UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Date of Report (Date of earliest event reported)
November 18, 2002
Commission Registrant, State of Incorporation I.R. S. Employer
File Number Address, and Telephone Number Identification No.
- ----------- ----------------------------- ------------------
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895
(An Oklahoma Corporation)
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790
1 Riverside Plaza, Columbus, Ohio 43215-2373
Telephone (614) 223-1000
Item 5. Other Events
This Current Report on Form 8-K (Report) is limited to the
reclassification of financial statements of AEP Generating Company (AEGCo),
Appalachian Power Company (APCo), Central Power and Light Company (CPL),
Columbus Southern Power Company (CSPCo), Indiana Michigan Power Company (I&M),
Kentucky Power Company (KPCo), Ohio Power Company (OPCo), Public Service Company
of Oklahoma (PSO), Southwestern Electric Power Company (SWEPCo), and West Texas
Utilities Company (WTU), to reflect certain reclassifications of revenue from
forward trading activities to a net basis of reporting and its impacts upon
management's discussion and analysis, the financial statements and the related
notes, and the selected financial data as originally reported in our Annual
Report on Form 10-K for the fiscal year ended December 31, 2001 (Form 10-K). NO
ATTEMPT HAS BEEN MADE IN THIS REPORT TO MODIFY OR UPDATE OTHER DISCLOSURES
EXCEPT AS REQUIRED TO REFLECT THE EFFECTS OF THE RECLASSIFICATIONS DESCRIBED
BELOW.
As previously disclosed in our Quarterly Report on Form 10-Q for the
quarter ended September 30, 2002, prior to the third quarter of 2002, we
recorded and reported upon settlement, sales under forward trading contracts as
revenues and purchased energy expenses. Effective July 1, 2002, we reclassified
revenues such forward trading activity to a net basis of reporting which
resulted in a substantial reduction in both revenues and purchased energy
expense as well as nonoperating income and expense for APCo, CSPCo, OPCo, KPCo,
and I&M but did not have any impact on the financial condition, results of
operations or cash flows for such companies. Our third quarter Form 10-Q,
previously filed with the Securities and Exchange Commission, reflects such
reclassifications. This Report provides updated information to conform such
filing to the presentation reported in our third quarter Form 10-Q. Accordingly,
this report provides additional information previously reported in our Form
10-K in Item 6. Selected Financial Data, Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations, Item 8.
Financial Statements and Suplementary Data, and Item 14. Exhibits, Financial
Statement Schedules and Reports on Form 8-K to reflect the aforementioned
reclassifications.
Contents
Page
Glossary of Terms A-1
Forward Looking Information A-4
AEP Generating Company
Selected Financial Data B-1
Management's Narrative Analysis of Results of Operations B-2
Statements of Income and Statements of Retained Earnings B-3
Balance Sheets B-4
Statements of Cash Flows B-6
Statements of Capitalization B-7
Index to Notes to Financial Statements B-8
Independent Auditors' Report B-9
Appalachian Power Company and Subsidiaries
Selected Consolidated Financial Data C-1
Management's Discussion and Analysis of Results of Operations C-2
Consolidated Statements of Income and Consolidated Statements of C-7
Comprehensive Income
Consolidated Balance Sheets C-8
Consolidated Statements of Cash Flows C-10
Consolidated Statements of Retained Earnings C-11
Consolidated Statements of Capitalization C-12
Schedule of Long-term Debt C-13
Index to Notes to Consolidated Financial Statements C-14
Independent Auditors' Report C-15
Central Power and Light Company and Subsidiaries
Selected Consolidated Financial Data D-1
Management's Discussion and Analysis of Results of Operations D-2
Consolidated Statements of Income D-6
Consolidated Balance Sheets D-7
Consolidated Statements of Cash Flows D-9
Consolidated Statements of Retained Earnings D-10
Consolidated Statements of Capitalization D-11
Schedule of Long-term Debt D-12
Index to Notes to Consolidated Financial Statements D-13
Independent Auditors' Report D-14
Columbus Southern Power Company and Subsidiaries
Selected Consolidated Financial Data E-1
Management's Narrative and Analysis of Results of Operations E-2
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings E-6
Consolidated Balance Sheets E-7
Consolidated Statements of Cash Flows E-9
Consolidated Statements of Capitalization E-10
Schedule of Long-term Debt E-11
Index to Notes to Consolidated Financial Statements E-12
Independent Auditors' Report E-13
Indiana Michigan Power Company and Subsidiaries
Selected Consolidated Financial Data F-1
Management's Discussion and Analysis of Results of Operations F-2
Consolidated Statements of Income and Consolidated Statements of F-7
Comprehensive Income
Consolidated Balance Sheets F-8
Consolidated Statements of Cash Flows F-10
Consolidated Statements of Retained Earnings F-11
Consolidated Statements of Capitalization F-12
Schedule of Long-term Debt F-13
Index to Notes to Consolidated Financial Statements F-15
Independent Auditors' Report F-16
Kentucky Power Company
Selected Financial Data G-1
Management's Narrative Analysis of Results of Operations G-2
Statements of Income, Statements of Comprehensive Income G-6
and Statements of Retained Earnings
Balance Sheets G-7
Statements of Cash Flows G-9
Statements of Capitalization G-10
Schedule of Long-term Debt G-11
Index to Notes to Financial Statements G-12
Independent Auditors' Report G-13
Ohio Power Company and Subsidiaries
Selected Consolidated Financial Data H-1
Management's Discussion and Analysis of Results of Operations H-2
Consolidated Statements of Income and Consolidated Statements of H-7
Comprehensive Income
Consolidated Balance Sheets H-8
Consolidated Statements of Cash Flows H-10
Consolidated Statements of Retained Earnings H-11
Consolidated Statements of Capitalization H-12
Schedule of Long-term Debt H-13
Index to Notes to Consolidated Financial Statements H-15
Independent Auditors' Report H-16
Public Service Company of Oklahoma and Subsidiaries
Selected Consolidated Financial Data I-1
Management's Narrative Analysis of Results of Operations I-2
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings I-5
Consolidated Balance Sheets I-6
Consolidated Statements of Cash Flows I-8
Consolidated Statements of Capitalization I-9
Schedule of Long-term Debt I-10
Index to Notes to Consolidated Financial Statements I-11
Independent Auditors' Report I-12
Southwestern Electric Power Company and Subsidiaries
Selected Consolidated Financial Data J-1
Management's Discussion and Analysis of Results of Operations J-2
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings J-6
Consolidated Balance Sheets J-7
Consolidated Statements of Cash Flows J-9
Consolidated Statements of Capitalization J-10
Schedule of Long-term Debt J-11
Index to Notes to Consolidated Financial Statements J-12
Independent Auditors' Report J-13
West Texas Utilities Company
Selected Financial Data K-1
Management's Narrative Analysis of Results of Operations K-2
Statements of Income and Statements of Retained Earnings K-6
Balance Sheets K-7
Statements of Cash Flows K-9
Statements of Capitalization K-10
Schedule of Long-term Debt K-11
Index to Notes to Consolidated Financial Statements K-12
Independent Auditors' Report K-13
Notes to Financial Statements L-1
Management's Discussion and Analysis of Financial Condition,
Contingencies and Other Matters M-1
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. The parent company of
AEGCo,APCo, CSPCo, CPL, I&MCo, KPCo, OPCo, PSO, SWEPCo and WTU
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.
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.
FASB............................... Financial Accounting Standards Board.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB ............................... First Mortgage Bond.
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.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
Midwest ISO........................ An independent operator of transmission assets in the Midwest.
MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool......................... AEP System's Money Pool.
MPSC............................... Michigan Public Service Commission.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatthour.
NEIL............................... Nuclear Electric Insurance Limited.
Nox................................ Nitrogen oxide.
NOx Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states
including seven of the states in which AEP companies operates.
NP................................. Notes Payable.
NRC................................ Nuclear Regulatory Commission.
Ohio Act........................... The Ohio Electric Restructuring Act of 1999.
Ohio EPA........................... Ohio Environmental Protection Agency.
OPCo............................... Ohio Power Company, an AEP electric utility subsidiary.
OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which
AEP and CSPCo own a 44.2% equity interest.
PCBs............................... Polychlorinated Biphenyls.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP................................ Potentially Responsible Party.
PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO............................... The Public Utilities Commission of Ohio.
PUCT............................... The Public Utility Commission of Texas.
PUHCA.............................. Public Utility Holding Company Act of 1935, as amended.
PURPA.............................. The Public Utility Regulatory Policies Act of 1978.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
RTO................................ Regional Transmission Organization.
SEC................................ Securities and Exchange Commission.
SFAS............................... Statement of Financial Accounting Standards issued by the Financial
Accounting Standards Board.
SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
Types of Regulation.
SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of
Application of Statement 71.
SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed of.
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
and Hedging Activities.
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by
Central Power and Light Company, an AEP electric utility subsidiary .
STPNOC............................. STP Nuclear Operating Company, a non-profit Texas corporation which
operates STP on behalf of its joint owners including CPL.
Superfund.......................... The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Appeals Court............... The Third District of Texas Court of Appeals.
Texas Legislation.................. Legislation enacted in 1999 to restructure the electric utility industry in Texas.
Travis District Court.............. State District Court of Travis County, Texas.
TVA ............................... Tennessee Valley Authority.
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.
Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4%
by Columbus Southern Power Company, an AEP subsidiary.
FORWARD LOOKING INFORMATION
This discussion includes forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934. These forward-looking
statements reflect assumptions, and involve a number of risks and uncertainties.
Among the factors both foreign and domestic that could cause actual results to
differ materially from forward looking statements are: electric load and
customer growth; abnormal weather conditions; available sources of and prices
for coal and gas; availability of generating capacity; risks related to energy
trading and construction under contract; the speed and degree to which
competition is introduced to our power generation business; the structure and
timing of a competitive market for electricity and its impact on prices, the
ability to
recover net regulatory assets, other stranded costs and implementation costs in
connection with deregulation of generation in certain states; the timing of the
implementation of AEP's restructuring plan; new legislation and government
regulations; the ability to successfully control costs; the success of new
business ventures; the economic climate and growth in our service and trading
territories; the ability to successfully challenge new environmental regulations
and to successfully litigate claims that the Company violated the Clean Air Act;
inflationary trends; litigation concerning AEP's merger with CSW; changes in
electricity and gas market prices and interest rates; fluctuations in foreign
currency exchange rates, and other risks and unforeseen events.
AEP GENERATING COMPANY
AEP GENERATING COMPANY
Selected Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $227,548 $228,516 $217,189 $224,146 $227,868
Operating Expenses 220,571 220,092 211,849 215,415 218,828
------- - ------- - ------- - ------- - -------
Operating Income 6,977 8,424 5,340 8,731 9,040
Nonoperating Income 3,484 3,429 3,659 3,364 3,603
Interest Charges 2,586 3,869 2,804 3,149 3,857
----- --- ----- --- ----- --- ----- --- -----
Net Income $7,875 $7,984 $6,195 $8,946 $8,786
====== ====== ====== ====== ======
December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $648,254 $642,302 $640,093 $636,460 $633,450
Accumulated Depreciation 337,151 315,566 295,065 277,855 257,191
------- - ------- - ------- - ------- - -------
Net Electric Utility Plant $311,103 $326,736 $345,028 $358,605 $376,259
======== ======== ======== ======== ========
Total Assets $361,341 $374,602 $398,640 $403,892 $419,058
======== ======== ======== ======== ========
Common Stock and Paid-in Capital $ 24,434 $ 24,434 $ 30,235 $ 36,235 $ 40,235
Retained Earnings 13,761 9,722 3,673 2,770 2,528
------ --- ----- --- ----- --- ----- --- -----
Total Common Shareholder's Equity $ 38,195 $ 34,156 $ 33,908 $ 39,005 $ 42,763
======== ======== ======== ======== ========
Long-term Debt (a) $ 44,793 $ 44,808 $ 44,800 $ 44,792 $ 69,570
======== ======== ======== ======== ========
Total Capitalization
And Liabilities $361,341 $374,602 $398,640 $403,892 $419,058
======== ======== ======== ======== ========
(a) Including portion due within one year.
AEP GENERATING COMPANY
Management's Narrative Analysis of Results of Operations
AEP Generating Company is engaged in the generation and wholesale sale
of electric power to two affiliates under long-term agreements.
Operating revenues are derived from the sale of Rockport Plant energy
and capacity to two affiliated companies, I&M and KPCo pursuant to FERC approved
long-term unit power agreements. Under the terms of its unit power agreement,
I&M is required to buy all of AEGCo's Rockport capacity when the unit power
agreement with KPCo expires in 2004. The unit power agreements provide for
recovery of costs including a FERC approved rate of return on common equity and
a return on other capital net of temporary cash investments. Under terms of the
unit power agreements, AEGCo accumulates all expenses monthly and prepares the
bills for its affiliates. In the month the expenses are incurred, AEGCo
recognizes the billing revenues and establishes a receivable from the affiliated
companies.
Net income decreased $0.1 million or 1% as a result of a slight decrease
in the return on other capital. Lower interest charges caused the return on
other capital to decrease.
Income statement items which changed significantly were:
Increase
(Decrease)
(dollars in millions) From Previous Year
Amount %
Operating Revenues $(1.0) N.M.
Other Operation Expense 0.7 7
Maintenance Expense (0.8) (8)
Taxes Other Than Income Taxes 0.4 10
Interest Charges (1.3) (33)
N.M. = Not Meaningful
The decrease in operating revenues reflects a decrease in the return on
other capital reflecting a decline in interest charges.
Other operation expense increased due to the costs of an air quality
test project and increased benefits and compensation costs.
The decrease in maintenance expense can be attributed to a shorter
duration of maintenance outages for boiler inspection and repair in 2001.
Taxes other than income taxes increased due to an increase in Indiana
real and personal property taxes reflecting an unfavorable accrual adjustment
and a higher estimated liability accrued in 2001.
The decrease in interest charges was primarily due to a decline in
interest rates in 2001. The Federal Reserve reduced short-term interest rates
eleven times in 2001. AEGCo benefited from the declining short-term interest
rates since its short-term borrowings and through July 13, 2001 its long-term
debt were based on short-term interest rates. AEGCo's long-term debt interest
rates varied daily until July 2001 when we chose to fix the rate at 4.05% for
five years.
AEP GENERATING COMPANY
Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Sales to AEP Affiliates $227,338 $227,983 $152,559
Other 210 533 64,630
--- ----- --- -- ------
TOTAL OPERATING REVENUES 227,548 228,516 217,189
------- - ------- - -------
OPERATING EXPENSES:
Fuel 102,828 102,978 94,481
Rent - Rockport Plant Unit 2 68,283 68,283 68,283
Other Operation 11,025 10,295 10,451
Maintenance 8,853 9,616 10,492
Depreciation 22,423 22,162 21,845
Taxes Other Than Income Taxes 4,257 3,854 3,866
Income Taxes 2,902 2,904 2,431
----- --- ----- --- -----
TOTAL OPERATING EXPENSES 220,571 220,092 211,849
------- - ------- - -------
OPERATING INCOME 6,977 8,424 5,340
NONOPERATING INCOME 30 6 92
NONOPERATING EXPENSES 16 17 27
NONOPERATING INCOME TAX CREDITS 3,470 3,440 3,594
INTEREST CHARGES 2,586 3,869 2,804
----- --- ----- --- -----
NET INCOME $7,875 $7,984 $6,195
====== ====== ======
Statements of Retained Earnings
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $ 9,722 $3,673 $2,770
NET INCOME 7,875 7,984 6,195
CASH DIVIDENDS DECLARED 3,836 1,935 5,292
----- - ----- - -----
RETAINED EARNINGS DECEMBER 31 $13,761 $9,722 $3,673
======= ====== ======
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Balance Sheets
December 31,
2001 2000
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $638,297 $635,215
General 3,012 2,795
Construction Work in Progress 6,945 4,292
----- --- -----
Total Electric Utility Plant 648,254 642,302
Accumulated Depreciation 337,151 315,566
------- - -------
NET ELECTRIC UTILITY PLANT 311,103 326,736
------- - -------
OTHER PROPERTY AND INVESTMENTS 119 6
--- ------- -
CURRENT ASSETS:
Cash and Cash Equivalents 983 2,757
Accounts Receivable:
Affiliated Companies 22,344 21,374
Miscellaneous 147 2,341
Fuel - at average cost 15,243 11,006
Materials and Supplies - at average cost 4,480 3,979
Prepayments 244 145
--- ----- ---
TOTAL CURRENT ASSETS 43,441 41,602
------ -- ------
REGULATORY ASSETS 5,207 5,504
----- --- -----
DEFERRED CHARGES 1,471 754
----- ----- ---
TOTAL $361,341 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
December 31,
2001 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 13,761 9,722
------ --- -----
Total Common Shareholder's Equity 38,195 34,156
Long-term Debt 44,793 -
------ ---- ----
TOTAL CAPITALIZATION 82,988 34,156
------ -- ------
OTHER NONCURRENT LIABILITIES 76 358
- -- ----- ---
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 44,808
Advances from Affiliates 32,049 28,068
Accounts Payable:
General 7,582 6,109
Affiliated Companies 1,654 7,724
Taxes Accrued 4,777 4,993
Rent Accrued - Rockport Plant Unit 2 4,963 4,963
Other 3,481 4,443
----- --- -----
Total CURRENT LIABILITIES 54,506 101,108
------ - -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 116,617 122,188
------- - -------
REGULATORY LIABILITIES:
Deferred Investment Tax Credits 56,304 59,718
Amounts Due to Customers for Income Taxes 22,725 23,996
------ -- ------
Total REGULATORY LIABILITIES 79,029 83,714
------ -- ------
DEFERRED INCOME TAXES 27,975 32,928
------ -- ------
DEFERRED CREDITS 150 150
--- ----- ---
CONTINGENCIES (Note 8)
TOTAL $361,341 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $7,875 $7,984 $6,195
Adjustments for Noncash Items:
Depreciation 22,423 22,162 21,845
Deferred Federal Income Taxes (6,224) (5,842) (5,282)
Deferred Investment Tax Credits (3,414) (3,396) (3,448)
Amortization of Deferred Gain on Sale and
Leaseback - Rockport Plant Unit 2 (5,571) (5,571) (5,571)
Change in Certain Current Assets and Liabilities:
Accounts Receivable 1,224 1,392 (2,213)
Fuel, Materials and Supplies (4,738) 6,486 (6,263)
Accounts Payable (4,597) (13,157) 14,394
Taxes Accrued (216) 708 1,058
Other Assets (569) 1,636 (6)
Other Liabilities (1,244) (404) (1,564)
------ ---- ---- -- ------
Net Cash Flows From Operating Activities 4,949 11,998 19,145
----- -- ------ -- ------
INVESTING ACTIVITIES:
Construction Expenditures (6,868) (5,190) (8,349)
Proceeds From Sales of Property - - 331
---- ---- ---- ----- ---
Net Cash Flows Used For Investing
Activities (6,868) (5,190) (8,018)
------ -- ------ -- ------
FINANCING ACTIVITIES:
Return of Capital to Parent Company - (5,801) (6,000)
Change in Short-term Debt (net) - (24,700) 250
Change in Advances From Affiliates (net) 3,981 28,068 -
Dividends Paid (3,836) (1,935) (5,292)
------ -- ------ -- ------
Net Cash Flows From (Used For)
Financing Activities 145 (4,368) (11,042)
--- -- ------ - -------
Net Increase (Decrease) in Cash and Cash Equivalents (1,774) 2,440 85
Cash and Cash Equivalents January 1 2,757 317 232
----- ----- --- ----- ---
Cash and Cash Equivalents December 31 $ 983 $2,757 $ 317
=====- ====== =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,509,000, $3,531,000 and
$2,468,000 and for income taxes was $8,597,000, $6,820,000 and $6,565,000 in
2001, 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Statements of Capitalization
December 31,
2001 2000
---- ----
(in thousands)
COMMON STOCK EQUITY (a) $38,195 $ 34,156
------- --------
LONG-TERM DEBT
Installment Purchase Contracts - City of Rockport (b)
Series Due Date
1995 A, 2025 (c) 22,500 22,500
1995 B, 2025 (c) 22,500 22,500
Unamortized Discount (207) (192)
Amount Due Within One Year - (44,808)
---- - -------
Long-term Debt Excluding Amount Due Within One Year 44,793 -
------ ---- ----
TOTAL CAPITALIZATION $82,988 $ 34,156
======= ========
(a) In 2000 and 1999, AEGCo returned capital to AEP in the amounts of $5.8
million and $6 million, respectively. There were no other material transactions
affecting common stock and paid-in capital in 2001, 2000 and 1999. (b)
Installment purchase contracts were entered into in connection with the issuance
of pollution control revenue bonds by the City of Rockport, Indiana. The terms
of the installment purchase contracts require AEGCo to pay amounts sufficient to
enable the payment of interest and principal on the related pollution control
revenue bonds issued to refinance the construction costs of pollution control
facilities at the Rockport Plant.
(c) These series have an adjustable interest rate that can be a daily, weekly,
commercial paper or term rate as designated by AEGCo. Prior to July 13, 2001,
AEGCo selected a daily rate which ranged from 0.9% to 5.6% during 2001 and from
1.65% to 6.1% during 2000 and averaged 2.8% in 2001 and 4.1% in 2000. Effective
July 13, 2001, AEGCo selected a term rate of 4.05% for five years ending July
12, 2006. The interest rates were 5% for Series A and 4.9% for Series B at
December 31, 2000.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
Index to Notes to Financial Statements
The notes to AEGCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to AEGCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Effects of Regulation Note 6
Commitments and Contingencies Note 8
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Related Party Transactions Note 20
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of Directors
of AEP Generating Company:
We have audited the accompanying balance sheets and statements of
capitalization of AEP Generating Company as of December 31, 2001 and 2000, and
the related statements of income, retained earnings, and cash flows for each of
the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all
material respects, the financial position of AEP Generating Company as of
December 31, 2001 and 2000, and the results of its operations and its cash flows
for each of the three years in the period ended December 31, 2001 in conformity
with accounting principles generally accepted in the United States of America.
Deloitte & Touche LLP
Columbus, Ohio
February 22, 2002
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,784,259 $1,759,253 $1,586,050 $1,672,244 $1,628,515
Operating Expenses 1,509,273 1,558,099 1,344,814 1,443,701 1,388,521
--------- - --------- - --------- - --------- - ---------
Operating Income 274,986 201,154 241,236 228,543 239,994
Nonoperating Income
(Loss) 6,868 11,752 8,096 (8,301) (222)
Interest Charges 120,036 148,000 128,840 126,912 119,258
------- --- ------- --- ------- ---- ------- --- -------
Income Before
Extraordinary Item 161,818 64,906 120,492 93,330 120,514
Extraordinary Gain - 8,938 - - -
- ---- ----- ----- ------ ---- -- --------- ------ ----
Net Income 161,818 73,844 120,492 93,330 120,514
Preferred Stock
Dividend
Requirements 2,011 2,504 2,706 2,497 7,006
----- ----- ----- ----- ----- ------ ----- ----- -----
Earnings Applicable
to Common Stock $159,807 $ 71,340 $117,786 $ 90,833 $113,508
======== ======== ======== ======== ========
December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,664,657 $5,418,278 $5,262,951 $5,087,359 $4,901,046
Accumulated
Depreciation and
Amortization 2,296,481 2,188,796 2,079,490 1,984,856 1,869,057
--------- - --------- - --------- - --------- - ---------
Net Electric Utility
Plant $3,368,176 $3,229,482 $3,183,461 $3,102,503 $3,031,989
========== ========== ========== ========== ==========
Total Assets $5,107,938 $6,633,724 $4,354,400 $4,047,038 $3,883,430
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $976,244 $975,676 $974,717 $924,091 $873,506
Accumulated Other
Comprehensive Income
(Loss) (340) - - - -
Retained Earnings 150,797 120,584 175,854 179,461 207,544
------- --- ------- --- ------- --- ------- --- -------
Total Common
Shareholder's Equity $1,126,701 $1,096,260 $1,150,571 $1,103,552 $1,081,050
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 17,790 $ 17,790 $ 18,491 $ 19,359 $ 19,747
Subject to Mandatory
Redemption 10,860 10,860 20,310 22,310 22,310
------ ---- ------ ---- ------ ---- ------ ---- ------
Total Cumulative
Preferred Stock $ 28,650 $ 28,650 $ 38,801 $ 41,669 $ 42,057
======== ======== ======== ======== ========
Long-term Debt (a) $1,556,559 $1,605,818 $1,665,307 $1,552,455 $1,494,535
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 46,285 $ 63,160 $ 64,645 $ 65,175 $ 60,110
======== ======== ======== ======== ========
Total Capitalization
And Liabilities $5,107,938 $6,633,724 $4,354,400 $4,047,038 $3,883,430
========== ========== ========== ========== ==========
(a) Including portion due within one year.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
APCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to 917,000 retail customers in
southwestern Virginia and southern West Virginia. APCo as a member of the AEP
Power Pool shares in the revenues and costs of the AEP Power Pool's wholesale
sales to neighboring utility systems and power marketers including power trading
transactions. APCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among
the Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and the receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of revenues and
costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to APCo as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. Although trading contracts
are generally short-term, there are also long-term trading contracts. We
recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts prior
to settlement is commonly referred to as mark-to-market (MTM) accounting. It
represents the change in the unrealized gain or loss throughout the contract's
term. When the contract actually settles, that is, the energy is actually
delivered in a sale or received in a purchase or the parties agree to forego
delivery and receipt of electricity and net settle in cash, the unrealized gain
or loss is reversed and the actual realized cash gain or loss is recognized.
Therefore, over the trading contract's term an unrealized gain or loss is
recognized as the contract's market value changes. When the contract settles the
total gain or loss is realized in cash but only the difference between the
accumulated unrealized net gains or losses recorded in prior months and the cash
proceeds is recognized. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.
The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse the previously recorded unrealized gain or
loss.
Depending on whether the delivery point for the electricity is in
AEP's traditional marketing area or not determines where the contract is
reported on APCo's income statement. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale and purchase contracts with delivery points in AEP's traditional
marketing area are included in revenues when the contracts settle. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts in AEP's traditional marketing area are included in revenues on a net
basis. Physical forward sale and purchase contracts for delivery outside of
AEP's traditional marketing area are included in nonoperating income when the
contract settles. Prior to settlement, changes in the fair value of physical
forward sale and purchase contracts with delivery points outside of AEP's
traditional marketing area are included in nonoperating income on a net basis.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
results of operations from recording additional changes in fair values using
mark-to-market accounting.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing APCo to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Results of Operations
Net Income
Net income increased $88 million or 119% in 2001 primarily due to the
effect of a court decision related to a corporate owned life insurance (COLI)
program recorded in 2000. In February 2001 the U.S. District Court for the
Southern District of Ohio ruled against AEP and certain of its subsidiaries,
including APCo, in a suit over deductibility of interest claimed in AEP's
consolidated tax return related to COLI. In 1998 and 1999 APCo paid the disputed
taxes and interest attributable to the COLI interest deductions for taxable
years 1991-98. The payments were included in Other Property and Investments
pending the resolution of this matter. Also contributing to the increase in net
income was growth in and strong performance by the wholesale marketing and
trading business in the first half of 2001 offset in part by the effect of
extremely mild November and December weather combined with weak economic
conditions which reduced retail energy sales.
The adverse court decision on COLI caused the $47 million decrease in
2000's net income. Income before extraordinary items decreased $56 million or
46% in 2000 primarily due to the COLI decision. An extraordinary gain from the
discontinuance of SFAS 71 regulatory accounting of $9 million after tax was
recorded in June 2000.
(See Note 2, "Extraordinary Items and Cumulative Effect".)
Operating Revenues
Operating revenues increased 1% in 2001 due to increases in Energy
Delivery and Sales to AEP affiliates. The increase in operating revenue of 11%
in 2000 is mainly due to an increase in wholesale marketing and trading volume
and sales to AEP affiliates. The changes in the components of revenues were as
follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
---------------------------
Amount % Amount %
Retail* $ (38.9) (5) $ 2 N.M.
Electricity
Marketing
and Trading (28.0) (11) 147.7 140
Unrealized MTM 46.3 272 (22.0) N.M.
Other 8.9 14 (18.2) (22)
-------- --------
Total
Marketing
and Trading (11.7) (1) 109.5 12
Energy Delivery* 20.1 3 9.3 2
Sales to AEP
Affiliates 16.6 11 54.4 54
-------- --------
Total
Revenues $ 25.0 1 $ 173.2 11
======== ========
N.M. = Not Meaningful
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
The decrease in wholesale marketing and trading revenues in 2001 is
driven by decrease trading margins. Wholesale marketing and trading revenues
increased in 2000 as a result of an increase in electric marketing and trading
volume. The maturing of the Intercontinental Exchange, the development of
proprietary tools, and increased staffing of energy traders have resulted in an
increase in the number of forward electricity purchase and sale contracts in
AEP's traditional marketing area.
While wholesale marketing and trading volumes rose, kilowatthour sales
to industrial customers decreased in 2001. This decrease was due to the economic
recession. Also, in the fourth quarter, sales to residential and commercial
customers declined. The recession reduced demand, especially, in the fourth
quarter.
The increase in sales to AEP affiliates in 2001 and 2000 is due to a
significant increase in AEP Power Pool transactions. As the quantity of energy
sold by the AEP Power Pool rose, APCo's contribution of energy to the Pool rose,
accounting for the increase in APCo's revenues from sales to AEP affiliates. The
AEP Power Pool was able to make additional sales to third parties in 2000 as a
result of an affiliated company's major industrial customer's decision not to
continue its purchased power agreement.
Operating Expenses
The decrease in operating expenses in 2001 of 3% is due to decreases in
income taxes, other operation expense, fuel expense and taxes other than income
taxes partially offset by increases in electricity marketing expense and
depreciation and amortization expenses. Operating expenses increased 16% in 2000
due to an increase in purchases from AEP affiliates, other operation expense and
income taxes offset in part by decreases in fuel expense and electricity
marketing expense. Changes in the components of operating expenses are as
follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
-----------------------------
Amount % Amount %
Fuel $ (17.6) (5) $ (75.6) (17)
Marketing
Purchases 17.4 70 (35.3) (59)
AEP Affiliate
Purchases (8.9) (3) 224.8 172
Other Operation (18.6) (7) 31.3 13
Maintenance 7.9 6 0.7 1
Depreciation and
Amortization 17.3 11 14.2 10
Taxes Other Than
Income Taxes (11.8)(11) (1.0) (1)
Income Taxes (34.5)(27) 54.2 72
-------- --------
Total $ (48.8) (3) $ 213.3 16
======== ========
The decrease in fuel expense in 2001 is due to a decline in generation
as a result of scheduled plant maintenance. Fuel expense decreased in 2000 due
to the combined effect of the discontinuance of deferral accounting for over or
under recovery of fuel costs in the West Virginia jurisdiction effective January
1, 2000 under the terms of a rate settlement agreement and a decline in
generation due to scheduled plant maintenance.
Electricity marketing purchases increased in 2001 due to increases in
purchases of replacement power due to scheduled plant maintenance. The decrease
in power purchases in 2000 is due to increased purchases from AEP affiliates
caused by an increase in available generation.
Purchased power from AEP affiliates decreased in 2001 as the result of
a decrease in AEP Power Pool capacity charges due to a reduction in APCo's MLR.
The significant increase in purchased power from AEP affiliates in 2000 reflects
additional purchases of power from the AEP Power Pool as a result of increased
availability of generation. The AEP Power Pool was able to supply more power to
APCo since an affiliate's nuclear unit returned to service in June 2000, a major
industrial customer discontinued purchasing power from an affiliate in January
2000, and generating unit outage management improved.
Other operation expense decreased in 2001 mainly due to the effect of
AEPSC billings in 2000 for the disallowance of the COLI program interest
deduction. Additionally, the decrease was the result of a gain recorded on the
disposition of SO2 emission allowances offset in part by increased wholesale
power trading incentive compensation expense. The increase in other operation
expense in 2000 was due to increased wholesale marketing costs including
increased accruals for incentive compensation, increased use of emission
allowances due to stricter air quality standards of Phase II of the 1990 Clean
Air Act Amendments which became effective January 1, 2000 and AEPSC billings for
the COLI disallowance.
During June 2000 we discontinued the application of SFAS 71 in the
Virginia and West Virginia jurisdictions. Consequently net generation-related
regulatory assets were transferred to the energy delivery business' regulated
distribution business where the Virginia and West Virginia jurisdictions
authorized the recovery of these transition regulatory assets through regulated
rates. Depreciation and amortization expense increased in 2001 and 2000 due to
accelerated amortization, beginning in July 2000, of the transition regulatory
assets. Additional investments in the energy delivery business' distribution and
transmission plant also contributed to the increases in depreciation and
amortization expense.
The decrease in taxes other than income taxes in 2001 is due to the
elimination of the Virginia gross receipts tax as a result of a tax law change
due to deregulation in that state.
Income taxes attributable to operations decreased in 2001 due to the
effect of the disallowance of COLI interest deductions in 2000 offset in part by
an increase in pre-tax operating income. The increase in income taxes
attributable to operations in 2000 was due to the disallowance of COLI interest
deductions.
Nonoperating Income and Nonoperating Expenses
The increase in nonoperating income for both 2001 and 2000 is due to
increases in the wholesale business' trading transactions outside of the AEP
System's traditional marketing area. Nonoperating expenses increased in 2001 due
to trading overheads and traders' compensation.
Interest Charges
Interest charges decreased in 2001 primarily due to the effect of
recognizing in 2000 previously deferred interest payments to the IRS related to
the COLI disallowances and interest on resultant state income tax deficiencies.
Additionally, the decrease in 2001 is due to the retirement of first mortgage
bonds in 2000. The increase in interest charges in 2000 was due to the
recognition of deferred interest payments related to the COLI disallowances and
interest on the resultant prior years state income taxes.
Extraordinary Gain
The extraordinary gain recorded in June 2000 was the result of the
discontinuance of SFAS 71 for the generation portion of APCo's business.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $1,017,938 $1,029,657 $920,158
Energy Delivery 595,036 574,918 565,660
Sales to AEP Affiliates 171,285 154,678 100,232
------- --- ------- --- -------
Total Operating Revenues 1,784,259 1,759,253 1,586,050
--------- - --------- - ---------
OPERATING EXPENSES:
Fuel 351,557 369,161 444,711
Purchased Power:
Electricity Marketing 42,092 24,720 59,979
AEP Affiliates 346,878 355,774 130,991
Other Operation 260,518 279,114 247,859
Maintenance 132,373 124,493 123,834
Depreciation and Amortization 180,393 163,089 148,874
Taxes Other Than Income Taxes 99,878 111,692 112,722
Income Taxes 95,584 130,056 75,844
------ --- ------- ---- ------
Total Operating Expenses 1,509,273 1,558,099 1,344,814
--------- - --------- - ---------
OPERATING INCOME 274,986 201,154 241,236
NONOPERATING INCOME 49,507 31,204 21,042
NONOPERATING EXPENSES 41,500 16,329 12,755
NONOPERATING INCOME TAX EXPENSE 1,139 3,123 191
INTEREST CHARGES 120,036 148,000 128,840
------- --- ------- --- -------
INCOME BEFORE EXTRAORDINARY ITEM 161,818 64,906 120,492
EXTRAORDINARY GAIN - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(Inclusive of Tax Benefit of $7,872,000) - 8,938 -
---- ----- ----- ------ ----
NET INCOME 161,818 73,844 120,492
PREFERRED STOCK DIVIDEND REQUIREMENTS 2,011 2,504 2,706
----- ----- ----- ----- -----
EARNINGS APPLICABLE TO COMMON STOCK $159,807 $ 71,340 $117,786
======== ======== ========
Consolidated Statements of Comprehensive Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
NET INCOME $161,818 $73,844 $120,492
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (340) - -
---- --- ---- ---- ----
COMPREHENSIVE INCOME $161,478 $73,844 $120,492
======== ======= ========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
2001 2000
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,093,532 $2,058,952
Transmission 1,222,226 1,177,079
Distribution 1,887,020 1,816,925
General 257,957 254,371
Construction Work in Progress 203,922 110,951
------- --- -------
Total Electric Utility Plant 5,664,657 5,418,278
Accumulated Depreciation and Amortization 2,296,481 2,188,796
--------- - ---------
NET ELECTRIC UTILITY PLANT 3,368,176 3,229,482
--------- - ---------
OTHER PROPERTY AND INVESTMENTS 53,736 56,967
------ ---- ------
LONG-TERM ENERGY TRADING CONTRACTS 316,249 322,038
------- --- -------
CURRENT ASSETS:
Cash and Cash Equivalents 13,663 5,847
Advances to Affiliates - 8,387
Accounts Receivable:
Customers 113,371 243,298
Affiliated Companies 63,368 63,919
Miscellaneous 11,847 16,179
Allowance for Uncollectible Accounts (1,877) (2,588)
Fuel - at average cost 56,699 39,076
Materials and Supplies - at average cost 59,849 57,515
Accrued Utility Revenues 30,907 66,499
Energy Trading Contracts 566,284 2,024,222
Prepayments 16,018 6,307
------ ----- -----
TOTAL CURRENT ASSETS 930,129 2,528,661
------- - ---------
REGULATORY ASSETS 397,383 447,750
------- --- -------
DEFERRED CHARGES 42,265 48,826
------ ---- ------
TOTAL $5,107,938 $6,633,724
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
December 31,
2001 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 715,786 715,218
Accumulated Other Comprehensive Income (Loss) (340) -
Retained Earnings 150,797 120,584
------- --- -------
Total Common Shareholder's Equity 1,126,701 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 1,476,552 1,430,812
--------- - ---------
TOTAL CAPITALIZATION 2,631,903 2,555,722
--------- - ---------
OTHER NONCURRENT LIABILITIES 84,104 105,883
------ --- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 80,007 175,006
Short-term Debt - 191,495
Advances From Affiliates 291,817 -
Accounts Payable - General 131,387 153,422
Accounts Payable - Affiliated Companies 84,518 107,556
Taxes Accrued 55,583 63,258
Customer Deposits 13,177 12,612
Interest Accrued 21,770 21,555
Energy Trading Contracts 549,703 2,080,025
Other 75,299 85,378
------ ---- ------
Total CURRENT LIABILITIES 1,303,261 2,890,307
--------- - ---------
DEFERRED INCOME TAXES 703,575 682,474
------- --- -------
DEFERRED INVESTMENT TAX CREDITS 38,328 43,093
------ ---- ------
LONG-TERM ENERGY TRADING CONTRACTS 257,129 258,788
------- --- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 89,638 97,457
------ ---- ------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $5,107,938 $6,633,724
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 161,818 $73,844 $ 120,492
Adjustments for Noncash Items:
Depreciation and Amortization 180,505 163,202 149,791
Deferred Federal Income Taxes 42,498 8,602 13,033
Deferred Investment Tax Credits (4,765) (4,915) (4,972)
Deferred Power Supply Costs (net) 1,411 (84,408) 35,955
Mark-to-Market of Energy Trading Contracts (68,254) (1,843) (8,939)
Provision for Rate Refunds - (4,818) 4,818
Extraordinary Gain - (8,938) -
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) 134,099 (166,911) 10,989
Fuel, Materials and Supplies (19,957) 18,487 (4,812)
Accrued Utility Revenues 35,592 (13,081) (7,433)
Accounts Payable (45,073) 159,369 (9,273)
Taxes Accrued (7,675) 14,220 13,319
Revenue Refunds Accrued - 181 (95,267)
Incentive Plan Accrued (2,451) 10,662 1,507
Disputed Tax and Interest Related to COLI - 72,440 (4,124)
Change in Operating Reserves (5,358) (19,770) 7,451
Rate Stabilization Deferral - 75,601 -
Change in Other Assets 19,418 (13,021) (8,669)
Change in Other Liabilities (27,954) 9,817 (22,455)
------- ---- ----- -- -------
Net Cash Flows From Operating Activities 393,854 288,720 191,411
------- -- ------- -- -------
INVESTING ACTIVITIES:
Construction Expenditures (306,046) (199,285) (211,416)
Proceeds From Sales of Property and Other 1,182 159 19,296
Net Cost of Removal and Other (8,434) (7,500) (24,373)
------ --- ------ -- -------
Net Cash Flows Used For Investing
Activities (313,298) (206,626) (216,493)
-------- - -------- - --------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company - - 50,000
Issuance of Long-term Debt 124,588 74,788 227,236
Retirement of Cumulative Preferred Stock - (9,924) (2,675)
Retirement of Long-term Debt (175,000) (136,166) (116,688)
Change in Short-term Debt (net) (191,495) 68,015 47,080
Change in Advances From Affiliates 300,204 (8,387) -
Dividends Paid on Common Stock (129,594) (126,612) (121,392)
Dividends Paid on Cumulative Preferred Stock (1,443) (1,938) (2,257)
------ --- ------ --- ------
Net Cash Flows From (Used For)
Financing Activities (72,740) (140,224) 81,304
------- - -------- --- ------
Net Increase (Decrease) in Cash and Cash Equivalents 7,816 (58,130) 56,222
Cash and Cash Equivalents January 1 5,847 63,977 7,755
----- --- ------ ---- -----
Cash and Cash Equivalents December 31 $13,663 $ 5,847 $63,977
======= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $117,283,000, $124,579,000
and $125,900,000 and for income taxes was $56,981,000, $63,682,000 and
$55,157,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under
capital leases were $2,510,000, $14,116,000 and $13,868,000 in 2001, 2000 and
1999, respectively.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
Retained Earnings January 1 $120,584 $175,854 $179,461
Net Income 161,818 73,844 120,492
------- -- ------ - -------
282,402 249,698 299,953
------- - ------- - -------
Deductions:
Cash Dividends Declared:
Common Stock 129,594 126,612 121,392
Cumulative Preferred Stock:
4-1/2% Series 801 811 850
5.90% Series 278 307 425
5.92% Series 364 364 364
6.85% Series - 289 579
---- ----- --- ----- ---
Total Cash Dividends Declared 131,037 128,383 123,610
Capital Stock Expense 568 731 489
--- ----- --- ----- ---
Total Deductions 131,605 129,114 124,099
------- - ------- - -------
Retained Earnings December 31 $150,797 $120,584 $175,854
======== ======== ========
See Notes to Financial Statements Beginning on Page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,126,701 $1,096,260
---------- ----------
PREFERRED STOCK: No par value - authorized shares 8,000,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series(a) 2001 (b) Year Ended December 31, December 31, 2001
- ------ ------------ ---------------------------- -----------------
2001 2000 1999
---- ---- ----
Not Subject to Mandatory Redemption:
4-1/2% $110 - 7,011 8,671 177,905 17,790 17,790
---------- ----------
Subject to Mandatory Redemption:
5.90% (c) (d) - 10,000 20,000 47,100 4,710 4,710
5.92% (c) (d) - - - 61,500 6,150 6,150
---------- ----------
10,860 10,860
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 639,365 739,015
Installment Purchase Contracts 234,904 234,782
Senior Unsecured Notes 518,247 468,113
Junior Debentures 161,507 161,367
Other Long-term Debt 2,536 2,541
Less Portion Due Within One Year (80,007) (175,006)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,476,552 1,430,812
---------- ----------
TOTAL CAPITALIZATION $2,631,903 $2,555,722
========== ==========
(a) The sinking fund provisions of each series subject to mandatory redemption
have been met by purchase of shares in advance of the due date. APCo
redeemed 84,500 shares of the 6.85% series of preferred stock subject to
mandatory redemption in 2000.
(b) The cumulative preferred stock is callable at the price indicated plus
accrued dividends. The involuntary liquidation preference is $100 per
share. The aggregate involuntary liquidation price for all shares of
cumulative preferred stock may not exceed $300 million. The unissued shares
of the cumulative preferred stock may or may not possess mandatory
redemption characteristics upon issuance.
(c) Commencing in 2003 and continuing through 2007 APCo may redeem at $100 per
share 25,000 shares of the 5.90% series and 30,000 shares of the 5.92%
series outstanding under sinking fund provisions at its option and all
outstanding shares must be reacquired in 2008. Shares previously redeemed
may be applied to meet the sinking fund requirement.
