports its borrowings from
the Money Pool as Advances from Affiliates.
In March 2001 APCo commenced factoring customer accounts
receivable and accrued utility revenue balances to an affiliate, AEP
Credit, Inc. Under the factoring arrangement APCo sells without recourse
certain of its customer accounts receivable and accrued utility revenue
balances to AEP Credit, Inc. and is charged a fee based on AEP Credit,
Inc.'s financing costs, uncollectible accounts experience for APCo's
receivables and administrative costs. The cost of factoring is included
in other operation expense. At March 31, 2001 the amount of APCo's
factored accounts receivable and accrued utility revenues was $78
million.
8. CONTINGENCIES
Litigation
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. On March
5, 2001, AEP and the individual defendants filed a comprehensive motion
to dismiss all claims against all defendents in the consolidated cases.
The Court has set oral arguments of the motion for June 7, 2001.
Although management believes these shareholder actions are without merit
and intends to continue 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 October 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
As discussed in Note 8 of the Notes to Financial Statements in
the 2000 Annual Report, SWEPCo has been involved in litigation
concerning the mining of lignite from jointly owned lignite reserves.
SWEPCo and CLECO are each a 50% owner of Dolet Hills Power Station Unit
1 and 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 these reserves. Since 1997 SWEPCo and CLECO have been
involved in litigation with DHMV and its partners in U.S. District Court
for the Western District of Louisiana. In April 2000, the parties agreed
to settle the litigation. As part of the settlement, a subsidiary of
SWEPCo will purchase DHMV's interest in the mining assets and will
assume the related obligations for mine reclamation. The settlement
agreement would give CLECO the option, beginning July 1, 2002, to
acquire up to a 50% interest in the mining assets. The litigation has
been stayed to provide the parties a reasonable period of time to
complete the settlement process. 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.
In May 2000 the AEP System companies filed motions to dismiss all
or portions of the complaints. On March 28 and 30, 2001, the Court
issued orders granting the motions in part and denying them in part. The
Court ruled claims for civil penalties based on activities that occurred
more than five years before the date the complaints were filed cannot be
imposed. Claims for injunctive relief are not subject to a time limit.
On February 23, 2001, the plaintiffs filed a motion for partial
summary judgment 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. On April 9, 2001, the AEP System companies filed a motion
requesting the Court deny plaintiffs' motion as premature, and issue an
order allowing discovery to continue. 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 extended 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 those owned
by 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 (SCR) technology (expected
to be operational in 2001) to reduce NOx emissions on its two-unit 2,600
MW Gavin Plant. Construction of SCR 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). Construction of SCR
technology on KPCo's Big Sandy Plant Unit 2 is scheduled for completion
in May 2003 at an estimated cost of $107 million.
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 for 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.
Other
AEP and its subsidiary registrants continue to be involved in
certain other matters discussed in the 2000 Annual Report.
M-8
REGISTRANTS' COMBINED 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 subsidiary registrants. Management's discussion and analysis of
results of operations for AEP and each of its subsidiary registrants for the
first quarter March 31, 2001 is presented with their financial statements
earlier in this document.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
year-to-date period were $336 million for AEP Consolidated. The following table
shows the additions by certain AEP subsidiary registrants.
Company Amount
------- ------
(in millions)
APCo $41
CPL 39
I&M 19
OPCo 65
SWEPCo 22
During the first three months of 2001, the AEP System issued $40 million
of notes payable due in 2004 with an interest rate of 6.73% and increased the
level of borrowing under the SEEBOARD Revolving Credit Facility by $89 million.
Retirements of debt were: first mortgage bonds totaling $120 million with
interest rates ranging from 5.91% to 6 3/8% due in 2001, $61 million of notes
payable with interest rates ranging from 6.20% to 7.5625% due in 2001 and a
decrease in short-term debt of $225 million.
The following table shows the retirements by certain AEP subsidiary
registrants:
Principal
Type Amount Interest Due
Company of Debt Retired Rate Date
------- ------- ----------- -------- ----
(in millions) (%)
APCo FMB $100 6-3/8 March 1, 2001
OPCo NP 30 6.20 January 31, 2001
PSO FMB 6 5.91 March 1, 2001
PSO FMB 5 6.02 March 1, 2001
PSO FMB 9 6.02 March 1, 2001
CPL redeemed $500,000 of its 8.00% trust preferred securities on
February 1, 2001.
On May 10, 2001, AEP issued $1.25 billion of debt consisting of $1
billion of senior notes and $250 million of putable callable notes. The interest
rate on the senior notes is 6.125% and they are due in May 2006. The putable
callable notes (Series B notes) have a fixed interest rate of 5.5% until May
2003. At that date the Series B notes may be subject to call by a third party
for purchase and remarketing, in which case the maturity would extend until May
2013. In the event the Series B notes are not called for remarketing, AEP must
redeem them.