(d) Not callable until after 2002.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
6-3/8 2001 - March 1 $ - $100,000
7.38 2002 - August 15 50,000 50,000
7.40 2002 - December 1 30,000 30,000
6.65 2003 - May 1 40,000 40,000
6.85 2003 - June 1 30,000 30,000
6.00 2003 - November 1 30,000 30,000
7.70 2004 - September 1 21,000 21,000
7.85 2004 - November 1 50,000 50,000
8.00 2005 - May 1 50,000 50,000
6.89 2005 - June 22 30,000 30,000
6.80 2006 - March 1 100,000 100,000
8.50 2022 - December 1 70,000 70,000
7.80 2023 - May 1 30,237 30,237
7.15 2023 - November 1 20,000 20,000
7.125 2024 - May 1 45,000 45,000
8.00 2025 - June 1 45,000 45,000
Unamortized Discount (1,872) (2,222)
-------- --------
Total $639,365 $739,015
======== ========
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into, in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
2001 2000
(in thousands)
% Rate Due
Industrial Development
Authority of
Russell County, Virginia:
7.70 2007 - November 1 $ 17,500 $ 17,500
5.00 2021 - November 1 19,500 19,500
Putnam County, West Virginia:
5.45 2019 - June 1 40,000 40,000
6.60 2019 - July 1 30,000 30,000
Mason County, West Virginia:
7-7/8 2013 - November 1 10,000 10,000
6.85 2022 - June 1 40,000 40,000
6.60 2022 - October 1 50,000 50,000
6.05 2024 - December 1 30,000 30,000
Unamortized Discount (2,096) (2,218)
Total $234,904 $234,782
======== ========
Under the terms of the installment purchase contracts, APCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
(a) 2001 - June 27 $ - $ 75,000
(a) 2003 - August 20 125,000 -
7.45 2004 - November 1 50,000 50,000
6.60 2009 - May 1 150,000 150,000
7.20 2038 - March 31 100,000 100,000
7.30 2038 - June 30 100,000 100,000
Unamortized Discount (6,753) (6,887)
Total $518,247 $468,113
======== ========
(a) A floating interest rate is determined monthly. The rate on December 31,
2001 and 2000 was 2.839% and 6.95%, respectively.
Junior debentures outstanding were as follows:
December 31,
2001 2000
(in thousands)
8-1/4% Series A due
2026 - September 30 $ 75,000 $ 75,000
8% Series B due 2027
- March 31 90,000 90,000
Unamortized Discount (3,493) (3,633)
-------- --------
Total $161,507 $161,367
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.
At December 31, 2001, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2002 $ 80,007
2003 225,007
2004 121,008
2005 80,010
2006 100,011
Later Years 964,730
----------
Total Principal Amount 1,570,773
Unamortized Discount (14,214)
Total $1,556,559
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes to APCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to APCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Rate Matters Note 5
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments
and Derivatives Note 12
Income Taxes Note 13
Supplementary Information Note 14
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Related Party Transactions Note 20
Subsequent Events Note 21
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Appalachian Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Appalachian Power Company and its
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Appalachian Power Company and
its subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,738,837 $1,770,402 $1,482,475 $1,406,117 $1,376,282
Operating Expenses 1,443,106 1,463,304 1,188,490 1,123,330 1,124,963
--------- - --------- - --------- - --------- - ---------
Operating Income 295,731 307,098 293,985 282,787 251,319
Nonoperating Income
(Loss) 5,324 7,235 8,113 760 8,277
Interest Charges 116,268 124,766 114,380 122,036 131,173
------- --- ------- --- ------- --- ------- --- -------
Income Before
Extraordinary Item 184,787 189,567 187,718 161,511 128,423
Extraordinary Loss (2,509) - (5,517) - -
------ ------ ---- ---- ------ ------ ---- ------ ----
Net Income 182,278 189,567 182,201 161,511 128,423
Preferred Stock
Dividend
Requirements 242 241 6,931 6,901 9,523
Gain (Loss) on
Reacquired Preferred
Stock - - (2,763) - 2,402
---- ------ ---- ---- ------ ------ ---- ----- -----
Earnings Applicable
To Common Stock $182,036 $189,326 $172,507 $154,610 $121,302
======== ======== ======== ======== ========
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,769,707 $5,592,444 $5,511,894 $5,336,191 $5,215,749
Accumulated
Depreciation
And Amortization 2,446,027 2,297,189 2,247,225 2,072,686 1,891,406
--------- - --------- - --------- - --------- - ---------
Net Electric Utility
Plant $3,323,680 $3,295,255 $3,264,669 $3,263,505 $3,324,343
========== ========== ========== ========== ==========
Total Assets $5,115,986 $5,467,684 $4,847,850 $4,735,476 $4,897,380
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $573,888 $573,888 $573,888 $573,888 $573,888
Retained Earnings 826,197 792,219 758,894 734,387 828,777
------- --- ------- --- ------- --- ------- --- -------
Total Common
Shareholder's Equity $1,400,085 $1,366,107 $1,332,782 $1,308,275 $1,402,665
========== ========== ========== ========== ==========
Preferred Stock $ 5,967 $ 5,967 $ 5,967 $163,204 $163,204
======= ======= ======= ======== ========
CPL - Obligated,
Mandatorily
Redeemable Preferred
Securities of
Subsidiary Trust
Holding Solely
Junior Subordinated
Dentures of CPL $136,250 $148,500 $150,000 $150,000 $150,000
======== ======== ======== ======== ========
Long-term Debt (a) $1,253,768 $1,454,559 $1,454,541 $1,350,706 $1,414,335
========== ========== ========== ========== ==========
Total Capitalization
And Liabilities $5,115,986 $5,467,684 $4,847,850 $4,735,476 $4,897,380
========== ========== ========== ========== ==========
(a) Including portion due within one year.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
CPL is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 689,000 retail
customers in southern Texas. CPL also sells electric power at wholesale to other
utilities, municipalities and rural electric cooperatives.
Wholesale power marketing and trading activities are conducted on CPL's
behalf by AEP. CPL shares in the revenues and costs of the AEP Power Pool's
wholesale sales to and forward trades with other utility systems and power
marketers.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to CPL. Trading
activities allocated to CPL involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. It represents the change in the unrealized gain or loss throughout
the contract's term. When the contract actually settles, that is, the energy is
actually delivered in a sale or received in a purchase or the parties agree to
forego delivery and receipt of electricity and net settle in cash, the
unrealized gain or loss is reversed out of revenues and the actual realized cash
gain or loss is recognized in revenues. Therefore, over the trading contract's
term an unrealized gain or loss is recognized as the contract's market value
changes. When the contract settles the total gain or loss is realized in cash
but only the difference between the accumulated unrealized net gains or losses
recorded in prior months and the cash proceeds is recognized. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities as appropriate.
Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record our share of any difference between
the contract price and the market price as an unrealized gain or loss in
revenues. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse to revenues the previously recorded unrealized
gain or loss. Prior to settlement, the change in the fair value of physical
forward sale and purchase contracts is included in revenues on a net basis. Upon
settlement of a forward trading contract, the amount realized is included in
revenues, with the prior change in unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
revenues from recording additional changes in fair values using mark-to-market
accounting.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing CPL to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Results of Operations
Income before extraordinary item decreased $5 million or 3% in 2001.
The decrease was primarily a result of a settlement of Texas municipal franchise
fees (see Note 8) and increased maintenance expense.
Income before extraordinary item increased $2 million or 1% in 2000
primarily as a result of increased retail energy sales, the post merger sharing
of AEP's power marketing and trading operations which increased wholesale sales
to neighboring utilities and power marketers and the effect of an unfavorable
adjustment in 1999 as a result of FERC's approval of a transmission coordination
agreement. These items were offset in part by a rise in interest expense.
Operating Revenues
Operating revenues decreased 2% in 2001 and increased 19% in 2000. The
increase in 2000 is primarily due to an increase in wholesale marketing and
trading activities.
The following analyzes the changes in operating revenues:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
---- ----
Amount % Amount %
------ - ------ -
Retail* $4.2 - $193.6 23
Wholesale
Marketing
and Trading (79.1) (11) 72.3 95
Unrealized
MTM 28.1 343 (8.2) -
Other 16.9 27 (8.9) (12)
Total
Marketing
and
Trading (29.9) (2) 248.8 25
Energy
Delivery* (5.6) (1) 29.1 6
Sales to AEP
Affiliates 4.0 11 10.0 36
--- --- -- ----
Total
Revenues $(31.5) (2) $287.9 19
====== ======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Retail operating revenues increased 23% in 2000 due to an increase in
fuel and purchased power related revenues, reflecting rising prices for natural
gas and purchased power, and an increase in weather-related demand for
electricity. Through December 31, 2001 the Texas fuel and purchased power clause
recovery mechanism provides for the accrual of revenues to recover fuel and
purchased power cost increases until reviewed and approved for billing to
customers by the PUCT. As a result increases in fuel and purchased power
expenses and related accrued revenues do not adversely affect results of
opertions.
The decrease in wholesale marketing and trading revenues in 2001 is
primarily attributable to unfavorable wholesale marketing and trading
conditions.
The increase in wholesale marketing and trading revenues in 2000 is
primarily attributable to CPL's initial participation in AEP's power marketing
and trading operations. Since becoming a subsidiary of AEP as a result of the
merger in June 2000, CPL shares in AEP's power marketing and trading
transactions with other non-affiliated entities.
Operating Expenses
Total operating expenses decreased 1% in 2001 and increased 23% in
2000. The 2001 decrease is due primarily to a decrease in fuel costs partially
offset by purchased power, taxes and maintenance. The 2000 increase was
primarily due to increased costs of fuel and purchased power and a rise in other
operation expense. The changes in the components of operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
---- ----
Amount % Amount %
------ - ------ -
Fuel $(58.8) (11) $146.9 36
Marketing
Purchases (16.2) (11) 92.5 180
AEP
Affiliate
Purchases 26.0 80 15.9 95
Other
Operation 1.7 1 28.4 10
Maintenance 10.7 18 (9.6) (14)
Depreciation
And
Amortization (10.4) (6) 1.1 1
Taxes Other
Than Income
Taxes 14.4 19 2.7 4
Income Taxes 12.4 12 (3.1) (3)
-- ---- -- ----
Total $(20.2) (1) $274.8 23
====== ======
N.M. = Not Meaningful
The decrease in fuel expense in 2001 was primarily due to a reduction
in the average cost of fuel primarily from a decline in natural gas prices. CPL
uses natural gas as fuel for 71% of its generating capacity. The nature of the
natural gas market is such that both long-term and short-term contracts are
generally based on the current spot market price. Changes in natural gas prices
affect CPL's fuel expense, however, as explained above, they generally do not
impact results of operations.
Fuel expense increased in 2000 primarily due to a rise in the average
cost of fuel reflecting large increases in natural gas prices.
Overall Purchased Power increased in both years largely due to higher
natural gas prices. Although gas prices declined in 2001, they were higher
during the first half of 2001 when CPL was making most of its purchases.
Throughout 2000 gas prices were increasing accounting for the rise in both AEP
Affiliates and Electricity Marketing Purchased Power Expense in 2000.
Other operation expense increased in 2000 due primarily to an increase in
transmission expenses that resulted from new prices for the ERCOT transmission
grid. Each year ERCOT establishes new rates to allocate the costs of the Texas
transmission system to Texas electric utilities. In addition to higher
transmission expenses, other operation expense increased due to higher
administrative expenses resulting from the Company's share of STP voluntary
severance expenses and Texas regulatory expenses.
The principal cause of the increase in maintenance expense in 2001 was
two refueling outages at the STP verses one in 2000. Also contributing to the
increase in maintenance expense were scheduled major overhauls of four power
plants.
Maintenance expense decreased in 2000 as a result of a 10-year service
inspection and refueling of STP Units 1 and 2 performed in 1999.
Taxes other than income taxes increased in 2001 due primarily to an
increase in franchise related taxes, including a settlement of disputed
franchise fees (see Note 8), and a new tax levied by the PUCT, the Texas System
Benefit Fund Assessment.
The increase in income tax expense was primarily due to adjustments
associated with prior year tax returns and an increase in pre-tax book income.
Interest Charges
The decrease in interest charges in 2001 was attributable to lower
average interest rates associated with short-term and long-term debt.
The increase in interest charges in 2000 can be attributed to higher
average interest rates on debt.
Extraordinary Loss
The extraordinary loss on reacquired debt recorded in 2001 was the result
of reacquisition of installment purchase contracts for Matagorda County,
Navigation District, Texas.
Preferred Stock Dividends
Preferred stock dividends decreased in 2000 as a result of the redemption
of preferred stock in the fourth quarter of 1999, which resulted in a loss on
reacquired preferred stock recorded in 1999.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $1,223,893 $1,253,836 $1,005,037
Energy Delivery 473,182 478,814 449,667
Sales to AEP Affiliates 41,762 37,752 27,771
------ ---- ------ ---- ------
TOTAL REVENUES 1,738,837 1,770,402 1,482,475
OPERATING EXPENSES:
Fuel 492,057 550,903 403,989
Purchased Power:
Electricity Marketing 127,816 144,021 51,482
AEP Affiliates 58,641 32,591 16,673
Other Operation 321,227 319,539 291,131
Maintenance 71,212 60,528 70,165
Depreciation and Amortization 168,341 178,786 177,702
Taxes Other Than Income Taxes 90,916 76,477 73,823
Income Taxes 112,896 100,459 103,525
------- --- ------- --- -------
Total Operating Expenses 1,443,106 1,463,304 1,188,490
--------- - --------- - ---------
OPERATING INCOME 295,731 307,098 293,985
NONOPERATING INCOME 22,552 5,830 6,420
NONOPERATING EXPENSES 17,626 3,668 3,593
NONOPERATING INCOME TAX EXPENSE (CREDIT) (398) (5,073) (5,286)
INTEREST CHARGES 116,268 124,766 114,380
------- --- ------- --- -------
INCOME BEFORE EXTRAORDINARY ITEM 184,787 189,567 187,718
EXTRAORDINARY LOSS ON REACQUIRED DEBT (Inclusive
of Tax $1,351,000 and $2,971,000 for 2001 and
1999, respectively) (2,509) - (5,517)
------ ------ ---- ---- ------
NET INCOME 182,278 189,567 182,201
PREFERRED STOCK DIVIDEND REQUIREMENTS 242 241 6,931
LOSS ON REACQUIRED PREFERRED STOCK - - (2,763)
---- ------ ---- ---- ------
EARNINGS APPLICABLE TO COMMON STOCK $182,036 $189,326 $172,507
======== ======== ========
See Notes to Financial Statements Beginning on Page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
2001 2000
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,169,421 $3,175,867
Transmission 663,655 581,931
Distribution 1,279,037 1,221,750
General 241,137 237,764
Construction Work in Progress 169,075 138,273
Nuclear Fuel 247,382 236,859
------- --- -------
Total Electric Utility Plant 5,769,707 5,592,444
Accumulated Depreciation and Amortization 2,446,027 2,297,189
--------- - ---------
NET ELECTRIC UTILITY PLANT 3,323,680 3,295,255
--------- - ---------
OTHER PROPERTY AND INVESTMENTS 47,950 44,225
------ ---- ------
LONG-TERM ENERGY TRADING CONTRACTS 72,502 65,786
------ ---- ------
CURRENT ASSETS:
Cash and Cash Equivalents 10,909 14,253
Accounts Receivable:
General 38,459 67,787
Affiliated Companies 6,249 31,272
Allowance for Uncollectible Accounts (186) (1,675)
Fuel Inventory - at LIFO cost 38,690 22,842
Materials and Supplies - at average cost 55,475 53,108
Under-recovered Fuel Costs - 127,295
Energy Trading Contracts 212,979 476,839
Prepayments 2,742 3,014
----- ----- -----
TOTAL CURRENT ASSETS 365,317 794,735
------- --- -------
REGULATORY ASSETS 226,806 202,440
------- --- -------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 959,294 953,249
------- --- -------
NUCLEAR DECOMMISSIONING TRUST FUND 98,600 93,592
------ ---- ------
DEFERRED CHARGES 21,837 18,402
------ ---- ------
TOTAL $5,115,986 $5,467,684
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
December 31,
2001 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 826,197 792,219
------- --- -------
Total Common Shareholder's Equity 1,400,085 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 136,250 148,500
Long-term Debt 988,768 1,254,559
------- - ---------
TOTAL CAPITALIZATION 2,531,070 2,775,133
--------- - ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 265,000 200,000
Advances from Affiliates 354,277 269,712
Accounts Payable - General 65,307 128,957
Accounts Payable - Affiliated Companies 49,301 40,962
Over-Recovered Fuel 57,762 -
Taxes Accrued 83,512 55,526
Interest Accrued 18,524 26,217
Energy Trading Contracts 219,486 485,521
Other 49,512 40,630
------ ---- ------
Total CURRENT LIABILITIES 1,162,681 1,247,525
--------- - ---------
DEFERRED INCOME TAXES 1,163,795 1,242,797
--------- - ---------
DEFERRED INVESTMENT TAX CREDITS 122,892 128,100
------- --- -------
LONG-TERM ENERGY TRADING CONTRACTS 62,138 65,295
------ ---- ------
DEFERRED CREDITS 73,410 8,834
------ ----- -----
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $5,115,986 $5,467,684
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 182,278 $ 189,567 $ 182,201
Adjustments for Noncash Items:
Depreciation and Amortization 168,341 178,786 177,702
Extraordinary Loss on Reacquired Debt 2,509 - 5,517
Deferred Income Taxes (72,568) 16,263 19,938
Deferred Investment Tax Credits (5,208) (5,207) (5,207)
Mark-to-Market of Energy Trading Contracts (12,048) 8,191 -
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) 52,862 (32,902) (13,426)
Fuel, Materials and Supplies (18,215) 8,680 (4,476)
Interest Accrued (7,693) 11,494 (12,313)
Fuel Recovery 185,057 (96,872) (40,046)
Accounts Payable (55,311) 45,873 (3,061)
Taxes Accrued 27,986 14,405 (5,734)
Transmission Coordination Agreement Settlement - 15,519 (15,519)
Change in Other Assets 10,756 599 19,974
Change in Other Liabilities 11,174 12,233 (554)
------ --- ------ ------ -----
Net Cash Flows From Operating Activities 469,920 366,629 304,996
------- -- ------- -- -------
INVESTING ACTIVITIES:
Construction Expenditures (193,732) (199,484) (210,823)
Proceeds From Sales of Property and Other (354) - 15,063
---- ----- ---- --- ------
Net Cash Flows Used For Investing
Activities (194,086) (199,484) (195,760)
-------- - -------- - --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 260,162 149,248 358,887
Retirement of Preferred Stock - - (160,001)
Retirement of Long-term Debt (475,606) (151,440) (261,700)
Change in Advances from Affiliates (net) 84,565 (52,446) 161,860
Special Deposit for Reacquisition of Long-term Debt - 50,000 (50,000)
Dividends Paid on Common Stock (148,057) (156,000) (148,000)
Dividends Paid on Cumulative Preferred Stock (242) (249) (7,835)
---- ----- ---- --- ------
Net Cash Flows Used For
Financing Activities (279,178) (160,887) (106,789)
-------- - -------- - --------
Net Increased (Decrease) in Cash and Cash Equivalents (3,344) 6,258 2,447
Cash and Cash Equivalents January 1 14,253 7,995 5,548
------ ---- ----- ---- -----
Cash and Cash Equivalents December 31 $10,909 $14,253 $ 7,995
======= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts (including distributions on
Trust Preferred Securities) was $109,835,000, $110,010,000 and $125,222,000 and
for income taxes was $161,529,000, $48,141,000 and $78,393,000 in 2001, 2000 and
1999,respectively.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $792,219 $758,894 $734,387
NET INCOME 182,278 189,567 182,201
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 148,057 156,000 148,000
Preferred Stock 242 241 6,931
Other 1 1 -
LOSS ON REACQUIRED PREFERRED STOCK - - (2,763)
---- ---- ---- -- ------
BALANCE AT END OF PERIOD $826,197 $792,219 $758,894
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDERS' EQUITY $1,400,085 $1,366,107
---------- ----------
PREFERRED STOCK - authorized shares 3,035,000 $100 par value
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2001 Year Ended December 31, December 31, 2001
- ------ ------------ ---------------------------- -----------------
2001 2000 1999
---- ---- ----
Not Subject to Mandatory Redemption:
4.00% $105.75 - - - 42,038 4,204 4,204
4.20% 103.75 - - - 17,476 1,748 1,748
Premium 15 15
---------- ----------
Total Preferred Stock 5,967 5,967
---------- ----------
TRUST PREFERRED SECURITIES:
CPL-obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely Junior Subordinated Debentures of CPL, 8.00%,
due April 30, 2037 136,250 148,500
---------- ----------
LONG-TERM (See Schedule of Long-term Debt):
First Mortgage Bonds 614,200 615,000
Installment Purchase Contracts 489,568 489,559
Senior Unsecured Notes 150,000 350,000
Less Portion Due Within One year (265,000) (200,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 988,768 1,254,559
---------- ----------
TOTAL CAPITALIZATION $2,531,070 $2,775,133
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
---- ----
(in thousands)
% Rate Due
7.25 2004 - October 1 $100,000 $100,000
7.50 2002 - December 1 115,000 115,000
6-7/8 2003 - February 1 49,200 50,000
7-1/8 2008 - February 1 75,000 75,000
7.50 2023 - April 1 75,000 75,000
6-5/8 2005 - July 1 200,000 200,000
Unamortized Discount - -
-------- -----
Total $614,200 $615,000
======== ========
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection with the
issuance of pollution control revenue bonds by governmental authorities as
follows:
December 31,
2001 2000
---- ----
(in thousands)
% Rate Due
Matagorda County
Navigation District,
Texas:
6.00 2028 - July 1 $120,265 $120,265
6.10 2028 - July 1 - 100,635
6-1/8 2030 - May 1 60,000 60,000
4.90 2030 - May 1 - 111,700
4.95 2030 - May 1 - 50,000
3.75 2030(a) - May 1 111,700 -
4.00 2030(a) - May 1 50,000 -
4.55 2029(a) - Nov 1 100,635 -
Guadalupe-Blanco
River Authority
District, Texas:
(b) 2015 - November 1 40,890 40,890
Red River Authority
District, Texas:
6.00 2020 - June 1 6,330 6,330
Unamortized Discount (252) (261)
-------- --------
Total $489,568 $489,559
======== ========
(a)Installment Purchase Contract provides for bonds to be tendered in 2003 for
3.75% and 4.00% series and in 2006 for 4.55% series. Therefore, these
installment purchase contracts have been classified for payments in those years.
(b) A floating interest rate is determined monthly. The rate on December 31,
2001 was 1.9%.
Under the terms of the installment purchase contracts, CPL is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
---- ----
(in thousands)
% Rate Due
2001 - November 23 $ - $200,000
(c) 2002 - February 22 150,000 150,000
-------- --------
Total $150,000 $350,000
======== ========
(c) A floating interest rate is determined monthly. The rate on December 31,
2001 and 2000 was 2.56% and 7.20%, respectively.
At December 31, 2001, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2002 $265,000
2003 210,900
2004 100,000
2005 200,000
2006 100,635
Later Years 377,485
--- -------
Total Principal Amount 1,254,020
Unamortized Discount (252)
------ ----
Total $1,253,768
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes to CPL financial statements are combined with the notes to financial
statements for AEP and its other subsidiary registrants. Listed below are the
combined notes that apply to CPL. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Trust Preferred Securities Note 18
Jointly Owned Electric Utility Plant Note 19
Related Party Transactions Note 20
Subsequent Events Note 21
Subsequent Events (Unaudited) Note 22
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors
of Central Power and Light Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Central Power and Light Company and
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The consolidated financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the consolidated financial statements, were audited by other
auditors whose report, dated February 25, 2000, expressed an unqualified opinion
on those statements.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such 2001 and 2000 consolidated financial statements
present fairly, in all material respects, the financial position of Central
Power and Light Company and subsidiaries as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.
We also audited the adjustments described in Note 3 that were applied
to restate the 1999 consolidated financial statements to give retroactive effect
to the conforming change in the method of accounting for vacation pay accruals.
In our opinion, such adjustments are appropriate and have been properly applied.
Deloitte & Touche LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
COLUMBUS SOUTHERN POWER COMPANY
AND SUBSIDIARIES
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,350,319 $1,304,409 $1,190,997 $1,187,745 $1,094,851
Operating Expenses 1,098,142 1,108,532 968,207 975,534 899,724
--------- - --------- --- ------- --- ------- --- -------
Operating Income 252,177 195,877 222,790 212,211 195,127
Nonoperating Income
(Loss) 7,738 5,153 2,709 (1,343) 3,137
Interest Charges 68,015 80,828 75,229 77,824 78,885
------ --- ------ ---- ------ ---- ------ ---- ------
Income Before
Extraordinary Item 191,900 120,202 150,270 133,044 119,379
Extraordinary Loss (30,024) (25,236) - - -
------- -- ------- ------ ---- ------ ---- ------ ----
Net Income 161,876 94,966 150,270 133,044 119,379
Preferred Stock
Dividend
Requirements 1,095 1,783 2,131 2,131 2,442
----- ---- ----- ----- ----- ----- ----- ----- -----
Earnings Applicable to
Common Stock $160,781 $93,183 $148,139 $130,913 $116,937
======== ======= ======== ======== ========
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $3,354,320 $3,266,794 $3,151,619 $3,053,565 $2,976,110
Accumulated Depreciation 1,377,032 1,299,697 1,210,994 1,134,348 1,074,588
--------- - --------- - --------- - --------- - ---------
Net Electric Utility
Plant $1,977,288 $1,967,097 $1,940,625 $1,919,217 $1,901,522
========== ========== ========== ========== ==========
Total Assets $3,105,868 $3,888,302 $2,809,990 $2,681,690 $2,613,860
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $615,395 $614,380 $613,899 $613,518 $613,138
Retained Earnings 176,103 99,069 246,584 186,441 138,172
------- ---- ------ --- ------- --- ------- --- -------
Total Common
Shareholder's Equity $791,498 $713,449 $860,483 $799,959 $751,310
======== ======== ======== ======== ========
Cumulative Preferred
Stock - Subject to
Mandatory
Redemption (a) $ 10,000 $ 15,000 $ 25,000 $ 25,000 $ 25,000
======== ======== ======== ======== ========
Long-term Debt (a) $791,848 $899,615 $924,545 $959,786 $969,600
======== ======== ======== ======== ========
Obligations Under
Capital Leases (a) $ 34,887 $ 42,932 $ 40,270 $ 42,362 $ 38,587
======== ======== ======== ======== ========
Total Capitalization and
Liabilities $3,105,868 $3,888,302 $2,809,990 $2,681,690 $2,613,860
========== ========== ========== ========== ==========
(a) Including portion due within one year.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Management's Narrative Analysis of Results of Operations
Columbus Southern Power Company is a public utility engaged in the
generation, purchase, sale, transmission and distribution of electric power to
678,000 retail customers in central and southern Ohio. CSPCo as a member of the
AEP Power Pool shares in the revenues and costs of the AEP Power Pool's
wholesale sales to neighboring utility systems and power marketers including
power trading transactions. CSPCo also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among
the Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing AEP Power Pool revenues and costs. The result of this calculation is the
member load ratio (MLR) which determines each company's percentage share of AEP
Power Pool revenues and costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to CSPCo as a
member of the AEP Power Pool. Trading activities involve the purchase and sale
of energy under physical forward contracts at fixed and variable prices and
buying and selling financial energy contracts which includes exchange traded
futures and options and over-the-counter options and swaps. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts prior
to settlement is commonly referred to as mark-to-market (MTM) accounting. It
represents the change in the unrealized gain or loss throughout the contract's
term. When the contract actually settles, that is, the energy is actually
delivered in a sale or received in a purchase or the parties agree to forego
delivery and receipt and net settle in cash, the unrealized gain or loss is
reversed and the actual realized cash gain or loss is recognized. Therefore,
over the trading contract's term an unrealized gain or loss is recognized as the
contract's market value changes. When the contract settles the total gain or
loss is realized in cash but only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized. Unrealized mark-to-market gains and losses are included in the
Balance Sheet as energy trading contract assets or liabilities as appropriate.
The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse the previously recorded unrealized gain or
loss.
Depending on whether the delivery point for the electricity is in
AEP's traditional marketing area or not determines where the contract is
reported on CSPCo's income statement. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale and purchase contracts with delivery points in AEP's traditional
marketing area are included in revenues when the contracts settle. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts in AEP's traditional marketing area are included in revenues on a net
basis. Physical forward sale and purchase contracts for delivery outside of
AEP's traditional marketing area are included in nonoperating income when the
contract settles. Prior to settlement, changes in the fair value of physical
forward sale and purchase contracts with delivery points outside of AEP's
traditional marketing area are included in nonoperating income on a net basis.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
results of operations from recording additional changes in fair values using
mark-to-market accounting.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing CSPCo to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Results of Operations
Net Income Increases
Income before extraordinary item increased by $72 million or 60% in 2001
primarily due to the effect of a court decision related to a corporate owned
life insurance (COLI) program recorded in 2000. In February 2001 the U.S.
District Court for the Southern District of Ohio ruled against AEP and certain
of its subsidiaries, including CSPCo, in a suit over the deductibility of
interest claimed in AEP's consolidated tax return related to COLI. In 1998 and
1999 CSPCo paid the disputed taxes and interest attributable to the COLI
interest deductions for taxable years 1991-98. The payments were included in
Other Property and Investments pending the resolution of this matter. Also
contributing to the increase in net income in 2001 was growth in and strong
performance by the wholesale business in the first half of 2001 offset in part
by the effect of extremely mild weather in November and December combined with
weak economic conditions which reduced retail energy sales.
Operating Revenues Increase
Operating revenues increased 4% in 2001 due to increased revenues to
commercial customers and to AEP affiliates. Changes in the components of
operating revenues were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
Amount %
Retail* $(65.1) (10)
Wholesale Marketing and
Trading (16.2) (11)
Unrealized MTM 23.1 N.M.
Other 0.8 2
------
Total Marketing and
Trading (57.4) (7)
Energy Delivery* 85.2 21
Sales to AEP Affiliates 18.1 37
------
Total Revenues $ 45.9 4
======
N.M. = Not Meaningful
*Reflects the allocation in 2000 of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
Operating revenues increased due to increased kilowatt hour sales to
commercial customers and increased sales to affiliated companies.
Operating Expenses
Operating expenses declined slightly in 2001 due to declines in fuel,
maintenance expense, taxes other than income taxes and income taxes partially
offset by an increase in depreciation expense. Changes in the components of
operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions)
Amount %
Fuel $(14.0) (7)
Marketing Purchases 1.1 11
AEP Affiliate Purchases 4.4 2
Other Operation Expense (0.4) -
Maintenance Expense (7.2) (10)
Depreciation and
Amortization 27.7 28
Taxes Other Than
Income Taxes (11.7) (10)
Income Taxes (10.3) (9)
------
Total $(10.4) (1)
======
Fuel costs decreased by $14 million due to a 12.5% decrease in
generation partially offset by increased coal prices of 6.3%
Reversal of a quality of service regulatory liability accrual and
reduced maintenance of overhead distribution lines accounted for the decease in
maintenance expense.
Depreciation and amortization expense increased significantly due to
amortization of transition regulatory assets which began in January 2001. With
the implementation of customer choice in Ohio on January 1, 2001, the PUCO
approved the Company's plan for recovery of generation-related regulatory assets
through frozen transition rates. Concurrent with the start of the transition
period, we began amortization of the transition regulatory assets. Depreciation
expense also increased due to additional plant investment.
The decrease in taxes other than income taxes in 2001 is due to a
decrease in property tax rates on generation property partially offset by a new
state excise tax.
The decrease in income tax expense was primarily due to an unfavorable
ruling in AEP's suit against the government over interest deductions claimed
relating to AEP's COLI program which was recorded in 2000 offset in part by an
increase in pre-tax income.
Nonoperating Income Increase
The increases in nonoperating income in 2001 and 2000 is primarily due
to increased net gains on forward electricity trading transactions outside AEP's
traditional marketing area. Net gains on power trading outside our traditional
marketing area increased in 2001 and in 2000 reflecting favorable market
conditions and increased trading activity.
Interest Charges Decrease
Interest charges for 2001 decreased as a result of the recognition in
2000 of deferred interest payments to the IRS related to the COLI disallowances
as well as reduced debt in 2001.
Extraordinary Loss
In 2001 we recorded an extraordinary loss of $30 million net of tax to
write-off prepaid Ohio excise taxes stranded by Ohio deregulation (see Note 2,
"Extraordinary Items and Cumulative Effect").
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $799,589 $856,998 $781,999
Energy Delivery 483,219 398,046 389,280
Sales to AEP Affiliates 67,511 49,365 19,718
------ ---------- ----------
Total Operating Revenues 1,350,319 1,304,409 1,190,997
--------- - --------- - ---------
OPERATING EXPENSES:
Fuel 175,153 189,155 185,511
Purchased Power:
Electricity Marketing 10,957 9,879 27,951
AEP Affiliates 292,199 287,750 199,574
Other Operation 219,497 219,840 189,549
Maintenance 62,454 69,676 65,229
Depreciation and Amortization 127,364 99,640 94,532
Taxes Other Than Income Taxes 111,481 123,223 120,146
Income Taxes 99,037 109,369 85,715
------ --- ------- ---- ------
TOTAL OPERATING EXPENSES 1,098,142 1,108,532 968,207
--------- - --------- --- -------
OPERATING INCOME 252,177 195,877 222,790
NONOPERATING INCOME 32,756 20,580 5,779
NONOPERATING EXPENSES 21,095 8,070 6,010
NONOPERATING INCOME TAX EXPENSE (CREDIT) 3,923 7,357 (2,940)
INTEREST CHARGES 68,015 80,828 75,229
------ ---- ------ ---- ------
INCOME BEFORE EXTRAORDINARY ITEM 191,900 120,202 150,270
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION - Net of
tax (Note 2) (30,024) (25,236) -
------- --- ------- ------ ----
NET INCOME 161,876 94,966 150,270
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,095 1,783 2,131
----- ----- ----- ----- -----
EARNINGS APPLICABLE TO COMMON STOCK $160,781 $ 93,183 $148,139
======== ======== ========
Consolidated Statements of Retained Earnings
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
Retained Earnings January 1 $ 99,069 $246,584 $186,441
Net Income 161,876 94,966 150,270
------- -- ------ - -------
260,945 341,550 336,711
------- - ------- - -------
Deductions:
Cash Dividends Declared:
Common Stock 82,952 240,600 87,996
Cumulative Preferred Stock - 7% Series 875 1,400 1,750
--- --- ----- --- -----
Total Cash Dividends Declared 83,827 242,000 89,746
Capital Stock Expense 1,015 481 381
----- ----- --- ----- ---
Total Deductions 84,842 242,481 90,127
------ - ------- -- ------
Retained Earnings December 31 $176,103 $ 99,069 $246,584
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
2001 2000
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,574,506 $1,564,254
Transmission 401,405 360,302
Distribution 1,159,105 1,096,365
General 146,732 156,534
Construction Work in Progress 72,572 89,339
------ ---- ------
Total Electric Utility Plant 3,354,320 3,266,794
Accumulated Depreciation 1,377,032 1,299,697
--------- - ---------
NET ELECTRIC UTILITY PLANT 1,977,288 1,967,097
--------- - ---------
OTHER PROPERTY AND INVESTMENTS 40,369 39,848
------ ---- ------
LONG-TERM ENERGY TRADING CONTRACTS 193,915 171,820
------- --- -------
CURRENT ASSETS:
Cash and Cash Equivalents 12,358 11,600
Accounts Receivable:
Customers 41,770 73,711
Affiliated Companies 63,470 49,591
Miscellaneous 16,968 18,807
Allowance for Uncollectible Accounts (745) (659)
Fuel - at average cost 20,019 13,126
Materials and Supplies - at average cost 38,984 38,097
Accrued Utility Revenues 7,087 9,638
Energy Trading Contracts 347,198 1,079,704
Prepayments 28,733 46,735
------ ---- ------
TOTAL CURRENT ASSETS 575,842 1,340,350
------- - ---------
REGULATORY ASSETS 262,267 291,553
------- --- -------
DEFERRED CHARGES 56,187 77,634
------ ---- ------
TOTAL $3,105,868 $3,888,302
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
December 31,
2001 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 574,369 573,354
Retained Earnings 176,103 99,069
------- ---- ------
Total Common Shareholder's Equity 791,498 713,449
Cumulative Preferred Stock - Subject to
Mandatory Redemption 10,000 15,000
Long-term Debt 571,348 899,615
------- --- -------
TOTAL CAPITALIZATION 1,372,846 1,628,064
--------- - ---------
OTHER NONCURRENT LIABILITIES 36,715 47,584
------ ---- ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 220,500 -
Advances from Affiliates 181,384 88,732
Accounts Payable - General 62,393 89,846
Accounts Payable - Affiliated Companies 83,697 72,493
Taxes Accrued 116,364 162,904
Interest Accrued 10,907 13,369
Energy Trading Contracts 334,958 1,109,682
Other 34,600 60,701
------ ---- ------
TOTAL CURRENT LIABILITIES 1,044,803 1,597,727
--------- - ---------
DEFERRED INCOME TAXES 443,722 422,759
------- --- -------
DEFERRED INVESTMENT TAX CREDITS 37,176 41,234
------ ---- ------
LONG-TERM ENERGY TRADING CONTRACTS 157,706 138,073
------- --- -------
DEFERRED CREDITS 12,900 12,861
------ ---- ------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $3,105,868 $3,888,302
========== ==========
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 161,876 $ 94,966 $ 150,270
Adjustments for Noncash Items:
Depreciation and Amortization 128,500 100,182 94,962
Deferred Federal Income Taxes 24,108 (4,063) 10,481
Deferred Investment Tax Credits (4,058) (3,482) (3,994)
Deferred Fuel Costs (net) - 5,352 8,889
Mark to Market of Energy Trading Contracts (44,680) (3,393) (2,369)
Extraordinary Loss 30,024 25,236 -
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) 19,987 (29,737) 5,166
Fuel, Materials and Supplies (7,780) 11,957 (7,777)
Accrued Utility Revenues 2,551 38,479 (7,990)
Accounts Payable (16,249) 81,284 9,292
Disputed Tax and Interest Related to COLI - 39,483 (2,240)
Change in Other Assets (42,066) (121,115) (14,898)
Change in Other Liabilities (18,769) 132,441 3,388
------- --- ------- ---- -----
Net Cash Flows From Operating Activities 233,444 367,590 243,180
------- --- ------- -- -------
INVESTING ACTIVITIES:
Construction Expenditures (132,532) (127,987) (115,321)
Proceeds From Sales and Leaseback
Transactions and Other 10,841 1,560 1,858
------ ----- ----- ---- -----
Net Cash Flows Used For Investing
Activities (121,691) (126,427) (113,463)
-------- -- -------- - --------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 92,652 88,732 -
Issuance of Affiliated Long-term Debt 200,000 - -
Retirement of Preferred Stock (5,000) (10,000) -
Retirement of Long-term Debt (314,733) (25,274) (35,523)
Change in Short-term Debt (net) - (45,500) (7,000)
Dividends Paid on Common Stock (82,952) (240,600) (87,996)
Dividends Paid on Cumulative Preferred Stock (962) (1,575) (1,750)
---- ---- ------ --- ------
Net Cash Flows Used For
Financing Activities (110,995) (234,217) (132,269)
-------- -- -------- - --------
Net Increase (Decrease) in Cash and Cash Equivalents 758 6,946 (2,552)
Cash and Cash Equivalents January 1 11,600 4,654 7,206
------ ----- ----- ---- -----
Cash and Cash Equivalents December 31 $12,358 $ 11,600 $ 4,654
======= ======== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $68,596,000, $68,506,000
and $72,007,000 and for income taxes was $80,485,000, $81,109,000 and
$71,809,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under
capital leases were $1,019,000, $10,777,000 and $6,855,000 in 2001, 2000 and
1999, respectively.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 791,498 $ 713,449
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 2,500,000
$25 par value - authorized shares 7,000,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2001 Year Ended December 31, December 31, 2001
- ------ ------------ ---------------------------- -----------------
2001 2000 1999
---- ---- ----
Subject to Mandatory Redemption:
7.00% (a) 50,000 100,000 - 100,000 10,000 15,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
Notes - Affiliated 200,000
First Mortgage Bonds 243,197 537,119
Installment Purchase Contracts 91,220 91,166
Senior Unsecured Notes 147,458 159,318
Junior Debentures 109,973 112,012
Less Portion Due Within One Years (220,500) -
---------- ----------
Total Long-term Debt Excluding Portion Due Within One Year 571,348 899,615
---------- ----------
TOTAL CAPITALIZATION $1,372,846 $1,628,064
========== ==========
(a) A sinking fund requires the redemption of 50,000 shares at $100 a share on
or before August 1 of each year. The Company has the right, on each sinking
fund date, to redeem an additional 50,000 shares which the Company did in
August 2000. The sinking fund provisions of the 7% series aggregate
$5,000,000 in 2002 and 2003.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
7.25 2002 - October 1 $ 14,000 $ 56,500
7.15 2002 - November 1 6,500 20,000
6.80 2003 - May 1 13,000 45,000
6.60 2003 - August 1 25,000 40,000
6.10 2003 - November 1 5,000 20,000
6.55 2004 - March 1 26,500 50,000
6.75 2004 - May 1 26,000 50,000
8.70 2022 - July 1 2,000 35,000
8.40 2022 - August 1 - 15,000
8.55 2022 - August 1 15,000 15,000
8.40 2022 - August 15 14,000 25,500
8.40 2022 - October 15 13,000 13,000
7.90 2023 - May 1 40,000 50,000
7.75 2023 - August 1 33,000 33,000
7.45 2024 - March 1 - 30,000
7.60 2024 - May 1 11,000 41,000
Unamortized Discount (803) (1,881)
-------- --------
Total $243,197 $537,119
======== ========
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by the Ohio Air Quality
Development Authority:
December 31,
2001 2000
(in thousands)
% Rate Due
6-3/8 2020 - December 1 $48,550 $48,550
6-1/4 2020 - December 1 43,695 43,695
Unamortized Discount (1,025) (1,079)
Total $91,220 $91,166
======= =======
Under the terms of the installment purchase contracts, CSPCo is
required to pay amounts sufficient to enable the payment of interest on and the
principal (at stated maturities and upon mandatory redemptions) of related
pollution control revenue bonds issued to finance the construction of pollution
control facilities at the Zimmer Plant.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
- ------ ------------------
6.85 2005 - October 3 $ 36,000 $ 48,000
6.51 2008 - February 1 52,000 52,000
6.55 2008 - June 26 60,000 60,000
Unamortized Discount (542) (682)
-------- --------
Total $147,458 $159,318
======== ========
Notes payable to parent company were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
Variable 2002 - Sept 25 $200,000 $ -
Junior debentures outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
- ------ ------------------
8-3/8 2025 - Sept 30 $ 72,843 $ 75,000
7.92 2027 - March 31 40,000 40,000
Unamortized Discount (2,870) (2,988)
-------- --------
Total $109,973 $112,012
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.
At December 31, 2001, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2002 $220,500
2003 43,000
2004 52,500
2005 36,000
2006 -
Later Years 445,088
Total Principal Amount 797,088
Unamortized Discount (5,240)
Total $791,848
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes to CSPCo's financial statements are combined with the notes to
financial statements for AEP and its other subsidiary registrants. Listed below
are the combined notes that apply to CSPCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Supplementary Information Note 14
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Jointly Owned Electric Utility Plant Note 19
Related Party Transactions Note 20
Subsequent Events Note 21
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors
of Columbus Southern Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Columbus Southern Power Company and
its subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for each of the three
years in the period ended December 31, 2001. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of Columbus Southern Power
Company and its subsidiaries as of December 31, 2001 and 2000, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 2001 in conformity with accounting principles
generally accepted in the United States of America.
Deloitte & Touche LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
INDIANA MICHIGAN POWER COMPANY
AND SUBSIDIARIES
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,526,997 $1,488,209 $1,351,666 $1,405,794 $1,339,232
Operating Expenses 1,367,292 1,522,911 1,243,014 1,239,787 1,131,444
---------- ---------- ---------- ---------- ----------
Operating Income
(Loss) 159,705 (34,702) 108,652 166,007 207,788
Nonoperating Income
(Loss) 9,730 9,933 4,530 (839) 4,415
Interest Charges 93,647 107,263 80,406 68,540 65,463
---------- ---------- ---------- ---------- ----------
Net Income (Loss) 75,788 (132,032) 32,776 96,628 146,740
Preferred Stock
Dividend
Requirements 4,621 4,624 4,885 4,824 5,736
---------- ---------- ---------- ---------- ----------
Earnings (Loss)
Applicable to
Common Stock $ 71,167 $ (136,656) $ 27,891 $ 91,804 $ 141,004
========== ========== ========== ========== ==========
December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $4,923,721 $4,871,473 $4,770,027 $4,631,848 $4,514,497
Accumulated
Depreciation and
Amortization 2,436,972 2,280,521 2,194,397 2,081,355 1,973,937
---------- ---------- ---------- ---------- ----------
Net Electric Utility
Plant $2,486,749 $2,590,952 $2,575,630 $2,550,493 $2,540,560
========== ========== ========== ========== ==========
Total Assets $4,817,008 $5,811,038 $4,576,696 $4,148,523 $3,967,798
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $ 789,800 $ 789,656 $ 789,323 $ 789,189 $ 789,056
Accumulated Other
Comprehensive Income
(Loss) (3,835) - - - -
Retained Earnings 74,605 3,443 166,389 253,154 278,814
---------- ---------- ---------- ---------- ----------
Total Common
Shareholder's Equity $ 860,570 $ 793,099 $ 955,712 $1,042,343 $1,067,870
========== ========== ========== ========== ==========
Cumulative Preferred
Stock:
Not Subject to
Mandatory
Redemption $ 8,736 $ 8,736 $ 9,248 $ 9,273 $ 9,435
Subject to
Mandatory
Redemption (a) 64,945 64,945 64,945 68,445 68,445
---------- ---------- ---------- ---------- ----------
Total Cumulative
Preferred Stock $ 73,681 $ 73,681 $ 74,193 $ 77,718 $ 77,880
========== ========== ========== ========== ==========
Long-term Debt (a) $1,652,082 $1,388,939 $1,324,326 $1,175,789 $1,049,237
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 61,933 $ 163,173 $ 187,965 $ 186,427 $ 195,227
========== ========== ========== ========== ==========
Total Capitalization
And Liabilities $4,817,008 $5,811,038 $4,576,696 $4,148,523 $3,967,798
========== ========== ========== ========== ==========
(a) Including portion due within one year. (a)
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
I&M is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to 567,000 retail customers in
its service territory in northern and eastern Indiana and a portion of
southwestern Michigan. As a member of the AEP Power Pool, I&M shares the
revenues and the costs of the AEP Power Pool's wholesale sales to neighboring
utilities and power marketers including power trading transactions. I&M also
sells wholesale power to municipalities and electric cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among
its members based on their relative peak demands and generating reserves through
the payment of capacity charges and the receipt of capacity credits. AEP Power
Pool members are also compensated for the out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is each company's
member load ratio (MLR) which determines each company's percentage share of
revenues and costs.
Under the terms of unit power agreements, I&M purchases AEGCo's 50% share
of the 2,600 MW Rockport Plant capacity unless it is sold to other utilities.
AEGCo is an affiliate that is not a member of the AEP Power Pool. A long-term
unit power agreement with an unaffiliated utility expired at the end of 1999 for
the sale of 455 MW of AEGCo's Rockport Plant capacity. An agreement between
AEGCo and KPCo provides for the sale of 390 MW of AEGCo's Rockport Plant
capacity to KPCo through 2004. Therefore, effective January 1, 2000, I&M began
purchasing 910 MW of AEGCo's 50% share of Rockport Plant capacity.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, I&M's consolidated financial statements reflect the actions of
regulators that can result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate regulated. In
accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to I&M as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. The majority of trading
activities represent physical forward electricity contracts that are typically
settled by entering into offsetting physical contracts. Although trading
contracts are generally short-term, there are also long-term trading contracts.
Accounting standards applicable to trading activities require that
changes in the fair value of trading contacts be recognized in revenues prior to
settlement and is commonly referred to as mark-to-market (MTM) accounting. Since
I&M is a cost-based rate-regulated entity, changes in the fair value of physical
forward sale and purchase contracts in AEP's traditional marketing area are
deferred as regulatory liabilities (gains) or regulatory assets (losses). The
deferral reflects the fact that power sales and purchases are included in
regulated rates on a settlement basis. AEP's traditional marketing area is up to
two transmission systems from the AEP service territory. The change in the fair
value of physical forward sale and purchase contracts outside AEP's traditional
marketing area is included in nonoperating income on a net basis.
Mark-to-market accounting represents the change in the unrealized gain
or loss throughout the contract's term. When the contract actually settles, that
is, the energy is actually delivered in a sale or received in a purchase or the
parties agree to forego delivery and receipt of electricity and net settle in
cash, the unrealized gain or loss is reversed and the actual realized cash gain
or loss is recognized in the income statement. Therefore, as the contract's
market value changes over the contract's term an unrealized gain or loss is
deferred for contracts with delivery points in AEP's traditional marketing area
and for contracts with delivery points outside of AEP's traditional marketing
area the unrealized gain or loss is recognized as nonoperating income. When the
contract settles the total gain or loss is realized in cash and the impact on
the income statement depends on whether the contract's delivery points are
within or outside of AEP's traditional marketing area. For contracts with
delivery points in AEP's traditional marketing area, the total gain or loss
realized in cash is recognized in the income statement. Physical forward trading
sale and purchase contracts with delivery points in AEP's traditional marketing
area are included in revenues when the contracts settle. Prior to settlement,
changes in the fair value of physical forward sale and purchase contracts in
AEP's traditional marketing area are deferred as regulatory liabilities (gains)
or regulatory assets (losses). For contacts with delivery points outside of
AEP's traditional marketing area only the difference between the accumulated
unrealized net gains or losses recorded in prior months and the cash proceeds is
recognized in the income statement. Physical forward sale and purchase contracts
for delivery outside of AEP's traditional marketing area are included in
nonoperating income when the contract settles. Prior to settlement, changes in
the fair value of physical forward sale and purchase contracts with delivery
points outside of AEP's traditional marketing area are included in nonoperating
income on a net basis. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in non-operating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
non-operating income and reverse to nonoperating income the prior unrealized
gain or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing I&M to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Results of Operations
During 2000 both of the Cook Plant nuclear units were successfully
restarted after being shutdown in September 1997 due to questions regarding the
operability of certain safety systems which arose during a NRC architect
engineer design inspection. See discussion in Note 4 of the Notes to Financial
Statements.
A reduction in other operation and maintenance expense in 2001 reflects the
completion of restart work on the Cook Plant and was the primary reason for a
$208 million increase in net income. As a result of the costs incurred in 2000
to restart the Cook Plant nuclear units and a disallowance of interest
deductions for a corporate owned life insurance (COLI) program, net income
declined $165 million in 2000. In February 2001 the U.S. District Court for the
Southern District of Ohio ruled against AEP and certain of its subsidiaries,
including I&M, in a suit over deductibility of interest claimed in AEP's
consolidated tax return related to COLI. In 1998 and 1999 I&M paid the disputed
taxes and interest attributable to the COLI interest deductions for the taxable
years 1991-98 and deferred them.
Operating Revenues Increase
Operating revenues increased 3% in 2001 and 10% in 2000 due to increased
sales to AEP affiliates through the AEP Power Pool. The following analyzes the
changes in operating revenues:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
------------------------------
Amount % Amount %
Retail* $ (2.3) N.M. $(88.6) (12)
Marketing
and Trading (12.0) (4) 78.6 37
Other 5.0 13 (13.0) (26)
-------- ------
(9.3) (1) (23.0) (3)
Energy
Delivery* 3.4 1 0.1 N.M.
Sales to AEP
Affiliates 44.7 21 159.4 313
-------- ------
Total $ 38.8 3 $136.5 10
======== ======
N.M. = Not Meaningful
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
The increases in operating revenues in 2001 and 2000 are primarily due to
increased sale to AEP affiliates reflecting increased availability of Cook Plant
and a 91% increase in volume of power purchased from AEGCo in 2000. I&M
increased its sales to AEP affiliates in 2000 when additional electricity became
available. The return to service of the Cook Plant units in June and December
2000 and purchasing more power from AEGCo due to the expiration of AEGCo's
contract to sell power to an unaffiliated entity, increased the amount of power
I&M could sell to its affiliates in the AEP Power Pool.
Retail revenues decreased in 2000 when the accrual of power supply
recovery revenues ceased at the end of 1999 pursuant to Cook Plant settlement
agreements. The accrued power supply recovery revenues are being amortized over
a five-year period ending December 31, 2003. The decline in retail revenues was
partially offset by an increase in wholesale marketing and trading revenues. In
2000 staffing increases in energy trading resulted in an increase in the number
of forward electricity purchase and sale contracts in AEP's traditional
marketing area.
Operating Expenses
Total operating expenses decreased 10% in 2001 and increased 23% in 2000
primarily due to the expiration of an AEGCo unit power agreement to sell part of
its Rockport Plant generation to an unaffiliated utility and the increase in
operating expenses in 2000 for the unfavorable COLI tax ruling and costs related
to the extended Cook Plant outage and restart efforts. The changes in the
components of operating expenses were:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
-----------------------------
Amount % Amount %
Fuel $ 39.2 19 $ 25.5 14
Marketing
Purchases 4.9 36 (21.5) (61)
AEP Affiliate
Purchases (27.2) (10) 65.1 32
Other Operation (147.7) (25) 136.5 30
Maintenance (92.6) (42) 84.5 62
Depreciation and
Amortization 9.3 6 4.9 3
Taxes Other Than
Income Taxes 4.9 8 (5.2) (8)
Income Taxes 53.6 N.M. (9.9) (95)
------- ------
Total $ (155.6) (10) $279.9 23
======== ======
N.M. = Not Meaningful
The increase in fuel expense in 2001 and 2000 reflects an increase in
nuclear generation as the Cook Plant units returned to service following the
extended outage.
Electricity marketing purchases increased in 2001 due to increased
purchases from third parties for sales for resale. The decrease in electricity
marketing purchases in 2000 is primarily due to a decrease in volume of power
purchased as our generation became available.
The decline in purchased power from AEP affiliates in 2001 reflects generation
from the Cook Plant replacing purchases from the AEP Power Pool. Purchases from
the AEP Power Pool declined 21% in 2001. As a result of the expiration of
AEGCo's power sale contract with an unaffiliated utility on December 31, 1999,
I&M purchased more of AEGCo's share of Rockport Plant power. Purchases from
AEGCo increased 91% in 2000.
The decrease in other operation and maintenance expenses in 2001 was
primarily due to the cessation of expenditures to prepare the Cook Plant nuclear
units for restart with their return to service in 2000. Other operation and
maintenance expenses increased in 2000 primarily due to expenditures to prepare
the Cook Plant units for restart. In 1999 the IURC and MPSC approved settlement
agreements which allowed the deferral of $200 million of Cook Plant restart
costs in 1999 for amortization over five years from 1999 through 2003. As a
result, other operation and maintenance expense in 1999 reflected a net deferral
of $160 million. See discussion in Note 4 of the Notes to Financial Statements.
The increase in depreciation and amortization charges in 2001 reflects
increased generation and distribution plant investments and amortization of
I&M's share of deferred merger costs.
Taxes other than income taxes increased in 2001 due to higher real and
personal property tax expense from the effect of a favorable accrual adjustment
recorded in December 2000 to match estimated amounts with actual expenses. The
decrease in taxes other than income tax in 2000 is primarily attributable to
decreases in real and personal property taxes reflecting the favorable accrual
adjustment and Indiana gross receipts taxes reflecting an unfavorable accrual
adjustment related to the 1998 tax year recorded in 1999 for gross receipts tax.
The significant increase in income taxes attributable to operations in
2001 is due to an increase in pre-tax operating income. Income taxes
attributable to operations decreased in 2000 due to a decrease in pre-tax
operating income.
Nonoperating Income, Expenses and Income Taxes Increase
The increases in nonoperating income in 2001 and 2000 is primarily due to
increased net gains on forward electricity trading transactions outside AEP's
traditional marketing area. Net gains on power trading outside our traditional
marketing area increased in 2001 and 2000 reflecting favorable market conditions
and increased trading activity.
Nonoperating expenses increased in 2001 due to increased trading
overheads and traders' compensation.
The increases in nonoperating income taxes in 2001 and 2000 reflects the
increase in nonoperating pre-tax income.
Interest Charges
The decrease in 2001 interest charges reflects the recognition in 2000 of
deferred interest payments to the IRS on disputed income taxes from the
disallowance of tax deductions for COLI interest for the years 1991-1998.
Interest charges increased in 2000 due to increased borrowings to support
expenditures for the Cook Plant restart effort and the recognition of deferred
interest payments to the IRS on the disputed taxes.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $957,548 $966,882 $989,817
Energy Delivery 314,410 311,019 310,880
Sales to AEP Affiliates 255,039 210,308 50,969
------- ------- ------
TOTAL OPERATING REVENUES 1,526,997 1,488,209 1,351,666
--------- --------- ---------
OPERATING EXPENSES:
Fuel 250,098 210,870 185,419
Purchased Power:
Electricity Marketing 18,707 13,785 35,328
AEP Affiliates 238,237 265,475 200,372
Other Operation 449,115 596,861 460,303
Maintenance 127,263 219,854 135,331
Depreciation and Amortization 164,230 154,920 149,988
Taxes other Than Income Taxes 65,518 60,622 65,843
Income Taxes 54,124 524 10,430
------ ------- ------
TOTAL OPERATING EXPENSES 1,367,292 1,522,911 1,243,014
--------- --------- ---------
OPERATING INCOME (LOSS) 159,705 (34,702) 108,652
NONOPERATING INCOME 41,684 25,138 14,219
NONOPERATING EXPENSES 26,911 11,016 8,383
NONOPERATING INCOME TAXES 5,043 4,189 1,306
INTEREST CHARGES 93,647 107,263 80,406
------ ------- ------
NET INCOME (LOSS) 75,788 (132,032) 32,776
PREFERRED STOCK DIVIDEND REQUIREMENTS 4,621 4,624 4,885
----- ----- -----
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $ 71,167 $ (136,656) $ 27,891
======== ========== ========
Consolidated Statements of Comprehensive Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
NET INCOME (LOSS) $75,788 $(132,032) $32,776
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flows Interest Rate Hedge (3,835) - -
------ ---- ----
COMPREHENSIVE INCOME (LOSS) $71,953 $(132,032) $32,776
======= ========= =======
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
2001 2000
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $2,758,160 $2,708,436
Transmission 957,336 945,709
Distribution 900,921 863,736
General (including nuclear fuel) 233,005 257,152
Construction Work in Progress 74,299 96,440
------ ------
Total Electric Utility Plant 4,923,721 4,871,473
Accumulated Depreciation and Amortization 2,436,972 2,280,521
--------- ---------
NET ELECTRIC UTILITY PLANT 2,486,749 2,590,952
--------- ---------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS 834,109 778,720
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 215,544 194,554
------- -------
OTHER PROPERTY AND INVESTMENTS 127,977 131,417
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 16,804 14,835
Advances to Affiliates 46,309 -
Accounts Receivable:
Customers 60,864 106,832
Affiliated Companies 31,908 48,706
Miscellaneous 25,398 27,491
Allowance for Uncollectible Accounts (741) (759)
Fuel - at average cost 28,989 16,532
Materials and Supplies - at average cost 91,440 84,471
Energy Trading Contracts 399,195 1,222,925
Accrued Utility Revenues 2,072 -
Prepayments 6,497 6,066
----- -----
TOTAL CURRENT ASSETS 708,735 1,527,099
------- ---------
REGULATORY ASSETS 408,927 552,140
------- -------
DEFERRED CHARGES 34,967 36,156
------ ------
TOTAL $4,817,008 $5,811,038
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
December 31,
2001 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 733,216 733,072
Accumulated Other Comprehensive Income (Loss) (3,835) -
Retained Earnings 74,605 3,443
------ -----
Total Common Shareholder's Equity 860,570 793,099
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,312,082 1,298,939
--------- ---------
TOTAL CAPITALIZATION 2,246,333 2,165,719
--------- ---------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 600,244 560,628
Other 87,025 108,600
------ -------
TOTAL OTHER NONCURRENT LIABILITIES 687,269 669,228
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 340,000 90,000
Advances from Affiliates - 253,582
Accounts Payable - General 90,817 119,472
Accounts Payable - Affiliated Companies 43,956 75,486
Taxes Accrued 69,761 68,416
Interest Accrued 20,691 21,639
Obligations Under Capital Leases 10,840 100,848
Energy Trading and Derivative Contracts 383,714 1,267,981
Other 72,435 97,070
------ ------
TOTAL CURRENT LIABILITIES 1,032,214 2,094,494
--------- ---------
DEFERRED INCOME TAXES 400,531 487,945
------- -------
DEFERRED INVESTMENT TAX CREDITS 105,449 113,773
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 77,592 81,299
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 175,581 156,343
------- -------
DEFERRED CREDITS 92,039 42,237
------ ------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $4,817,008 $5,811,038
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $75,788 $(132,032) $32,776
Adjustments for Noncash Items:
Depreciation and Amortization 166,360 163,391 153,921
Amortization of Incremental Nuclear
Refueling Outage Expenses (net) 418 5,737 8,480
Amortization (Deferral) of Nuclear
Outage Costs (net) 40,000 40,000 (160,000)
Deferred Federal Income Taxes (29,205) (125,179) 85,727
Deferred Investment Tax Credits (8,324) (7,854) (8,152)
Mark-to-Market of Energy Trading Contracts (19,502) (10,859) (2,602)
Unrecovered Fuel and Purchased Power Costs 37,501 37,501 (84,696)
Changes in Certain Current Assets
And Liabilities:
Accounts Receivable (net) 64,841 (25,305) (19,178)
Fuel, Materials and Supplies (19,426) 10,743 (12,880)
Accrued Utility Revenues (2,072) 44,428 (7,151)
Accounts Payable (60,185) 85,056 19,068
Taxes Accrued 1,345 19,446 13,809
Disputed Tax and Interest Related to COLI - 56,856 (3,228)
Change in Other Assets (5,871) (68,160) (48,879)
Change in Other Liabilities (5,461) 37,668 63,763
------ ------ ------
Net Cash Flows From Operating Activities 236,207 131,437 30,778
------- ------- ------
INVESTING ACTIVITIES:
Construction Expenditures (91,052) (171,071) (165,331)
Buyout of Nuclear Fuel Leases (92,616) - -
Other 1,074 587 2,501
----- --- -----
Net Cash Flows Used For Investing Activities (182,594) (170,484) (162,830)
-------- -------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 297,656 199,220 247,989
Retirement of Cumulative Preferred Stock - (314) (3,597)
Retirement of Long-term Debt (44,922) (148,000) (109,500)
Change in Advances from Affiliates (net) (299,891) 253,582 -
Change in Short-term Debt (net) - (224,262) 115,562
Dividends Paid on Common Stock - (26,290) (114,656)
Dividends Paid on Cumulative Preferred Stock (4,487) (3,368) (5,856)
------ ------ ------
Net Cash Flows From (Used For)
Financing Activities (51,644) 50,568 129,942
------- ------ -------
Net Increase (Decrease) in Cash and
Cash Equivalents 1,969 11,521 (2,110)
Cash and Cash Equivalents January 1 14,835 3,314 5,424
------ ----- -----
Cash and Cash Equivalents December 31 $16,804 $ 14,835 $ 3,314
======= ======== =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was
$92,140,000,$82,511,000 and $78,703,000 and for income taxes was $100,470,000,
$73,254,000 and $(71,395,000) in 2001, 2000 and 1999, respectively. Noncash
acquisitions under capital leases were $1,023,000, $22,218,000 and $10,852,000
in 2001, 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Retained Earnings
Year Ended December 31,
2001 2000 1999
---- ---- ----
(in thousands)
Retained Earnings January 1 $3,443 $ 166,389 $253,154
Net Income (Loss) 75,788 (132,032) 32,776
------ -------- ------
79,231 34,357 285,930
------ ------ -------
Deductions:
Cash Dividends Declared:
Common Stock - 26,290 114,656
Cumulative Preferred Stock:
4-1/8% Series 229 230 244
4.56% Series 66 66 66
4.12% Series 72 74 78
5.90% Series 897 897 963
6-1/4% Series 1,203 1,203 1,250
6.30% Series 834 834 834
6-7/8% Series 1,186 1,186 1,238
----- ----- -----
Total Cash Dividends Declared 4,487 30,780 119,329
Capital Stock Expense 139 134 212
--- --- ---
Total Deductions 4,626 30,914 119,541
----- ------ -------
Retained Earnings December 31 $ 74,605 $ 3,443 $166,389
======== ======= ========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 860,570 $ 793,099
---------- ----------
PREFERRED STOCK:
$100 Par Value - Authorized 2,250,000 shares
$25 Par Value - Authorized 11,200,000 shares
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2001 Year Ended December 31, December 31, 2001
- ------ ------------ ------------------------ -----------------
2001 2000 1999
---- ---- ----
Not Subject to Mandatory Redemption:
4-1/8% 106.125 - 3,750 97 55,389 5,539 5,539
4.56% 102 - - 150 14,412 1,441 1,441
4.12% 102.728 - 1,375 - 17,556 1,756 1,756
---------- ----------
8,736 8,736
---------- ----------
Subject to Mandatory Redemption:
5.90% (a,b) - - 15,000 152,000 15,200 15,200
6-1/4% (a,b) - - 10,000 192,500 19,250 19,250
6.30% (a,b) - - - 132,450 13,245 13,245
6-7/8% (a,c) - - 10,000 172,500 17,250 17,250
---------- ----------
64,945 64,945
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 264,141 308,976
Installment Purchase Contracts 310,239 309,717
Senior Unsecured Notes 696,144 397,435
Other Long-term Debt 219,947 211,307
Junior Debentures 161,611 161,504
Less Portion Due Within One Year (340,000) (90,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,312,082 1,298,939
---------- ----------
TOTAL CAPITALIZATION $2,246,333 $2,165,719
========== ==========
(a) Not callable until after 2002. There are no aggregate sinking fund
provisions through 2002. Sinking fund provisions require the redemption of
15,000 shares in 2003 and 67,500 shares each year in 2004, 2005 and 2006.
The sinking fund provisions of each series subject to mandatory redemption
have been met by purchase of shares in advance of the due date.
(b) Commencing in 2004 and continuing through 2008 the Company may redeem, at
$100 per share, 20,000 shares of the 5.90% series, 15,000 shares of the
6-1/4% series and 17,500 shares of the 6.30% series outstanding under
sinking fund provisions at its option and all remaining outstanding shares
must be redeemed not later than 2009. Shares previously redeemed may be
applied to meet the sinking fund requirement.
(c) Commencing in 2003 and continuing through the year 2007, a sinking fund
will require the redemption of 15,000 shares each year and the redemption
of the remaining shares outstanding on April 1, 2008, in each case at $100
per share. Shares previously redeemed may be applied to meet the sinking
fund requirement.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
7.63 2001 - June 1 $ - $ 40,000
7.60 2002 - November 1 50,000 50,000
7.70 2002 - December 15 40,000 40,000
6.10 2003 - November 1 30,000 30,000
8.50 2022 - December 15 75,000 75,000
7.35 2023 - October 1 15,000 20,000
7.20 2024 - February 1 30,000 30,000
7.50 2024 - March 1 25,000 25,000
Unamortized Discount (859) (1,024)
-------- --------
$264,141 $308,976
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into, in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
City of Lawrenceburg, Indiana:
7.00 2015 - April 1 $ 25,000 $ 25,000
5.90 2019 - November 1 52,000 52,000
City of Rockport, Indiana:
(a) 2014 - August 1 50,000 50,000
7.60 2016 - March 1 40,000 40,000
6.55 2025 - June 1 50,000 50,000
(b) 2025 - June 1 50,000 50,000
City of Sullivan, Indiana:
5.95 2009 - May 1 45,000 45,000
Unamortized Discount (1,761) (2,283)
$310,239 $309,717
(a) A variable interest rate is determined weekly. The average weighted
interest rate was 2.4% for 2001 and 4.5% for 2000.
(b) In June 2001 an auction rate was established. Auction rates are determined
by standard procedures every 35 days. The auction rate for June through
December 2001 ranged from 1.55% to 2.9% and averaged 2.4%. Prior to June
25, 2001, an adjustable interest rate was a daily, weekly, commercial paper
or term rate as designated by I&M. A weekly rate was selected which ranged
from 1.9% to 4.9% in 2001 and from 2.9% to 5.9% in 2000 and averaged 3.3%
during 2001 and 4.2% during 2000.
The terms of the installment purchase contracts require I&M to pay
amounts sufficient for the cities to pay interest on and the principal (at
stated maturities and upon mandatory redemptions) of related pollution control
revenue bonds issued to finance the construction of pollution control facilities
at certain generating plants. On the variable rate series the principal is
payable at the stated maturities or on the demand of the bondholders at periodic
interest adjustment dates which occur weekly. The variable rate bonds due in
2014 are supported by a bank letter of credit which expires in 2002.
Accordingly, the variable rate installment purchase contracts have been
classified for repayment purposes based on the expiration date of the letter of
credit.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
- ------ ------------------
(a) 2002 - September 3 $200,000 $200,000
6-7/8 2004 - July 1 150,000 150,000
6.125 2006 - December 15 300,000 -
6.45 2008 - November 10 50,000 50,000
Unamortized Discount (3,856) (2,565)
$696,144 $397,435
(a) A floating interest rate is determined quarterly. The rate on December 31,
2001 and 2000 was 2.71% and 7.31%, respectively. The average interest rate
was 5.1% in 2001 and 7.3% in 2000.
Junior debentures outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
- ------ -----------------
8.00 2026 - March 31 $ 40,000 $ 40,000
7.60 2038 - June 30 125,000 125,000
Unamortized Discount (3,389) (3,496)
-------- --------
Total $161,611 $161,504
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of I&M.
At December 31, 2001, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2002 $ 340,000
2003 30,000
2004 150,000
2005 -
2006 300,000
Later Years 841,947
----------
Total Principal Amount 1,661,947
Unamortized Discount (9,865)
----------
Total $1,652,082
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
Index to Notes to Financial Statements
The notes to I&M's financial statements are combined with the notes to financial
statements for AEP and its other subisidiary registrants. Listed below are the
combined notes that apply to I&M. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Merger Note 3
Nuclear Plant Restart Note 4
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Supplementary Information Note 14
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Related Party Transactions Note 20
Subsequent Events Note 21
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Indiana Michigan Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Indiana Michigan Power Company and
its subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, comprehensive income, retained earnings and cash flows for
each of the three years in the period ended December 31, 2001. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Indiana Michigan Power Company
and its subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
KENTUCKY POWER COMPANY
KENTUCKY POWER COMPANY
Selected Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $379,025 $389,875 $358,757 $362,999 $340,635
Operating Expenses 331,347 340,137 304,082 311,106 293,779
------- ------- ------- ------- -------
Operating Income 47,678 49,738 54,675 51,893 46,856
Nonoperating
Income (Loss) 1,248 2,070 (327) (1,726) (464)
Interest Charges 27,361 31,045 28,918 28,491 25,646
------ ------ ------ ------ ------
Net Income $ 21,565 $ 20,763 $ 25,430 $ 21,676 $ 20,746
======== ======== ======== ======== ========
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $1,128,415 $1,103,064 $1,079,048 $1,043,711 $1,006,955
Accumulated
Depreciation and
Amortization 384,104 360,648 340,008 315,546 296,318
------- ------- ------- ------- -------
Net Electric
Utility Plant $744,311 $742,416 $739,040 $728,165 $710,637
======== ======== ======== ======== ========
Total Assets $1,153,243 $1,509,064 $986,638 $921,847 $886,671
========== ========== ======== ======== ========
Common Stock and
Paid-in Capital $209,200 $209,200 $209,200 $199,200 $179,200
Accumulated Other
Comprehensive
Income (Loss) (1,903)
Retained Earnings 48,833 57,513 67,110 71,452 78,076
------ ------ ------ ------ ------
Total Common
Shareholder's
Equity $256,130 $266,713 $276,310 $270,652 $257,276
======== ======== ======== ======== ========
Long-term Debt (a) $346,093 $330,880 $365,782 $368,838 $341,051
======== ======== ======== ======== ========
Obligations Under
Capital Leases(a) $ 9,583 $ 14,184 $ 15,141 $ 18,977 $ 18,725
======= ======== ======== ======== ========
Total
Capitalization
and Liabilities $1,153,243 $1,509,064 $986,638 $921,847 $886,671
========== ========== ======== ======== ========
(a) Including portion due within one year.
KENTUCKY POWER COMPANY
Management's Narrative Analysis of Results of Operations
KPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power serving 172,000 retail customers
in eastern Kentucky. KPCo as a member of the AEP Power Pool shares in the
revenues and costs of the AEP Power Pool's wholesale sales to neighboring
utility systems and power marketers including power trading transactions. KPCo
also sells wholesale power to municipalities.
The cost of the AEP Power Pool's generating capacity is allocated among
the Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges and the receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, KPCo's financial statements reflect the actions of regulators that can
result in the recognition of revenues and expenses in different time periods
than enterprises that are not rate regulated. In accordance with SFAS 71,
regulatory assets (deferred expenses) and regulatory liabilities (future revenue
reductions or refunds) are recorded to reflect the economic effects of
regulation by matching expenses with their recovery through regulated revenues
in the same accounting period.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to KPCO as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. The majority of trading
activities represent physical forward electricity contracts that are typically
settled by entering into offsetting physical contracts. Although trading
contracts are generally short-term, there are also long-term trading contracts.
Accounting standards applicable to trading activities require that changes in
the fair value of trading contacts be recognized in revenues prior to settlement
and is commonly referred to as mark-to-market (MTM) accounting. Since KPCO is a
cost-based rate-regulated entity, changes in the fair value of physical forward
sale and purchase contracts in AEP's traditional marketing area are deferred as
regulatory liabilities (gains) or regulatory assets (losses). AEP's traditional
marketing area is up to two transmission systems from the AEP Service territory.
The change in the fair value of physical forward sale and purchase contracts
outside AEP's traditional marketing area is included in nonoperating income on a
net basis.
Mark-to-market accounting represents the change in the unrealized gain or loss
throughout the contract's term. When the contract actually settles, that is, the
energy is actually delivered in a sale or received in a purchase or the parties
agree to forego delivery and receipt of electricity and net settle in cash, the
unrealized gain or loss is reversed and the actual realized cash gain or loss is
recognized in the income statement. Therefore, as the contract's market value
changes over the contract's term an unrealized gain or loss is deferred for
contracts with delivery points in AEP's traditional marketing area and for
contracts with delivery points outside of AEP's traditional marketing area the
unrealized gain or loss is recognized as nonoperating income. When the contract
settles the total gain or loss is realized in cash and the impact on the income
statement depends on whether the contract's delivery points are within or
outside of AEP's traditional marketing area. For contracts with delivery points
in AEP's traditional marketing area, the total gain or loss realized in cash is
recognized in the income statement. Physical forward trading sale and purchase
contracts with delivery points in AEP's traditional marketing area are included
in revenues when the contracts settle. Prior to settlement, changes in the fair
value of physical forward sale and purchase contracts in AEP's traditional
marketing area are deferred as regulatory liabilities (gains) or regulatory
assets (losses). For contacts with delivery points outside of AEP's traditional
marketing area only the difference between the accumulated unrealized net gains
or losses recorded in prior months and the cash proceeds is recognized in the
income statement. Physical forward sale and purchase contracts for delivery
outside of AEP's traditional marketing area are included in nonoperating income
when the contract settles. Prior to settlement, changes in the fair value of
physical forward sale and purchase contracts with delivery points outside of
AEP's traditional marketing area are included in nonoperating income on a net
basis. Unrealized mark-to-market gains and losses are included in the Balance
Sheet as energy trading assets or liabilities as appropriate.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing KPCO to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Net Income Increases
Net income increased $802 thousand or 4% in 2001 primarily due to the
effect of a court decision related
to a corporate owned life insurance (COLI) program recorded in 2000. In February
2001 the U.S. District Court for the Southern District of Ohio ruled against AEP
and certain of its subsidiaries, including KPCo, in a suit over deductibility of
interest claimed in AEP's consolidated tax return related to COLI. In 1998 and
1999 KPCo paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1992-98. The payments were included in Other
Property and Investments pending the resolution of this matter.
Operating Revenues
Operating revenues decreased $10.9 million or 3% in 2001 as a result of
decreased retail revenues and decreased trading margins in AEP's traditional
marketing area. Changes in the components of operating revenues were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
Amount %
Retail* $(13.5) (9)
Wholesale Marketing
and Trading (7.0) (12)
Other (0.7) (4)
----
Subtotal (21.2) (9)
-----
Energy Delivery* 9.8 8
Sales to AEP Affiliates 0.5 1
---
Total $(10.9) (3)
======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Retail revenues decreased as a result of mild weather conditions. Usage
by residential customers declined in response to warmer temperatures during
November and December 2001. Commercial and industrial sales were stable.
The decrease in wholesale marketing and trading revenues is driven by
decreased trading margins. The maturing of the Intercontinental Exchange, the
development of propriety tools, and increased staffing of energy traders have
resulted in an increase in the number of forward electricity purchase and sale
contracts in AEP's traditional marketing area yet unfavorable market conditions
offset the increase in trading activity.
Energy delivery revenues rose largely from providing additional
transmission services as a result of increased wholesale marketing and trading
transactions and from increased assignment of fees for transmission and
distribution delivery services.
Operating Expenses
Operating expenses decreased $8.8 million in 2001 primarily due to
decreases in fuel costs and income taxes. Changes in the components of operating
expenses were as follows:
Increase (Decrease)
From Previous Year)
(dollars in millions)
Amount %
Fuel $(4.0) (5)
Marketing Purchases (1.9) (96)
AEP Affiliate Purchases 2.5 2
Other Operation 5.8 11
Maintenance (3.4) (13)
Depreciation and
Amortization 1.5 5
Taxes Other Than
Income Taxes 0.6 8
Income Taxes (9.9) (51)
- ----
Total $(8.8) (3)
=====
The decrease in fuel expense is a result of sharing profits from the
trading of power with customers in accordance with the Kentucky Public Service
Commission's fuel clause mechanism. Under this mechanism, the profits from
KPCo's portion of AEP's wholesale marketing and trading activities are shared
with retail customers. This sharing is recognized through credits to fuel
expense, thus reducing fuel expense.
The decrease in marketing purchases was driven by lower demand and
increased net generation. The increase in other operation expense is
attributable to increased trading incentive compensation
expense, reduced AEP transmission equalization credits and expenses for a full
year of factoring accounts receivable. Under the AEP East Region Transmission
Agreement, KPCo and certain affiliates share the costs associated with the
ownership of their transmission system based upon each company's peak demand and
investment. An increase in KPCo's peak demand relative to its affiliates' peak
demand was the main reason for the decline in transmission equalization credits.
Factoring of accounts receivable began in June 2000. In 2001 we incurred a full
year of factoring expenses compared with a partial year in 2000.
Lower maintenance expense in 2001 is a result of performing significant
planned maintenance at the Big Sandy Plant in 2000 for which there was no
comparable activity in the current year.
Additions to property, plant and equipment accounted for the increase in
depreciation expense. These additions included capitalized software and general
distribution equipment upgrades and improvements.
Taxes other than income taxes rose as a result of increases in real and
personal property tax accruals reflecting higher taxable property values.
The decrease in income tax expense was primarily due to a decrease in
pre-tax book income and the effect of an unfavorable ruling in 2000 in AEP's
suit against the government over interest deductions claimed in prior years
related to AEP's COLI program.
Nonoperating Income and Nonoperating Expenses Increase
The increase in nonoperating income in 2001 is primarily due to
increased net gains on forward electricity trading transactions outside AEP's
traditional marketing area. Net gains on power trading outside our traditional
marketing area increased in 2001 reflecting favorable market conditions and
increased trading activity.
Nonoperating expenses increased in 2001 due to trading overheads and
traders' compensation.
The decrease in nonoperating income taxes in 2001 reflects the decrease
in nonoperating pre-tax income.
Interest Charges Decrease
The decline in interest expense was due to the effect of recognizing
in 2000 previously deferred interest payments to the IRS related to the COLI
disallowances and interest on resultant state income tax deficiencies.
KENTUCKY POWER COMPANY
Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $205,476 $226,708 $185,342
Energy Delivery 131,183 121,346 129,113
Sales to AEP Affiliates 42,366 41,821 44,302
------ ------ ------
TOTAL REVENUES 379,025 389,875 358,757
------- ------- -------
OPERATING EXPENSES:
Fuel 70,635 74,638 84,369
Purchased Power:
Electricity Marketing 86 1,940 8,951
AEP Affiliates 130,204 127,707 84,000
Other Operation 58,275 52,495 52,055
Maintenance 22,444 25,866 21,452
Depreciation and Amortization 32,491 31,028 29,221
Taxes Other Than Income Taxes 7,854 7,251 8,091
Income Taxes 9,358 19,212 15,943
----- ------ ------
TOTAL OPERATING EXPENSES 331,347 340,137 304,082
------- ------- -------
OPERATING INCOME 47,678 49,738 54,675
NONOPERATING INCOME 10,881 6,139 1,144
NONOPERATING EXPENSES 8,949 2,940 1,637
NONOPERATING INCOME TAX EXPENSE (CREDIT) 684 1,129 (166)
INTEREST CHARGES 27,361 31,045 28,918
------ ------ ------
NET INCOME $ 21,565 $ 20,763 $ 25,430
======== ======== ========
Statements of Comprehensive Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
NET INCOME $21,565 $20,763 $25,430
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (1,903) - -
------ ---- ----
COMPREHENSIVE INCOME $19,662 $20,763 $25,430
======= ======= =======
Statements of Retained Earnings
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
RETAINED EARNINGS JANUARY 1 $57,513 $67,110 $71,452
NET INCOME 21,565 20,763 25,430
CASH DIVIDENDS DECLARED 30,245 30,360 29,772
------ ------ ------
RETAINED EARNINGS DECEMBER 31 $48,833 $57,513 $67,110
======= ======= =======
See Notes to Financial Statements Beginning on Page L-1.
KENTUCKY POWER COMPANY
Balance Sheets
December 31,
2001 2000
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $271,070 $271,107
Transmission 374,116 360,563
Distribution 402,537 387,499
General 65,059 67,476
Construction Work in Progress 15,633 16,419
------ ------
Total Electric Utility Plant 1,128,415 1,103,064
Accumulated Depreciation and Amortization 384,104 360,648
------- -------
NET ELECTRIC UTILITY PLANT 744,311 742,416
------- --- -------
OTHER PROPERTY AND INVESTMENTS 6,492 6,559
----- ----- -----
LONG-TERM ENERGY TRADING CONTRACTS 77,972 76,503
------ ---- ------
CURRENT ASSETS:
Cash and Cash Equivalents 1,947 2,270
Accounts Receivable:
Customers 20,036 34,555
Affiliated Companies 16,012 22,119
Miscellaneous 3,333 6,419
Allowance for Uncollectible Accounts (264) (282)
Fuel - at average cost 12,060 4,760
Materials and Supplies - at average cost 15,766 15,408
Accrued Utility Revenues 5,395 6,500
Energy Trading Contracts 139,605 480,739
Prepayments 1,314 766
---------- ------- ---
TOTAL CURRENT ASSETS 215,204 573,254
------- --- -------
REGULATORY ASSETS 97,692 98,515
------ ---- ------
DEFERRED CHARGES 11 572 11,817
------ ---- ------
TOTAL $1,153,243 $1,509,064
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
December 31,
2001 2000
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $50:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $ 50,450
Paid-in Capital 158,750 158,750
Accumulated Other Comprehensive Income (Loss) (1,903) -
Retained Earnings 48,833 57,513
---- ------ ---- ------
Total Common Shareholder's Equity 256,130 266,713
Long-term Debt 251,093 270,880
---------- --- -------
TOTAL CAPITALIZATION 507,223 537,593
--- ------- --- -------
OTHER NONCURRENT LIABILITIES 11,929 18,348
---- ------ ---- ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 95,000 60,000
Advances from Affiliates 66,200 47,636
Accounts Payable - General 24,050 32,043
Accounts Payable - Affiliated Companies 22,557 37,506
Customer Deposits 4,461 4,389
Taxes Accrued 10,305 11,885
Interest Accrued 5,269 5,610
Energy Trading and Derivative Contracts 144,364 494,086
Other 12,296 14,517
---- ------ ---- ------
Total CURRENT LIABILITIES 384,502 707,672
--- ------- --- -------
DEFERRED INCOME TAXES 168,304 165,935
--- ------- --- -------
DEFERRED INVESTMENT TAX CREDITS 10,405 11,656
---- ------ ---- ------
LONG-TERM ENERGY TRADING CONTRACTS 63,412 61,478
---- ------ ---- ------
DEFERRED CREDITS 7,468 6,382
----- ----- ----- -----
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $1,153,243 $1,509,064
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 21,565 $20,763 $25,430
Adjustments for Noncash Items:
Depreciation and Amortization 32,491 31,034 29,228
Deferred Income Taxes 6,293 3,765 2,596
Deferred Investment Tax Credits (1,251) (1,252) (1,292)
Deferred Fuel Costs (net) (4,707) 2,948 828
Mark-to-Market of Energy Trading Contracts (1,454) (4,376) (863)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) 23,694 (20,930) (6,618)
Fuel, Materials and Supplies (7,658) 8,386 (7,014)
Accrued Utility Revenues 1,105 7,237 (177)
Accounts Payable (22,942) 39,883 4,935
Taxes Accrued (1,580) 2,025 2,604
Disputed Tax and Interest Related to COLI - 5,943 (567)
Change in Other Assets (2,762) 62,653 11,547
Change in Other Liabilities (9,446) (62,702) (13,837)
------ -- ------- -- -------
Net Cash Flows From Operating Activities 33,348 95,377 46,800
------ --- ------ --- ------
INVESTING ACTIVITIES:
Construction Expenditures (37,206) (36,209) (44,339)
Proceeds From Sales of Property 216 266 168
--- ------ --- ------ ---
Net Cash Flows Used For Investing
Activities (36,990) (35,943) (44,171)
------- -- ------- -- -------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company - - 10,000
Issuance of Long-term Debt 75,000 69,685 79,740
Retirement of Long-term Debt (60,000) (105,000) (83,307)
Change in Short-term Debt (net) - (39,665) 19,315
Change in Advances From Affiliates (net) 18,564 47,636 -
Dividends Paid (30,245) (30,360) (29,772)
------- -- ------- -- -------
Net Cash Flows From (Used For)
Financing Activities 3,319 (57,704) (4,024)
----- -- ------- --- ------
Net Increase (Decrease) in Cash and Cash Equivalents (323) 1,730 (1,395)
Cash and Cash Equivalents January 1 2,270 540 1,935
----- ------ --- ---- -----
Cash and Cash Equivalents December 31 $1,947 $ 2,270 $ 540
====== ======= =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $27,090,000, $28,619,000
and $29,845,000 and for income taxes was $7,549,000, $7,923,000 and $12,050,000
in 2001, 2000 and 1999, respectively. Noncash acquisitions under capital leases
were $817,000, $2,817,000 and $2,219,000 in 2001, 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $256,130 $266,713
-------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 59,383 119,341
Senior Unsecured Notes 147,625 147,490
Notes Payable 100,000 25,000
Junior Debentures 39,085 39,049
Less Portion Due Within One Year (95,000) (60,000)
------- - -------
Long-term Debt Excluding Portion Due Within One Year 251,093 270,880
------- - -------
TOTAL CAPITALIZATION $507,223 $537,593
======== ========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
8.95 2001 - May 10 $ - $ 20,000
8.90 2001 - May 21 - 40,000
6.65 2003 - May 1 15,000 15,000
6.70 2003 - June 1 15,000 15,000
6.70 2003 - July 1 15,000 15,000
7.90 2023 - June 1 14,500 14,500
Unamortized Discount (117) (159)
-------- --------
$ 59,383 $119,341
======== ========
First mortgage bonds are secured by first mortgage liens on electric utility
plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
- ------ ------------------
(a) 2002 - November 19 $ 70,000 $ 70,000
6.91 2007 - October 1 48,000 48,000
6.45 2008 - November 10 30,000 30,000
Unamortized Discount (375) (510)
-------- --------
147,625 147,490
Less Portion Due Within
One Year 70,000 -
-------- --------
Total $ 77,625 $147,490
======== ========
(a) A floating interest rate is determined monthly. The rate on December 31,
2001 was 4.3% and on December 31, 2000 was 7.4%.
Notes payable to parent company were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
4.336 2003 - May 15 $15,000 $ -
6.501 2006 - May 15 60,000 -
------- ------
$75,000 $ -
======= ======
Notes payable to banks outstandings were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
7.45 2002 - September 20 $25,000 $25,000
======= =======
Junior debentures outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
8.72 2025 - June 30 $40,000 $40,000
Unamortized Discount (915) (951)
------- -------
Total $39,085 $39,049
======= =======
Interest may be deferred and payment of principal and interest on the junior
debentures is subordinated and subject in right to the prior payment in full of
all senior indebtedness of the Company.