OTHER MATTERS
Industry Restructuring
As discussed in the 2000 Annual Report, restructuring legislation has
been enacted in seven of the eleven state retail jurisdictions in which the AEP
domestic electric utility companies operate. 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. The following
paragraphs discuss significant events occurring in 2001 related to industry
restructuring.
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 under
the Ohio Act. Alternative suppliers have been approved to compete for CSPCo's
and OPCo's commercial and industrial customers. Presently, virtually all
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 frozen
transition generation rates including fuel rates from January 1, 2001 to
December 31, 2005 for all classes of customers.
As discussed in Note 7 of the Notes to Financial Statements in the 2000
Annual Report, CSPCo and OPCo filed an appeal with the Ohio Supreme Court
related to a tax expense issue which would result in duplicate expense of $40
million and $50 million, respectively, for a twelve month period beginning on
May 1, 2001. One of the items CSPCo and OPCo requested was a stay of the PUCO
ordered implementation date (May 1, 2001) for an excise tax credit rider. On
April 13, 2001, the Ohio Supreme Court denied the companies' stay request.
Management does not expect the Ohio Supreme Court to hear arguments on the
merits of this case until the fourth quarter of 2001.
One of the intervenors at the hearings for approval of a transition
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 OPCo's and CSPCo's recovery of their transition generation-related
regulatory assets. Management is unable to predict the outcome of litigation.
The resolution of this matter could negatively impact future results of
operations.
Virginia Restructuring - Affecting AEP and APCo
In connection with a Virginia law that provides for a transition to
choice of electricity supplier for retail customers beginning on January 1, 2002
(which is described in Note 7 of the Notes to Financial Statements in the 2000
Annual Report), APCo was required to make a filing with the Virginia SCC to
unbundle rates and separate generation from transmission and distribution. On
January 3, 2001, APCo filed its corporate separation plan and rate unbundling
plan with the Virginia SCC, which included a 1999 cost of service study required
by the Virginia SCC's regulations. That filing indicated that additional
information about APCo's proposed corporate separation plan would be filed at a
later date.
On April 11, 2001, the Virginia SCC directed APCo to file the
additional information required to complete its corporate separation filing when
that information becomes available. APCo was also directed to file, by May 15,
2001, all information necessary for the Virginia SCC to fully consider a
functional separation of APCo, by divisions. If in connection with the
transition process, the Virginia SCC were to reduce APCo's rates or deny
recovery of generation related regulatory assets, it would have an adverse
effect on results of operations.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry. In February 2001 the Arkansas General
Assembly passed legislation that was signed into law by the Governor that
extended the date for electric retail competition to October 1, 2003, and
provided the Arkansas Commission with the authority to delay that date for up to
two additional years.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
The Texas Restructuring Legislation gives Texas customers of
investor-owned utilities the opportunity to choose their electric provider and
eliminates the fuel clause reconciliation process beginning January 1, 2002. A
2004 true-up proceeding will determine the amount of stranded costs, if any,
including the final fuel recovery, net regulatory asset recovery, certain
environmental costs, accumulated excess earnings offsets and other issues.
As discussed in the 2000 Annual Report, the method used to determine
initial stranded costs to be recovered beginning on January 1, 2002 has been
controversial. During 2000 CPL submitted estimates of stranded costs and the
PUCT held hearings. In February 2001 the PUCT issued an interim decision
determining an initial amount of stranded costs for CPL of negative $580
million. In April 2001 the PUCT ruled that its current estimate of CPL's
stranded costs was negative $615 million. CPL disagrees with the ruling that it
has a stranded benefit and has requested a rehearing.
In April 2001 the PUCT issued an order requiring CPL to reduce future
distribution rates by $54.8 million over a five-year period in order to return
estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring
Legislation intended that excess earnings would be used to reduce stranded cost.
Final stranded cost amounts and the treatment of excess earnings will be
determined in the 2004 true-up proceeding. The PUCT currently estimates that CPL
will have no stranded cost and has ordered the rate reduction to return excess
earnings, pending the outcome of the 2004 true-up proceeding. Management
believes that CPL will have stranded costs in 2004, and that the current
treatment of excess earnings will be amended at that time. CPL expensed excess
earnings amounts in 1999 and 2000. Consequently, the April order has no effect
on reported net income.
A Texas settlement agreement in connection with the AEP and CSW merger
permits CPL to apply for regulatory purposes up to $20 million of previously
identified STP ECOM plant assets a year in 2000 and 2001 to reduce excess
earnings, if any. For book purposes, STP ECOM plant assets will be depreciated
in accordance with GAAP, on a systematic and rational basis unless impaired. To
the extent excess earnings exceed $20 million in 2001, CPL will establish a
regulatory liability or reduce regulatory assets by a charge to earnings.
Beginning January 1, 2002, fuel costs will no longer be subject to PUCT
fuel reconciliation proceedings under the Texas Restructuring Legislation.
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.
These final fuel balances will be included in each company's 2004 true-up
proceeding. 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. At March 31, 2001, CPL's, SWEPCo's and
WTU's Texas jurisdictional unrecovered deferred fuel balances were $125 million,
$25.4 million and $66.8 million, respectively. The elimination of the fuel
clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to the
risk of fuel market price increases and could adversely affect future results of
operations beginning in 2002.
In response to CPL's request to implement an interim fuel surcharge to
collect underrecovered fuel costs, the PUCT voted in April 2001 to defer
implementation of the requested fuel surcharge until CPL's final fuel
reconciliation as part of its 2004 true-up proceeding. CPL has requested a
rehearing on the surcharge denial. Based upon the decision in the CPL fuel
surcharge proceeding, management expects that the PUCT may also defer recovery
of requested fuel surcharges for SWEPCo and WTU currently pending before PUCT
until their 2004 true-up proceedings. 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 are not
recovered, it would have a negative impact on results of operations.
In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up
proceeding to recover all or a portion of their generation-related
regulatory assets, unrecovered fuel balances, stranded costs and other
restructuring related costs, it could have a material adverse effect on
results of operations, cash flows and possibly financial condition.
Litigation
- ----------
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. On March 5, 2001, AEP and the individual defendants filed a
comprehensive motion to dismiss all claims against all defendents in the
consolidated cases. The Court has set oral arguments of the motion for June 7,
2001. Although management believes these shareholder actions are without merit
and intends to continue 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 the 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 October 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.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo
As discussed in Note 8 of the Notes to Financial Statements in the 2000
Annual Report, SWEPCo has been involved in litigation concerning the mining of
lignite from jointly owned lingite reserves. SWEPCo and CLECO are each a 50%
owner of Dolet Hills Power Station Unit 1 and 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 these reserves. Since 1997 SWEPCo and CLECO have been involved in
litigation with DHMV and its partners in U.S. District Court for the Western
District of Louisiana. In April 2000, the parties agreed to settle the
litigation. As part of the settlement, a subsidiary of SWEPCo will purchase
DHMV's interest in the mining assets and will assume the related obligations for
mine reclamation. The settlement agreement would give CLECO the option,
beginning July 1, 2002, to acquire up to a 50% interest in the mining assets.
The litigation has been stayed to provide the parties a reasonable period of
time to complete the settlement process. 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, 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.
In May 2000 the AEP System companies filed motions to dismiss all or
portions of the complaints. On March 28 and 30, 2001, the Court issued orders
granting the motions in part and denying them in part. The Court ruled claims
for civil penalties based on activities that occurred more than five years
before the date the complaints were filed cannot be imposed. Claims for
injunctive relief are not subject to a time limit.
On February 23, 2001, the plaintiffs filed a motion for partial summary
judgment 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. On April 9, 2001, the AEP
System companies filed a motion requesting the Court deny plaintiffs' motion as
premature, and issue an order allowing discovery to continue. 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, 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 extended 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 those owned by 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 (SCR) technology (expected to be
operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin
Plant. Construction of SCR 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). Construction of SCR technology on KPCo's Big Sandy Plant Unit 2 is
scheduled for completion in May 2003 at an estimated cost of $107 million.
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.
The following table shows the estimated compliance cost for certain of
AEP's subsidiary registrants.
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 or operating costs for 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.
N-1
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 occur 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 quarter ending March 31,
2001 were $14 million, $25 million, and $6 million, respectively. Based on this
VaR analysis, at March 31, 2001 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 for December 31, 2000 because all companies are under $1 million.
VaR for Registrant Subsidiaries:
March 31 December 31,
2001 2000
---- ----
Low High Average High Average
(in millions) (in millions)
APCo $1 $6 $3 $2 $6
CPL - 1 - 1 4
CSPCo 1 3 2 1 3
I&M 1 4 2 1 4
KPCo - 1 1 - 1
OPCo 1 5 2 2 5
PSO - 1 - 1 3
SWEPCo - 1 - 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. The potential loss in fair
value as of March 31, 2001 has not materially changed since year end.
O-1
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
AEP and WTU
On April 12, 2001, the Texas Natural Resource Conservation Commission
("TNRCC") issued a Notice of Enforcement Action to WTU's Oak Creek Power Station
alleging violations of limits contained in the water discharge permit applicable
to the plant. The notice references the potential for corrective action,
administrative penalties, or both. A meeting has been scheduled with the TNRCC
to explore resolution of this matter.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Ehibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges.
(b) Reports on Form 8-K:
AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo OPCo, PSO, SWEPCo and WTU
No reports on Form 8-K were filed during the quarter ended March 31,
2001.
P-1
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto
---------------------- ------------------------
Armando A. Pena Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer
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
By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto
---------------------- ------------------------
Armando A. Pena Joseph M. Buonaiuto
Vice President and Controller and Chief Accounting Officer
Treasurer
Date: May 11, 2001