At December 31, 2001, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2002 $ 95,000
2003 60,000
2004 -
2005 -
2006 60,000
Later Years 132,500
--------
Total Principal Amount 347,500
Unamortized Discount 1,407
--------
Total $346,093
KENTUCKY POWER COMPANY
Index to Notes to Financial Statements
The notes to KPCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to KPCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Merger Note 3
Effects of Regulation Note 6
Commitments and Contingencies Note 8
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Related Party Transactions Note 20
Subsequent Events Note 21
INDEPENDENT AUDITORS' REPORT
To the Shareholder and Board of
Directors of Kentucky Power Company:
We have audited the accompanying balance sheets and statements of
capitalization of Kentucky Power Company as of December 31, 2001 and 2000, and
the related statements of income, comprehensive income, retained earnings, and
cash flows for each of the three years in the period ended December 31, 2001.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material
respects, the financial position of Kentucky Power Company as of December 31,
2001 and 2000, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2001 in conformity with
accounting principles generally accepted in the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
OHIO POWER COMPANY AND SUBSIDIARIES
OHIO POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $2,098,105 $2,140,331 $1,978,826 $2,105,547 $1,892,110
Operating Expenses 1,857,395 1,913,504 1,689,997 1,816,175 1,615,717
--------- - --------- - --------- - --------- - ---------
Operating Income 240,710 226,827 288,829 289,372 276,393
Nonoperating Income
(Loss) 18,686 (5,004) 7,000 588 14,822
Interest Charges 93,603 119,210 83,672 80,035 82,526
------ --- ------- ---- ------ ---- ------ ---- ------
Income Before
Extraordinary Item 165,793 102,613 212,157 209,925 208,689
Extraordinary Loss (18,348) (18,876) - - -
------- --- ------- ------ ---- ------ ---- ------ ----
Net Income 147,445 83,737 212,157 209,925 208,689
Preferred Stock
Dividend
Requirements 1,258 1,266 1,417 1,474 2,647
- ----- ----- ----- ----- ----- ----- ----- ----- -----
Earnings Applicable
To Common Stock $146,187 $ 82,471 $210,740 $208,451 $206,042
======== ======== ======== ======== ========
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility
Plant $5,390,576 $5,577,631 $5,400,917 $5,257,841 $5,155,797
Accumulated
Depreciation 2,452,571 2,764,130 2,621,711 2,461,376 2,349,995
--------- - --------- - --------- - --------- - ---------
Net Electric Utility
Plant $2,938,005 $2,813,501 $2,779,206 $2,796,465 $2,805,802
========== ========== ========== ========== ==========
Total Assets $4,916,067 $6,242,557 $4,677,209 $4,344,680 $4,163,202
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $783,684 $783,684 $783,577 $783,536 $783,497
Accumulated Other
Comprehensive Income
(Loss) (196)
Retained Earnings 401,297 398,086 587,424 587,500 590,151
------- --- ------- --- ------- --- ------- --- -------
Total Common
Shareholder's Equity $1,184,785 $1,181,770 $1,371,001 $1,371,036 $1,373,648
========== ========== ========== ========== ==========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 16,648 $ 16,648 $ 16,937 $ 17,370 $ 17,542
Subject to Mandatory
Redemption (a) 8,850 8,850 8,850 11,850 11,850
----- ----- ----- ----- ----- ---- ------- ---- ------
Total Cumulative
Preferred Stock $ 25,498 $ 25,498 $ 25,787 $ 29,220 $ 29,392
======== ======== ======== ======== ========
Long-term Debt (a) $1,203,841 $1,195,493 $1,151,511 $1,084,928 $1,095,226
========== ========== ========== ========== ==========
Obligations Under
Capital Leases (a) $ 80,666 $116,581 $136,543 $142,635 $157,487
======== ======== ======== ======== ========
Total Capitalization
and Liabilities $4,916,067 $6,242,557 $4,677,209 $4,344,680 $4,163,202
========== ========== ========== ========== ==========
(a) Including portion due within one year.
OHIO POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
OPCo is a public utility engaged in the generation, purchase, sale, transmission
and distribution of electric power to 698,000 retail customers in northwestern,
east central, eastern and southern sections of Ohio. OPCo supplies electric
power to the AEP Power Pool and shares the revenues and costs of the AEP Power
Pool's wholesale sales to neighboring utility systems and power marketers
including power trading transactions. OPCo also sells wholesale power to
municipalities and cooperatives.
The cost of the AEP Power Pool's generating capacity is allocated among
Pool members based on their relative peak demands and generating reserves
through the payment of capacity charges or the receipt of capacity credits. AEP
Power Pool members are also compensated for their out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the AEP
Power Pool. The AEP Power Pool calculates each company's prior twelve month peak
demand relative to the total peak demand of all member companies as a basis for
sharing revenues and costs. The result of this calculation is the member load
ratio (MLR) which determines each company's percentage share of AEP Power Pool
revenues and costs.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to OPCo as a member
of the AEP Power Pool. Trading activities involve the purchase and sale of
energy under physical forward contracts at fixed and variable prices and buying
and selling financial energy contracts which includes exchange traded futures
and options and over-the-counter options and swaps. Although trading contracts
are generally short-term, there are also long-term trading contracts. We
recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts prior
to settlement is commonly referred to as mark-to-market (MTM) accounting. It
represents the change in the unrealized gain or loss throughout the contract's
term. When the contract actually settles, that is, the energy is actually
delivered in a sale or received in a purchase or the parties agree to forego
delivery and receipt of electricity and net settle in cash, the unrealized gain
or loss is reversed and the actual realized cash gain or loss is recognized.
Therefore, over the trading contract's term an unrealized gain or loss is
recognized as the contract's market value changes. When the contract settles the
total gain or loss is realized in cash but only the difference between the
accumulated unrealized net gains or losses recorded in prior months and the cash
proceeds is recognized. Unrealized mark-to-market gains and losses are included
in the Balance Sheet as energy trading contract assets or liabilities as
appropriate.
The majority of our trading activities represent physical forward
electricity contracts that are typically settled by entering into offsetting
contracts. An example of our trading activities is when, in January, we enter
into a forward sales contract to deliver electricity in July. At the end of each
month until the contract settles in July, we would record our share of any
difference between the contract price and the market price as an unrealized gain
or loss. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse the previously recorded unrealized gain or
loss.
Depending on whether the delivery point for the electricity is in
AEP's traditional marketing area or not determines where the contract is
reported on OPCo's income statement. AEP's tradititonal marketing area is up to
two transmission systems from the AEP service territory. Physical forward
trading sale and purchase contracts with delivery points in AEP's traditional
marketing area are included in revenues when the contracts settle. Prior to
settlement, changes in the fair value of physical forward sale and purchase
contracts in AEP's traditional marketing area are included in revenues on a net
basis. Physical forward sale and purchase contracts for delivery outside of
AEP's traditional marketing area are included in nonoperating income when the
contract settles. Prior to settlement, changes in the fair value of physical
forward sale and purchase contracts with delivery points outside of AEP's
traditional marketing area are included in nonoperating income on a net basis.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
results of operations from recording additional changes in fair values using
mark-to-market accounting.
Trading of electricity options, futures and swaps, represents financial
transactions with unrealized gains and losses from changes in fair values
reported net in nonoperating income until the contracts settle. When these
financial contracts settle, we record our share of the net proceeds in
nonoperating income and reverse to nonoperating income the prior unrealized gain
or loss.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing OPCo to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Results of Operations
Income before extraordinary item increased $63 million or 62% in 2001
primarily due to the effect of a court decision related to a corporate owned
life insurance (COLI) program recorded in 2000. In February 2001 the U.S.
District Court for the Southern District of Ohio ruled against AEP and certain
of its subsidiaries, including OPCo, in a suit over deductibility of interest
claimed in AEP's consolidated tax returns related to COLI. In 1998 and 1999 OPCo
paid the disputed taxes and interest attributable to the COLI interest
deductions for taxable years 1991-98. The payments were included in Other
Property and Investments pending the resolution of this matter. Net income was
also favorably impacted by the growth in and strong performance by the wholesale
business. The favorable effects of the COLI decision and wholesale business were
offset in part by the commencement of the amortization of transition regulatory
assets in 2001, the effect of mild winter weather and the recent economic
downturn.
Income before extraordinary item decreased $110 million or 52% in 2000
due predominantly to the unfavorable COLI decision.
Operating Revenues
Operating revenues decreased 2% in 2001 due to decreased sales to the AEP
Power Pool and increased 8% in 2000 because of the significant increase in
wholesale marketing and trading volume. The changes in the components of
revenues were as follows:
Increase (Decrease)
From Previous Year
(Dollars in Millions)
2001 2000
-----------------------------
Amount % Amount %
Retail* $ (66.0) (8) $(135.7) (15)
Wholesale
Marketing and
Trading (18.5) (8) 104.3 84
Unrealized MTM 32.6 N.M. (10.3) N.M.
Other (4.3) (5) 2.8 4
-------- -------
Total
Marketing and
Trading (56.2) (5) (38.9) (3)
Energy
Delivery* 85.1 18 7.4 2
Sale to AEP
Affiliates (71.1)(12) 193.0 50
-------- -------
Total $ (42.2) (2) $ 161.5 8
======== =======
* Reflects for 2000 the allocation of certain transmission and distribution
revenues included in bundled retail rates to energy delivery.
The decrease in operating revenues in 2001 decreased resulted from
decrease in sales to the AEP Power Pool due to AEP System plant availability.
Sales to AEP affiliates decreased in 2001 because an affiliate was able
to supply more power to the Power Pool from two nuclear units that returned to
service in June and December 2000.
The decrease in 2000 retail revenues was a result of one of OPCo's major
industrial customers deciding not to continue its power purchase agreement. OPCo
was able to deliver additional power to the power pool in 2000. This accounted
for the increase in sales to AEP affiliates in 2000. The maturing of the
Intercontinental Exchange, the development of proprietory tools, and increased
staffing of energy traders has resulted in an increase in the number of forward
electricity purchase and sale contracts in AEP's traditional marketing area
caused Wholesale Marketing and Trading to increase in 2000.
Operating Expenses
Operating expenses decreased by 3% in 2001 mostly due to amortization of
transition regulatory assets partly offset by decreases in fuel expense and
income taxes. Operating expenses increased by 13% in 2000 mostly due to
increases in fuel expense, other operation expense and income taxes.
Changes in the components of operating expenses were as follows:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
---- ----
Amount % Amount %
Fuel $ (85) (11) $ 84 12
Marketing
Purchases 15 30 (35) (42)
AEP Affiliate
Purchases 12 23 30 143
Other Operation (4) (1) 79 24
Maintenance 18 15 4 3
Depreciation
and Amortization 84 54 7 5
Taxes Other Than
Income Taxes (10) (6) 5 3
Income Taxes (86) (46) 50 36
------ ----
Total Operating
Expenses $ (56) (3) $224 13
====== ====
Fuel expense decreased 11% in 2001 mainly due to a 9% decrease in net
generation because of decreased sales to the AEP Power Pool caused by an
affiliate's two nuclear units returning to service. Fuel expense increased in
2000 due to increases in generation and the average cost of fuel consumed
reflecting shutdown costs included in the cost of coal delivered from affiliated
mining operations.
Marketing purchases expense increased in 2001 and decreased in 2000. The
changes were due to increases/decreases in MWH purchases from third parties for
resale to wholesale customers and to meet internal demand.
Other operation expense increased in 2000 mainly due to increased power
generation costs. Increased emission allowance consumption and allowance prices
and increased costs of AEP's growing power marketing and trading operation,
including trader incentive compensation, accounted for the increase in power
generation costs. The increase in emission allowance usage and prices resulted
from the stricter air quality standards of Phase II of the 1990 Clean Air Act
Amendments which became effective on January 1, 2000.
Maintenance expense increased in 2001 mainly due to boiler repairs at
Amos, Cardinal, Kammer, Mitchell, Muskingum and Sporn plants, and boiler
inspections at the Amos and Cardinal plants.
The commencement of amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
retail electricity supply under Ohio deregulation accounted for the significant
increase in depreciation and amortization expense in 2001.
The decrease in taxes other than income taxes in 2001 was due to a
decrease in property tax expense reflecting a reduction in rates on generation
property under the Ohio Restructuring law partially offset by a new state excise
tax.
Income taxes decreased in 2001 due to an unfavorable ruling in AEP's suit
against the government over interest deductions claimed relating to AEP's COLI
program, which was recorded in 2000 and a decrease in pre-tax book income. The
increase in income tax expense in 2000 was primarily due to the unfavorable
ruling relating to AEP's COLI program.
Nonoperating Income and Nonoperating Expense
The increases in nonoperating income in 2001 and 2000 were due to an
increase in trading transactions outside of the AEP System's traditional
marketing area. Increases in nonoperating expenses in 2001 and 2000 were due to
increased trading overheads and compensation.
Interest Charges
The major reason for the decrease in interest expense in 2001 was the
recognition in 2000 of deferred interest payments to the IRS related to COLI
disallowances. The increase in interest expense in 2000 was due to the
recognition of deferred interest payments related to the COLI disallowance.
Extraordinary Loss
In the second quarter of 2001 an extraordinary loss of $18 million net of
tax was recorded to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation. In 2000 the application of regulatory accounting for generation
under SFAS 71 was discontinued which resulted in an after tax extraordinary loss
of $19 million.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
--- -----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $1,034,026 $1,090,297 $1,129,152
Energy Delivery 552,713 467,587 460,182
Sales to AEP Affiliates 511,366 582,447 389,492
------- --- ------- --- -------
TOTAL OPERATING REVENUES 2,098,105 2,140,331 1,978,826
--------- - --------- - ---------
OPERATING EXPENSES:
Fuel 686,568 771,969 687,672
Purchased Power:
Electricity Marketing 63,441 48,657 83,479
AEP Affiliates 62,585 50,741 20,864
Other Operation 400,790 404,410 325,495
Maintenance 142,878 124,735 121,299
Depreciation and Amortization 239,982 155,944 149,055
Taxes Other Than Income Taxes 159,778 169,527 164,213
Income Taxes 101,373 187,521 137,920
------- --- ------- --- -------
TOTAL OPERATING EXPENSES 1,857,395 1,913,504 1,689,997
--------- - --------- - ---------
OPERATING INCOME 240,710 226,827 288,829
NONOPERATING INCOME 53,378 37,454 14,316
NONOPERATING EXPENSES 37,072 24,300 12,744
NONOPERATING INCOME TAX EXPENSE (CREDIT) (2,380) 18,158 (5,428)
INTEREST CHARGES 93,603 119,210 83,672
------ --- ------- ---- ------
INCOME BEFORE EXTRAORDINARY ITEM 165,793 102,613 212,157
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION -
Net of tax (See Note 2) (18,348) (18,876) -
------- --- ------- ------ ----
NET INCOME 147,445 83,737 212,157
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,258 1,266 1,417
----- ----- ----- ----- -----
EARNINGS APPLICABLE TO COMMON STOCK $146,187 $ 82,471 $210,740
======== ======== ========
Consolidated Statements of Comprehensive Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
NET INCOME $147,445 $83,737 $212,157
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (196) - -
---- ---- ----
COMPREHENSIVE INCOME $147,249 $83,737 $212,157
======== ======= ========
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
December 31,
2001 2000
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $3,007,866 $2,764,155
Transmission 891,283 870,033
Distribution 1,081,122 1,040,940
General (including mining assets at December 31, 2000) 245,232 707,417
Construction Work in Progress 165,073 195,086
--- ------- --- -------
Total Electric Utility Plant 5,390,576 5,577,631
Accumulated Depreciation and Amortization 2,452,571 2,764,130
- --------- - ---------
NET ELECTRIC UTILITY PLANT 2,938,005 2,813,501
- --------- - ---------
OTHER PROPERTY AND INVESTMENTS 62,303 109,124
---- ------ --- -------
LONG-TERM ENERGY TRADING CONTRACTS 263,734 255,938
--- ------- --- -------
CURRENT ASSETS:
Cash and Cash Equivalents 8,848 31,393
Advances to Affiliates - 92,486
Accounts Receivable:
Customers 84,694 139,732
Affiliated Companies 148,563 126,203
Miscellaneous 20,409 39,046
Allowance for Uncollectible Accounts (1,379) (1,054)
Fuel - at average cost 84,724 82,291
Materials and Supplies - at average cost 88,768 96,053
Accrued Utility Revenues - 264
Energy Trading Contracts 472,246 1,608,298
Prepayments and Other 20,865 32,882
---- ------ ---- ------
TOTAL CURRENT ASSETS 927,738 2,247,594
--- ------- - ---------
REGULATORY ASSETS 644,625 714,710
--- ------- --- -------
DEFERRED CHARGES 79,662 101,690
---- ------ --- -------
TOTAL $4,916,067 $6,242,557
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
December 31,
2001 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) (196) -
Retained Earnings 401,297 398,086
--- ------- --- -------
Total Common Shareholder's Equity 1,184,785 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 1,203,841 1,077,987
- --------- - ---------
TOTAL CAPITALIZATION 2,414,124 2,285,255
- --------- - ---------
OTHER NONCURRENT LIABILITIES 130,386 542,017
--- ------- --- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 117,506
Advances From Affiliates 300,213 -
Accounts Payable - General 134,418 179,691
Accounts Payable - Affiliated Companies 176,520 121,360
Customer Deposits 5,452 39,736
Taxes Accrued 126,770 223,101
Interest Accrued 17,679 20,458
Obligations Under Capital Leases 16,405 32,716
Energy Trading Contracts 456,047 1,652,953
Other 87,070 151,934
---- ------ --- -------
Total CURRENT LIABILITIES 1,320,574 2,539,455
- --------- - ---------
DEFERRED INCOME TAXES 797,889 621,941
--- ------- --- -------
DEFERRED INVESTMENT TAX CREDITS 21,925 25,214
---- ------ ---- ------
LONG-TERM ENERGY TRADING CONTRACTS 214,487 205,670
--- ------- --- -------
DEFERRED CREDITS 16,682 23,005
---- ------ ---- ------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $4,916,067 $6,242,557
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
----- -----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 147,445 $83,737 $ 212,157
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization 252,123 200,350 193,780
Deferred Income Taxes 215,833 (65,956) 3,666
Deferred Investment Tax Credits (3,289) (3,399) (3,458)
Deferred Fuel Costs (net) - (56,869) (76,978)
Extraordinary Loss 18,348 18,876 -
Mark to Market of Energy Trading Contracts (59,833) (5,614) (4,234)
Change in Certain Current Assets and Liabilities:
Accounts Receivable (net) 51,640 51,430 (49,309)
Fuel, Materials and Supplies 4,852 46,645 (60,500)
Accrued Utility Revenues 264 45,311 (2,074)
Accounts Payable 9,887 56,069 9,195
Disputed Tax and Interest Related to COLI - 110,494 (6,272)
Accumulated Provisions - Noncurrent (392,026) 145,573 66,573
Taxes Accrued (96,331) 60,919 (776)
Customer Deposits (34,284) 31,540 (3,763)
Change in Other Assets 79,831 (439,448) (67,515)
Change in Other Liabilities (107,704) 359,640 127,288
-------- ------- -------
Net Cash Flows From Operating Activities 86,756 639,298 337,780
------ ------- -------
INVESTING ACTIVITIES:
Construction Expenditures (344,571) (254,016) (193,870)
Proceeds From Sales of Property and Other 16,778 6,354 5,900
Investment in Coal Companies (32,115) - -
------- ---- ----
Net Cash Flows Used For
Investing Activities (359,908) (247,662) (187,970)
-------- -------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 300,000 74,748 222,308
Change in Advances From Affiliates (net) 392,699 (92,486) -
Retirement of Cumulative Preferred Stock - (182) (3,392)
Retirement of Long-term Debt (297,858) (30,663) (158,638)
Change in Short-term Debt (net) - (194,918) 71,913
Dividends Paid on Common Stock (142,976) (271,813) (210,813)
Dividends Paid on Cumulative Preferred Stock (1,258) (1,262) (1,420)
------ ------ ------
Net Cash Flows Used For
Financing Activities 250,607 (516,576) (80,042)
------- -------- -------
Net Increase (Decrease) in Cash and Cash Equivalents (22,545) (124,940) 69,768
Cash and Cash Equivalents January 1 31,393 156,333 86,565
------ ------- ------
Cash and Cash Equivalents December 31 $ 8,848 $31,393 $ 156,333
======= ======= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $94,747,000,
$87,120,000 and $78,739,000 and for income taxes was $(22,417,000), $142,710,000
and $94,606,000 in 2001, 2000 and 1999, respectively. Noncash acquisitions under
capital leases were $2,380,000, $17,005,000 and $28,561,000 in 2001, 2000 and
1999, respectively.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Retained Earnings
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
Retained Earnings January 1 $398,086 $587,424 $587,500
Net Income 147,445 83,737 212,157
------- ------ -------
545,531 671,161 799,657
------- ------- -------
Deductions:
Cash Dividends Declared:
Common Stock 142,976 271,813 210,813
Cumulative Preferred Stock:
4.08% Series 58 59 61
4.20% Series 96 96 97
4.40% Series 139 139 142
4-1/2% Series 439 442 460
5.90% Series 428 428 472
6.02% Series 66 66 156
6.35% Series 32 32 32
-- -- --
Total Dividends 144,234 273,075 212,233
------- ------- -------
Retained Earnings December 31 $401,297 $398,086 $587,424
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $1,184,785 $1,181,770
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 3,762,403
$25 par value - authorized shares 4,000,000
Call Price Shares
December 31, Par Number of Shares Redeemed Outstanding
Series(a) 2001 Value Year Ended December 31, December 31, 2001
- ------ ------------ ----- --------------------------- -----------------
2001 2000 1999
---- ---- ----
Not Subject to Mandatory Redemption:
4.08% $103 $100 - - 373 14,595 1,460 1,460
4.20% 103.20 100 - 276 - 22,824 2,282 2,282
4.40% 104 100 - 432 330 31,512 3,151 3,151
4-1/2% 110 100 - 2,181 3,631 97,546 9,755 9,755
------ ------
16,648 16,648
------ ------
Subject to Mandatory Redemption:
5.90% (b) - $100 - - 10,000 72,500 7,250 7,250
6.02% (c) - 100 - - 20,000 11,000 1,100 1,100
6.35% (c) - 100 - - - 5,000 500 500
------ ------
8,850 8,850
------ ------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 141,544 316,294
Installment Purchase Contracts 233,235 233,130
Senior Unsecured Notes 396,962 471,583
Notes Payable to Affiliated Company 300,000 -
Notes Payable - 30,000
Junior Debentures 132,100 131,980
Other Long-term Debt - 12,506
Less Portion Due Within One Year - (117,506)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 1,203,841 1,077,987
---------- ----------
TOTAL CAPITALIZATION $2,414,124 $2,285,255
========== ==========
(a) The series subject to mandatory redemption are not callable until after
2002. The sinking fund provisions of each series subject to mandatory
redemption have been met by purchase of shares in advance of the due date.
(b) Commencing in 2004 and continuing through the year 2008, a sinking fund for
the 5.90% cumulative preferred stock will require the redemption of 22,500
shares each year and the redemption of the remaining shares outstanding on
January 1, 2009, in each case at $100 per share. Shares previously redeemed
may be applied to meet sinking fund requirements.
(c) Commencing in 2003 and continuing through 2007 cumulative preferred stock
sinking funds will require the redemption of 20,000 shares each year of the
6.02% series and 15,000 shares each year of the 6.35% series, in each case
at $100 per share. All remaining outstanding shares must be redeemed in
2008. Shares previously redeemed may be applied to meet the sinking fund
requirements.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
6.75 2003 - April 1 $ 29,850 $ 38,850
6.55 2003 - October 1 27,315 32,135
6.00 2003 - November 1 12,500 25,000
6.15 2003 - December 1 20,000 50,000
8.80 2022 - February 10 5,000 50,000
7.75 2023 - April 1 5,000 40,000
7.375 2023 - October 1 20,250 40,000
7.10 2023 - November 1 12,000 20,000
7.30 2024 - April 1 10,000 21,500
Unamortized Discount (371) (1,191)
-------- --------
Total $141,544 $316,294
======== ========
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
Mason County, West
Virginia:
5.45% 2016 - December 1 $ 50,000 $ 50,000
Marshall County, West
Virginia:
5.45% 2014 - July 1 50,000 50,000
5.90% 2022 - April 1 35,000 35,000
6.85% 2022 - June 1 50,000 50,000
Ohio Air Quality
Development
5.15% 2026 - May 1 50,000 50,000
Unamortized Discount (1,765) (1,870)
Total $233,235 $233,130
======== ========
Under the terms of the installment purchase contracts, OPCo is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
- ------ ------------------
(a) 2001 - May 16 $ - $ 75,000
6.75 2004 - July 1 100,000 100,000
7.00 2004 - July 1 75,000 75,000
6.73 2004 - November 1 48,000 48,000
6.24 2008 - December 4 37,225 37,225
7-3/8 2038 - June 30 140,000 140,000
Unamortized Discount (3,263) (3,642)
-------- --------
Total $396,962 $471,583
======== ========
(a) Redeemed on 5/16/01.
Notes payable to parent company were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
4.336% 2003 - May 15 $ 60,000 $ -
6.501% 2006 - May 15 240,000 -
-------- ------
Total $300,000 $ -
======== ======
Notes payable outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
6.20 2001 - January 31 $ - $ 5,000
6.20 2001 - January 31 - 7,000
6.20 2001 - January 31 - 18,000
------- -------
Total $ - $30,000
======= =======
Junior debentures outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
8.16 2025 - September 30 $ 85,000 $ 85,000
7.92 2027 - March 31 50,000 50,000
Unamortized Discount (2,900) (3,020)
Total $132,100 $131,980
======== ========
Interest may be deferred and payment of principal and interest on the
junior debentures is subordinated and subject in right to the prior payment in
full of all senior indebtedness of the Company.
Finance obligations were entered into by the Company's coal mining
subsidiaries for mining facilities and equipment through sale and leaseback
transactions. In accordance with SFAS 98, the transactions did not qualify as
sales and leasebacks for accounting purposes and therefore are shown as other
long-term debt. The remaining long-term debt obligation was paid off in the
first quarter of 2001.
At December 31, 2001, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2002 $ -
2003 149,665
2004 223,000
2005 -
2006 240,000
Later Years 599,475
----------
Total Principal Amount 1,212,140
Unamortized Discount 8,299
----------
Total $1,203,841
OHIO POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes to OPCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to OPCo. The combined footnotes begin on page
L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Acquisitions and Dispositions Note 9
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments
and Derivatives Note 12
Income Taxes Note 13
Supplementary Information Note 14
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Related Party Transactions Note 20
Subsequent Events Note 21
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Ohio Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Ohio Power Company and its
subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, comprehensive income, retained earnings, and cash flows
for each of the three years in the period ended December 31, 2001. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Ohio Power Company and its
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001 in conformity with accounting principles generally accepted in
the United States of America.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
PUBLIC SERVICE COMPANY OF OKLAHOMA
AND SUBSIDIARIES
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $957,000 $956,398 $749,390 $780,159 $712,690
Operating Expenses 860,012 859,729 650,677 665,085 630,666
------- ------- ------- ------- -------
Operating Income 96,988 96,669 98,713 115,074 82,024
Nonoperating Income (Loss) 20 8,974 946 (91) 1,649
Interest Charges 39,249 38,980 38,151 38,074 37,218
------ ------ ------ ------ ------
Net Income 57,759 66,663 61,508 76,909 46,455
Preferred Stock Dividend
Requirements 213 212 212 213 364
Gain On Reacquired
Preferred Stock - - - - 4,211
---- ---- ---- ---- -----
Earnings Applicable to
Common Stock $ 57,546 $ 66,451 $ 61,296 $ 76,696 $ 50,302
======== ======== ======== ======== ========
December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $2,695,099 $2,604,670 $2,459,705 $2,391,722 $2,339,908
Accumulated Depreciation
and Amortization 1,184,443 1,150,253 1,114,255 1,082,081 1,031,322
--------- --------- --------- --------- ---------
Net Electric Utility Plant $1,510,656 $1,454,417 $1,345,450 $1,309,641 $1,308,586
========== ========== ========== ========== ==========
Total Assets $1,917,897 $2,138,333 $1,524,726 $1,470,939 $1,464,562
========== ========== ========== ========== ==========
Common Stock and Paid-in
Capital $337,230 $337,230 $337,230 $337,230 $337,230
Retained Earnings 142,994 137,688 139,237 142,941 135,245
------- ------- ------- ------- -------
Total Common Shareholder's
Equity $480,224 $474,918 $476,467 $480,171 $472,475
======== ======== ======== ======== ========
Cumulative Preferred Stock:
Not Subject to Mandatory
Redemption $ 5,283 $ 5,283 $ 5,286 $ 5,287 $ 5,287
======= ======= ======= ======= =======
Preferred Securities of
Subsidiary Trust $ 75,000 $ 75,000 $ 75,000 $ 75,000 $ 75,000
======== ======== ======== ======== ========
Long-term Debt (a) $451,129 $470,822 $384,516 $384,064 $438,703
======== ======== ======== ======== ========
Total Capitalization and
Liabilities $1,917,897 $2,138,333 $1,524,726 $1,470,939 $1,464,562
========== ========== ========== ========== ==========
(a) Including portion due within one year.
PUBLIC SERVICE COMPANY OF OKLAHOMA
Management's Narrative Analysis of Results of Operations
PSO is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 502,000 retail
customers in eastern and southwestern Oklahoma. PSO also sells electric power at
wholesale to other utilities, municipalities and rural electric cooperatives.
Wholesale power marketing and trading activities are conducted on PSO's
behalf by AEP. PSO, along with the other AEP electric operating subsidiaries,
shares in the revenues and costs of AEP's wholesale sales to and forward trades
with other utility systems and power marketers.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a cost-based rate-regulated electric public utility
company, PSO's consolidated financial statements reflect the actions of
regulators that can result in the recognition of revenues and expenses in
different time periods than enterprises that are not rate regulated. In
accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to PSO. Trading
activities allocated to PSO involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
Accounting standards applicable to trading activities require that changes in
the fair value of trading contracts be recognized in revenues prior to
settlement and is commonly referred to as mark-to-market (MTM) accounting. Since
PSO is a cost-based rate-regulated entity,whose revenues are based on settled
transaction, unrealized changes in the fair value of physical forward sale and
purchase contracts are deferred as regulatory liabilities (gains) or regulatory
assets (losses).
Mark-to-market accounting represents the change in the unrealized gain or loss
throughout the contract's term. When the contract actually settles, that is, the
energy is actually delivered in a sale or received in a purchase or the parties
agree to forego delivery and receipt and net settle in cash, the unrealized gain
or loss is reversed and the actual realized cash gain or loss is recognized in
the income statement. Therefore, as the contract's market value changes over the
contract's term an unrealized gain or loss is deferred as a regulatory liability
or a regulatory asset. When the contract settles the total gain or loss is
realized in cash and recognized in the income statement. Physical forward
trading sale and purchase contracts are included in revenues when the contracts
settle. Prior to settlement, changes in the fair value of physical forward sale
and purchase contracts are deferred as regulatory liabilities (gains) or
regulatory assets (losses). Unrealized mark-to-market gains and losses are
included in the Balance Sheet as energy trading contract assets or liabilities
as appropriate.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing PSO to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Results of Operations
Net income decreased $8.9 million or 13.4% in 2001 due primarily due to
the effect of a gain on the sale of a minority interest in Scientech, Inc.
recorded in year 2000.
Operating Revenues
Revenues increased as a result of favorable fuel-related revenues
associated with the Oklahoma fuel clause recovery mechanism.
Increase (Decrease)
From Previous Year
Amount %
(dollars in millions)
Retail* $ 49.1 8
Wholesale Marketing
and Trading (95.3) (130)
Other 7.9 41
------
Total Marketing and
Trading (38.3) (5)
Energy Delivery* 16.8 7
Sales to AEP Affiliates 22.1 151
------
Total Revenues $ 0.6 -
======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Revenues from retail customers increased primarily as a result of an
increase in fuel-related revenues. Rising prices for natural gas used for
generation and higher purchased power prices accounted for the increase in
fuel-related revenues. The Oklahoma fuel clause recovery mechanism provides for
the accrual of fuel-related revenues until reviewed and approved for billing to
customers by the Oklahoma Corporation Commission. The accrual of additional fuel
and purchased power revenues is offset by increases in fuel and purchased power
expenses. As a result, accrued fuel-related revenues do not impact results of
operations.
The decrease in wholesale marketing and trading revenues is
attributable to unfavorable wholesale marketing and trading conditions.
Operating Expenses Increase
Operating expenses were $0.3 million more in 2001 than in 2000 largely
as a result of increased fuel expenses. Changes in the components of operating
expenses were as follows:
Increase (Decrease)
From Previous Year
Amount %
(dollars in millions)
Fuel $ 58.5 15
Marketing Purchases (63.9) (73)
Affiliated Purchases (17.0) (28)
Other Operation 16.0 13
Maintenance 0.3 N.M.
Depreciation and Amortization 3.8 5
Taxes Other Than
Income Taxes (1.2) (4)
Income Taxes 3.8 12
------
Total $ 0.3 -
------
N.M. = Not Meaningful
Fuel expense increased primarily from the recovery of fuel cost due to
regulated recovery mechanisms offset in part by a 4% decrease in generation.
The decrease in purchased power expense was primarily attributable to
reduced prices caused by decreased electricity demand.
Other operation expenses increased due mainly to a true-up adjustment in
2000 under a FERC-approved Transmission Coordination Agreement and a full year
of our share of incentive compensation for power trading.
Depreciation expense increased due to investment relating to repowering
Northeast Station Units 1 and 2.
The increase in income tax expense was primarily due to adjustments
associated with prior year tax returns offset in part by a decrease in pre-tax
book income.
Nonoperating Income
Nonoperating income decreased primarily from the effect of a gain
recorded in 2000 on the sale of PSO's minority interest in Scientech, Inc.
Scientech provides services, systems and instruments, which describe, regulate,
monitor and enhance the safety and reliability of power plant operations and
their environmental impact.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $658,352 $696,626 $479,346
Energy Delivery 261,877 245,124 256,327
Sales to AEP Affiliates 36,771 14,648 13,717
------ ------ ------
TOTAL OPERATING REVENUES 957,000 956,398 749,390
------- ------- -------
OPERATING EXPENSES:
Fuel 461,470 402,933 269,316
Purchased Power:
Electricity Marketing 24,187 88,088 40,274
AEP Affiliates 43,758 60,788 34,619
Other Operation 137,678 121,697 121,896
Maintenance 46,188 45,858 45,809
Depreciation and Amortization 80,245 76,418 74,736
Taxes Other Than Income Taxes 31,973 28,688 30,520
Income Taxes 34,513 35,259 33,507
------ ------ ------
TOTAL OPERATING EXPENSES 860,012 859,729 650,677
------- ------- -------
OPERATING INCOME 96,988 96,669 98,713
NONOPERATING INCOME 2,112 8,807 2,580
NONOPERATING EXPENSES 1,740 1,139 3,849
NONOPERATING INCOME TAX EXPENSE (CREDIT) 352 (1,306) (2,215)
INTEREST CHARGES 39,249 38,980 38,151
------ ------ ------
NET INCOME 57,759 66,663 61,508
PREFERRED STOCK DIVIDEND REQUIREMENTS 213 212 212
--- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 57,546 $ 66,451 $ 61,296
======== ======== ========
Consolidated Statements of Retained Earnings
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
BEGINNING OF PERIOD $137,688 $139,237 $142,941
NET INCOME 57,759 66,663 61,508
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 52,240 68,000 65,000
Preferred Stock 213 212 212
--- --- ---
BALANCE AT END OF PERIOD $142,994 $137,688 $139,237
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
2001 2000
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,034,711 $914,096
Transmission 427,110 396,695
Distribution 972,806 938,053
General 203,572 206,731
Construction Work in Progress 56,900 149,095
------ -------
Total Electric Utility Plant 2,695,099 2,604,670
Accumulated Depreciation and Amortization 1,184,443 1,150,253
--------- ---------
NET ELECTRIC UTILITY PLANT 1,510,656 1,454,417
--------- ---------
OTHER PROPERTY AND INVESTMENTS 41,020 38,211
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 55,215 52,275
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 5,795 11,301
Accounts Receivable:
Customers 31,144 60,424
Affiliated Companies 10,905 3,453
Allowance for Uncollectible Accounts (44) (467)
Fuel - at LIFO cost 21,559 28,113
Materials and Supplies - at average cost 36,785 29,642
Under-recovered Fuel Costs - 43,267
Energy Trading Contracts 162,200 378,911
Prepayments 2,368 1,559
----- -----
TOTAL CURRENT ASSETS 270,712 556,203
------- -------
REGULATORY ASSETS 35,004 29,338
------ ------
DEFERRED CHARGES 5,290 7,889
----- -----
TOTAL $1,917,897 $2,138,333
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
December 31,
2001 2000
---- ----
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued Shares: 10,482,000
Outstanding Shares: 9,013,000 $157,230 $157,230
Paid-in Capital 180,000 180,000
Retained Earnings 142,994 137,688
------- -------
Total Common Shareholder's Equity 480,224 474,918
------- -------
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 345,129 450,822
------- -------
TOTAL CAPITALIZATION 905,636 1,006,023
------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 106,000 20,000
Advances from Affiliates 123,087 81,120
Accounts Payable - General 72,759 104,379
Accounts Payable - Affiliated Companies 40,857 64,556
Customer Deposits 21,041 19,294
Over-Recovered Fuel 8,720 -
Taxes Accrued 18,150 1,659
Interest Accrued 7,298 8,336
Energy Trading Contracts 167,658 385,809
Other 12,296 12,137
------ ------
TOTAL CURRENT LIABILITIES 577,866 697,290
------- -------
DEFERRED INCOME TAXES 296,877 312,060
------- -------
DEFERRED INVESTMENT TAX CREDITS 33,992 35,783
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 56,203 35,292
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 47,323 51,885
------ ------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $1,917,897 $2,138,333
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $57,759 $66,663 $61,508
Adjustments for Noncash Items:
Depreciation and Amortization 80,245 76,418 74,736
Deferred Income Taxes (17,751) 25,453 14,521
Deferred Investment Tax Credits (1,791) (1,791) (1,791)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) 21,405 (28,826) (1,668)
Fuel, Materials and Supplies (589) 677 (8,985)
Other Property and Investments (2,809) 7,994 (2,108)
Accounts Payable (55,319) 89,330 (8,000)
Taxes Accrued 16,491 (16,821) (4,615)
Fuel Recovery 51,987 (36,798) (21,709)
Transmission Coordination Agreement Settlement - (15,063) 15,063
Changes in Other Assets (9,150) 4,452 10,227
Changes in Other Liabilities 9,381 (6,073) (15,736)
----- ------ -------
Net Cash Flows From Operating Activities 149,859 165,615 111,443
------- ------- -------
INVESTING ACTIVITIES:
Construction Expenditures (124,520) (176,851) (103,122)
Other Items (359) - (8,659)
---- ---- ------
Net Cash Flows Used For
Investing Activities (124,879) (176,851) (111,781)
-------- -------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 105,625 33,232
Retirement of Long-term Debt (20,000) (20,000) (33,700)
Change in Advances From Affiliates (net) 41,967 1,951 63,277
Dividends Paid on Common Stock (52,240) (68,000) (65,000)
Dividends Paid on Cumulative Preferred Stock (213) (212) (212)
---- ---- ----
Net Cash Flows (used For) From
Financing Activities (30,486) 19,364 (2,403)
------- ------ ------
Net Increase (Decrease) in Cash and Cash Equivalents (5,506) 8,128 (2,741)
Cash and Cash Equivalents January 1 11,301 3,173 5,914
------ ----- -----
Cash and Cash Equivalents December 31 $ 5,795 $11,301 $ 3,173
======= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $38,250,000, $33,732,000
and $37,081,000 and for income taxes was $38,653,000, $25,786,000 and
$23,871,000 in 2001, 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 480,224 $ 474,918
---------- ----------
PREFERRED STOCK: Cumulative $100 par value - authorized shares 700,000,
redeemable at the option of PSO upon 30 days notice.
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2001 Year Ended December 31, December 31, 2001
- ------ ------------ ---------------------------- -----------------
2001 2000 1999
---- ---- ----
Not Subject to Mandatory Redemption:
4.00% $105.75 - 25 9 44,606 4,460 4,460
4.24% 103.19 - - - 8,069 807 807
Premium 16 16
---------- ----------
5,283 5,283
---------- ----------
TRUST PREFERRED SECURITIES
PSO-obligated, mandatorily redeemable preferred securities of subsidiary trust
holding solely Junior Subordinated Debentures of PSO, 8.00%,
due April 30, 2037 75,000 75,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 297,772 317,465
Installment Purchase Contracts 47,357 47,357
Senior Unsecured Notes 106,000 106,000
Less Portion Due Within One Year (106,000) (20,000)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 345,129 450,822
---------- ----------
TOTAL CAPITALIZATION $ 905,636 $1,006,023
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
---- ----
(in thousands)
% Rate Due
5.91 2001 - March 1 $ - $6,000
6.02 2001 - March 1 - 5,000
6.02 2001 - March 1 - 9,000
6.25 2003 - April 1 35,000 35,000
7.25 2003 - July 1 65,000 65,000
7.38 2004 - December 1 50,000 50,000
6.50 2005 - June 1 50,000 50,000
7.38 2023 - April 1 100,000 100,000
Unamortized Discount (2,228) (2,535)
-- ------ -- ------
$297,772 $317,465
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2001 2000
---- ----
(in thousands)
% Rate Due
Oklahoma Environmental
Finance Authority (OEFA):
5.90 2007 - December 1 $ 1,000 $ 1,000
Oklahoma Development
Finance Authority (ODFA):
4.875 2014 - June 1 33,700 33,700
Red River Authority
of Texas:
6.00 2020 - June 1 12,660 12,660
Unamortized Discount (3) (3)
----- -----
Total $47,357 $47,357
======= =======
Under the terms of the installment purchase contracts, PSO is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
---- ----
(in thousands)
% Rate Due
(a) 2002 - November 21 $106,000 $106,000
======== ========
(a) A floating interest rate is determined monthly. The rate on December 31,
2001 and 2000 was 2.775% and 7.376%.
At December 31, 2001, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2002 $106,000
2003 100,000
2004 50,000
2005 50,000
2006 -
Later Years 147,360
-------
Total Principal Amount 453,360
Unamortized Discount (2,231)
------
Total $451,129
========
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes to PSO's financial statements are combined with the notes to financial
statements for AEP and its other subisidiary registrants. Listed below are the
combined notes that apply to PSO. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Trust Preferred Securities Note 18
Jointly Owned Electric Utility Plant Note 19
Related Party Transactions Note 20
Subsequent Events Note 21
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Public Service Company of Oklahoma:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Public Service Company of Oklahoma
and subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The consolidated financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the consolidated financial statements, were audited by other
auditors whose report, dated February 25, 2000, expressed an unqualified opinion
on those statements.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such 2001 and 2000 consolidated financial statements
present fairly, in all material respects, the financial position of Public
Service Company of Oklahoma and subsidiaries as of December 31, 2001 and 2000,
and the results of their operations and their cash flows for the years then
ended in conformity with accounting principles generally accepted in the United
States of America.
We also audited the adjustments described in Note 3 that were applied to
restate the 1999 consolidated financial statements to give retroactive effect to
the conforming change in the method of accounting for vacation pay accruals. In
our opinion, such adjustments are appropriate and have been properly applied.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
SOUTHWESTERN ELECTRIC POWER COMPANY
AND SUBSIDIARIES
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Selected Consolidated Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $1,101,326 $1,118,274 $971,527 $952,952 $939,869
Operating Expenses 955,119 989,996 824,465 802,274 800,396
------- ------- ------- ------- -------
Operating Income 146,207 128,278 147,062 150,678 139,473
Nonoperating Income
(Loss) 741 3,851 (1,965) 2,451 4,029
Interest Charges 57,581 59,457 58,892 55,135 50,536
------ ------ ------ ------ ------
Income Before
Extraordinary Item 89,367 72,672 86,205 97,994 92,966
Extraordinary Loss - - (3,011) - -
---- ---- ------ ---- ----
Net Income 89,367 72,672 83,194 97,994 92,966
Preferred Stock Dividend
Requirements 229 229 229 705 2,467
Gain (Loss) on
Reacquired Preferred
Stock - - - (856) 1,819
---- ---- ---- ---- -----
Earnings Applicable to
Common Stock $ 89,138 $ 72,443 $ 82,965 $ 96,433 $ 92,318
======== ======== ======== ======== ========
December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $3,460,764 $3,319,024 $3,231,431 $3,157,911 $3,081,443
Accumulated Depreciation
and Amortization 1,550,618 1,457,005 1,384,242 1,317,057 1,225,865
--------- --------- --------- --------- ---------
Net Electric Utility
Plant $1,910,146 $1,862,019 $1,847,189 $1,840,854 $1,855,578
========== ========== ========== ========== ==========
Total Assets $2,496,600 $2,657,956 $2,106,215 $2,081,454 $2,134,618
========== ========== ========== ========== ==========
Common Stock and
Paid-in Capital $380,660 $380,660 $380,660 $380,660 $380,660
Retained Earnings 308,915 293,989 283,546 296,581 320,148
------- ------- ------- ------- -------
Total Common
Shareholder's Equity $689,575 $674,649 $664,206 $677,241 $700,808
======== ======== ======== ======== ========
Preferred Stock $ 4,704 $ 4,704 $ 4,706 $ 4,707 $ 30,639
======= ======= ======= ======= ========
Trust Preferred
Securities $110,000 $110,000 $110,000 $110,000 $110,000
======== ======== ======== ======== ========
Long-term Debt (a) $645,283 $645,963 $541,568 $587,673 $589,980
======== ======== ======== ======== ========
Total Capitalization and Liabilities
$2,496,600 $2,657,956 $2,106,215 $2,081,454 $2,134,618
========== ========== ========== ========== ==========
(a) Including portion due within one year.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Results of Operations
SWEPCo is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power to approximately 431,000 retail
customers in northeastern Texas, northwestern Louisiana, and western Arkansas.
SWEPCo also sells electric power at wholesale to other utilities, municipalities
and rural electric cooperatives.
Wholesale power marketing and trading activities are conducted on
SWEPCo's behalf by AEP. SWEPCo, along with the other AEP electric operating
subsidiaries, shares in the revenues and costs of AEP's wholesale sales to and
forward trades with other utility systems and power marketers.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - Our financial statements reflect the actions of
regulators since our electricity supply sales in the Louisiana jurisdiction and
our transmission and distribution operations our cost-based rate-regulated. As a
result of the regulators' actions our financial statements can recognize
revenues and expenses in different time periods than enterprises that are not
rate regulated. In accordance with SFAS 71, regulatory assets (deferred
expenses) and regulatory liabilities (future revenue reductions or refunds) are
recorded to reflect the economic effects of regulation by matching expenses with
their recovery through regulated revenues in the same accounting period.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
When regulatory assets are probable of recovery through regulated rates,
we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to SWEPCo. Trading
activities allocated to SWEPCo involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We generally recognize revenues from trading activities based on changes in the
fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. It represents the change in the unrealized gain or loss throughout
the contract's term. When the contract actually settles, that is, the energy is
actually delivered in a sale or received in a purchase or the parties agree to
forego delivery and receipt and net settle in cash, the unrealized gain or loss
is reversed out of revenues and the actual realized cash gain or loss is
recognized in revenues. Therefore, over the trading contract's term an
unrealized gain or loss is recognized as the contract's market value changes.
When the contract settles the total gain or loss is realized in cash but only
the difference between the accumulated unrealized net gains or losses recorded
in prior months and the cash proceeds is recognized. Unrealized mark-to-market
gains and losses are included in the Balance Sheet as energy trading contract
assets or liabilities as appropriate.
Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record any difference between the contract
price and the market price as an unrealized gain or loss in revenues. In July
when the contract settles, we would realize the gain or loss in cash and reverse
to revenues the previously recorded unrealized gain or loss. Prior to
settlement, the change in the fair value of physical forward sale and purchase
contracts is included in revenues on a net basis. Upon settlement of a forward
trading contract, the amount realized is included in revenues, with the prior
change in unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
revenues from recording additional changes in fair values using mark-to-market
accounting.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading and derivative contracts exposing SWEPCo to market risk. See
"Market Risks" section of MD&A for a discussion of the policies and procedures
used to manage exposure to risk from trading activities.
Results of Operations
Net income increased $16.7 million or 23% for the year resulting from
the favorable impact of our sharing in AEP's power marketing and trading
activities for a full year. The $10.5 million or 13% decrease in net income in
2000 is due to increased operating expenses.
Operating Revenues
Operating revenues decreased $16.9 million or 2% in 2001. The slight
decrease in operating revenues resulted from unfavorable wholesale marketing and
trading conditions.
Operating revenues increased in 2000 due to the post merger sharing of
AEP's power marketing and trading sales, and offset by an unfavorable revenue
adjustment in 1999 as a result of FERC's approval of a transmission coordination
agreement. The transmission coordination agreement provides the means by which
the AEP West electric operating companies plan, operate and maintain their
separate transmission assets as a single system. The agreement also establishes
the method by which these companies allocate transmission revenues received
under open access transmission tariffs.
The following analyzes the changes in operating revenues:
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
---- ----
Amount % Amount %
Retail* $ 14.3 3 $ 29.9 6
Wholesale
Marketing and
Trading (86.3) (49) 58.4 50
Mark to Market 15.5 N.M. (4.7) N.M.
Other 35.4 113 8.5 37
------ ------
Total Marketing
and Trading (21.1) (3) 92.1 15
Energy
Delivery* (11.9) (3) 45.6 15
Sales to AEP
Affiliates 16.1 26 9.0 17
------ ------
Total
Revenues $(16.9) (2) $146.7 15
====== ======
N.M. = Not Meaningful
* Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
The decrease in wholesale marketing and trading revenues in 2001 is
primarily attributable to unfavorable wholesale marketing and trading
conditions.
The significant increase in wholesale revenues in 2000 is attributable to
SWEPCo's participation in AEP's power marketing and trading operations after the
merger of CSW and AEP. Revenues also increased in 2000 because of additional
fuel and purchased power revenues and a rise in sales volume caused by warmer
summer temperatures. The increase in fuel and purchased power revenues reflects
rising prices for natural gas used for generation and related higher costs for
purchased power. The Texas and Arkansas fuel clause recovery mechanisms provide
for the accrual of fuel-related revenues until reviewed and approved for billing
to customers by the regulator. The accrual of additional fuel-related revenues
is generally offset by increases in fuel and purchased power expenses. As a
result fuel-related revenues do not impact results of operations. Since SWEPCo
became a subsidiary of AEP as a result of the merger in June 2000, SWEPCo shares
in the AEP System's power marketing and trading transactions with other
entities.
Operating Expenses
Total operating expenses decreased 4% in 2001 and increased 20% for 2000.
Increase (Decrease)
From Previous Year
(dollars in millions)
2001 2000
---- ----
Amount % Amount %
Fuel $(41.2) (8) $119.2 31
Electricity
Marketing
Purchases (40.4) (69) 28.6 96
Affiliated
Purchases 2.5 19 5.8 77
Other Operation 11.9 7 17.2 12
Maintenance (.4) N.M. 10.9 17
Depreciation and
Amortization 14.9 14 (4.2) (4)
Taxes Other Than
Income Taxes 2.0 4 N.M. N.M.
Income Taxes 15.9 60 (12.0) (31)
------ ------
Total $(34.8) (4) $165.5 20
====== ======
N.M. = Not Meaningful
Fuel expense decreased in 2001 from lower natural gas prices and a mild
summer resulting in a reduction in generation. Fuel expense increased in 2000
due to an increase in the average unit cost of fuel as a result of an increase
in the spot market price for natural gas and an increase in generation to meet
the rise in demand for electricity.
The decrease in purchased power expense in 2001 was mainly due to reduced
prices caused by decreased electricity demand. The major increase in purchased
power expense in 2000 was primarily caused by higher natural gas prices.
Due to the acquisition of Dolet Hills mining operation in June 2001,
other operation expense increased for the year. Other operation expense
increased in 2000 due primarily to increased regulatory and consulting expenses.
Maintenance expense increased in 2000 as a result of costs to restore
service and make repairs following a severe ice storm.
Depreciation and amortization expense increased in 2001 due primarily to
an increase in excess earnings accruals under the Texas restructuring
legislation and the acquisition of Dolet Hills mining operation.
The increase in 2001 income tax expense was primarily due to an increase
in pre-tax book income. The decrease in income tax expense attributable to
operations in 2000 was primarily due to a decrease in pre-tax operating income.
Nonoperating Expense
The decrease in nonoperating expense in 2000 was due to the effect of a
1999 write off of acquisition expenses following CSW's decision not to continue
to pursue the acquisition of Cajun Electric Power Cooperatives non-nuclear
assets.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES:
Electricity Marketing and Trading $689,085 $710,200 $618,040
Energy Delivery 333,004 344,950 299,369
Sales to AEP Affiliates 79,237 63,124 54,118
------ ------ ------
TOTAL OPERATING REVENUES 1,101,326 1,118,274 971,527
--------- --------- -------
OPERATING EXPENSES:
Fuel 457,613 498,805 379,597
Purchased Power:
Electricity Marketing 18,164 58,518 29,820
AEP Affiliates 15,858 13,338 7,551
Other Operation 171,314 159,459 142,385
Maintenance 74,677 75,123 64,241
Depreciation and Amortization 119,543 104,679 108,831
Taxes Other Than Income Taxes 55,834 53,830 53,783
Income Taxes 42,116 26,244 38,257
------ ------ ------
TOTAL OPERATING EXPENSES 955,119 989,996 824,465
------- ------- -------
OPERATING INCOME 146,207 128,278 147,062
NONOPERATING INCOME 4,512 5,487 2,550
NONOPERATING EXPENSES 3,229 3,112 9,341
NONOPERATING INCOME TAX EXPENSE (CREDIT) 542 (1,476) (4,826)
INTEREST CHARGES 57,581 59,457 58,892
------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 89,367 72,672 86,205
EXTRAORDINARY LOSS (net of tax of $1,621,000) - - (3,011)
---- ---- ------
NET INCOME 89,367 72,672 83,194
PREFERRED STOCK DIVIDEND REQUIREMENTS 229 229 229
--- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 89,138 $ 72,443 $ 82,965
======== ======== ========
Consolidated Statements of Retained Earnings
BALANCE AT BEGINNING OF PERIOD $293,989 $283,546 $296,581
NET INCOME 89,367 72,672 83,194
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 74,212 62,000 96,000
Preferred Stock 229 229 229
--- --- ---
BALANCE AT END OF PERIOD $308,915 $293,989 $283,546
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheets
December 31,
2001 2000
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $1,429,356 $1,414,527
Transmission 538,749 519,317
Distribution 1,042,523 1,001,237
General 376,016 325,948
Construction Work in Progress 74,120 57,995
------ ------
Total Electric Utility Plant 3,460,764 3,319,024
Accumulated Depreciation and Amortization 1,550,618 1,457,005
--------- ---------
NET ELECTRIC UTILITY PLANT 1,910,146 1,862,019
--------- ---------
OTHER PROPERTY AND INVESTMENTS 43,000 39,627
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 63,372 62,605
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 5,415 1,907
Accounts Receivable:
Customers 42,326 42,310
Affiliated Companies 20,573 11,419
Allowance for Uncollectible Accounts (89) (911)
Fuel Inventory - at average cost 52,212 40,024
Materials and Supplies - at average cost 32,527 25,137
Under-recovered Fuel Costs 2,501 35,469
Energy Trading Contracts 186,159 453,781
Prepayments 18,716 16,780
------ ------
TOTAL CURRENT ASSETS 360,340 625,916
------- -------
REGULATORY ASSETS 51,989 57,082
------ ------
DEFERRED CHARGES 67,753 10,707
------ ------
TOTAL $2,496,600 $2,657,956
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
December 31,
2001 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 308,915 293,989
------- --- -------
Total Common Shareholder's Equity 689,575 674,649
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 494,688 645,368
------- -------
TOTAL CAPITALIZATION 1,298,967 1,434,721
--------- ---------
OTHER NONCURRENT LIABILITIES 34,997 11,290
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 150,595 595
Advances from Affiliates 123,609 16,823
Accounts Payable - General 71,810 107,747
Accounts Payable - Affiliated Companies 37,469 36,021
Customer Deposits 19,880 16,433
Taxes Accrued 36,522 11,224
Interest Accrued 13,631 13,198
Energy Trading Contracts 192,318 462,043
Other 26,166 15,064
------ ------
TOTAL CURRENT LIABILITIES 672,000 679,148
------- -------
DEFERRED INCOME TAXES 369,781 399,204
------- -------
DEFERRED INVESTMENT TAX CREDITS 48,714 53,167
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 17,828 18,288
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 54,313 62,138
------ ------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $2,496,600 $2,657,956
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $89,367 $72,672 $83,194
Adjustments for Noncash Items:
Depreciation and Amortization 119,543 104,679 108,831
Deferred Income Taxes (31,396) 14,653 (17,347)
Deferred Investment Tax Credits (4,453) (4,482) (4,565)
Mark-to-Market of Energy Trading Contracts (3,472) 4,677 -
Changes in Certain Assets and Liabilities:
Accounts Receivable (net) (9,992) (1,254) (11,134)
Fuel, Materials and Supplies (19,578) 22,103 (21,891)
Accounts Payable (34,489) 43,962 (12,953)
Taxes Accrued 25,298 (13,150) 1,185
Transmission Coordination Agreement Settlement - (24,406) 24,406
Fuel Recovery 32,968 (38,357) (2,490)
Change in Other Assets 856 57,418 24,500
Change in Other Liabilities 4,958 (36,887) (15,769)
----- ------- -------
Net Cash Flows From Operating Activities 169,610 201,628 155,967
------- ------- -------
INVESTING ACTIVITIES:
Construction Expenditures (111,725) (120,671) (111,019)
Purchase of Dolet Hills Mining Operations (85,716) - -
Other (411) 446 (4,167)
---- ---- ------
Net Cash Flows Used For
Investing Activities (197,852) (120,225) (115,186)
-------- -------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 149,360 -
Redemption of Preferred Stock - (1) (1)
Retirement of Long-term Debt (595) (45,595) (46,144)
Change in Advances From Affiliates (net) 106,786 (124,074) 100,192
Dividends Paid on Common Stock (74,212) (62,000) (96,000)
Dividends Paid on Cumulative Preferred Stock (229) (229) (229)
---- ---- ----
Net Cash Flows From (Used For)
Financing Activities 31,750 (82,539) (42,182)
------ ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents 3,508 (1,136) (1,401)
Cash and Cash Equivalents January 1 1,907 3,043 4,444
----- ----- -----
Cash and Cash Equivalents December 31 $ 5,415 $ 1,907 $ 3,043
======= ======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $51,126,000, $51,111,000
and $55,254,000 and for income taxes was $49,901,000, $27,994,000 and
$55,677,000 in 2001, 2000, and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Consolidated Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $ 689,575 $ 674,649
---------- ----------
PREFERRED STOCK: $100 par value - authorized shares 1,860,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2001 Year Ended December 31, December 31, 2001
- ------ ------------ ---------------------------- -----------------
2001 2000 1999
---- ---- ----
Not Subject to Mandatory Redemption:
4.28% $103.90 - - - 7,386 739 739
4.65% $102.75 - - 1 1,907 190 190
5.00% $109 - 12 2 37,715 3,771 3,771
Premium 4 4
---------- ----------
4,704 4,704
---------- ----------
TRUST PREFERRED SECURITIES
SWEPCo-obligated, mandatorily redeemable preferred securities of subsidiary
trust holding solely Junior Subordinated Debentures of SWEPCo, 7.875%,
due April 30, 2037 110,000 110,000
---------- ----------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 315,449 315,477
Installment Purchase Contracts 179,834 180,486
Senior Unsecured Notes 150,000 150,000
Less Portion Due Within One Year (150,595) (595)
---------- ----------
Long-term Debt Excluding Portion Due Within One Year 494,688 645,368
---------- ----------
TOTAL CAPITALIZATION $1,298,967 $1,434,721
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
6-5/8 2003 - February 1 $ 55,000 $ 55,000
7-3/4 2004 - June 1 40,000 40,000
6.20 2006 - November 1 5,650 5,795
6.20 2006 - November 1 1,000 1,000
7.00 2007 - September 1 90,000 90,000
7-1/4 2023 - July 1 45,000 45,000
6-7/8 2025 - October 1 80,000 80,000
Unamortized Discount (1,201) (1,318)
-------- --------
$315,449 $315,477
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
DeSoto County:
7.60 2019 - January 1 $ 53,500 $ 53,500
Sabine:
6.10 2018 - April 1 81,700 81,700
Titus County:
6.90 2004 - November 1 12,290 12,290
6.00 2008 - January 1 13,070 13,520
8.20 2011 - August 1 17,125 17,125
Unamortized Premium 2,149 2,351
-------- --------
$179,834 $180,486
Under the terms of the installment purchase contracts, SWEPCo is
required to pay amounts sufficient to enable the payment of interest on and the
principal (at stated maturities and upon mandatory redemptions) of related
pollution control revenue bonds issued to finance the construction of pollution
control facilities at certain plants.
Senior unsecured notes outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
(a) 2002 - March 1 $150,000 $150,000
======== ========
(a) A floating interest rate is determined monthly. The rate on December 31,
2001 and 2000 was 2.311% and 6.97%.
At December 31, 2001, future annual long-term debt payments are as follows:
Amount
------
(in thousands)
2002 $150,595
2003 55,595
2004 52,885
2005 595
2006 6,520
Later Years 378,145
--------
Total Principal Amount 644,335
Unamortized Premium 948
--------
Total $645,283
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
Index to Notes to Consolidated Financial Statements
The notes to SWEPCo's financial statements are combined with the notes to
financial statements for AEP and its other subisidiary registrants. Listed below
are the combined notes that apply to SWEPCo. The combined footnotes begin on
page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Acquistions and Dispositions Note 9
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Trust Preferred Securities Note 18
Jointly Owned Electric Utility Plant Note 19
Related Party Transactions Note 20
Subsequent Events Note 21
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of Southwestern Electric Power Company:
We have audited the accompanying consolidated balance sheets and
consolidated statements of capitalization of Southwestern Electric Power Company
and subsidiaries as of December 31, 2001 and 2000, and the related consolidated
statements of income, retained earnings, and cash flows for the years then
ended. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. The consolidated financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the consolidated financial statements, were audited by other
auditors whose report, dated February 25, 2000, expressed an unqualified opinion
on those statements.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such 2001 and 2000 consolidated financial statements
present fairly, in all material respects, the financial position of Southwestern
Electric Power Company and subsidiaries as of December 31, 2001 and 2000, and
the results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States of
America.
We also audited the adjustments described in Note 3 that were applied to
restate the 1999 consolidated financial statements to give retroactive effect to
the conforming change in the method of accounting for vacation pay accruals. In
our opinion, such adjustments are appropriate and have been properly applied.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
WEST TEXAS UTILITIES COMPANY
WEST TEXAS UTILITIES COMPANY
Selected Financial Data
Year Ended December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
INCOME STATEMENTS DATA:
Operating Revenues $556,458 $571,064 $445,709 $424,953 $397,779
Operating Expenses 523,068 518,723 391,910 365,677 353,195
------- ------- ------- ------- -------
Operating Income 33,390 52,341 53,799 59,276 44,584
Nonoperating Income
(Loss) 2,195 (1,675) 2,488 2,712 1,463
Interest Charges 23,275 23,216 24,420 24,263 24,570
------ ------ ------ ------ ------
Income Before
Extraordinary Item 12,310 27,450 31,867 37,725 21,477
Extraordinary Loss - - (5,461) - -
---- --- ------ ---- ----
Net Income 12,310 27,450 26,406 37,725 21,477
Preferred Stock
Dividend Requirements 104 104 104 104 144
--- --- --- --- ---
Gain on Reacquired
Preferred Stock - - - - 1,085
---- ---- ---- ---- -----
Earnings Applicable to
Common Stock $ 12,206 $ 27,346 $ 26,302 $ 37,621 $ 22,418
======== ======== ======== ======== ========
December 31,
2001 2000 1999 1998 1997
---- ---- ---- ---- ----
(in thousands)
BALANCE SHEETS DATA:
Electric Utility Plant $1,260,872 $1,229,339 $1,182,544 $1,146,582 $1,108,845
Accumulated
Depreciation and
Amortization 546,162 515,041 495,847 473,503 441,281
------- ------- ------- ------- -------
Net Electric Utility
Plant $714,710 $714,298 $686,697 $673,079 $667,564
======== ======== ======== ======== ========
Total Assets $923,420 $1,087,411 $861,205 $819,446 $826,858
======== ========== ======== ======== ========
Common Stock and
Paid-in Capital $139,450 $139,450 $139,450 $139,450 $139,450
Retained Earnings 105,970 122,588 113,242 114,940 117,319
------- ------- ------- ------- -------
Total Common
Shareholder's Equity $245,420 $262,038 $252,692 $254,390 $256,769
======== ======== ======== ======== ========
Cumulative Preferred Stock:
Not Subject to
Mandatory Redemption $ 2,482 $ 2,482 $ 2,482 $ 2,482 $ 2,483
======= ======= ======= ======= =======
Long-term Debt (a) $255,967 $255,843 $303,686 $303,518 $303,351
======== ======== ======== ======== ========
Total Capitalization
And Liabilities $923,420 $1,087,411 $861,205 $819,446 $826,858
======== ========== ======== ======== ========
(a) Including portion due within one year.
WEST TEXAS UTILITIES COMPANY
Management's Narrative Analysis of Results of Operations
WTU is a public utility engaged in the generation, purchase, sale,
transmission and distribution of electric power and provides electric power to
approximately 189,000 retail customers in west and central Texas. WTU also sells
electric power at wholesale to other utilities, municipalities and rural
electric cooperatives.
Wholesale power marketing and trading activities are conducted on WTU's
behalf by AEP. WTU, along with the other AEP electric operating subsidiaries,
shares in the revenues and costs of AEP's wholesale sales to and forward trades
with other utility systems and power marketers.
Critical Accounting Policies - Revenue Recognition
Regulatory Accounting - As a result of our cost-based rate-regulated
transmission and distribution operations, our financial statements reflect the
actions of regulators that can result in the recognition of revenues and
expenses in different time periods than enterprises that are not rate regulated.
In accordance with SFAS 71, regulatory assets (deferred expenses) and regulatory
liabilities (future revenue reductions or refunds) are recorded to reflect the
economic effects of regulation by matching expenses with their recovery through
regulated revenues in the same accounting period.
When regulatory assets are probable of recovery through regulated
rates, we record them as assets on the balance sheet. We test for probability of
recovery whenever new events occur, for example a regulatory commission order or
passage of new legislation. If we determine that recovery of a regulatory asset
is no longer probable, we write off that regulatory asset as a charge against
net income. A write off of regulatory assets may also reduce future cash flows
since there may be no recovery through regulated rates.
Traditional Electricity Supply and Delivery Activities - We recognize revenues
on an accrual basis for electricity supply sales and electricity transmission
and distribution delivery services. The revenues are recognized in our income
statement when the energy is delivered to the customer and include unbilled as
well as billed amounts. In general expenses are recorded when incurred.
Energy Marketing and Trading Activities - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). A portion of the
revenues and costs of AEP's trading activities are allocated to WTU. Trading
activities allocated to WTU involve the purchase and sale of energy under
physical forward contracts at fixed and variable prices. Although trading
contracts are generally short-term, there are also long-term trading contracts.
We recognize revenues from trading activities generally based on changes in the
fair value of energy trading contracts.
Recording the net change in the fair value of trading contracts as
revenues prior to settlement is commonly referred to as mark-to-market (MTM)
accounting. It represents the change in the unrealized gain or loss throughout
the contract's term. When the contract actually settles, that is, the energy is
actually delivered in a sale or received in a purchase or the parties agree to
forego delivery and receipt of electricity and net settle in cash, the
unrealized gain or loss is reversed out of revenues and the actual realized cash
gain or loss is recognized in revenues. Therefore, over the trading contract's
term an unrealized gain or loss is recognized as the contract's market value
changes. When the contract settles the total gain or loss is realized in cash
but only the difference between the accumulated unrealized net gains or losses
recorded in prior months and the cash proceeds is recognized. Unrealized
mark-to-market gains and losses are included in the Balance Sheet as energy
trading contract assets or liabilities as appropriate.
Our trading activities represent physical forward electricity contracts
that are typically settled by entering into offsetting contracts. An example of
our trading activities is when, in January, we enter into a forward sales
contract to deliver electricity in July. At the end of each month until the
contract settles in July, we would record our share of any difference between
the contract price and the market price as an unrealized gain or loss in
revenues. In July when the contract settles, we would realize our share of the
gain or loss in cash and reverse to revenues the previously recorded unrealized
gain or loss. Prior to settlement, the change in the fair value of physical
forward sale and purchase contracts is included in revenues on a net basis. Upon
settlement of a forward trading contract, the amount realized is included in
revenues, with the prior change in unrealized fair value reversed in revenues.
Continuing with the above example, assume that later in January or
sometime in February through July we enter into an offsetting forward contract
to buy electricity in July. If we do nothing else with these contracts until
settlement in July and if the volumes, delivery point, schedule and other key
terms match, then the difference between the sale price and the purchase price
represents a fixed value to be realized when the contracts settle in July. If
the purchase contract is perfectly matched with the sales contract, we have
effectively fixed the profit or loss; specifically it is the difference between
the contracted settlement price of the two contracts. Mark-to-market accounting
for these contracts will have no further impact on results of operations but
will have an offsetting and equal effect on trading contract assets and
liabilities. Of course we could also do similar transactions but enter into a
purchase contract prior to entering into a sales contract. If the sale and
purchase contracts do not match exactly as to volumes, delivery point, schedule
and other key terms, then there could be continuing mark-to-market effects on
revenues from recording additional changes in fair values using mark-to-market
accounting.
The fair value of open short-term trading contracts are based on
exchange prices and broker quotes. We mark-to-market open long-term trading
contracts based mainly on AEP-developed valuation models. These models estimate
future energy prices based on existing market and broker quotes and supply and
demand market data and assumptions. The fair values determined are reduced by
reserves to adjust for credit risk and liquidity risk. Credit risk is the risk
that the counterparty to the contract will fail to perform or fail to pay
amounts due AEP. Liquidity risk represents the risk that imperfections in the
market will cause the price to be less than or more than what the price should
be based purely on supply and demand. There are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. AEP has independent controls to evaluate the reasonableness of our
valuation models. However, energy markets, especially electricity markets, are
imperfect and volatile and unforeseen events can and will cause reasonable price
curves to differ from actual prices throughout a contract's term and when
contracts settle. Therefore, there could be significant adverse or favorable
effects on future results of operations and cash flows if market prices do not
correlate with the AEP-developed price models.
Volatility in commodities markets affects the fair values of all of our
open trading contracts exposing WTU to market risk. See "Market Risks" section
of MD&A for a discussion of the policies and procedures used to manage exposure
to risk from trading activities.
Results of Operations
Income before extraordinary items decreased $15.1 million or 55% during
2001, due mostly to a significant increase in other operation expense. The
significant increase in other operation expense is partially due to the effect
of a 2001 increase in energy delivery's transmission expenses that resulted from
new prices for the Electric Reliability Council of Texas (ERCOT) transmission
grid. Other operation expense also increased due to the effect of a favorable
adjustment made in 2000 related to a FERC-approved Transmission Coordination
Agreement.
Operating Revenues
Operating revenues decreased $14.6 million or 3% as shown below:
Increase (Decrease)
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Retail* $ (3.1) (2)
Wholesale Electric
Marketing and Trading (17.3) (12)
Unrealized MTM 6.3 N.M.
Other 6.8 18
------
Total Marketing and
Trading (7.4) (2)
Energy Delivery* (7.2) (4)
------
Total Revenues $(14.6) (3)
======
*Reflects the allocation of certain transmission and distribution revenues
included in bundled retail rates to energy delivery.
Revenues from retail customers decreased slightly in 2001 due to milder
than normal summer and winter weather.
Wholesale electric marketing and trading revenues decreased as a result
of unfavorable wholesale marketing and trading conditions.
Operating Expenses
Operating expense increased $4.3 million or 1% as shown below:
Increase (Decrease)
From Previous Year
(dollars in millions) Amount %
- ---------------------- ------ -
Fuel $ (6.0) (3)
Marketing Purchases 2.2 3
Affiliate Purchases (1.1) (2)
Other Operation 18.2 20
Maintenance 1.1 5
Depreciation and
Amortization (4.5) (8)
Taxes Other Than
Income Taxes 3.0 12
Income Taxes (8.6) (58)
------
Total $ 4.3 1
======
Fuel expense decreased in 2001 due to a decrease in generation offset in
part by an increase in the average spot market price for natural gas. The
decrease in generation reflects milder than normal summer and winter weather.
Other operation expense increased from the prior year primarily due to
the effect of two items. First, energy delivery's transmission expenses
increased as a result of new prices for the ERCOT transmission grid. The
increase in other operation expense is also attributable to a favorable
adjustment made in 2000 related to the FERC-approved Transmission Coordination
Agreement.
An increase in maintenance expense is the result of an overhaul in 2001
of the Oklaunion Power Plant.
Due to the recordation of increased accruals in 2000 for estimated excess
earnings under the Texas Legislation, depreciation and amortization expense
decreased during 2001.
The increase in taxes other than income taxes is the result of an
increase in Texas franchise tax assessments and an increase in the Texas PUCT
benefit assessment tax, a new tax in the state of Texas.
Income taxes decreased in 2001, reflecting a decrease in pre-tax income.
Nonoperating Income
Nonoperating income increased $2.7 million due to an increase in interest
income earned on under-recovered fuel during 2001.
Nonoperating Expense
The decrease in nonoperating expenses is mainly due to the effect of a
loss provision that was recorded in 2000 for the termination of merchandise
sales and the cost of phasing out the merchandising sales programs.
WEST TEXAS UTILITIES COMPANY
Statements of Income
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING REVENUES
Electricity Marketing and Trading $ 368,741 $ 376,206 $256,033
Energy Delivery 169,036 176,204 174,909
Sales to AEP Affiliates 18,681 18,654 14,767
---------- ---------- ------
Total Operating Revenues 556,458 571,064 445,709
------- ------- -------
OPERATING EXPENSES:
Fuel 177,140 183,154 123,348
Purchased Power:
Electricity Marketing 70,395 68,080 34,941
AEP Affiliates 56,656 57,773 26,591
Other Operation 111,248 93,078 94,290
Maintenance 22,343 21,241 19,604
Depreciation and Amortization 50,705 55,172 50,789
Taxes Other Than Income Taxes 28,319 25,321 28,268
Income Taxes 6,262 14,904 14,079
----- ------ ------
TOTAL OPERATING EXPENSES 523,068 518,723 391,910
------- ------- -------
OPERATING INCOME 33,390 52,341 53,799
NONOPERATING INCOME 12,199 9,530 14,515
NONOPERATING EXPENSES 10,695 12,664 11,169
NONOPERATING INCOME TAX EXPENSE (CREDIT) (691) (1,459) 858
INTEREST CHARGES 23,275 23,216 24,420
------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEMS 12,310 27,450 31,867
EXTRAORDINARY LOSS (net of tax of $2,941,000) - - (5,461)
---- ---- ------
NET INCOME 12,310 27,450 26,406
PREFERRED STOCK DIVIDEND REQUIREMENTS 104 104 104
--- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 12,206 $ 27,346 $ 26,302
======== ======== ========
Statements of Retained Earnings
BEGINNING OF PERIOD $122,588 $113,242 $114,940
NET INCOME 12,310 27,450 26,406
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 28,824 18,000 28,000
Preferred Stock 104 104 104
--- --- ---
BALANCE AT END OF PERIOD $105,970 $122,588 $113,242
======== ======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Balance Sheets
December 31,
2001 2000
---- ----
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
Production $443,508 $431,793
Transmission 250,023 235,303
Distribution 431,969 416,587
General 112,797 110,832
Construction Work in Progress 22,575 34,824
------ ------
Total Electric Utility Plant 1,260,872 1,229,339
Accumulated Depreciation and Amortization 546,162 515,041
------- -------
NET ELECTRIC UTILITY PLANT 714,710 714,298
------- -------
OTHER PROPERTY AND INVESTMENTS 24,933 23,154
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 21,532 20,804
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 2,454 6,941
Accounts Receivable:
Customers 18,720 36,217
Affiliated Companies 8,656 16,095
Allowance for Uncollectible Accounts (196) (288)
Fuel - at average cost 8,307 12,174
Materials and Supplies - at average cost 11,190 10,510
Under-recovered Fuel Costs 32,791 68,107
Energy Trading Contracts 63,252 150,793
Prepayments 966 851
--- ---
TOTAL CURRENT ASSETS 146,140 301,400
------- -------
REGULATORY ASSETS 13,659 24,808
------ ------
DEFERRED CHARGES 2,446 2,947
----- -----
TOTAL $923,420 $1,087,411
======== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
December 31,
2001 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 105,970 122,588
------- -------
Total Common Shareholder's Equity 245,420 262,038
Cumulative Preferred Stock
Not Subject to Mandatory Redemption 2,482 2,482
Long-term Debt 220,967 255,843
------- -------
TOTAL CAPITALIZATION 468,869 520,363
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 35,000 -
Advances from Affiliates 50,448 58,578
Accounts Payable - General 33,782 45,562
Accounts Payable - Affiliated Companies 11,388 42,212
Customer Deposits 4,191 2,659
Taxes Accrued 17,358 18,901
Interest Accrued 1,244 3,717
Energy Trading Contracts 65,414 153,539
Other 12,001 7,906
------ -----
TOTAL CURRENT LIABILITIES 230,826 333,074
------- -------
DEFERRED INCOME TAXES 145,049 157,038
------- -------
DEFERRED INVESTMENT TAX CREDITS 22,781 24,052
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 18,455 20,648
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 37,440 32,236
------ ------
COMMITMENTS AND CONTINGENCIES (Note 8)
TOTAL $923,420 $1,087,411
======== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Statements of Cash Flows
Year Ended December 31,
-----------------------
2001 2000 1999
---- ---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 12,310 $27,450 $26,406
Adjustments for Noncash Items:
Depreciation and Amortization 50,705 55,172 50,789
Deferred Federal Income Taxes (11,891) 8,164 12,026
Deferred Investment Tax Credits (1,271) (1,271) (1,275)
Extraordinary Loss - Discontinuance of SFAS 71 - - 5,461
Mark-to-Market of Energy Trading Contracts (1,818) 1,871 -
CHANGES IN CERTAIN ASSETS AND LIABILITIES:
Accounts Receivable (net) 24,844 (1,445) (18,890)
Fuel, Materials and Supplies 3,187 8,478 (3,785)
Accounts Payable (42,604) 28,393 7,229
Taxes Accrued (1,543) 6,443 2,427
Fuel Recovery 35,316 (53,841) (10,101)
Transmission Coordination Agreement Settlement - 15,465 (15,465)
Change in Other Assets (1,519) 3,361 5,615
Change in Other Liabilities 6,644 (3,962) 2,205
----- ------ -----
Net Cash Flows From Operating Activities 72,360 94,278 62,642
------ ------ ------
INVESTING ACTIVITIES:
Construction Expenditures (39,662) (64,477) (49,443)
Other (127) - (3,832)
---- ---- ------
Net Cash Used For Investing Activities (39,789) (64,477) (53,275)
------- ------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (48,000) -
Change in Advances From Affiliates (net) (8,130) 37,170 16,835
Dividends Paid on Common Stock (28,824) (18,000) (28,000)
Dividends Paid on Cumulative Preferred Stock (104) (104) (105)
---- ---- ----
Net Cash Used For Financing Activities (37,058) (28,934) (11,270)
------- ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents (4,487) 867 (1,903)
Cash and Cash Equivalents at Beginning of Period 6,941 6,074 7,977
----- ----- -----
Cash and Cash Equivalents at End of Period $2,454 $ 6,941 $ 6,074
====== ======= =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $19,279,000,
$19,088,000 and $17,577,000 and for income taxes was $21,997,000, $(906,000) and
$3,309,000 in 2001, 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Statements of Capitalization
December 31,
2001 2000
(in thousands)
COMMON SHAREHOLDER'S EQUITY $245,420 $262,038
-------- --------
PREFERRED STOCK: $100 par value - authorized shares 810,000
Call Price Shares
December 31, Number of Shares Redeemed Outstanding
Series 2001 Year Ended December 31, December 31, 2001
- ------ ------------ ---------------------------- -----------------
2001 2000 1999
---- ---- ----
Not Subject to Mandatory Redemption:
4.40% $107 - 1 2 23,672 2,367 2,367
Premium 115 115
-------- --------
2,482 2,482
-------- --------
LONG-TERM DEBT (See Schedule of Long-term Debt):
First Mortgage Bonds 211,657 211,533
Installment Purchase Contracts 44,310 44,310
Less Portion Due Within One Year (35,000) -
-------- --------
Long-term Debt Excluding Portion Due Within One Year 220,967 255,843
-------- --------
TOTAL CAPITALIZATION $468,869 $520,363
======== ========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
Schedule of Long-term Debt
First mortgage bonds outstanding were as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
7-3/4 2007 - June 1 $ 25,000 $ 25,000
6-7/8 2002 - October 1 35,000 35,000
7 2004 - October 1 40,000 40,000
6-1/8 2004 - February 1 40,000 40,000
6-3/8 2005 - October 1 72,000 72,000
Unamortized Discount (343) (467)
-------- --------
$211,657 $211,533
First mortgage bonds are secured by first mortgage liens on electric
utility plant. Certain indentures relating to the first mortgage bonds contain
improvement, maintenance and replacement provisions requiring the deposit of
cash or bonds with the trustee, or in lieu thereof, certification of unfunded
property additions.
Installment purchase contracts have been entered into, in connection
with the issuance of pollution control revenue bonds by governmental authorities
as follows:
December 31,
2001 2000
(in thousands)
% Rate Due
Red River Authority
of Texas:
6 2020 - June 1 $44,310 $44,310
======= =======
Under the terms of the installment purchase contracts, WTU is required
to pay amounts sufficient to enable the payment of interest on and the principal
(at stated maturities and upon mandatory redemptions) of related pollution
control revenue bonds issued to finance the construction of pollution control
facilities at certain plants.
At December 31, 2001, future annual long-term debt payments are as
follows:
Amount
------
(in thousands)
2002 $ 35,000
2003 -
2004 80,000
2005 72,000
2006 -
Later Years 69,310
--------
Principal Amount 256,310
Unamortized Discount (343)
--------
Total $255,967
WEST TEXAS UTILITIES COMPANY
Index to Notes to Financial Statements
The notes to WTU's financial statements are combined with the notes to financial
statements for AEP and its other subisidiary registrants. Listed below are the
combined notes that apply to WTU. The combined footnotes begin on page L-1.
Combined
Footnote
Reference
Significant Accounting Policies Note 1
Extraordinary Items and Cumulative Effect Note 2
Merger Note 3
Rate Matters Note 5
Effects of Regulation Note 6
Customer Choice and Industry Restructuring Note 7
Commitments and Contingencies Note 8
Benefit Plans Note 10
Business Segments Note 11
Risk Management, Financial Instruments and Derivatives Note 12
Income Taxes Note 13
Leases Note 15
Lines of Credit and Sale of Receivables Note 16
Unaudited Quarterly Financial Information Note 17
Jointly Owned Electric Utility Plant Note 19
Related Party Transactions Note 20
Subsequent Events Note 21
Subsequent Events (Unaudited) Note 22
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of
Directors of West Texas Utilities Company:
We have audited the accompanying balance sheets and statements of
capitalization of West Texas Utilities Company as of December 31, 2001 and 2000,
and the related statements of income, retained earnings, and cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits. The financial statements of the
Company for the year ended December 31, 1999, before the restatement described
in Note 3 to the financial statements, were audited by other auditors whose
report, dated February 25, 2000, expressed an unqualified opinion on those
statements.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such 2001 and 2000 financial statements present fairly,
in all material respects, the financial position of West Texas Utilities Company
as of December 31, 2001 and 2000, and the results of its operations and its cash
flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America.
We also audited the adjustments described in Note 3 that were applied to
restate the 1999 financial statements to give retroactive effect to the
conforming change in the method of accounting for vacation pay accruals. In our
opinion, such adjustments are appropriate and have been properly applied.
DELOITTE & TOUCHE LLP
Columbus, Ohio
February 22, 2002
(November 18, 2002 as to Note 21)
NOTES TO FINANCIAL STATEMENTS
The notes to financial statements that follow are a combined presentation for
indicated registrants. The following list of footnotes shows the registrant to
which they apply:
1. Significant Accounting Policies AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, WTU
2. Extraordinary Items and
Cumulative Effect APCo, CPL, CSPCo, OPCo, SWEPCo, WTU
3. Merger CPL, I&M, KPCo, PSO, SWEPCo, WTU
4. Nuclear Plant Restart I&M
5. Rate Matters APCo, CPL, PSO, SWEPCo, WTU
6. Effects of Regulation AEGCo,APCo, CPL,
CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
7. Customer Choice and Industry APCo, CPL, CSPCo, I&M, OPCo, PSO,
Restructuring SWEPCo, WTU
8. Commitments and Contingencies AEGCo,APCo, CPL, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo, WTU
9. Acquisitions and Dispositions OPCo, SWEPCo
10. Benefit Plans APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
11. Business Segments AEGCo, APCo, CPL, CSPCo,
I&M, KPCo, OPCo, PSO, SWEPCo, WTU
12. Risk Management, Financial AEGCo, APCo, CPL, CSPCo, I&M, KPCo
Instruments and Derivatives OPCo, PSO, SWEPCo, WTU
13. Income Taxes AEGCo, APCo, CPL, CSPCo, I&M,
KPCo, OPCo, PSO, SWEPCo, WTU
14. Supplementary Information APCo, CSPCo, I&M, OPCo
15. Leases AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
16. Lines of Credit and Sale AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
of Receivables OPCo, PSO, SWEPCo, WTU
17. Unaudited Quarterly Financial AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
Information OPCo, PSO, SWEPCo, WTU
18. Trust Preferred Securities CPL, PSO, SWEPCo
19. Jointly Owned Electric CPL, CSPCo, PSO, SWEPCo, WTU
Utility Plant
20. Related Party Transactions AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
21. Subsequent Events APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, WTU
22. Subsequent Events (Unaudited) CPL, WTU
1. Significant Accounting Policies:
Business Operations - AEP (not included herein) is the parent company of eleven
domestic electric utility operating companies whose principal business is the
generation, transmission and distribution of electric power. AEP as used herein
refers collectively to the eleven operating companies. Nine of AEP's eleven
domestic electric utility operating companies, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU, are SEC registrants. AEGCo is a domestic generating
company wholly-owned by AEP that is an SEC registrant. These companies are
subject to regulation by the FERC under the Federal Power Act and follow the
Uniform System of Accounts prescribed by FERC. They are subject to further
regulation with regard to rates and other matters by state regulatory
commissions.
AEP also engages in wholesale marketing and trading of electricity, and to a
lesser extent coal and emission allowances in the United States.
Rate Regulation - AEP is subject to regulation by the SEC under the PUHCA. The
rates charged by the utility subsidiaries are approved by the FERC and the state
utility commissions. The FERC regulates wholesale electricity operations and
transmission rates and the state commissions regulate retail rates.
Principles of Consolidation -The consolidated financial statements for APCo,
CPL, CSPCo, I&M, OPCo, PSO and SWEPCo include the registrant and its
wholly-owned subsidiaries. Significant intercompany items are eliminated in
consolidation. Equity investments not substantially controlled that are 50% or
less owned are accounted for using the equity method with their equity earnings
included in nonoperating income for the registrant subsidiaries.
Basis of Accounting - As cost-based rate-regulated electric public utility
companies, the financial statements herein reflect the actions of regulators
that result in the recognition of revenues and expenses in different time
periods than enterprises that are not rate regulated. In accordance with SFAS
71, "Accounting for the Effects of Certain Types of Regulation," regulatory
assets (deferred expenses) and regulatory liabilities (future revenue reductions
or refunds) are recorded to reflect the economic effects of regulation by
matching expenses with their recovery through regulated revenues. Application of
SFAS 71 for the generation portion of the business was discontinued as follows:
in Ohio by OPCo and CSPCo in September 2000, in Virginia and West Virginia by
APCo in June 2000, in Texas by CPL, WTU, and SWEPCo in September 1999 and in
Arkansas by SWEPCo in September 1999. See Note 7, "Customer Choice and Industry
Restructuring" for additional information.
Use of Estimates - The preparation of these financial statements in conformity
with generally accepted accounting principles necessarily includes the use of
estimates and assumptions by management. Actual results could differ from those
estimates.
Property, Plant and Equipment -Electric utility property, plant and equipment
are stated at original cost of the acquirer. Property, plant and equipment of
other operations and investments are stated at their fair market value at
acquisition plus the original cost of property acquired or constructed since the
acquisition, less disposals. Additions, major replacements and betterments are
added to the plant accounts. For cost-based rate regulated operations
retirements from the plant accounts and associated removal costs, net of
salvage, are deducted from accumulated depreciation. The costs of labor,
materials and overheads incurred to operate and maintain plant are included in
operating expenses.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
- - AFUDC is a noncash nonoperating income item that is capitalized and recovered
through depreciation over the service life of domestic regulated electric
utility plant. It represents the estimated cost of borrowed and equity funds
used to finance construction projects. The amounts of AFUDC for 2001, 2000 and
1999 were not significant. Effective with the discontinuance of the application
of SFAS 71 regulatory accounting for domestic generating assets in Arkansas,
Ohio, Texas, Virginia and West Virginia, interest is capitalized during
construction in accordance with SFAS 34, "Capitalization of Interest Costs." The
amounts of interest capitalized were not material in 2001, 2000, and 1999.
Depreciation, Depletion and Amortization - Depreciation of property, plant and
equipment is provided on a straight-line basis over the estimated useful lives
of property, other than coal-mining property, and is calculated largely through
the use of composite rates by functional class.
The following table provides the annual composite depreciation rates generally
used by the AEP registrant subsidiaries for the years 2001, 2000 and 1999 which
were as follows:
Nuclear Steam Hydro Transmission Distribution General
------- ----- ----- ------------ ------------ -------
AEGCo - % 3.5% - % - % - % 2.8%
APCo - 3.4 2.9 2.2 3.3 3.1
CPL 2.5 2.5 1.9 2.3 3.5 4.0
CSPCo - 3.2 - 2.3 3.6 3.2
I&M 3.4 4.5 3.4 1.9 4.2 3.8
KPCo - 3.8 - 1.7 3.5 2.5
OPCo - 3.4 2.7 2.3 4.0 2.7
PSO - 2.7 - 2.3 3.4 6.0
SWEPCo - 3.4 - 2.7 3.6 4.5
WTU - 2.8 - 3.1 3.3 6.6
Depreciation, depletion and amortization of coal-mining assets is provided over
each asset's estimated useful life or the estimated life of the mine, whichever
is shorter, and is calculated using the straight-line method for mining
structures and equipment. The units-of-production method is used to amortize
coal rights and mine development costs based on estimated recoverable tonnages
at a current average rate of $3.46 per ton in 2001, $5.07 per ton in 2000 and
$2.32 per ton in 1999. These costs are included in the cost of coal charged to
fuel expense.
Cash and Cash Equivalents - Cash and cash equivalents include temporary cash
investments with original maturities of three months or less.
Inventory - Except for CPL, PSO and WTU, the regulated utility companies value
fossil fuel inventories using a weighted average cost method. CPL, PSO and WTU,
utilize the LIFO method to value fossil fuel inventories. For those utilities
whose generation is unregulated, inventory of coal and oil is carried at the
lower of cost or market. Coal mine inventories are also carried at the lower of
cost or market.
Accounts Receivable - AEP Credit Inc. (formerly CSW Credit) factors accounts
receivable for the utility subsidiaries and certain non-affiliated utilities. On
December 31, 2001 AEP Credit, Inc. entered into a sale of receivables agreement
with a group of banks and commercial paper conduits. This transaction
constitutes a sale of receivables in accordance with SFAS 140, allowing the
receivables to be taken off of the companies balances sheet. See Note 16 for
further details.
Deferred Fuel Costs - The cost of fuel consumed is charged to expense when the
fuel is burned. Where applicable under governing state regulatory commission
retail rate orders, fuel cost over or under-recoveries are deferred as
regulatory liabilities or regulatory assets in accordance with SFAS 71. These
deferrals generally are amortized when refunded or billed to customers in later
months with the regulator's review and approval. See also Note 6 "Effects of
Regulation".
We are protected from fuel cost changes in Kentucky for KPCo, the SPP area of
Texas, Louisiana and Arkansas for SWEPCo, Oklahoma for PSO and Virginia for
APCo. Where fuel clauses have been eliminated due to the transition to market
pricing, (Ohio effective January 1, 2001 and in the Texas ERCOT area effective
January 1, 2002) changes in fuel costs impact earnings. In other state
jurisdictions, (Indiana, Michigan and West Virginia) where fuel clauses have
been frozen or suspended for a period of years, fuel cost changes also impact
earnings currently. See Note 5, "Rate Matters" and Note 7, "Customer Choice and
Industry Restructuring" for further information about fuel recovery.
Revenue Recognition - We recognize revenues from generation, transmission and
distribution of electricity. The revenues associated with these activities are
recorded when earned as physical commodities are delivered to contractual meter
points or services are provided. These revenues also include the accrual of
earned, but unbilled and/or not yet metered revenues. Such revenues are based on
contract prices or tariffs. Revenue recognition for energy marketing and trading
transactions is further discussed within the Energy Marketing and Trading
Transactions section below. The Company follows EITF 98-10 and marks to market
energy trading activities, which includes the net change in fair value of open
trading contracts in earnings. Mark-to-market gains and losses on open contracts
and net settlements of financial contracts (see below) are included in operating
revenues and nonoperating income, respectively, on a net basis. The net basis of
reporting for open contracts is permitted by EITF 98-10 and for settled
financial contracts is consistent with industry practice. Settled physical
forward trading transactions are reported on a net basis, as permitted by EITF
98-10.
Energy Marketing and Trading Transactions - AEP engages in wholesale electricity
marketing and trading transactions (trading activities). Trading activities
involve the purchase and sale of energy under forward contracts at fixed and
variable prices and the trading of financial energy contracts which includes
exchange futures and options and over-the-counter options and swaps. Although
trading contracts are generally short-term, there are long-term trading
contracts.
The majority of trading activities represent forward electricity contracts that
are typically settled by entering into offsetting physical contracts. Prior to
settlement the change in fair values of forward sale and purchase contracts are
included in AEP's revenues.
All of the registrant subsidiaries except AEGCo participate in AEP's wholesale
marketing and trading of electricity. APCo, CSPCo, I&M, KPCo and OPCo record
forward electricity trading sale and purchase contracts net in operating
revenues when the contracts settle for contracts with delivery points in AEP's
traditional marketing area and in nonoperating income for forward electricity
trading sale and purchase contracts outside AEP's traditional marketing area.
CPL, PSO, SWEPCo and WTU record forward electricity trading sale and purchase
contracts net in operating revenues.
APCo, CSPCo and OPCo account for open forward electricity sale and purchase
contracts on a mark-to-market basis and include the mark-to-market change in
operating revenues for open contracts in AEP's traditional marketing area and in
nonoperating income for open contracts beyond AEP's traditional marketing area.
I&M and KPCo account for open forward electricity sale and purchase contracts on
a mark-to-market basis and defer the mark-to-market change as regulatory assets
or liabilities for those open contracts in AEP's traditional marketing area and
include the mark-to-market change in nonoperating income for open contracts
beyond AEP's traditional marketing area.
CPL, PSO, SWEPCo and WTU account for open forward electricity sale and purchase
contracts on a mark-to-market basis. CPL includes the mark-to-market change for
open electricity trading contracts in revenues. PSO defers as regulatory assets
or liabilities the mark-to-market change for open forward electricity trading
contracts that are included in cost of service on a settlement basis for
ratemaking purposes. SWEPCo and WTU include the jurisdictional share of the
mark-to-market change in revenues for open electricity trading contracts for
those jurisdictions that are not subject to SFAS 71 cost based rate regulation
and defer as regulatory assets or liabilities the jurisdictional share of the
mark-to-market change for open contracts that are included in cost of service on
a settlement basis for ratemaking purposes.
Trading purchases and sales through electricity options, futures and swaps,
represent financial transactions with the net proceeds reported in nonoperating
income at fair value upon entering the contracts.
APCo, CSPCo, I&M, KPCo and OPCo share in AEP's trading sales and purchases
through electricity options, futures and swaps, which represent financial
transactions. Changes in fair values of these financial contracts are reported
net in nonoperating income. When these contracts settle, the net proceeds are
recorded in nonoperating income and the prior unrealized gain or loss is
reversed.
Recording of the net changes in fair value of open trading contracts is commonly
referred to as mark-to-market accounting.
All open contracts from trading activities are marked to market in accordance
with EITF 98-10. Except as noted above, the net mark-to-market (change in fair
value) amount included in results of operations on a net discounted basis. The
fair values of open short-term trading contracts are based on exchange prices
and broker quotes. Open long-term trading contracts are marked to market based
mainly on internally developed valuation models. The valuation models produce an
estimated fair value for open long-term trading contracts. The short-term and
long-term fair values are present valued and reduced by appropriate reserves for
counterparty credit risks and liquidity risk. The models are derived from
internally assessed market prices. Bid/ask price curves are developed for
inclusion in the model based on broker quotes and other available market data.
The curves are within the range between the bid and ask price. The end of the
month liquidity reserve is based on the difference in price between the price
curve and the bid side of the bid ask if we have a long position and the ask
side if we have a short position. This provides for a conservative valuation net
of the reserves. The use of these models to fair value open trading contracts
has inherent risks relating to the underlying assumptions employed by such
models. Independent controls are in place to evaluate the reasonableness of the
price curve models. Significant adverse or favorable effects on future results
of operations and cash flows could occur if market risks, at the time of
settlement, do not correlate with internally developed price models.
The effect of marking to market open electricity trading contracts in regulated
jurisdictions is deferred as regulatory assets or liabilities since these
transactions are included in cost of service on a settlement basis for
ratemaking purposes. Unrealized mark-to-market gains and losses from trading
activities whether deferred or recognized in revenues are part of Energy Trading
and Derivative Contracts assets or liabilities as appropriate.
Hedging and Related Activities - In order to mitigate the risks of market price
and interest rate fluctuations, certain subsidiaries utilize interest swaps and
currency swaps to hedge such market fluctuations. Changes in the market value of
these swaps are deferred until the gain or loss is realized on the underlying
hedged asset, liability or commodity. To qualify as a hedge, these transactions
must be designated as a hedge and changes in their fair value must correlate
with changes in the price and interest rate movement of the underlying asset,
liability or commodity. This in effect reduces exposure to the effects of market
fluctuations related to price and interest rates.
APCo, CSPCo, I&M, and OPCo enter into contracts to manage the exposure to
unfavorable changes in the cost of debt to be issued. These anticipatory debt
instruments are entered into in order to manage the change in interest rates
between the time a debt offering is initiated and the issuance of the debt
(usually a period of 60 days). Gains or losses from these transactions are
deferred and amortized over the life of the debt issuance with the amortization
included in interest charges. There were no such forward contracts outstanding
at December 31, 2001 or 2000. See Note 12 - "Risk Management, Financial
Instruments and Derivatives" for further discussion of the accounting for risk
management transactions.
Levelization of Nuclear Refueling Outage Costs - In order to match costs with
regulated revenues, incremental operation and maintenance costs associated with
periodic refueling outages at I&M's Cook Plant are deferred and amortized over
the period beginning with the commencement of an outage and ending with the
beginning of the next outage.
Maintenance Costs - Maintenance costs are expensed as incurred except where SFAS
71 requires the recordation of a regulatory asset to match the expensing of
maintenance costs with their recovery in cost based regulated revenues. See
below for an explanation of costs deferred in connection with an extended outage
at I&M's Cook Plant.
Amortization of Cook Plant Deferred Restart Costs - Pursuant to settlement
agreements approved by the IURC and the MPSC to resolve all issues related to an
extended outage of the Cook Plant, I&M deferred $200 million of incremental
operation and maintenance costs during 1999. The deferred amount is being
amortized to expense on a straight-line basis over five years from January 1,
1999 to December 31, 2003. I&M amortized $40 million in 2001, 2000 and 1999
leaving $80 million as an SFAS 71 regulatory asset at December 31, 2001 on the
Consolidated Balance Sheets of I&M.
Other Income and Other Expenses - Other Income includes equity earnings of
non-consolidated subsidiaries, gains on dispositions of property, interest and
dividends, an allowance for equity funds used during construction (explained
above) and various other non-operating and miscellaneous income. Other Expenses
includes losses on dispositions of property, miscellaneous amortization,
donations and various other non-operating and miscellaneous expenses.
Income Taxes - The AEP System follows the liability method of accounting for
income taxes as prescribed by SFAS 109, "Accounting for Income Taxes." Under the
liability method, deferred income taxes are provided for all temporary
differences between the book cost and tax basis of assets and liabilities which
will result in a future tax consequence. Where the flow-through method of
accounting for temporary differences is reflected in regulated revenues (that
is, deferred taxes are not included in the cost of service for determining
regulated rates for electricity), deferred income taxes are recorded and related
regulatory assets and liabilities are established in accordance with SFAS 71 to
match the regulated revenues and tax expense.
Investment Tax Credits - Investment tax credits have been accounted for under
the flow-through method except where regulatory commissions have reflected
investment tax credits in the rate-making process on a deferral basis.
Investment tax credits that have been deferred are being amortized over the life
of the regulated plant investment.
Excise Taxes - AEP's subsidiary registrants, as agents for state or local
governments, collect from customers certain excise taxes levied by the state or
local government upon the customer. These taxes are not recorded as revenue or
expense, but only as a pass-through billing to the customer to be remitted to
the government entity. Excise tax collections and payments related to taxes
imposed upon the customer are not presented in the income statement.
Debt and Preferred Stock - Gains and losses from the reacquisition of debt used
to finance regulated electric utility plant are generally deferred and amortized
over the remaining term of the reacquired debt in accordance with their
rate-making treatment. If debt associated with the regulated business is
refinanced, the reacquisition costs attributable to the portions of the business
that are subject to cost based regulatory accounting under SFAS 71 are generally
deferred and amortized over the term of the replacement debt commensurate with
their recovery in rates. Gains and losses on the reacquisition of debt for
operations not subject to SFAS 71 are reported as a component of net income.
Debt discount or premium and debt issuance expenses are deferred and amortized
over the term of the related debt, with the amortization included in interest
charges. Where rates are regulated redemption premiums paid to reacquire
preferred stock of the utility subsidiaries are included in paid-in capital and
amortized to retained earnings commensurate with their recovery in rates. The
excess of par value over costs of preferred stock reacquired is credited to
paid-in capital and amortized to retained earnings consistent with the timing of
its inclusion in rates in accordance with SFAS 71.
Nuclear Trust Funds - Nuclear decommissioning and spent nuclear fuel trust funds
represent funds that regulatory commissions have allowed us to collect through
rates to fund future decommissioning and spent fuel disposal liabilities. By
rules or orders, the state jurisdictional commissions (Indiana, Michigan and
Texas) and the FERC established investment limitations and general risk
management guidelines to protect their ratepayers' funds and to allow those
funds to earn a reasonable return. In general, limitations include:
o Acceptable investments (rated investment grade or above)
o Maximum percentage invested in a specific type of investment
o Prohibition of investment in obligations of the applicable company or its
affiliates.
Trust funds are maintained for each regulatory jurisdiction and managed by
investment managers, who must comply with the guidelines and rules of the
applicable regulatory authorities. The trust assets are invested in order to
optimize the after-tax earnings of the Trust, giving consideration to liquidity,
risk, diversification, and other prudent investment objectives.
Securities held in trust funds for decommissioning nuclear facilities and for
the disposal of spent nuclear fuel are included in Other Assets at market value
in accordance with SFAS 115, "Accounting for Certain Investments in Debt and
Equity Securities." Securities in the trust funds have been classified as
available-for-sale due to their long-term purpose. In accordance with SFAS 71,
unrealized gains and losses from securities in these trust funds are not
reported in equity but result in adjustments to the liability account for the
nuclear decommissioning trust funds and to regulatory assets or liabilities for
the spent nuclear fuel disposal trust funds in accordance with their treatment
in rates.
Comprehensive Income - Comprehensive income is defined as the change in equity
(net assets) of a business enterprise during a period from transactions and
other events and circumstances from non-owner sources. It includes all changes
in equity during a period except those resulting from investments by owners and
distributions to owners. Comprehensive income has two components, net income and
other comprehensive income. There were no material differences between net
income and comprehensive income for AEGCo, CPL, CSPCo, PSO, SWEPCo and WTU.
Components of Other Comprehensive Income - Accumulated Other Comprehensive
Income for AEP registrant subsidiaries as of December 31, 2001, is shown in
the following table. Registrant subsidiary balances for Accumulated Other
Comprehensive Income for the two years ended December 31, 2000 and 1999 were
zero.
December 31,
Components 2001
(thousands)
Foreign Currency Rate Hedge
APCo $ (340)
I&M (3,835)
KPCo (1,903)
OPCo (196)
Segment Reporting - The AEP System has adopted SFAS No. 131, which requires
disclosure of selected financial information by business segment as viewed by
the chief operating decision-maker. See Note 11 "Business Segments" for further
discussion and details regarding segments.
Reclassification - Certain prior year financial statement items have been
reclassified to conform to current year presentation. Such reclassification had
no impact on previously reported net income.
2. Extraordinary Items and Cumulative Effect:
Extraordinary Items - Extraordinary items were recorded for the discontinuance
of regulatory accounting under SFAS 71 for the generation portion of the
business in the Ohio, Virginia, West Virginia, Texas and Arkansas state
jurisdictions. See Note 7 "Customer Choice and Industry Restructuring" for
descriptions of the restructuring plans and related accounting effects. OPCo and
CSPCo recognized an extraordinary loss for stranded Ohio Public Utility Excise
Tax (commonly known as the Gross Receipts Tax - GRT) net of allowable Ohio coal
credits during the quarter ended June 30, 2001. This loss resulted from
regulatory decisions in connection with Ohio deregulation which stranded the
recovery of the GRT. Effective with the liability affixing on May 1, 2001, CSPCo
and OPCo recorded an extraordinary loss under SFAS 101. Both Ohio companies have
appealed to the Ohio Supreme Court the PUCO order on Ohio restructuring that the
Ohio companies believe failed to provide for recovery for the final year of the
GRT. The Ohio Supreme Court decision is expected in 2002.
In October 2001 CPL reacquired $101 million of pollution control bonds in
advance of their maturity. Since these pollution control bonds were used to
finance generation assets, a loss of $2 million after tax was recorded.
Cumulative Effect of Accounting Change - The FASB's Derivative Implementation
Group (DIG) issued accounting guidance under SFAS 133 for certain derivative
fuel supply contracts with volumetric optionality and derivative electricity
capacity contracts. This guidance, effective in the third quarter of 2001,
concluded that fuel supply contracts with volumetric optionality cannot qualify
for a normal purchase or sale exclusion from mark-to-market accounting and
provided guidance for determining when electricity capacity contracts can
qualify as a normal purchase or sale.
Predominantly all of AEP's fuel supply contracts for coal and gas and contracts
for electricity capacity, which are recorded on a settlement basis, do not meet
the criteria of a financial derivative instrument or qualify as a normal
purchase or sale. Therefore, AEP's contracts are generally exempt from the DIG
guidance described above. Beginning July 1, 2001, the effective date of the DIG
guidance, certain of AEP's fuel supply contracts with volumetric optionality
that qualify as financial derivative instruments are marked to market with any
gain or loss recognized in the income statement.
3. Merger:
On June 15, 2000, AEP, parent company of the electric operating companies,
merged with CSW so that CSW and its electric operating companies became a
wholly-owned subsidiary of AEP. Under the terms of the merger agreement,
approximately 127.9 million shares of AEP Common Stock were issued in exchange
for all the outstanding shares of CSW Common Stock based upon an exchange ratio
of 0.6 share of AEP Common Stock for each share of CSW Common Stock. Following
the exchange, former shareholders of AEP owned approximately 61.4 percent of the
corporation, while former CSW shareholders owned approximately 38.6 percent of
the corporation.
The merger was accounted for as a pooling of interests. Certain
reclassifications have been made to conform the historical financial statement
presentation of the electric operating companies of AEP and CSW.
As a result of the merger, certain electric operating companies include an
adjustment to conform vacation pay accruals.The following table shows the
vacation accrual conforming adjustment for CSW's registrant utility
subsidiaries:
Net Income
Reductions
Net Asset Year Ended
Reduction at December 31,
December 31, 1999 1999
----------------- ----
(in millions)
CPL $5.3 $0.7
PSO 2.8 1.1
SWEPCo 4.5 0.5
WTU 2.6 0.4
In connection with the merger, non-recoverable merger costs were expensed in
2001 and 2000. Such cost included transaction and transition costs not
recoverable from ratepayers. Merger transaction and transition costs recoverable
from ratepayers were deferred pursuant to state regulator approved settlement
agreements through December 31, 2001. The deferred merger costs are being
amortized over five to eight year recovery periods, depending on the specific
terms of the settlement agreements, and are included in depreciation and
amortization expense.
The following tables show the deferred merger cost and amortization expense of
the applicable subsidiary registrants:
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2000 December 31, 2000
----------------- -----------------
(in millions)
CPL $14.4 $1.3
I&M 6.9 0.7
KPCo 2.5 0.3
PSO 7.9 0.5
SWEPCo 6.1 0.5
WTU 4.2 0.4
Amortization
Merger Cost Expense for the
Deferral at Year Ended
December 31, 2001 December 31, 2001
----------------- -----------------
(in millions)
CPL $11.8 $2.6
I&M 9.1 1.7
KPCo 3.2 0.6
PSO 6.6 1.2
SWEPCo 5.0 1.1
WTU 3.5 0.8
Merger transition costs are expected to continue to be incurred for several
years after the merger and will be expensed or deferred for amortization as
appropriate. As hereinafter summarized, the state settlement agreements provide
for, among other things, a sharing of net merger savings with certain regulated
customers over periods of up to eight years through rate reductions which began
in the third quarter of 2000.
Summary of key provisions of Merger Rate Agreements:
State/Company Ratemaking Provisions
- ------------- ---------------------
Texas - CPL, SWEPCo $221 million rate reduction
WTU over 6 years. No base rate increases for 3 years
post merger.
Indiana - I&M $67 million rate reduction
over 8 years. Extension of
base rate freeze until
January 1, 2005. Requires
additional annual deposits of
$6 million to the nuclear
decommissioning trust fund for
the years 2001 through 2003.
Michigan - I&M Customer billing credits of approximately $14
million over 8 years. Extension of base rate freeze
until January 1, 2005.
Kentucky - KPCo Rate reductions of approximately $28 million
over 8 years. No base rate increases for 3 years post
merger.
Oklahoma - PSO Rate reductions of approximately $28 million
over 5 years. No base rate increase before January 1,
2003.
Arkansas - SWEPCo Rate reductions of $6 million
over 5 years.
Louisiana - SWEPCo Rate reductions of $18 million over 8 years.
Base rate cap until June 2005.
If actual merger savings are significantly less than the merger savings rate
reductions required by the merger settlement agreements in the eight-year period
following consummation of the merger, future results of operations, cash flows
and possibly financial condition could be adversely affected.
See Note 8, "Commitments and Contingencies" for information on a recent court
decision concerning the merger.
4. Nuclear Plant Restart:
I&M completed the restart of both units of the Cook Plant in 2000. Cook Plant
is a 2,110 MW two-unit plant owned and operated by I&M under licenses granted
by the NRC. I&M shut down both units of the Cook Plant in September 1997 due
to questions regarding the operability of certain safety systems that arose
during a NRC architect engineer design inspection.
Settlement agreements in the Indiana and Michigan retail jurisdictions that
address recovery of Cook Plant related outage costs were approved in 1999. The
IURC approved a settlement agreement that resolved all matters related to the
recovery of replacement energy fuel costs and all outage/restart costs and
related issues during the extended outage of the Cook Plant. The MPSC approved
a settlement agreement for two open Michigan power supply cost recovery
reconciliation cases that resolved all issues related to the Cook Plant
extended outage. The settlement agreements allowed:
o deferral of $200 million of non-fuel restart-related nuclear operation and
maintenance expense for amortization over five years ending December 31,
2003,
o deferral of certain unrecovered fuel and power supply costs for
amortization over five years ending December 31, 2003,
o a freeze in base rates through December 31, 2003 and a fixed fuel recovery
charge through March 1, 2004 in the Indiana jurisdiction, and
o a freeze in base rates and fixed power supply costs recovery factors until
January 1, 2004 for the Michigan jurisdiction.
The amounts of restart costs charged to other operation and maintenance expenses
were as follows:
Year Ended December 31,
2001 2000 1999
---- ---- ----
Costs Incurred $ 1 $297 $ 289
Deferred Pursuant to
Settlement Agreements - - (200)
Amortization of Deferrals 40 40 40
-- -- --
Charged to O&M Expense $41 $337 $ 129
=== ==== =====
At December 31, 2001 and 2000, deferred restart costs of $80 million and $120
million, respectively, remained in regulatory assets to be amortized through
2003. Also pursuant to the settlement agreements, accrued fuel-related revenues
of $38 million in 2001 and 2000 and $37 million in 1999 were amortized. At
December 31, 2001 and 2000, fuel-related revenues of $75 million and $113
million, respectively, were included in regulatory assets and will be amortized
through December 31, 2003 for both jurisdictions.
The amortization of restart costs and fuel-related revenues deferred under
Indiana and Michigan retail jurisdictional settlement agreements will adversely
affect results of operations through December 31, 2003 when the amortization
period ends. The annual amortization of restart cost and fuel-related revenue
deferrals is $78 million.
5. Rate Matters:
Texas Jurisdictional Fuel Filings - AEP's Texas electric operating companies
experienced significant natural gas price increases in the second half of 2000
and early 2001 which resulted in under-recovery of fuel costs and the need to
seek increases in fuel rates and surcharges to recover these under-recoveries.
During 2001 gas price declines and PUCT-approved fuel rate and fuel surcharge
increases resulted in lower unrecovered fuel balances for SWEPCo and WTU and an
overrecovered balance for CPL at the end of 2001.
Fuel recovery for Texas utilities is a multi-step procedure. When fuel costs
change, utilities file with the PUCT for authority to adjust fuel factors. If a
utility's prior fuel factors result in an over- or under-recovery of fuel, the
utility will also request a surcharge factor to refund or collect that amount.
While fuel factors are intended to recover all fuel-related costs, final
settlement of these accounts are subject to reconciliation and approval by the
PUCT.
Fuel reconciliation proceedings determine whether fuel costs incurred and
collected during the reconciliation period were reasonable and necessary. All
fuel costs incurred since the prior reconciliation date are subject to PUCT
review and approval. If material amounts are determined to be unreasonable and
ordered to be refunded to customers, results of operations and cash flows would
be negatively impacted.
According to Texas Restructuring Legislation, fuel cost in the Texas
jurisdiction after 2001 will no longer be subject to PUCT review and
reconciliation. During 2002 CPL and WTU will file final fuel reconciliations
with the PUCT to reconcile their fuel costs through the period ending December
31, 2001. The ultimate recovery of deferred fuel balances at December 31, 2001
will be decided as part of their 2004 true-up proceedings. If the final
under-recovered fuel balances or any amounts incurred but not yet reconciled are
disallowed, it would have a negative impact on results of operations and cash
flows.
In October 2001 the PUCT delayed the start of customer choice in the SPP area of
Texas. All of SWEPCo's Texas service territory and a small portion of WTU's
service territory are in the SPP. SWEPCo's fuel cost recovery procedures will
continue until competition begins. SWEPCo will continue to set fuel factors and
determine final fuel costs in fuel reconciliation proceedings during the SPP
delay period. The PUCT has ruled that WTU fuel factors in the SPP area will be
based upon the price to beat fuel factors offered by the WTU retail electric
provider in the ERCOT portion of WTU's service territory. The PUCT has initiated
a proceeding to determine the most appropriate method to reconcile fuel costs in
WTU's SPP area.
The following table lists the status of Texas jurisdictional reconciliation,
fuel cost subject to reconciliation and under(over)-recovered fuel balances:
Fuel cost subject
to reconciliation
Reconciliation at December 31, 2001
completed through
----------------- --------------------
Company
CPL June 30, 1998 $1.6 billion
SWEPCo December 31, 1999 314 million
WTU June 30, 2000 303 million
Under (Over)
-recovered fuel
balances at
Company December 31, 2001
CPL $(58) million
SWEPCo 7 million
WTU 34 million
During 2001 CPL, SWEPCo and WTU requested and received approval to increase
their fuel rates. In orders issued in 2001 the PUCT delayed consideration of
fuel surcharges for CPL and WTU to recover their underrecovered fuel until the
2004 true-up proceedings. CPL's net underrecovered position was eliminated
between the order date and year end 2001 as gas prices declined. For SWEPCo the
PUCT deferred $6.8 million of Texas jurisdictional unrecovered fuel for
consideration in a future proceeding.
Under Texas restructuring, newly organized retail electric providers will make
sales to consumers beginning January 1, 2002. These sales will be at fixed rates
during a transition period from 2002 through 2006. However, the fuel cost
component of a retail electric providers' fixed rates will be subject to
prospective adjustment twice a year based upon changes in a natural gas price
index. As part of the preparation for customer choice, CPL, SWEPCo and WTU filed
their proposed fuel factors to be implemented as part of the fixed rates
effective January 1, 2002. Fuel factors approved for CPL's and WTU's retail
electric providers were effective January 1, 2002. Due to the SPP area
competition delay, SWEPCo's proceeding was postponed.
WTU Fuel Filings - In December 2000 WTU filed with the PUCT an application to
reconcile fuel costs. During the reconciliation period of July 1, 1997 through
June 30, 2000, WTU incurred $348 million of Texas jurisdiction eligible fuel and
fuel-related expenses. In February 2002 the PUCT approved WTU's fuel cost for
the reconciliation period except for a disallowance of less than $50,000.
Texas Transmission Rates - On June 28, 2001, the Supreme Court of Texas ruled
that the transmission pricing mechanism created by the PUCT in 1996 was invalid.
The court upheld an appeal filed by unaffiliated Texas utilities that the PUCT
exceeded its statutory authority to set such rates for the period January 1,
1997 through August 31, 1999. Effective September 1, 1999, the legislature
granted this authority to the PUCT. CPL and WTU were not parties to the case.
However, the companies' transmission sales and purchases were priced using the
invalid rates. It is unclear what action the PUCT will take to respond to the
court's ruling. If the PUCT changes rates retroactively, the result could have a
material impact on results of operations and cash flows for CPL and WTU.
FERC Wholesale Fuel Complaints - In May 2000 certain WTU wholesale customers
filed a complaint with FERC alleging that WTU had overcharged them through the
fuel adjustment clause for certain purchased power costs related to 1999
unplanned outages at WTU's Oklaunion generation station. In November 2001
certain WTU wholesale customers filed an additional complaint at FERC asserting
that since 1997 WTU had billed wholesale customers for not only the 1999
Oklaunion outage costs, but also certain additional costs that are not
permissible under the fuel adjustment clause.
In December 2001 FERC issued an order requiring WTU to refund, with interest,
amounts associated with the May 2000 complaint that were previously billed to
wholesale customers. The effects of this order were recorded in 2001 and
management believes that as of December 31, 2001, it has fully provided for that
over billing. In response to the November 2001 complaint, management is working
to determine amounts of additional costs inappropriately billed to wholesale
customers, which could result in refunds, with interest. At this time,
management is unable to predict the negative impact this complaint will have on
future results of operations, cash flow and financial condition.
FERC Transmission Rates - In November 2001 FERC issued an order requiring CPL,
PSO, SWEPCo and WTU to submit revised open access transmission tariffs, and
calculate and issue refunds for overcharges from January 1, 1997. The order
resulted from a remand by an appeals court of a tariff compliance filing order
issued in November 1998 that had been appealed by certain customers. CPL and WTU
recorded refund provisions of $1.7 million and $0.7 million, respectively,
including interest in 2001 for this order. PSO and SWEPCo recorded $100,000 each
for this order making the AEP total $2.6 million.
West Virginia - On June 2, 2000, the WVPSC approved a Joint Stipulation between
APCo and other parties related to base rates and ENEC recoveries. The Joint
Stipulation allows for recovery of regulatory assets including any
generation-related regulatory assets through the following provisions:
o Frozen transition rates and a wires charge of 0.5 mills per KWH.
o The retention, as a regulatory liability, on the books of a net cumulative
deferred ENEC over-recovery balance of $66 million to be used to offset
the cost of deregulation when generation is deregulated in WV.
o The retention of net merger savings prior to December 31, 2004 resulting from
the merger of AEP and CSW. o A 0.5 mills per KWH wires charge for departing
customers provided for in the WV Restructuring Plan (see
Note 7 "Customer Choice and Industry Restructuring" for discussion of the
WV Restructuring Plan)
Management expects that the approved Joint Stipulation, plus the provisions of
pending restructuring legislation will, if the legislation becomes effective,
provide for the recovery of existing regulatory assets, other stranded costs and
the cost of deregulation in WV.
6. Effects of Regulation:
In accordance with SFAS 71 the financial statements include regulatory assets
(deferred expenses) and regulatory liabilities (deferred revenues) recorded in
accordance with regulatory actions in order to match expenses and revenues from
cost-based rates in the same accounting period. Regulatory assets are expected
to be recovered in future periods through the rate-making process and regulatory
liabilities are expected to reduce future cost recoveries. Among other things,
application of SFAS 71 requires that regulated rates be cost-based and the
recovery of regulatory assets be probable. Management has reviewed all the
evidence currently available and concluded that the requirements to apply SFAS
71 continue to be met for all electric operations in Indiana, Kentucky,
Louisiana, Michigan, Oklahoma and Tennessee.
When the generation portion of the electric utility operating companies'
business in Arkansas, Ohio, Texas, Virginia and WV no longer met the
requirements to apply SFAS 71, net regulatory assets were written off for that
portion of the business unless they were determined to be recoverable as a
stranded cost through regulated distribution rates or wire charges in accordance
with SFAS 101 and EITF 97-4. In the Ohio and WV jurisdictions generation-related
regulatory assets that are recoverable through transition rates have been
transferred to the distribution portion of the business and are being amortized
as they are recovered through charges to regulated distribution customers. As
discussed in Note 7, "Customer Choice and Industry Restructing" the Virginia SCC
ordered the generation-related regulatory assets in the Virginia jurisdiction to
remain with the generation portion of the business. Generation-related
regulatory assets in the Virginia jurisdiction are being amortized concurrent
with their recovery through capped rates. In the Texas jurisdiction
generation-related regulatory assets that have been tentatively approved for
recovery through securitization have been classified as "regulatory assets
designated for securitization." (See Note 7 "Customer Choice and Industry
Restructuring" for further details.)
The recognized regulatory assets and liabilities for the registrant subsidiaries
are of two types: those earning a return and those not earning a return. Items
not earning a return have their recovery period end date indicated. Regulatory
assets and liabilities are comprised of the following items:
AEGCo APCo
----------------------------- ----------------------------
Recovery Recovery
2001 2000 Period 2001 2000 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $(22,725) $(23,996) Note 1 $189,794 $217,540 Note 1
Transition - Regulatory
Assets Virginia 46,981 55,523 Jun. 2007
Transition - Regulatory
Assets West Virginia 127,998 135,946 Jun. 2011
Deferred Fuel Costs 11,732 14,669
Unamortized Loss on
Reacquired Debt 5,207 5,504 Note 2 10,421 11,676 Note 2
Deferred Storm Damage 6 1,244 Apr. 2002
Other 71,890 11,152 Note 3
--------- -------- -------- --------
Total Regulatory Assets $(17,518) $(18,492) $458,822 $447,750
========= ========= ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $56,304 $59,718 $ 38,328 $ 43,093
WV Rate Stabilization 75,601 75,601
Other 61,552 2,614
------- ------- -------- --------
Total Regulatory Liabilities $56,304 $59,718 $175,481 $121,308
======= ======= ======== ========
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-seven years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery periods.
CPL CSPCo
----------------------------- ----------------------------
Recovery Recovery
2001 2000 Period 2001 2000 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $200,496 $ 206,930 Note 1 $ 28,361 $ 31,853 Note 1
Transition - Regulatory
Assets 223,830 247,852 Dec. 2008
Excess Earnings (62,852) (39,700)
Regulatory Assets -
Designated For Securitization 959,294 953,249
Deferred Fuel Costs (57,762) 127,295 - -
Unamortized Loss on
Reacquired Debt 11,180 12,773 Note 2 7,010 8,340 Note 2
DOE Decontamination and
Decommissioning Assessment 3,170 3,622 Dec. 2004
Other 11,961 18,815 Note 3 3,066 3,508 Note 3
---------- ---------- -------- --------
Total Regulatory Assets $1,065,487 $1,282,984 $262,267 $291,553
========== ========== ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $122,893 $128,100 $37,176 $41,234
Other 31 11,510
-------- -------- ------- -------
Total Regulatory Liabilities $122,893 $128,100 $37,207 $52,744
======== ======== ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-seven years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery periods.
I&M KPCo
----------------------------- ----------------------------
Recovery Recovery
2001 2000 Period 2001 2000 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $171,605 $229,466 Note 1 $83,027 $85,926 Note 1
Deferred Fuel Costs 75,002 112,503 Dec. 2003 1,542 - Feb. 2002
Unamortized Loss on
Reacquired Debt 16,255 17,740 Note 2 51 459 Note 2
Cook Plant Restart Costs 80,000 120,000 Dec. 2003
DOE Decontamination and
Decommissioning Assessment 27,784 31,744 Dec. 2008
Other 38,281 40,687 Note 3 13,073 12,130 Note 3
--------- -------- ------- -------
Total Regulatory Assets $408,927 $552,140 $97,693 $98,515
========= ========= ======= =======
Regulatory Liabilities:
Deferred Investment
Tax Credits $105,449 $113,773 $10,405 $11,656
Other 52,479 9,930 6,551 3,172
-------- -------- ------- -------
Total Regulatory Liabilities $157,928 $123,703 $16,956 $14,828
======== ======== ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-seven years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery periods.
OPCo PSO
----------------------------- ----------------------------
Recovery Recovery
2001 2000 Period 2001 2000 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $186,740 $180,602 Note 1 $(26,085) $(28,652) Note 1
Transition - Regulatory
Assets 442,707 517,851 Dec. 2007
Deferred Fuel Costs 11,732 43,267
Unamortized Loss on
Reacquired Debt 5,502 6,106 Note 2 12,321 13,600 Note 2
Other 9,676 10,151 Note 3 11,707 15,738 Note 3
--------- -------- -------- ---------
Total Regulatory Assets $644,625 $714,710 $ 9,675 $ 43,953
========= ======== ======== =========
Regulatory Liabilities:
Deferred Investment
Tax Credits $21,925 $25,214 $33,992 $35,783
Other 1,237 10,994 31,858 2,015
------- ------- ------- -------
Total Regulatory Liabilities $23,162 $36,208 $65,850 $37,798
======= ======= ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-seven years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery periods.
SWEPCo WTU
----------------------------- ----------------------------
Recovery Recovery
2001 2000 Period 2001 2000 Period
---- ---- -------- ---- ---- --------
(in thousands)
Regulatory Assets:
Amounts Due From Customers
For Future Income Taxes $16,553 $14,558 Note 1 $(13,591) $(13,493) Note 1
Deferred Fuel Costs 7,384 35,469 36,872 67,655
Unamortized Loss on
Reacquired Debt 19,726 22,626 Note 2 8,198 11,204 Note 2
Other 15,711 19,898 Note 3 5,460 13,604 Note 3
------- ------- -------- --------
Total Regulatory Assets $59,374 $92,551 $ 36,939 $ 78,970
======= ======== ======== ========
Regulatory Liabilities:
Deferred Investment
Tax Credits $48,714 $53,167 $22,781 $24,052
Excess Earnings 500 17,300 15,100
Other 15,454 8,140 5,700 -
------- ------- ------- -------
Total Regulatory Liabilities $64,168 $61,807 $45,781 $39,152
======= ======= ======= =======
Note 1: This amount fluctuates from month to month and has no fixed recovery
period.
Note 2: Unamortized loss on reacquired debt varies in its recovery period for
each registrant and ranges from one to thirty-seven years recovery period across
all registrants. Note 3: Other may include items not earning a return and would
have various recovery periods.
7. Customer Choice and Industry
Restructuring:
Prior to 2001 customer choice/industry restructuring legislation was passed in
Ohio, Texas, Virginia and Michigan allowing retail customers to select
alternative generation suppliers. Customer choice began on January 1, 2001 in
Ohio and on January 1, 2002 in Michigan, Virginia and in the ERCOT area of
Texas. AEP's subsidiaries operate in both the ERCOT and SPP areas of Texas.
Legislation enacted in Oklahoma, Arkansas and WV to allow retail customers to
choose their electricity supplier is not yet effective. In 2001 Oklahoma delayed
implementation of customer choice indefinitely. Arkansas delayed the start of
customer choice until as late as October 2005. The Arkansas Commission has
recommended further delays of the start date or repeal of the restructuring
legislation. Before West Virginia's choice plan can be effective, tax
legislation must be passed to continue consistent funding for state and local
government. No further legislation has been passed related to restructuring in
Arkansas or West Virginia.
In general, state restructuring legislation provides for a transition from
cost-based rate regulated bundled electric service to unbundled cost-based rates
for transmission and distribution service and market pricing for the supply of
electricity with customer choice of supplier.
Ohio Restructuring - Affecting CSPCo and OPCo
Customer choice of electricity supplier and restructuring began on January 1,
2001, under the Ohio Act. During 2001 alternative suppliers registered and were
approved by the PUCO as required by the Ohio Act. At January 1, 2002, virtually
all customers continue to receive supply service from CSPCo and OPCo with a
legislatively required residential generation rate reduction of 5%. All
customers continue to be served by CSPCo and OPCo for transmission and
distribution services.
The Ohio Act provides for a five-year transition period to move from cost based
rates to market pricing for electric generation supply services. It granted the
PUCO broad oversight responsibility for promulgation of rules for competitive
retail electric generation service, approval of a transition plan for each
electric utility company and addressed certain major transition issues including
unbundling of rates and the recovery of stranded costs including regulatory
assets and transition costs.
The Ohio Act made several changes in the taxation of electric companies.
Effective January 1, 2001 the assessment percentage for property taxes on all
electric company property other than transmission and distribution was lowered
from 100% to 25%. The assessment percentage applicable to transmission and
distribution property remains at 88%. Also, electric companies were exempted
from the excise tax based on receipts. To make up for these tax reductions
electric distribution companies became subject to a new KWH based excise tax.
Since electric companies no longer paid the gross receipts tax, they became
liable, as of January 1, 2002 for the corporation franchise tax and municipal
income taxes.
In preparation for the January 1, 2001 start of the transition period, CSPCo and
OPCo filed a transition plan in December 1999. After negotiations with
interested parties including the PUCO staff, the PUCO approved a stipulation
agreement for CSPCo's and OPCo's transition plans. The approved plans included,
among other things, recovery of generation-related regulatory assets over seven
years for OPCo and over eight years for CSPCo through frozen transition rates
for the first five years of the recovery period and through a wires charge for
the remaining years. At December 31, 2000, the amount of regulatory assets to be
amortized as recovered was $518 million for OPCo and $248 million for CSPCo.
The stipulation agreement required the PUCO to consider implementation of a
gross receipts tax credit rider as the parties could not reach an agreement.
As of May 1, 2001, electric distribution companies became subject to an excise
tax based on KWH sold to Ohio customers. The last tax year for which Ohio
electric utilities will pay the excise tax based on gross receipts is May 1,
2001 through April 30, 2002. As required by law, the gross receipts tax is paid
in advance of the tax year for which the utility exercises its privilege to
conduct business. CSPCo and OPCo treat the tax payment as a prepaid expense and
amortized it to expense during the tax year.
Following a hearing on the gross receipts tax issue, the PUCO determined that
there was no duplicate tax overlap period. The PUCO ordered the gross receipts
tax credit rider to be effective May 1, 2001 instead of May 1, 2002 as proposed
by the companies. This order reduced CSPCo's and OPCo's revenues by
approximately $90 million. CSPCo's and OPCo's request for rehearing of the gross
receipts tax issue was also denied by the PUCO. A decision on an appeal of this
issue to the Ohio Supreme Court is pending.
As described in Note 2, the PUCO's denial of the request for recovery of the
final year's gross receipts tax and the tax liability affixing on May 1, 2001
stranded the prepaid asset. As a result, an extraordinary loss was recorded in
2001.
One of the intervenors at the hearings for approval of the settlement agreement
(whose request for rehearing was denied by the PUCO) filed with the Ohio Supreme
Court for review of the settlement agreement. During 2001 that intervenor
withdrew from competing in Ohio. The Court dismissed the intervenor's appeal.
CSPCo's and OPCo's fuel costs were no longer subject to PUCO fuel clause
recovery proceedings beginning January 1, 2001. The elimination of fuel clause
recoveries in Ohio subjects CSPCo and OPCo to risk of fuel market price
variations and could adversely affect their results of operations and cash
flows.
Virginia Restructuring - Affecting APCo
In Virginia, choice of electricity supplier for retail customers began on
January 1, 2002 under its restructuring law. A finding by the Virginia SCC that
an effective competitive market exists would be required to end the transition
period.
The restructuring law provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
net stranded cost recovery are: a capping of rates until as late as July 1,
2007, and the application of a wires charge upon customers who depart the
incumbent utility in favor of an alternative supplier prior to the termination
of the rate cap. Capped rates are the rates in effect at July 1, 1999 if no rate
change request was made by the utility. APCo did not request new rates;
therefore, its current rates are its capped rates. Virginia's restructuring law
does not permit the Virginia SCC to change generation rates during the
transition period except for changes in fuel costs, changes in state gross
receipts taxes, or to address financial distress of the utility.
The Virginia restructuring law also requires filings to be made that outline the
functional separation of generation from transmission and distribution and a
rate unbundling plan. On January 3, 2001, APCo filed its corporate separation
plan and rate unbundling plan with the Virginia SCC. The Virginia SCC approved
settlement agreements that resolved most issues except the assignment of
generation-related regulatory assets among functionally separated generation,
transmission and distribution organizations. The Virginia SCC determined that
generation-related regulatory assets and related amortization expense should be
assigned to APCo's generation function. Presently, capped rates are sufficient
to recover generation-related regulatory assets. Therefore, management
determined that recovery of APCo's generation-related regulatory assets remains
probable. APCo will not collect a wires charge in 2002 per the settlement
agreements. The settlement agreements and related Virginia SCC order addressed
functional separation leaving decisions related to corporate separation for
later consideration. The Virginia SCC order approving the settlement agreements
requires several compliance filings, including a fuel/replacement power cost
report during an extended outage of an affiliate's nuclear plant. Management is
unable to predict the outcome of the Virginia SCC's review of APCo's compliance
filings.
Texas Restructuring - Affecting CPL, SWEPCo and WTU
On January 1, 2002, customer choice of electricity supplier began in the ERCOT
area of Texas. Customer choice has been delayed in other areas of Texas
including the SPP area. All of SWEPCo's Texas service territory and a small
portion of WTU's service territory are located in the SPP. CPL operates entirely
in the ERCOT area of Texas.
Texas restructuring legislation, among other things:
o provides for the recovery of regulatory assets and other stranded costs
through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o freezes rates until January 1, 2002;
o provides for an earnings test for each of the three years of the rate
freeze period (1999 through 2001) which will reduce stranded cost
recoveries or if there is no stranded cost provides for a refund or their
use to fund certain capital expenditures;
o requires each utility to structurally unbundle into a retail electric
provider, a power generation company and a transmission and distribution
utility;
o provides for certain limits for ownership and control of generating
capacity by companies;
o provides for elimination of the fuel clause reconciliation
process beginning January 1, 2002; and
o provides for a 2004 true-up proceeding
to determine recovery of stranded costs including final fuel
recovery balances, net regulatory assets, certain environmental costs,
accumulated excess earnings and other issues.
Under the Texas Legislation, delivery of electricity continues to be the
responsibility of the local electric transmission and distribution utility
company at regulated prices. Each electric utility was required to submit a plan
to structurally unbundle its business activities into a retail electric
provider, a power generation company, and a transmission and distribution
utility. In 2000 CPL, SWEPCo and WTU filed and the PUCT approved business
separation plans. The business separation plans provided for CPL and WTU to
establish separate companies and divide their integrated utility operations and
assets into a power generation company, a transmission and distribution utility
and a retail electric provider. In February 2002 the PUCT approved amendments to
SWEPCo's plan. The amended plan separates SWEPCo's Texas jurisdictional
transmission and distribution assets and operations into two new regulated
transmission and distribution subsidiaries. In addition, a retail electric
provider was established by SWEPCo to provide retail electric service to
SWEPCo's Texas jurisdictional customers. Until competition commences in the SPP,
SWEPCo's assets will not be separated and the SWEPCo retail electric provider
will not commence operation.
Due to the SPP area delay in the start of competition, only CPL's and WTU's
retail electric providers commenced operations on January 1, 2002. Operations
for CPL, SWEPCo and WTU have been functionally separated.
Under the Texas Legislation, electric utilities are allowed to recover stranded
generation costs including generation-related regulatory assets. The stranded
costs can be refinanced through securitization (a financing structure designed
to provide lower financing costs than are available through conventional
financings).
In 1999 CPL filed with the PUCT to securitize $1.27 billion of its retail
generation-related regulatory assets and $47 million in other qualified
restructuring costs. The PUCT authorized the issuance of up to $797 million of
securitization bonds ($949 million of generation-related regulatory assets and
$33 million of qualified refinancing costs offset by $185 million of customer
benefits for accumulated deferred income taxes). Four parties appealed to the
Supreme Court of Texas which upheld the PUCT's securitization order. CPL issued
its securitization bonds in February 2002.
CPL included regulatory assets not approved for securitization in its request
for recovery of $1.1 billion of stranded costs. The $1.1 billion request
included $800 million of STP costs included in property, plant and
equipment-electric on CPL's consolidated balance sheets. These STP costs had
previously been identified as excess cost over market (ECOM) by the PUCT for
regulatory purposes. They are earning a lower return and being amortized on an
accelerated basis for rate-making purposes.
After hearings on the issue of stranded costs, the PUCT ruled in October 2001
that its current estimate of CPL's stranded costs was negative $615 million. CPL
disagrees with the ruling. The ruling indicated that CPL's costs were below
market after securitization of regulatory assets. Management believes CPL has a
positive stranded cost exclusive of securitized regulatory assets. The final
amount of CPL's stranded costs including regulatory assets and ECOM will be
established by the PUCT in the 2004 true-up proceeding. If CPL's total stranded
costs determined in the 2004 true-up are less than the amount of securitized
regulatory assets, the PUCT can implement an offsetting credit to transmission
and distribution rates.
The PUCT ruled that prior to the 2004 true-up proceeding, no adjustments would
be made to the amount of regulatory costs authorized by the PUCT to be
securitized. However, the PUCT also ruled that excess earnings for the period
1999-2001 should be refunded through distribution rates to the extent of any
over-mitigation of stranded costs represented by negative ECOM. In 2001 the PUCT
issued an order requiring CPL to reduce distribution rates by $54.8 million plus
accrued interest over a five-year period beginning January 1, 2002 in order to
return estimated excess earnings for 1999, 2000 and 2001. The Texas Legislation
intended that excess earnings reduce stranded costs. Final stranded cost amounts
and the treatment of excess earnings will be determined in the 2004 true-up
proceeding. Currently the PUCT estimates that CPL will have no stranded costs
and has ordered the rate reduction to return excess earnings. Since CPL expensed
excess earnings amounts in 1999, 2000 and 2001, the order has no additional
effect on reported net income but will reduce cash flows for the five year
refund period. The amount to be refunded is recorded as a regulatory liability.
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 has
appealed the PUCT's estimate of stranded costs and refund of excess earnings to
the Travis County District Court. Unaffiliated parties also appealed the PUCT's
refund order contending the entire $615 million of negative stranded costs
should be refunded presently. Management is unable to predict the outcome of
this litigation. An unfavorable ruling would have a negative impact on results
of operations, cash flows and possibly financial condition.
The Texas Legislation allows for several alternative methods to be used to value
stranded costs in the final 2004 true-up proceeding including the sale or
exchange of generation assets, the issuance of power generation company stock to
the public or the use of an ECOM model. To the extent that the final 2004
true-up proceeding determines that CPL should recover additional stranded costs,
the additional amount recoverable can also be securitized.
The Texas Legislation provides for an earnings test each year of the 1999
through 2001 rate freeze period. For CPL, any earnings in excess of the most
recently approved cost of capital in its last rate case must be applied to
reduce stranded costs. Companies without stranded costs, including SWEPCo and
WTU, must pay any excess earnings to customers, invest them in improvements to
transmission or distribution facilities or invest them to improve air quality at
generating facilities. The Texas Legislation requires PUCT approval of the
annual earnings test calculation.
The PUCT issued a final order for the 1999 earnings test in February 2001 and
adjustments to the accrued 1999 and 2000 excess earnings were recorded in
results of operations in the fourth quarter of 2000. After adjustments the 1999
excess earnings for CPL and WTU were $24 million and $1 million, respectively.
SWEPCo had no excess earnings in 1999. The PUCT issued a final order in
September 2001 for the 2000 excess earnings. CPL's, SWEPCo's and WTU's excess
2000 earnings were $23 million, $1 million and $17 million, respectively. An
estimate of 2001 excess earnings of $8 million for CPL, $2 million for SWEPCo
and none for WTU has been recorded and will be adjusted, if necessary, in 2002
when the PUCT issues its final order regarding 2001 excess earnings.
Due to the companies' disagreement with the PUCT, its staff and the Office of
Public Utility Counsel related to the proper determination of 2000 excess
earnings, the companies filed in district court in October 2001 seeking judicial
review of the PUCT's determination of excess earnings. A decision from the court
is not expected until later in 2002.
Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel
reconciliation proceedings for CPL and WTU's ERCOT customers. Consequently, CPL
and WTU will file a final fuel reconciliation with the PUCT to reconcile their
fuel costs through the period ending December 31, 2001. Due to the delay of
competition for the SPP area, SWEPCo, which operates in the SPP area, continues
to record and request recovery of fuel costs under the Texas fuel reconciliation
proceeding. For WTU's SPP area customers, the PUCT will determine a method to
reconcile their fuel costs beginning in 2002 (see Note 5 "Rate Matters"). 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, they could have a negative
impact on results of operations. The elimination of the fuel clause recoveries
in 2002 in the ERCOT area of Texas will subject the retail electric providers of
CPL and WTU to greater risks of fuel market price increases and could adversely
affect future results of operations beginning in 2002.
The affiliated retail electric providers of CPL, SWEPCo and WTU are required by
the Texas Legislation to offer residential and small commercial customers (with
a peak usage of less than 1000 KW) a price-to-beat rate until January 1, 2007.
In December 2001 the PUCT approved price-to-beat rates for CPL's and WTU's
retail electric providers. Customers with a peak usage of more than 1000 KW are
subject to market rates. The Texas restructuring legislation provides for the
price to beat to be adjusted up to two times annually to reflect changes in fuel
and purchased energy costs using a natural gas price index.
Due to the delay in the start of competition in the SPP areas of Texas, several
issues are pending before the PUCT. These issues impact SWEPCo's and WTU's Texas
SPP operations. WTU's Texas SPP operations are estimated to be less than 5% of
WTU's total operations.
West Virginia Restructuring - Affecting APCo
In 2000 the WVPSC issued an order approving an electricity restructuring plan
which the WV Legislature approved by joint resolution. The joint resolution
provides that the WVPSC cannot implement the plan until the legislature makes
tax law changes necessary to preserve the revenues of state and local
governments. Since the WV Legislature has not passed the required tax law
changes, the restructuring plan has not become effective. APCo and WPCo, provide
electric service in WV.
The WV restructuring plan provides for:
o deregulation of generation assets
o separation of the generation, transmission and distribution businesses
o a transition period with capped and fixed rates for up to 13 years
o establishment of a rate stabilization deferred liability balance of
$81 million ($76 million by APCo and $5 million by WPCo) by the end of
year ten of the transition period.
APCo's Joint Stipulation, discussed in Note 5 "Rate Matters" and approved by the
WVPSC in 2000 in connection with a base rate filing, provides additional
mechanisms to recover transition generation-related regulatory assets.
In order for customer choice to become effective in WV, the WV Legislature must
enact tax legislation. Management is unable to predict the timing of the passage
of such legislation.
Arkansas Restructuring - Affecting SWEPCo
In 1999 Arkansas enacted legislation to restructure its electric utility
industry. Major provisions of the legislation as amended are:
o retail competition delayed until as late as October 2005;
o transmission facilities must be operated by an ISO if owned by a company
which also owns generating facilities;
o rates will be frozen for one to three years;
o market power issues will be addressed by the Arkansas Commission; and
o an annual progress report to the Arkansas General Assembly on the
development of competition in electric markets and its impact on retail
customers is required.
Based on recommendations in the annual progress report filed by the Arkansas
Commission, the Arkansas General Assembly passed and the Governor signed
legislation in 2001 changing the start date of electric retail competition to
October 1, 2003, and providing the Arkansas Commission with authority to delay
that date for up to an additional two years.
The Arkansas Commission in December 2001 recommended further delays of the start
date or repeal of the restructuring legislation.
Discontinuance of the Application of SFAS 71 Regulatory Accounting in Arkansas,
Ohio, Texas, Virginia and West Virginia - Affecting APCo, CPL, CSPCo, OPCo,
SWEPCo and WTU
The enactment of restructuring legislation and the ability to determine
transition rates, wires charges and any resultant gain or loss under
restructuring legislation in Arkansas, Ohio, Texas, Virginia and West Virginia
enabled certain subsidiaries to discontinue regulatory accounting under SFAS 71
for the generation portion of their business in those states. Under the
provisions of SFAS 71, regulatory assets and regulatory liabilities are recorded
to reflect the economic effects of regulation by matching expenses with related
regulated revenues.
The discontinuance of the application of SFAS 71 in Arkansas, Ohio, Texas,
Virginia and West Virginia in accordance with the provisions of SFAS 101 and
EITF Issue 97-4 resulted in recognition of extraordinary gains or losses in 2000
and 1999. The discontinuance of SFAS 71 can require the write-off of regulatory
assets and liabilities related to the deregulated operations, unless their
recovery is provided through cost-based regulated rates to be collected in a
portion of operations which continues to be rate regulated. Additionally, a
company must determine if any plant assets are impaired when they discontinue
SFAS 71 accounting. At the time the companies discontinued SFAS 71, the analysis
showed that there was no accounting impairment of generation assets.
Prior to 1999, the electric utility operating companies' financial statements
reflected the economic effects of regulation under the requirements of SFAS 71.
As a result of deregulation of generation, the application of SFAS 71 for the
generation portion of the business in Arkansas, Ohio, Texas, Virginia and West
Virginia was discontinued. Remaining generation-related regulatory assets will
be amortized as they are recovered under terms of transition plans. Management
believes that substantially all generation-related regulatory assets and
stranded costs will be recovered under terms of the transition plans. If future
events including the 2004 true-up proceeding in Texas were to make their
recovery no longer probable, the applicable companies would write-off the
portion of such regulatory assets and stranded costs deemed unrecoverable as a
non-cash extraordinary charge to earnings. If any write-off of regulatory assets
or stranded costs occurred, it could have a material adverse effect on future
results of operations, cash flows and possibly financial condition.
Michigan Restructuring - Affecting I&M
On June 5, 2000, the Michigan Legislation became law. Its major provisions,
which were effective immediately, applied only to electric utilities with one
million or more retail customers. I&M has less than one million customers in
Michigan. Consequently, I&M was not immediately required to comply with the
Michigan Legislation.
The Michigan Legislation gives the MPSC broad power to issue orders to implement
retail customer choice of electric supplier no later than January 1, 2002
including recovery of regulatory assets and stranded costs. In compliance with
MPSC orders, on June 5, 2001, I&M filed its proposed unbundled rates, open
access tariffs and terms of service. On October 11, 2001, the MPSC approved a
settlement agreement which generally approved I&M's June 5, 2001 filing except
for agreed upon modifications. In accordance with the settlement agreement, I&M
agreed that recovery of implementation costs and regulatory assets would be
determined in future proceedings. The settlement agreement did not modify the
procedure for review of decom-missioning costs recoveries. Customer choice
commenced for I&M's Michigan customers on January 1, 2002. Effective with that
date the rates on I&M's Michigan customers' bills for retail electric service
were unbundled to allow customers the opportunity to evaluate the cost of
generation service for comparison with other offers. I&M's total rates in
Michigan remain unchanged and reflect cost of service. At this time, none of
I&M's customers have elected to change suppliers and no competing suppliers are
active in I&M's Michigan service territory.
Management has concluded that as of December 31, 2001 the requirements to apply
SFAS 71 continue to be met since I&M's rates for generation in Michigan continue
to be cost-based regulated. As a result I&M has not yet dis-continued regulatory
accounting under SFAS 71.
Oklahoma Restructuring - Affecting PSO
Under Oklahoma restructuring legislation passed in 1997 retail open access and
customer choice was scheduled to begin by July 1, 2002.
In June 2001 the Oklahoma Governor signed into law a bill to delay,
indefinitely, the implementation of the transition to customer choice and market
based pricing under restructuring legislation. Consequently, PSO will remain
rate-regulated until further legislation passes and continues the application of
SFAS 71 regulatory accounting.
8. Commitments and Contingencies:
Construction and Other Commitments - The following table shows the estimated
construction expenditures of the subsidiary registrants for 2002 - 2004:
(in millions)
AEGCo $171.9
APCo 815.5
CPL 573.1
CSPCo 408.7
I&M 556.9
KPCo 223.3
OPCo 1,008.0
PSO 364.9
SWEPCo 321.4
WTU 169.6
APCo, which operates in Virginia and West Virginia, has been seeking regulatory
approval to build a new high voltage transmission line for over a decade.
Through December 31, 2001 we had invested approximately $40 million in this
effort. If the required regulatory approvals are not obtained and the line is
not constructed, the $40 million investment would be written off adversely
affecting future results of operations and cash flows.
Long-term contracts to acquire fuel for electric generation have been entered
into for various terms. The expiration date of the longest fuel contract is 2006
for APCo, 2005 for CSPCo, 2014 for I&M, 2004 for KPCo, 2012 for OPCo, 2014 for
PSO, 2006 for SWEPCo and 2006 for WTU. The contracts provide for periodic price
adjustments and contain various clauses that would release the subsidiaries from
their obligations under certain force majeure conditions.
The AEP System has contracted to sell approximately 1,300 MW of capacity on a
long-term basis to unaffiliated utilities. Certain of these contracts totaling
250 MW of capacity are unit power agreements requiring the delivery of energy
only if the unit capacity is available. The power sales contracts expire from
2002 to 2012.
In connection with a lignite mining contract for its Henry W. Pirkey Power
Plant, SWEPCo has agreed under certain conditions, to assume the obligations of
the mining contractor. The contractor's actual obligation outstanding at
December 31, 2001 was $75 million.
As part of the process to receive a renewal of a Texas Railroad Commission
permit for lignite mining, SWEPCo has agreed to provide guarantees of mine
reclamation in the amount of $85 million. Since SWEPCo uses self-bonding, the
guarantee provides for SWEPCo to commit to use its resources to complete the
reclamation in the event the work is not completed by a third party miner. At
December 31, 2001 the cost to reclaim the mine is estimated to be approximately
$36 million.
OPCo has entered into a purchased power agreement to purchase electricity
produced by an unaffiliated entity's three-unit natural gas fired plant that is
under construction. The first unit is anticipated to be completed in October
2002 and the agreement will terminate 30 years after the third unit begins
operation. Under the terms of the agreement OPCo has the options to run the
plant until December 31, 2005 taking 100% of the power generated. For the
remainder of the 30 year contract term, OPCo will pay the variable costs to
generate the electricity it purchases which could be up to 20% of the plant's
capacity. The estimated fixed payments through December 2005 are $55 million.
Nuclear Plants - Affecting CPL and I&M
I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by
the NRC. CPL owns 25.2% of the two-unit 2,500 MW STP. STPNOC operates STP on
behalf of the joint owners under licenses granted by the NRC. The operation of a
nuclear facility involves special risks, potential liabilities, and specific
regulatory and safety requirements. Should a nuclear incident occur at any
nuclear power plant facility in the U.S., the resultant liability could be
substantial. By agreement I&M and CPL are partially liable together with all
other electric utility companies that own nuclear generating units for a nuclear
power plant incident at any nuclear plant in the U.S. In the event nuclear
losses or liabilities are underinsured or exceed accumulated funds and recovery
in rates is not possible, results of operations, cash flows and financial
condition would be adversely affected.
Nuclear Incident Liability - Affecting CPL and I&M
The Price-Anderson Act establishes insurance protection for public liability
arising from a nuclear incident at $9.5 billion and covers any incident at a
licensed reactor in the U.S. Commercially available insurance provides $200
million of coverage. In the event of a nuclear incident at any nuclear plant in
the U.S., the remainder of the liability would be provided by a deferred premium
assessment of $88 million on each licensed reactor in the U.S. payable in annual
installments of $10 million. As a result, I&M could be assessed $176 million per
nuclear incident payable in annual installments of $20 million. CPL could be
assessed $44 million per nuclear incident payable in annual installments of $5
million as its share of a STPNOC assessment. The number of incidents for which
payments could be required is not limited.
Insurance coverage for property damage, decommissioning and decontamination at
the Cook Plant and STP is carried by I&M and STPNOC in the amount of $1.8
billion each. Cook Plant and STPNOC jointly purchase $1 billion of excess
coverage for property damage, de-commissioning and decontamination. Additional
insurance provides coverage for extra costs resulting from a prolonged
accidental outage. I&M and STPNOC utilize an industry mutual insurer for the
placement of this insurance coverage. Participation in this mutual insurer
requires a contingent financial obligation of up to $36 million for I&M and $3
million for CPL which is assessable if the insurer's financial resources would
be inadequate to pay for losses.
SNF Disposal - Affecting CPL, and I&M
Federal law provides for government responsibility for permanent SNF disposal
and assesses nuclear plant owners fees for SNF disposal. A fee of one mill per
KWH for fuel consumed after April 6, 1983 at Cook Plant and STP is being
collected from customers and remitted to the U.S. Treasury. Fees and related
interest of $220 million for fuel consumed prior to April 7, 1983 at Cook Plant
have been recorded as long-term debt. I&M has not paid the government the Cook
Plant related pre-April 1983 fees due to continued delays and uncertainties
related to the federal disposal program. At December 31, 2001, funds collected
from customers towards payment of the pre-April 1983 fee and related earnings
thereon are in external funds and approximate the liability. CPL is not liable
for any assessments for nuclear fuel consumed prior to April 7, 1983 since the
STP units began operation in 1988 and 1989.
Decommissioning and Low Level Waste Accumulation Disposal - Affecting CPL and
I&M
Decommissioning costs are accrued over the service lives of the Cook Plant and
STP. The licenses to operate the two nuclear units at Cook Plant expire in 2014
and 2017. After expiration of the licenses, Cook Plant is expected to be
decommissioned through dismantlement. The estimated cost of decommissioning and
low level radioactive waste accumulation disposal costs for Cook Plant ranges
from $783 million to $1,481 million in 2000 nondiscounted dollars. The wide
range is caused by variables in assumptions including the estimated length of
time SNF may need to be stored at the plant site subsequent to ceasing
operations. This, in turn, depends on future developments in the federal
government's SNF disposal program. Continued delays in the federal fuel disposal
program can result in increased decommissioning costs. I&M is re-covering
estimated Cook Plant decommissioning costs in its three rate-making
jurisdictions based on at least the lower end of the range in the most recent
decommissioning study at the time of the last rate proceeding. The amount
recovered in rates for decommissioning the Cook Plant and deposited in the
external fund was $27 million in 2001 and $28 million in 2000 and 1999.
The licenses to operate the two nuclear units at STP expire in 2027 and 2028.
After expiration of the licenses, STP is expected to be decommissioned using the
decontamination method. CPL estimates its portion of the costs of
decommissioning STP to be $289 million in 1999 nondiscounted dollars. CPL is
accruing and recovering these decommissioning costs through rates based on the
service life of STP at a rate of $8 million per year.
Decommissioning costs recovered from customers are deposited in external trusts.
In 2001 and 2000 I&M deposited in its decommissioning trust an additional $12
million and $6 million, respectively, related to special regulatory commission
approved funding for decommissioning of the Cook Plant. Trust fund earnings
increase the fund assets and the recorded liability and decrease the amount
needed to be recovered from ratepayers. Decommissioning costs including
interest, unrealized gains and losses and expenses of the trust funds are
recorded in other operation expense for Cook Plant. For STP, nuclear
decommissioning costs are recorded in other operation expense, interest income
of the trusts are recorded in nonoperating income and interest expense of the
trust funds are included in interest charges.
On I&M's balance sheets, nuclear decommissioning trust assets are included in
other assets and a corresponding nuclear decommissioning liability is included
in other noncurrent liabilities. On CPL's balance sheets, the nuclear
decommissioning liability of $99 million is included in electric utility
plant-accumulated depreciation and amortization. At December 31, 2001 and 2000,
the decommissioning liability for Cook Plant and STP combined totals $699
million and $654 million, respectively.
Municipal Franchise Fee Litigation - Affecting CPL
In 2001 CPL settled litigation regarding municipal franchise fees in Texas. CPL
paid $11 million to settle the litigation and be released from any further
liability. The City of San Juan, Texas had filed a class action suit in 1996
seeking $300 million in damages.
Texas Base Rate Litigation - Affecting CPL
In 2001 the Texas Supreme Court denied CPL's request to review a case resulting
from a 1997 PUCT base rate order. The Court also denied CPL's rehearing request.
The primary issues were:
o the classification of $800 million of invested capital in STP as
ECOM and assigning it a lower return on equity than other generation
property;
o and an $18 million disallowance of an affiliate service billings.
Lignite Mining Agreement Litigation - Affecting SWEPCo
In 2001 SWEPCo settled ongoing litigation concerning lignite mining in
Louisiana. Since 1997 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 jointly own lignite reserves
in the Dolet Hills area of northwestern Louisiana. Under terms of a settlement,
SWEPCo purchased an unaffiliated mine operator's interest in the mining
operations and related debt and other obligations for $86 million.
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo, I&M, and
OPCo
Since 1999 APCo, CSPCo, I&M, and OPCo have been involved in litigation regarding
generating plant emissions under the Clean Air Act. Federal EPA and a number of
states alleged that AEP System companies and eleven unaffiliated utilities
modified certain units at coal fired generating plants in violation of the Clean
Air Act. Federal EPA filed complaints against AEP System companies in U.S.
District Court for the Southern District of Ohio. A separate lawsuit initiated
by certain special interest groups was consolidated with the Federal EPA case.
The alleged modification of the generating units occurred over a 20 year period.
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. 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). In March
2001 the District Court ruled claims for civil penalties based on activities
that occurred more than five years before the filing date of the complaints
cannot be imposed. There is no time limit on claims for injunctive relief.
In February 2001 the government filed a motion requesting a determination that
four projects undertaken on units at Sporn, Cardinal and Clinch River plants do
not constitute "routine maintenance, repair and replacement" as used in the
Clean Air Act. Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and intends to vigorously
pursue its defense.
In January 2002 the U.S. Court of Appeals for the 11th Circuit ruled that TVA
may pursue its court challenge of a Federal EPA administrative order charging
similar violations to those in the complaints against AEP System companies and
other utilities.
Management is unable to estimate the loss or range of loss related to the
contingent liability for civil penalties under the Clear Air Act proceedings and
unable to predict the timing of resolution of these matters due to the number of
alleged violations and the significant number of issues yet to be determined by
the Court. 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 (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 results of operations and cash flows.
NOx Reductions - Affecting AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo and SWEPCo
Federal EPA issued a NOx Rule requiring substantial reductions in NOx emissions
in a number of eastern states, including certain states in which the AEP
System's generating plants are located. The NOx Rule has been upheld on appeal.
The compliance date for the NOx Rule is May 31, 2004.
The NOx Rule required states to submit plans to comply with its provisions. In
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 approvable compliance plans. Those states could face stringent
sanctions 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. AEP System companies and other utilities requested
that the D.C. Circuit Court review this ruling.
In 2000 Federal EPA also adopted a revised rule (the Section 126 Rule) granting
petitions filed by certain northeastern states under the Clean Air Act. The rule
imposes emissions reduction requirements comparable to the NOx Rule beginning
May 1, 2003, for most of AEP System companies' coal-fired generating units.
Affected utilities including certain AEP System companies, petitioned the D.C.
Circuit Court to review the Section 126 Rule.
After review, the D.C. Circuit Court instructed Federal EPA to justify the
methods it used to allocate allowances and project growth for both the NOx Rule
and the Section 126 Rule. AEP System companies' and other utilities requested
that the D.C. Circuit Court vacate the Section 126 Rule or suspend its May 2003
compliance date. On August 24, 2001, the D.C. Circuit Court issued an order
tolling the compliance schedule until Federal EPA responds to the Court's
remand. Federal EPA has announced that it intends to adopt May 31, 2004, as the
compliance date for the Section 126 Rule when it finalizes the NOx budgets for
both rules.
In 2000 the Texas Natural Resource Conservation Commission adopted rules
requiring significant reductions in NOx emissions from utility sources,
including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005
for SWEPCo.
During 2001 selective catalytic reduction (SCR) technology to reduce NOx
emissions on OPCo's Gavin Plant commenced operations. Construction of SCR
technology at certain other AEP System companies' generating units continues
with completion scheduled in 2002 through 2006.
Our estimates indicate that compliance with the NOx Rule, the Texas Natural
Resource Conservation Commission rule and the Section 126 Rule could result in
required capital expenditures of approximately $1.6 billion of which
approximately $450 million has been spent through December 31, 2001 for the AEP
System. Estimated compliance costs and amounts spent by registrant subsidiaries
are as follows:
Estimated Amount Spent
Compliance Cost
--------------- ------------
(in millions)
AEGCo $125 $ -
APCo 365 130
CPL 57 4
CSPCo 106 1
I&M 202 -
KPCo 140 13
OPCo 606 277
SWEPCo 28 21
Since compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the preliminary estimates depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital and operating costs of additional pollution
control equipment are recovered from customers, they will have an adverse effect
on results of operations, cash flows and possibly financial condition.
Merger Litigation - On January 18, 2002, the U.S. Court of Appeals for the
District of Columbia ruled that the SEC failed to prove that the June 15, 2000
merger of AEP with CSW meets the requirements of the PUHCA and sent the case
back to the SEC for further review. Specifically, the court told the SEC to
revisit its conclusion that the merger met PUHCA requirements that utilities be
"physically interconnected" and confined to a "single area or region." In its
June 2000 approval of the merger, the SEC agreed that the AEP and CSW companies'
systems are integrated because they have transmission access rights to a single
high-voltage line through Missouri and also met the PUCHA's single region
requirement because it is now technically possible to centrally control the
output of power plants across many states. In its ruling, the appeals court said
that the SEC failed to explain its conclusions that the transmission integration
and single region requirements are satisfied.
Management believes that the merger meets the requirements of the PUHCA and
expects the matter to be resolved favorably.
Enron Bankruptcy - Affecting APCo, CSPCo, I&M, KPCo and OPCo
At the date of Enron's bankruptcy certain electric operating companies had open
trading contracts and trading accounts receivables and payables with Enron. In
the fourth quarter of 2001 certain registrants provided the following amounts
for their estimated loss from the Enron bankruptcy:
Amounts
Amounts Net of
Registrant Provided Tax
-------- -- ---
(in millions)
APCo $5.2 $3.4
CSPCo 3.2 2.1
I&M 3.4 2.2
KPCo 1.3 0.8
OPCo 4.3 2.8
The amounts provided were based on an analysis of contracts where certain
registrants and Enron are counterparties, the offsetting of receivables and
payables, and the application of deposits from Enron. If there are any adverse
unforeseen developments in the bankruptcy proceedings, our future results of
operations, cash flows and possibly financial condition could be adversely
impacted.
Other - AEP's registrant subsidiaries are involved in a number of other legal
proceedings and claims. While management is unable to predict the ultimate
outcome of these matters, it is not expected that their resolution will have a
material adverse effect on results of operations, cash flows or financial
condition.
9. Acquisitions and Dispositions:
SFAS 141 "Business Combinations" apply to all business combinations initiated
and consummated after June 30, 2001.
SWEPCo purchased the Dolet Hills mining operations including existing mine
reclamation liabilities at its jointly owned lignite reserves in Louisiana. The
purchase resulted from a litigation settlement discussed in Note 8, "Commitments
and Contingencies". Management expects the acquisition to have minimal impact on
results of operations.
Regarding the above acquisition management has recorded the assets
acquired and liabilities assumed at their estimated fair values in accordance
with SFAS 141 based on currently available information and on current
assumptions as to future operations. The allocation of the purchase price is
subject to revision based on the final determinations.
Dispositions
In July 2001 OPCo, an AEP subsidiary, sold coal mines in Ohio and West Virginia
and agreed to purchase approximately 34 million tons of coal from the purchaser
of the mines through 2008. The sale is expected to have a nominal impact on
results of operations and cash flows.
10. Benefit Plans:
The registrant subsidiaries participate in two AEP System qualified and two
non-qualified pension plans. Substantially all employees are covered by one or
both of the pension plans. Postretirement benefits other than pensions are
provided for retired employees for medical and death benefits under an AEP
System plan.
Both of the AEP System's nonqualified pension plans had accumulated benefit
obligations in excess of plan assets of $40 million and $26 million at December
31, 2001 and $41 million and $26 million at December 31, 2000. There are no plan
assets in the nonqualified plans.
The AEP System's OPEB plans had accumulated benefit obligations in excess of
plan assets of $944 million and $964 million at December 31, 2001 and 2000,
respectively.
The following table provides the net periodic benefit cost (credit) for the
plans by the following AEP registrant subsidiaries for fiscal years 2001, 2000
and 1999:
US US
Pension OPEB
Plans Plans
2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
(in thousands)
APCo $(13,645) $(14,047) $(3,925) $22,810 $ 22,139 $19,431
CPL (3,411) (2,986) (4,270) 8,214 6,656 7,595
CSPCo (10,624) (10,905) (4,893) 10,328 9,643 8,623
I&M (7,805) (8,565) (1,259) 15,077 14,155 13,664
KPCo (1,922) (2,075) (393) 2,438 2,364 2,652
OPCo (14,879) (15,041) (4,979) 34,444 116,205 52,518
PSO (2,480) (2,196) (3,129) 6,187 4,277 5,516
SWEPCo (3,051) (2,606) (3,734) 6,399 4,152 4,913
WTU (1,664) (1,585) (2,221) 3,729 2,929 3,377
The weighted-average assumptions as of December 31, used in the measurement of
the Company's benefit obligations are shown in the following tables:
U.S.
Pension Plans U.S. OPEB Plans
------------------------ -------------------
2001 2000 1999 2001 2000 1999
---- ---- ---- ---- ---- ----
% % % % % %
Discount rate 7.25 7.50 8.00 7.25 7.50 8.00
Expected return on plan assets 9.00 9.00 9.00 8.75 8.75 8.75
Rate of compensation increase 3.7 3.2 3.8 N/A N/A N/A
AEP Savings Plans - The AEP Savings Plans are defined contribution plans offered
to non-UMWA U.S. employees. Beginning in 2001 AEP registrant subsidiaries
contributions to the plans increased to 4.5% of the initial 6% of employee pay
contributed from the previous 3% of the initial 6% of employee base pay
contributed.
The following table provides the cost for contributions to the savings plans by
the following AEP registrant subsidiaries for fiscal years 2001, 2000 and 1999:
2001 2000 1999
---- ---- ----
(in thousands)
APCo $7,031 $3,988 $4,091
CPL 3,046 3,161 3,284
CSPCo 2,789 1,638 1,679
I&M 7,833 4,231 3,996
KPCo 1,016 544 561
OPCo 6,398 3,713 3,744
PSO 2,235 2,306 2,435
SWEPCo 2,776 2,880 2,961
WTU 1,558 1,708 1,766
Other UMWA Benefits - OPCo provides UMWA pension, health and welfare benefits
for certain unionized mining employees, retirees, and their survivors who meet
eligibility requirements. The benefits are administered by UMWA trustees and
contributions are made to their trust funds. Contributions are expensed as paid
as part of the cost of active mining operations and were not material in 2001,
2000 and 1999.
11. Business Segments:
In fiscal year 2000, AEP's registrant subsidiaries were considered single,
vertically integrated units, and were reported collectively in a Domestic
Electric Utilities segment.
In 2001, we moved toward our goal of functionally and structurally segregating
our businesses. The ensuing realignment of our operations resulted in our
business segments, Wholesale and Energy Delivery. The business activities of
each of these segments are as follows:
Wholesale
o Generation of electricity for sale to retail and wholesale customers
o Marketing and trading of electricity
Energy Delivery
o Electricity transmission
o Electricity distribution
Segment results of operations for the twelve months ended December 31, 2001,
2000 and 1999 are shown below. These amounts include certain estimates and
allocations where necessary.
We have used Earnings before Interest and Income Taxes (EBIT) as a measure of
segment operating performance. The EBIT measure is total operating revenues net
of total operating expenses and other routine income and deductions from income.
It differs from net income in that It does not take into account interest
expense or income taxes. EBIT is believed to be a reasonable gauge of results of
operations. By excluding interest and income taxes, EBIT does not give guidance
regarding the demand of debt service or other interest requirements, or tax
liabilities or taxation rates. The effects of interest expense and taxes on
overall corporate performance can be seen in the consolidated income statement.
Geographically our business is transacted in the United States. Of the
registrant operating company subsidiaries, all of the registrant subsidiaries
except AEGCo have two business segments. The segment results for
each of these subsidiaries are reported in the table below. AEGCo has one
segment, a wholesale generation business. AEGCo's results of operations are
reported in AEGCo's financial statements.
Twelve Months Ended Twelve Months Ended
December 31, 2001 December 31, 2000
----------------- -----------------
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
--------- ---- --------- ----
(in thousands) (in thousands)
Wholesale Segment
APCo $1,189,223 $164,844 $2,855,337 $1,184,335 $ 154,525 $3,708,252
CPL 1,265,655 303,926 2,977,504 1,291,588 273,650 3,182,192
CSPCo 867,100 232,372 1,987,756 906,363 235,860 2,488,513
I&M 1,212,587 117,396 3,318,919 1,177,190 (146,297) 4,003,805
KPCo 247,842 4,935 585,847 268,529 22,379 766,605
OPCo 1,545,392 240,128 3,156,115 1,672,744 289,084 4,007,722
PSO 695,123 52,086 907,165 711,274 54,072 1,011,432
SWEPCo 768,322 82,409 1,223,334 773,324 27,055 1,302,398
WTU 387,422 7,930 396,147 394,860 13,910 466,499
Energy Delivery Segment
APCo $595,036 $213,733 $2,252,601 $574,918 $191,560 $2,925,472
CPL 473,182 109,587 2,138,482 478,814 136,069 2,285,492
CSPCo 483,219 130,503 1,118,112 398,046 81,896 1,399,789
I&M 314,410 111,206 1,498,089 311,019 126,241 1,807,233
KPCo 131,183 54,033 567,396 121,346 49,770 742,459
OPCo 552,713 118,261 1,759,952 467,587 138,418 2,234,835
PSO 261,877 79,787 1,010,732 245,124 85,524 1,126,901
SWEPCo 333,004 107,197 1,273,266 344,950 129,842 1,355,558
WTU 169,036 33,226 527,273 176,204 50,201 620,912
Registrant Subsidiaries
Company Total
APCo $1,784,259 $378,577 $5,107,938 $1,759,253 $346,085 $6,633,724
CPL 1,738,837 413,513 5,115,986 1,770,402 409,719 5,467,684
CSPCo 1,350,319 362,875 3,105,868 1,304,409 317,756 3,888,302
I&M 1,526,997 228,602 4,817,008 1,488,209 (20,056) 5,811,038
KPCo 379,025 58,968 1,153,243 389,875 72,149 1,509,064
OPCo 2,098,105 358,389 4,916,067 2,140,331 427,502 6,242,557
PSO 957,000 131,873 1,917,897 956,398 139,596 2,138,333
SWEPCo 1,101,326 189,606 2,496,600 1,118,274 156,897 2,657,956
WTU 556,458 41,156 923,420 571,064 64,111 1,087,411
Twelve Months Ended December 31, 1999
Revenues From External Customers Segment EBIT Total Assets
(in thousands)
Wholesale Segment
APCo $1,020,390 $116,907 $2,434,110
CPL 1,032,808 267,165 2,821,449
CSPCo 801,717 214,312 1,798,394
I&M 1,040,786 (18,055) 3,153,344
KPCo 229,644 18,569 501,212
OPCo 1,518,644 278,415 3,002,768
PSO 493,063 56,521 721,195
SWEPCo 672,158 95,385 1,032,045
WTU 270,800 25,008 369,457
Energy Delivery Segment
APCo $565,660 $208,460 $1,920,290
CPL 449,667 133,172 2,026,401
CSPCo 389,280 93,962 1,011,596
I&M 310,880 142,973 1,423,352
KPCo 129,113 51,556 485,426
OPCo 460,182 149,906 1,674,441
PSO 256,327 74,430 803,531
SWEPCo 299,369 83,143 1,074,170
WTU 174,909 46,216 491,748
Registrant Subsidiaries
Company Total
APCo $1,586,050 $325,367 $4,354,400
CPL 1,482,475 400,337 4,847,850
CSPCo 1,190,997 308,274 2,809,990
I&M 1,351,666 124,918 4,576,696
KPCo 358,757 70,125 986,638
OPCo 1,978,826 428,321 4,677,209
PSO 749,390 130,951 1,524,726
SWEPCo 971,527 178,528 2,106,215
WTU 445,709 71,224 861,205
12. Risk Management, Financial
Instruments and Derivatives:
Risk Management
We are subject to market risks in our day to day operations. Our risk policies
have been reviewed with the Board of Directors, approved by a Risk Management
Committee and administered by Chief Risk Officer. The Risk Management Committee
establishes risk limits, approves risk policies, assigns responsibilities
regarding the oversight and management of risk and monitors risk levels. This
committee receives daily, weekly, and monthly reports regarding compliance with
policies, limits and procedures. The committee meets monthly and consists of the
Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.
The risks and related strategies that management can employ are:
Risk Description Strategy
Price Risk Volatility in Trading and
commodity prices hedging
Interest Rate Risk Changes in
Interest rates Hedging
Foreign Exchange Fluctuations in
Risk foreign currency
rates Hedging
Credit Risk Non-performance
on contracts Guarantees,
with Collateral
counterparties
We employ physical forward purchase and sale contracts, over-the-counter
options, swaps, and other derivative contracts to offset price risk where
appropriate. However, we engage in trading of electricity, and to a lesser
degree coal and emission allowances and as a result the we are subject to price
risk. This risk is managed by the management of the trading operations, the
Chief Risk Officer and the Risk Management Committee. If the risk from trading
activities exceeds certain pre-determined limits, the positions are modified or
hedged to reduce the risk to the limits unless specifically approved by the Risk
Management Committee. Although we do not hedge all commodity price exposure,
manage-ment makes informed risk taking decisions supported by the above
described risk management controls.
We are exposed to risk from changes in the market prices of coal and natural gas
used to generate electricity where generation is no longer regulated or where
existing fuel clauses are suspended or frozen. The protection afforded by fuel
clause recovery mechanisms has either been eliminated by the implementation of
customer choice in Ohio (effective January 1, 2001) and in the ERCOT area of
Texas (effective January 1, 2002) or frozen by settlement agreements in Indiana,
Michigan and West Virginia. To the extent all fuel supply for the generating
units in these states are not under fixed price long-term contracts, we are
subject to market price risk. We continue to be protected against market price
changes by active fuel clauses in Oklahoma, Arkansas, Louisiana, Kentucky,
Virginia and the SPP area of Texas.
We employ fair value hedges, cash flow hedges and swaps to mitigate changes in
interest rates or fair values on short and long-term debt when management deems
it necessary. We do not hedge all interest rate risk.
We employ cash flow forward hedge contracts to lock-in prices on transactions
denominated in foreign currencies where deemed necessary. We do not hedge all
foreign currency exposure.
Our open trading contracts, including structured transactions, are
marked-to-market daily using the price model and price curve(s) corresponding to
the instrument. Forwards and swaps are generally valued by subtracting the
contract price from the market price and then multiplying the difference by the
contract volume and adjusting for net present value and other impacts.
Significant estimates in valuing such contracts include forward price curves,
volumes, seasonality, weather, and other factors.
Forwards and swaps (which are a series of forwards) are valued based on forward
price curves which represent a series of projected prices at which transactions
can be executed in the market. The forward price curve includes the market's
expectations for prices of a delivered commodity at that future date. The
forward price curve is developed from the market bid price, which is the highest
price which traders are willing to pay for a contract, and the ask or offer
price, which is the lowest price traders are willing to receive for selling a
contract.
Options contracts, consisting primarily of options on forwards and spread
options, are valued using models, which are variations on Black-Scholes option
models. The market-related inputs are the interest rate curve, the underlying
commodity forward price curve, and the implied volatility curve. Option prices
or volatilities may be quoted in the market. Significant estimates in valuing
these contracts include forward price curves, volumes, and other volatilities.
Market prices utilized in valuing all forward contracts, OTC options, swaps and
structured transactions represent mid-market price, which is the average of the
bid and ask prices. These bids and offers come from brokers, on-line exchanges
such as the Intercontinental Exchange, and directly from other counterparties.
These prices exist for delivery periods and locations being traded or quoted and
vary by period, location and commodity. For periods and locations that are not
liquid and for which external information is not readily available, management
uses the best information available to develop bid and ask prices and forward
curves.
Electricity markets have primary trading hubs or delivery points/regions and
less liquid secondary delivery points. In North American natural gas markets,
the primary delivery points are generally traded from Henry Hub, Louisiana. The
less liquid gas or power trading points may trade as a spread (based on
transportation costs, constraints, etc.) from the nearest liquid trading hub.
Also, some commodities trade more often and therefore are more liquid than
others. For example, peak electricity is a more liquid product than off-peak
electricity. Henry Hub gas trades in monthly blocks for up to 36 months and
after that only trades in seasonal or calendar blocks. In the near term, forward
price curves for gas have a seasonal shape. They are based on market quotes
beyond that.
For all these factors, the curve used for valuation is the mid-point. At times
bids or offers may not be available due to market events, volatility,
constraints, long-dated part of the curve, etc. When this occurs, the Company
uses its best judgment to estimate the curve values until actual values are
available again. The value used will be based on various factors such as last
trade price, recent price trend, product spreads, location spreads (including
transportation costs), cross commodity spreads (e.g., heat rate conversion of
gas to power), time spreads, cost of carry (e.g., cost of gas storage), marginal
production cost, cost of new entrant capacity, and alternative fuel costs. Also,
an energy commodity contract's price volatility generally increases as it
approaches the delivery month. Spot price volatility (e.g., daily or hourly
prices) can cause contract values to change substantially as open positions
settle against spot prices. When a portion of a curve has been estimated for a
period of time and market changes occur, assumptions are updated to align the
company's curve to the market.
The fair values determined are reduced by reserves to adjust for credit risk and
liquidity risk. Credit risk is based on credit ratings of counterparties and
represents the risk that the counterparty to the contract will fail to perform
or fail to pay amounts due. Liquidity risk represents the risk that
imperfections in the market will cause the price to be less than or more than
what the price should be based purely on supply and demand. The liquidity
reserve essentially reserves half of the difference between bids and offers for
each open position, such that the wider the bid-offer spread (indicating lower
liquidity), the greater the reserve.
We also mark to market derivatives that are not trading contracts in accordance
with generally accepted accounting principles. There may be unique models for
these transactions, but the curves the company inputs into the models are the
same forward curves, which are described above.
We have developed independent controls to evaluate the reasonableness of our
valuation models and curves. However, there are inherent risks related to the
underlying assumptions in models used to fair value open long-term trading
contracts. Therefore, there could be a significant favorable or adverse effect
on future results of operations and cash flows if market prices at settlement
differ from the price models and curves.
We limit credit risk by extending unsecured credit to entities based on internal
ratings. We use Moody's Investor Service, Standard and Poor's and qualitative
and quantitative data to independently assess the financial health of
counterparties on an ongoing basis. This data, in conjunction with the ratings
information, is used to determine appropriate risk parameters. We also require
cash deposits, letters of credit and parental/affiliate guarantees as security
from certain below investment grade counterparties in our normal course of
business.
We trade electricity with numerous counterparties. Since our
open energy trading contracts are valued based on changes in market prices of
the related commodities, our exposures change daily. We believe that our credit
and market exposures with any one counterparty is not material to financial
condition at December 31, 2001. At December 31, 2001 less than 5% of the
counterparties were below investment grade as expressed in terms of Net Mark to
Market Assets. Net Mark to Market Assets represents the aggregate difference
(either positive or negative) between the forward market price for the remaining
term of the contract and the contractual price.
We enter into transactions for electricity as part of wholesale trading
operations. Electric transactions are executed over-the-counter with
counterparties or through brokers. Brokers and counterparties require cash or
cash related instruments to be deposited on these transactions as margin against
open positions. These margin accounts are restricted and therefore are not
included in cash and cash equivalents on the Balance Sheet. We can be subject to
further margin requirements should related commodity prices change.
The margin deposits at December 31, 2001 for the registrants were:
(in thousands)
APCo $2,832
CPL 299
CSP 1,736
I&M 1,879
KPCo 698
OPCo 2,862
PSO 247
SWEPCo 299
WTU 99
Financial Derivatives and Hedging
In the first quarter of 2001, we adopted SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS 137 and SFAS 138. SFAS
133 requires that entities recognize all derivatives including fair value hedges
as either assets or liabilities and measure such derivatives at fair value.
Changes in the fair value of derivatives are included in earnings unless
designated as a cash flow hedge. This practice is commonly referred to as
mark-to-market accounting. Changes in the fair value of derivatives that are
designated as effective cash flow hedges are included in other comprehensive
income. Derivatives included in the transition adjustment are interest rate
swaps, foreign currency swaps and commodity swaps, options and futures.
The amounts of net revenue margins recorded in 2001, 2000 and 1999 for the
registrant subsidiaries were:
2001 2000 1999
---- ---- ----
(in thousands)
APCo $78,521 $72,649 $28,970
CPL 15,711 3,385 -
CSPCo 51,765 48,142 14,800
I&M 36,089 58,909 16,147
KPCo 12,466 23,417 5,563
OPCo 65,118 73,474 24,389
PSO (2,483) 9,268 -
SWEPCo 7,897 6,404 -
WTU (1,491) 1,821 -
The fair value of open trading contracts that are marked-to-market are based on
management's best estimates using over-the-counter quotations and exchange
prices for short-term open trading contracts, and internally developed price
curves for open long-term trading contracts. The fair values of trading
contracts at December 31 are:
2001 2000
------------------ --------------------
Fair Fair
Value Value
(in thousands) (in thousands)
APCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals 801,306 2,234,522
Options - OTC 46,649 59,814
Swaps 34,578 51,470
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals (748,016) (2,258,596)
Options - OTC (21,895) (35,955)
Swaps (36,921) (44,855)
KPCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals 197,545 530,828
Options - OTC 11,503 14,207
Swaps 8,529 12,227
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals (190,389) (536,512)
Options - OTC (5,372) (8,521)
Swaps (9,106) (10,656)
2001 2000
------------------ --------------------
Fair Fair
Value Value
(in thousands) (in thousands)
I&M
Trading Assets
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals 560,393 1,349,950
Options - OTC 31,397 36,139
Swaps 22,950 31,095
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals (513,026) (1,371,793)
Options - OTC (15,864) (25,807)
Swaps (24,505) (27,099)
OPCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals 668,142 1,776,259
Options - OTC 38,108 46,731
Swaps 29,730 41,788
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals (619,756) (1,792,417)
Options - OTC (18,227) (29,350)
Swaps (32,551) (37,398)
CSPCo
Trading Assets
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals 491,290 1,192,203
Options - OTC 28,612 31,918
Swaps 21,211 27,461
Trading Liabilities
Electric
Futures and
Options-NYMEX (net) $ - $ -
Physicals (456,613) (1,204,948)
Options - OTC (13,403) (19,220)
Swaps (22,648) (23,932)
2001 2000
------------------ --------------------
Fair Fair
Value Value
(in thousands) (in thousands)
CPL
Trading Assets
Electric
Physicals $285,481 $ 542,626
Trading Liabilities
Electric
Physicals (281,624) (550,817)
PSO
Trading Assets
Electric
Physicals 217,415 431,186
Trading Liabilities
Electric
Physicals (214,981) (437,694)
SWEPCo
Trading Assets
Electric
Physicals 249,531 516,385
Trading Liabilities
Electric
Physicals (246,631) (524,180)
WTU
Trading Assets
Electric
Physicals 84,784 171,597
Trading Liabilities
Electric
Physicals (83,869) (174,187)
The FASB's Derivatives Implementation Group (DIG) Issued guidance, effective in
the third quarter of 2001, regarding the imple-mentation of SFAS 133 for certain
fuel supply contracts with volume optionality and electricity capacity
contracts. The guidance concluded that fuel supply contracts with volumetric
optionality cannot qualify for a normal purchase or sale exclusion from
mark-to-market accounting and provided guidance for determining when electricity
capacity con-tracts can qualify as normal purchases or sales.
Predominantly all of our contracts for coal, gas and electricity, which are
recorded on a settlement basis, do not meet the criteria of a financial
derivative instrument and qualify as normal purchases or sales. As a result they
are exempt from the DIG guidance described above and have not been
marked-to-market. Beginning July 1, 2001, the effective date of the DIG
guidance, certain of our fuel supply contracts with volumetric optionality that
qualify as financial derivative instruments are marked to market with any gain
or loss recognized in the income statement.
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 trans-action. 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 of the item being
hedged. Changes in the fair value that result from ineffectiveness of a hedge
under SFAS 133 are recognized currently in earnings through mark-to-market
accounting. Changes in the fair value of effective cash flow 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 the accounting periods in which the variability of cash flows of the
hedged items affect earnings.
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 at December 31, 2001.
(in thousands)
APCo
Transition Adjustment, January 1, 2001 $-
Effective portion of changes in fair value (340)
Reclasses from OCI to net income -
--
Accumulated OCI derivative gain, December 31, 2001 $(340)
=====
KPCo
Transition Adjustment, January 1, 2001 $(557)
Effective portion of changes in fair value (2,348)
Reclasses from OCI to net income 1,002
-----
Accumulated OCI derivative gain, December 31, 2001 $(1,903)
=======
I&M
Transition Adjustment, January 1, 2001 $(317)
Effective portion of changes in fair value (5,368)
Reclasses from OCI to net income 1,850
-----
Accumulated OCI derivative gain, December 31, 2001 $(3,835)
=======
OPCo
Transition Adjustment, January 1, 2001 $-
Effective portion of changes in fair value (196)
Reclasses from OCI to net income -
--
Accumulated OCI derivative gain, December 31, 2001 $(196)
=====
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 5
years.
FINANCIAL INSTRUMENTS
Market Valuation of Non-Derivative Financial Instrument
The book values of cash and cash equivalents, accounts receivable, short-term
debt and accounts payable approximate fair value because of the short-term
maturity of these instruments. The book value of the pre-April 1983 spent
nuclear fuel disposal liability approximates the best estimate of its fair
value.
The fair values of long-term debt and preferred stock subject to mandatory
redemption are based on quoted market prices for the same or similar issues and
the current dividend or interest rates offered for instruments with similar
maturities. These instruments are not marked-to-market. The estimates presented
are not necessarily indicative of the amounts that we could realize in a current
market exchange. The book values and fair values of significant financial
instruments for AEP's registrant subsidiaries December 31, 2001 and 2000 are
summarized in the following tables.
2001 2000
Book Value Fair Value Book Value Fair Value
---------- ---------- ---------- ----------
(in thousands) (in thousands)
AEGCo
Long-term Debt $45,000 $45,268 $45,000 $45,000
APCo
Long-term Debt $1,556,559 $1,439,531 $1,605,818 $1,601,313
Preferred Stock 10,860 10,860 10,860 10,725
CPL
Long-term Debt $1,253,768 $1,278,644 $1,454,559 $1,463,690
Trust Preferred Securities 136,250 135,760 148,500 147,431
CSPCo
Long-term Debt $791,848 $802,194 $899,615 $908,620
Preferred Stock 10,000 10,100 15,000 14,892
I&M
Long-term Debt $1,652,082 $1,672,392 $1,388,939 $1,377,230
Preferred Stock 64,945 62,795 64,945 63,941
KPCo
Long-term Debt $346,093 $350,233 $330,880 $335,408
OPCo
Long-term Debt $1,203,841 $1,227,880 $1,195,493 $1,176,367
Preferred Stock 8,850 8,837 8,850 8,780
PSO
Long-term Debt $451,129 $462,903 $470,822 $476,964
Trust Preferred Securities 75,000 74,730 75,000 72,180
SWEPCo
Long-term Debt $645,283 $656,998 $645,963 $651,586
Trust Preferred Securities 110,000 109,780 110,000 106,700
WTU
Long-term Debt $255,967 $266,846 $255,843 $261,315
Other Financial Instruments - Nuclear Trust Funds Recorded at Market Value - The
trust investments which are classified as held for sale for decommissioning and
SNF disposal, reported in other assets, are recorded at market value in
accordance with SFAS 115. At December 31, 2001 and 2000 the fair values of the
trust investments were $933 million and $873 million, respectively, and had a
cost basis of $839 million and $768 million, respectively. The change in market
value in 2001, 2000, and 1999 was a net unrealized holding loss of $11 million,
and net unrealized holding gain of $6 million, and $18 million, respectively.
13. Income Taxes:
The details of the registrant subsidiaries' income taxes as reported are as
follows:
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 2001 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 9,126 $ 71,623 $190,671 $ 88,013 $ 107,286
Deferred (6,224) 27,198 (72,568) 14,923 (45,785)
Deferred Investment Tax Credits - (3,237) (5,207) (3,899) (7,377)
------- -------- -------- -------- ---------
Total 2,902 95,584 112,896 99,037 54,124
------- -------- -------- -------- ---------
Charged (Credited) to
Nonoperating Income (net):
Current (56) (19,165) (398) (13,803) (10,590)
Deferred - 21,832 - 17,885 16,580
Deferred Investment Tax Credits (3,414) (1,528) - (159) (947)
------- -------- -------- -------- ---------
Total (3,470) 1,139 (398) 3,923 5,043
------- -------- -------- -------- ---------
Total Income Tax as Reported $ (568) $ 96,723 $112,498 $102,960 $ 59,167
======= ======== ======== ======== =========
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 2001 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 7,726 $(62,298) $ 53,030 $ 77,965 $ 19,424
Deferred 2,812 166,166 (16,726) (31,396) (11,891)
Deferred Investment Tax Credits (1,180) (2,495) (1,791) (4,453) (1,271)
------- -------- -------- -------- --------
Total 9,358 101,373 34,513 42,116 6,262
------- -------- -------- -------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (2,725) (21,600) 352 542 (691)
Deferred 3,481 20,014 - - -
Deferred Investment Tax Credits (72) (794) - - -
------- -------- -------- -------- -------
Total 684 (2,380) 352 542 (691)
------- -------- -------- -------- -------
Total Income Tax as Reported $10,042 $ 98,993 $ 34,865 $ 42,658 $ 5,571
======= ======== ======== ======== =======
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 8,746 $129,165 $ 89,403 $120,494 $ 134,796
Deferred (5,842) 3,838 16,263 (7,746) (126,748)
Deferred Investment Tax Credits - (2,947) (5,207) (3,379) (7,524)
------- -------- -------- -------- ---------
Total 2,904 130,056 100,459 109,369 524
------- -------- -------- -------- ---------
Charged (Credited) to
Nonoperating Income (net):
Current (44) 327 (5,073) 3,777 2,950
Deferred - 4,764 - 3,683 1,569
Deferred Investment Tax Credits (3,396) (1,968) - (103) (330)
------- -------- ------- -------- ---------
Total (3,440) 3,123 (5,073) 7,357 4,189
------- -------- ------- -------- ---------
Total Income Tax as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713
======= ======== ======= ======== =========
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 2000 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $17,878 $259,608 $11,597 $16,073 $ 6,774
Deferred 2,521 (70,263) 25,453 14,653 9,401
Deferred Investment Tax Credits (1,187) (1,824) (1,791) (4,482) (1,271)
------- -------- ------- ------- -------
Total 19,212 187,521 35,259 26,244 14,904
------- -------- ------- ------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (50) 15,426 (1,306) (1,476) (222)
Deferred 1,244 4,307 - - (1,237)
Deferred Investment Tax Credits (65) (1,575) - - -
------- ------- ------- ------- --------
Total 1,129 18,158 (1,306) (1,476) (1,459)
------- ------- ------- ------- -------
Total Income Tax as Reported $20,341 $205,679 $33,953 $24,768 $13,445
======= ======== ======= ======= =======
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 1999 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $ 7,713 $69,522 $ 89,112 $79,410 $(67,368)
Deferred (5,282) 8,981 19,620 9,737 85,345
Deferred Investment Tax Credits - (2,659) (5,207) (3,432) (7,547)
------- ------- -------- ------- --------
Total 2,431 75,844 103,525 85,715 10,430
------- ------- -------- ------- --------
Charged (Credited) to
Nonoperating Income (net):
Current (146) (1,548) (5,604) (3,122) 1,529
Deferred - 4,052 318 744 382
Deferred Investment Tax Credits (3,448) (2,313) - (562) (605)
------- ------- -------- ------- --------
Total (3,594) 191 (5,286) (2,940) 1,306
------- ------- -------- ------- --------
Total Income Taxes as Reported $(1,163) $76,035 $ 98,239 $82,775 $ 11,736
======= ======= ======== ======= ========
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 1999 (in thousands)
Charged (Credited) to Operating
Expenses (net):
Current $14,897 $135,540 $20,777 $ 60,169 $ 3,328
Deferred 2,239 4,205 14,521 (17,347) 12,026
Deferred Investment Tax Credits (1,193) (1,825) (1,791) (4,565) (1,275)
------- -------- ------- -------- -------
Total 15,943 137,920 33,507 38,257 14,079
------- -------- ------- -------- -------
Charged (Credited) to
Nonoperating Income (net):
Current (424) (3,256) (2,215) (4,826) 858
Deferred 357 (539) - - -
Deferred Investment Tax Credits (99) (1,633) - - -
------- -------- ------- -------- -------
Total (166) (5,428) (2,215) (4,826) 858
------- -------- ------- -------- -------
Total Income Taxes as Reported $15,777 $132,492 $31,292 $ 33,431 $14,937
======= ======== ======= ======== =======
Shown below is a reconciliation for each AEP registrant subsidiary of the
difference between the amount of federal income taxes computed by multiplying
book income before federal income taxes by the statutory rate, and the amount of
income taxes reported.
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 2001 (in thousands)
Net Income (Loss) $7,875 $161,818 $182,278 $161,876 $ 75,788
Extraordinary (Gains) Loss - - 2,509 30,024 -
Income Tax Benefit - - - - -
Income Taxes (568) 96,723 112,498 102,960 59,167
------ -------- -------- -------- --------
Pre-Tax Income (Loss) $7,307 $258,541 $297,285 $294,860 $134,955
====== ======== ======== ======== ========
Income Tax on Pre-Tax Income (Loss)
at Statutory Rate (35%) $ 2,557 $ 90,490 $104,050 $103,201 $ 47,234
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 230 2,977 8,477 2,757 21,224
Corporate Owned Life Insurance - 450 - 544 (148)
Nuclear Fuel Disposal Costs - - - - (3,292)
Allowance for Funds Used
During Construction (1,078) - - - (1,606)
Rockport Plant Unit 2 Investment
Tax Credit 374 - - - -
Removal Costs - - - - -
Investment Tax Credits (net) (3,414) (4,765) (5,207) (4,058) (8,324)
State Income Taxes 1,050 9,613 9,652 5,727 6,137
Other (287) (2,042) (4,474) (5,211) (2,058)
------- -------- -------- -------- --------
Total Income Taxes as Reported $ (568) $ 96,723 $112,498 $102,960 $ 59,167
======= ======== ======== ======== ========
Effective Income Tax Rate N.M. 37.4% 37.9% 34.9% 43.8%
==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 2001 (in thousands)
Net Income $21,565 $147,445 $ 57,759 $ 89,367 $12,310
Extraordinary Loss - 18,348 - - -
Income Tax Benefit - - - - -
Income Taxes 10,042 98,993 34,865 42,658 5,571
------- -------- -------- -------- -------
Pre-Tax Income $31,607 $264,786 $ 92,624 $132,025 $17,881
======= ======== ======== ======== =======
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $11,062 $ 92,675 $32,418 $ 46,209 $ 6,259
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 1,581 7,972 - - 1,463
Corporate Owned Life Insurance 334 1,852 - - -
Nuclear Fuel Disposal Costs - - - - -
Allowance for Funds Used
During Construction - - - - -
Rockport Plant Unit 2 Investment
Tax Credit - - - - -
Removal Costs (420) - - - -
Investment Tax Credits (net) (1,252) (3,289) (1,791) (4,453) (1,271)
State Income Taxes 318 9,752 5,137 5,451 1,283
Other (1,581) (9,969) (899) (4,549) (2,163)
------- -------- ------- -------- -------
Total Income Taxes as Reported $10,042 $ 98,993 $34,865 $ 42,658 $ 5,571
======= ======== ======= ======== =======
Effective Income Tax Rate 31.8% 37.4% 37.6% 32.3% 31.2%
==== ==== ==== ==== ====
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 2000 (in thousands)
Net Income (Loss) $7,984 $ 73,844 $189,567 $ 94,966 $(132,032)
Extraordinary (Gains) Loss (1,066) 39,384
Income Tax Benefit - (7,872) - (14,148) -
Income Taxes (536) 133,179 95,386 116,726 4,713
------ -------- -------- -------- ---------
Pre-Tax Income (Loss) $7,448 $198,085 $284,953 $236,928 $(127,319)
====== ======== ======== ======== =========
Income Tax on Pre-Tax Income (Loss)
at Statutory Rate (35%) $ 2,607 $ 69,330 $99,733 $ 82,925 $(44,561)
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 452 7,606 7,556 10,529 20,378
Corporate Owned Life Insurance - 54,824 - 29,259 42,587
Nuclear Fuel Disposal Costs - - - - (3,957)
Allowance for Funds Used
During Construction (1,070) - - - (2,211)
Rockport Plant Unit 2 Investment
Tax Credit 374 - - - -
Removal Costs - (1,197) - - -
Investment Tax Credits (net) (3,396) (4,915) (5,207) (3,482) (7,854)
State Income Taxes 784 9,950 2,296 89 6,004
Other (287) (2,419) (8,992) (2,594) (5,673)
------- -------- ------- -------- --------
Total Income Taxes as Reported $ (536) $133,179 $95,386 $116,726 $ 4,713
======= ======== ======= ======== ========
Effective Income Tax Rate N.M. 67.2% 33.5% 49.3% N.M.
==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 2000 (in thousands)
Net Income $20,763 $ 83,737 $ 66,663 $72,672 $27,450
Extraordinary Loss 40,157
Income Tax Benefit - (21,281) - - -
Income Taxes 20,342 205,679 33,953 24,768 13,445
------- -------- -------- ------- -------
Pre-Tax Income $41,105 $308,292 $100,616 $97,440 $40,895
======= ======== ======== ======= =======
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $14,387 $107,903 $35,216 $ 34,104 $14,313
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 1,827 27,577 - - 1,204
Corporate Owned Life Insurance 5,149 84,453 - - -
Nuclear Fuel Disposal Costs - - - - -
Allowance for Funds Used
During Construction - - - - -
Rockport Plant Unit 2 Investment
Tax Credit - - - - -
Removal Costs (420) - - - -
Investment Tax Credits (net) (1,252) (3,398) (1,791) (4,482) (1,271)
State Income Taxes 1,597 (1,988) 3,037 1,650 -
Other (946) (8,868) (2,509) (6,504) (801)
------- -------- ------- -------- -------
Total Income Taxes as Reported $20,342 $205,679 $33,953 $ 24,768 $13,445
======= ======== ======= ======== =======
Effective Income Tax Rate 49.5% 66.8% 33.8% 25.4% 32.9%
==== ==== ==== ==== ====
AEGCo APCo CPL CSPCo I&M
Year Ended December 31, 1999 (in thousands)
Net Income $ 6,195 $120,492 $182,201 $150,270 $32,776
Extraordinary Loss 8,488
Income Tax Benefit - - (2,971) - -
Income Taxes (1,163) 76,035 98,239 82,775 11,736
------- -------- -------- -------- -------
Pre-Tax Income $ 5,032 $196,527 $285,957 $233,045 $44,512
======= ======== ======== ======== =======
Income Tax on Pre-Tax
Income at Statutory Rate (35%) $ 1,762 $ 68,785 $100,085 $ 81,566 $15,580
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 446 12,593 7,981 8,846 19,966
Corporate Owned Life Insurance - - - - 594
Nuclear Fuel Disposal Costs - - - - (3,347)
Allowance for Funds Used
During Construction (1,069) - - - (2,174)
Rockport Plant Unit 2
Investment Tax Credit 374 - - - -
Removal Costs - (3,220) - - -
Investment Tax Credits (net) (3,448) (4,972) (5,207) (3,994) (8,152)
State Income Taxes 467 3,305 6,965 58 (4,635)
Other 305 (456) (11,585) (3,701) (6,096)
------- -------- -------- -------- -------
Total Income Taxes as Reported $(1,163) $ 76,035 $ 98,239 $ 82,775 $11,736
======= ======== ======== ======== =======
Effective Income Tax Rate N.M. 38.7% 34.4% 35.6% 26.4%
==== ==== ==== ==== ====
KPCo OPCo PSO SWEPCo WTU
Year Ended December 31, 1999 (in thousands)
Net Income $25,430 $212,157 $61,508 $83,194 $26,406
Extraordinary Loss 4,632 8,402
Income Tax Benefit - - - (1,621) (2,941)
Income Taxes 15,777 132,492 31,292 33,431 14,937
------- -------- ------- -------- -------
Pre-Tax Income $41,207 $344,649 $92,800 $119,636 $46,804
======= ======== ======= ======== =======
Income Tax on Pre-Tax Income
at Statutory Rate (35%) $14,423 $120,628 $ 32,480 $ 41,873 $16,382
Increase (Decrease) in Income Tax
Resulting from the Following Items:
Depreciation 1,843 17,517 - - 1,120
Corporate Owned Life Insurance - 198 - - -
Removal Costs (420) - - - -
Investment Tax Credits (net) (1,292) (3,458) (1,791) (4,565) (1,275)
State Income Taxes 1,809 1,090 3,054 2,924 -
Other (586) (3,483) (2,451) (6,801) (1,290)
------- -------- -------- -------- -------
Total Income Taxes as Reported $15,777 $132,492 $ 31,292 $ 33,431 $14,937
======= ======== ======== ======== =======
Effective Income Tax Rate 38.3% 38.5% 33.8% 28.0% 32.0%
==== ==== ==== ==== ====
The following tables show the elements of the net deferred tax liability and the
significant temporary differences for each AEP registrant subsidiary:
AEGCo APCo CPL CSPCo I&M
December 31, 2001 (in thousands)
Deferred Tax Assets $ 75,856 $ 162,334 $ 130,863 $ 74,767 $ 332,225
Deferred Tax Liabilities (103,831) (865,909) (1,294,658) (518,489) (732,756)
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (27,975) $(703,575) $(1,163,795) $(443,722) $(400,531)
========= ========= =========== ========= =========
Property Related Temporary Differences $ (70,581) $(530,298) $ (808,922) $(323,139) $(306,151)
Amounts Due From Customers For
Future Federal Income Taxes 9,292 (55,206) (70,174) (9,839) (46,756)
Deferred State Income Taxes (3,822) (56,747) - (8,968) (38,015)
Translation Regulatory Assets - (34,783) - (78,298) -
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 40,816 - - - 27,157
Accrued Nuclear Decommissioning Expense - - - - 43,707
Deferred Fuel and Purchased Power - - - - (26,270)
Deferred Cook Plant Restart Costs - - - - (28,000)
Nuclear Fuel - - - - (16,062)
Regulatory Assets Designated
for Securitization - - (332,198) - -
All Other (net) (3,680) (26,541) 47,499 (23,478) (10,141)
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (27,975) $(703,575) $(1,163,795) $(443,722) $(400,531)
========= ========= =========== ========= =========
KPCo OPCo PSO SWEPCo WTU
December 31, 2001 (in thousands)
Deferred Tax Assets $ 30,927 $ 135,938 $ 59,421 $ 56,189 $ 22,888
Deferred Tax Liabilities (199,231) (933,827) (356,298) (425,970) (167,937)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(168,304) $(797,889) $(296,877) $(369,781) $(145,049)
========= ========= ========= ========= =========
Property Related Temporary Differences $(118,147) $(595,974) $(320,900) $(362,884) $(149,309)
Amounts Due From Customers For
Future Federal Income Taxes (20,215) (61,130) 10,199 (6,441) 4,757
Deferred State Income Taxes (25,267) (18,440) - - -
Translation Regulatory Assets - (154,947) - - -
Deferred Fuel and Purchased Power - 20,323 - - -
Provision for Mine Shutdown Costs - 18,365 - - -
All Other (net) (4,675) (6,086) 13,824 (456) (497)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(168,304) $(797,889) $(296,877) $(369,781) $(145,049)
========= ========= ========= ========= =========
AEGCo APCo CPL CSPCo I&M
December 31, 2000 (in thousands)
Deferred Tax Assets $ 81,480 $ 178,487 $ 67,184 $ 88,198 $ 342,900
Deferred Tax Liabilities (114,408) (860,961) (1,309,981) (510,957) (830,845)
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945)
========= ========= =========== ========= =========
Property Related Temporary Differences $ (78,113) $(510,950) $ (773,454) $(343,045) $(324,198)
Amounts Due From Customers For
Future Federal Income Taxes 10,317 (55,085) (72,426) (11,142) (55,218)
Deferred State Income Taxes (5,478) (86,351) - - (69,982)
Translation Regulatory Asset - (40,554) - (68,817) -
Net Deferred Gain on Sale and
Leaseback-Rockport Plant Unit 2 42,766 - - - 28,454
Accrued Nuclear Decommissioning Expense - - - - 34,702
Deferred Fuel and Purchased Power - - - - (39,395)
Deferred Cook Plant Restart Costs - - - - (42,000)
Nuclear Fuel - - - - (28,319)
Regulatory Assets Designated
for Securitization - - (332,198) - -
All Other (net) (2,420) 10,466 (64,719) 245 8,011
--------- --------- ----------- --------- ---------
Net Deferred Tax Liabilities $ (32,928) $(682,474) $(1,242,797) $(422,759) $(487,945)
========= ========= =========== ========= =========
KPCo OPCo PSO SWEPCo WTU
December 31, 2000 (in thousands)
Deferred Tax Assets $ 32,807 $ 330,878 $ 60,010 $ 47,615 $ 16,604
Deferred Tax Liabilities (198,742) (952,819) (372,070) (446,819) (173,642)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038)
========= ========= ========= ========= =========
Property Related Temporary Differences $(116,109) $(586,039) $(313,248) $(375,427) $(150,264)
Amounts Due From Customers For
Future Federal Income Taxes (19,680) (57,759) 11,082 (6,015) 4,723
Deferred State Income Taxes (29,695) (14,282) (36,487) - -
Translation Regulatory Asset - (53,149) - - -
Deferred Fuel and Purchased Power - (116,224) - - -
Provision for Mine Shutdown Costs - 63,995 - - -
Postretirement Benefits - 93,306 - - -
All Other (net) (451) 48,211 26,593 (17,762) (11,497)
--------- --------- --------- --------- ---------
Net Deferred Tax Liabilities $(165,935) $(621,941) $(312,060) $(399,204) $(157,038)
========= ========= ========= ========= =========
We have settled with the IRS all issues from the audits of our consolidated
federal income tax returns for the years prior to 1991. We have received Revenue
Agent's Reports from the IRS for the years 1991 through 1996, and have filed
protests contesting certain proposed adjustments. Returns for the years 1997
through 2000 are presently being audited by the IRS. Management is not aware of
any issues for open tax years that upon final resolution are expected to have a
material adverse effect on results of operations.
COLI Litigation - On February 20, 2001, the U.S. District Court for the Southern
District of Ohio ruled against AEP in its suit against the United States over
deductibility of interest claimed by AEP in its consolidated federal income tax
returns related to its COLI program. AEP had filed suit to resolve the IRS'
assertion that interest deductions for AEP's COLI program should not be allowed.
In 1998 and 1999 we paid the disputed taxes and interest attributable to COLI
interest deductions for taxable years 1991-98 to avoid the potential assessment
by the IRS of additional interest on the contested tax. The payments were
included in other assets pending the resolution of this matter. As a result of
the U.S. District Court's decision to deny the COLI interest deductions, net
income was reduced by the amounts shown in the table below in 2000. The Company
has filed an appeal of the U.S. District Court's decision with the U.S. Court of
Appeals for the 6th Circuit.
The earnings reductions for affected registrant subsidiaries are as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
The AEP System companies join in the filing of a consolidated federal income tax
return. The allocation of the AEP System's current consolidated federal income
tax to the System companies is in accordance with SEC rules under the 1935 Act.
These rules permit the allocation of the benefit of current tax losses to the
System companies giving rise to them in determing their current tax expense. The
tax loss of the System parent company, AEP Co., Inc., is allocated to its
subsidiaries with taxable income. With the exception of the loss of the parent
company, the method of allocation approximates a separate return result for each
company in the consolidated group.
14. Supplementary Information:
The amounts of power purchased by the registrant subsidiaries from Ohio Valley
Electric Corporation, which is 44.2% owned by the AEP System, for the years
ended December 31, 2001, 2000, and 1999 were:
APCo CSPCo I&M OPCo
---- ----- --- ----
(in thousands)
Year Ended December 31, 2001 $45,542 $12,626 $20,723 $47,757
Year Ended December 31, 2000 30,998 8,706 15,204 31,134
Year Ended December 31, 1999 21,774 6,006 10,227 25,623
15. Leases:
Leases of property, plant and equipment are for periods up to 35 years and
require payments of related property taxes, maintenance and operating costs. The
majority of the leases have purchase or renewal options and will be renewed or
replaced by other leases.
Lease rentals for both operating and capital leases are generally charged to
operating expenses in accordance with rate-making treatment for regulated
operations. The components of rental costs are as follows:
AEGCo APCo CPL CSPCo I&M KPCo
Year Ended December 31, 2001 (in thousands)
Lease Payments on
Operating Leases $76,262 $ 6,142 $5,948 $ 7,063 $104,574 $1,191
Amortization of Capital Leases 281 12,099 - 7,206 17,933 2,740
Interest on Capital Leases 55 3,789 - 2,396 4,424 808
------- ------- ------ ------- -------- ------
Total Lease Rental Costs $76,598 $22,030 $5,948 $16,665 $126,931 $4,739
======= ======= ====== ======= ======== ======
OPCo PSO SWEPCo WTU
Year Ended December 31, 2001 (in thousands)
Lease Payments on
Operating Leases $63,913 $4,010 $2,277 $1,534
Amortization of Capital Leases 14,443 - - -
Interest on Capital Leases 5,818 - - -
------- ------ ------ ------
Total Lease Rental Costs $84,174 $4,010 $2,277 $1,534
======= ====== ====== ======
AEGCo APCo CPL CSPCo I&M KPCo
Year Ended December 31, 2000 (in thousands)
Lease Payments on
Operating Leases $73,858 $ 7,128 $ - $ 7,683 $ 81,446 $1,978
Amortization of Capital Leases 281 13,900 - 7,776 26,341 3,931
Interest on Capital Leases 55 3,930 - 2,690 10,908 1,054
------- ------- ------- ------- -------- ------
Total Lease Rental Costs $74,194 $24,958 $ - $18,149 $118,695 $6,963
======= ======= ======= ======= ======== ======
OPCo PSO SWEPCo WTU
Year Ended December 31, 2000 (in thousands)
Lease Payments on
Operating Leases $51,981 $ - $ - $ -
Amortization of Capital Leases 37,280 - - -
Interest on Capital Leases 9,584 - - -
------- ------ ------ ------
Total Lease Rental Costs $98,845 $ - $ - $ -
======= ====== ====== ======
AEGCo APCo CPL CSPCo I&M KPCo
Year Ended December 31, 1999 (in thousands)
Lease Payments on
Operating Leases $74,269 $ 5,647 $ - $ 5,687 $ 81,611 $ 199
Amortization of Capital Leases 364 13,749 - 7,427 11,320 4,299
Interest on Capital Leases 64 4,267 - 2,720 9,338 1,162
------- ------- ------ ------- -------- ------
Total Lease Rental Costs $74,697 $23,663 $ - $15,834 $102,269 $5,660
======= ======= ====== ======= ======== ======
OPCo PSO SWEPCo WTU
Year Ended December 31, 1999 (in thousands)
Lease Payments on
Operating Leases $ 60,026 $ - $ - $ -
Amortization of Capital Leases 35,622 - - -
Interest on Capital Leases 9,552 - - -
-------- ------ ------ ------
Total Lease Rental Costs $105,200 $ - $ - $ -
======== ====== ====== ======
Property, plant and equipment under capital leases and related obligations
recorded on the Consolidated Balance Sheets are as follows:
AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2001 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $1,983 $ 2,712 $ 6,380 $ 4,826 $ 1,138 $ 22,477
Distribution 14,593
Other:
Mining Assets and Other 129 82,292 $54,999 86,267 17,658 114,944
------ ------- ------- -------- ------- --------
Total Property, Plant
and Equipment 2,112 85,004 61,379 105,686 18,796 137,421
Accumulated Amortization 1,801 38,745 26,044 43,768 9,213 57,429
------ ------- ------- -------- ------- --------
Net Property, Plant and
Equipment Under
Capital Leases $ 311 $46,259 $35,335 $ 61,918 $ 9,583 $ 79,992
====== ======= ======= ======== ======= ========
Obligations Under Capital Leases:
Noncurrent Liability $ 76 $33,928 $27,052 $ 51,093 $ 6,742 $ 64,261
Liability Due Within One Year 235 12,357 7,835 10,840 2,841 16,405
------ ------- ------- -------- ------- --------
Total Obligations Under
Capital Leases $ 311 $46,285 $34,887 $ 61,933 $ 9,583 $ 80,666
====== ======= ======= ======== ======= ========
AEGCo APCo CSPCo I&M KPCo OPCo
Year Ended December 31, 2000 (in thousands)
Property, Plant and Equipment
Under Capital Leases
Production $2,017 $ 6,276 $ 2 $ 7,023 $ 1,730 $ 24,709
Distribution 14,595
Other:
Nuclear Fuel
(net of amortization) 89,872
Mining Assets and Other 177 93,437 68,352 97,383 22,072 200,308
------ ------- ------- -------- ------- --------
Total Property, Plant
and Equipment 2,194 99,713 68,354 208,873 23,802 225,017
Accumulated Amortization 1,603 36,553 25,422 45,700 9,618 108,436
------ ------- ------- -------- ------- --------
Net Property, Plant and
Equipment Under
Capital Leases $ 591 $63,160 $42,932 $163,173 $14,184 $116,581
====== ======= ======= ======== ======= ========
Obligations Under Capital Leases:
Noncurrent Liability $ 358 $50,350 $35,199 $ 62,325 $11,091 $ 83,866
Liability Due Within One Year 233 12,810 7,733 100,848 3,093 32,715
------ ------- ------- -------- ------- --------
Total Obligations Under
Capital Leases $ 591 $63,160 $42,932 $163,173 $14,184 $116,581
====== ======= ======= ======== ======= ========
Properties under operating leases and related obligations are not included in
the Consolidated Balance Sheets.
CPL, PSO, SWEPCo and WTU do not lease property, plant and equipment under
capital leases.
Future minimum lease payments consisted of the following at December 31, 2001:
AEGCo APCo CSPCo I&M KPCo OPCo
Capital (in thousands)
- -------
2002 $217 $13,718 $ 8,932 $11,759 $ 3,093 $ 18,516
2003 132 11,625 7,284 10,028 2,441 17,521
2004 20 9,371 6,111 7,947 1,824 14,701
2005 6 6,440 5,248 6,282 1,449 11,520
2006 1 4,690 3,903 5,335 891 10,305
Later Years - 7,613 11,400 17,882 1,548 28,948
---- ------- ------- ------- ------- --------
Total Future Minimum
Lease Payments 376 53,457 42,878 59,233 11,246 101,511
Less Estimated Interest Element 65 7,172 7,991 (2,700) 1,663 20,845
---- ------- ------- ------- ------- --------
Estimated Present Value of
Future Minimum Lease Payments $311 $46,285 $34,887 $61,933 $ 9,583 $ 80,666
==== ======= ======= ======= ======= ========
AEGCo APCo CPL CSPCo I&M KPCo
(in thousands)
Noncancellable Operating Leases
2002 $ 73,854 $ 3,193 $ 5,948 $ 2,104 $ 82,627 $ 717
2003 73,854 3,108 5,948 1,991 79,923 691
2004 73,854 2,402 5,948 1,623 77,104 571
2005 73,854 2,155 5,948 1,308 75,736 544
2006 73,854 1,887 5,948 1,279 75,595 398
Later Years 1,181,664 4,563 - 3,198 1,186,678 1,842
---------- ------- ------- ------- ---------- ------
Total Future Minimum
Lease Payments $1,550,934 $17,308 $29,740 $11,503 $1,577,663 $4,763
========== ======= ======= ======= ========== ======
OPCo PSO SWEPCo WTU
(in thousands)
Noncancellable Operating Leases
2002 $ 62,945 $4,010 $ 2,277 $1,534
2003 62,914 4,010 2,277 1,534
2004 63,323 4,010 2,277 1,534
2005 62,836 4,010 2,277 1,534
2006 63,242 4,010 2,277 1,534
Later Years 244,069 - - -
-------- ------ ------- ------
Total Future Minimum
Lease Payments $559,329 $20,050 $11,385 $7,670
======== ======= ======= ======
Operating leases include lease agreements with special purpose entities related
to Rockport Plant Unit 2 and the Gavin Plant's flue gas desulfurization system
(Gavin Scrubbers). The Rockport Plant lease resulted from a sale and leaseback
transaction in 1989. The gain from the sale was deferred and is being amortized
over the term of the lease which expires in 2022. The Gavin Scrubber lease
expires in 2009. AEGCo and OPCo have no ownership interest in the special
purpose entities and do not guarantee their debt. The special purpose entities
are not consolidated in accordance with applicable accounting standards. As a
result, neither the leased plant and equipment nor the debt of the special
purpose entities is included in AEGCo or OPCo's balance sheets. The future lease
payment obligations to the special purpose entities are included in the above
table of future minimum lease payments under noncancellable operating leases.
16. Lines of Credit and Sale of Receivables:
The AEP System uses short-term debt, primarily commercial paper, to meet
fluctuations in working capital requirements and other interim capital needs.
AEP has established a money pool to coordinate short-term borrowings for certain
subsidiaries, including AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo
and WTU and also incurs borrowings outside the money pool for other
subsidiaries.
The registrant subsidiaries incurred interest expense for amounts borrowed from
the AEP money pool as follows:
Year Ended December 31,
2001 2000 1999
(in millions)
AEGCo 0.8 - -
APCo 9.8 - -
CPL 11.4 16.9 14.1
CSPCo 5.0 1.4 -
I&M 13.1 0.8 -
KPCo 2.3 - -
OPCo 14.6 9.2 -
PSO 6.3 7.5 2.0
SWEPCo 3.4 4.2 4.7
WTU 3.1 2.7 0.6
Interest income earned from amounts advanced to the AEP money pool by the
registrant subsidiaries were:
Year Ended December 31,
2001 2000 1999
(in millions)
APCo 1.7 - -
CPL 0.1 - -
CSPCo 0.8 1.1 -
I&M 1.6 9.0 -
KPCo 0.1 1.8 -
OPCo 8.6 3.4 -
SWEPCo 0.1 - 0.1
WTU - - 0.2
Under a factoring arrangement the registrant subsidiaries (excluding AEGCo) sell
without recourse certain of their customer accounts receivable and accrued
utility revenue balances to AEP Credit and are charged a fee based on AEP Credit
financing costs, uncollectible accounts experience for each company's
receivables and administrative costs. The costs of factoring customer accounts
receivable is reported as an operating expense. At December 31, 2001 the amount
of factored accounts receivable and accrued utility revenues for each registrant
subsidiary was as follows:
Company (in millions)
- -------
APCo $ 61
CPL 89
CSPCo 106
I&M 95
KPCo 26
OPCo 100
PSO 43
SWEPCo 47
WTU 23
The fees paid by the registrant subsidiaries to AEP Credit for factoring
customer accounts receivable were:
Year Ended December 31,
2001 2000 1999
(in millions)
APCo $ 5.2 $- $-
CPL 14.7 15.7 14.7
CSPCo 15.2 10.8 -
I&M 8.5 6.8 -
KPCo 2.7 1.9 -
OPCo 12.8 8.4 -
PSO 9.6 8.3 6.5
SWEPCo 7.4 9.2 9.3
WTU 3.8 4.0 3.5
17. Unaudited Quarterly Financial Information:
The unaudited quarterly financial information for each registrant subsidiary
follows:
Quarterly Periods
Ended AEGCo APCo CPL CSPCo I&M
----------------- ----- ---- --- ----- ---
(in thousands)
2001
March 31
Operating Revenues $60,507 $501,204 $432,910 $327,437 $387,813
Operating Income 1,807 88,152 64,152 51,932 52,698
Income (Loss) Before
Extraordinary Items 1,980 61,787 35,031 37,671 32,363
Net Income (Loss) 1,980 61,787 35,031 37,671 32,363
June 30
Operating Revenues $52,217 $430,412 $470,420 $333,995 $382,234
Operating Income 1,882 59,362 82,351 62,894 47,340
Income (Loss) Before
Extraordinary Items 2,063 36,419 52,518 47,418 27,374
Net Income (Loss) 2,063 36,419 52,518 21,011 27,374
September 30
Operating Revenues $57,417 $434,450 $527,117 $375,691 $398,457
Operating Income 1,615 60,381 112,598 76,920 44,509
Income Before Extraordinary Items 2,051 30,317 83,702 65,318 25,064
Net Income 2,051 30,317 83,702 65,318 25,064
December 31
Operating Revenues $57,407 $418,193 $308,390 $313,196 $358,493
Operating Income 1,673 67,091 36,630 60,431 15,158
Income (Loss) Before
Extraordinary Items 1,781 33,295 13,536 41,493 (9,013)
Net Income (Loss) 1,781 33,295 11,027 37,876 (9,013)
Quarterly Periods
Ended KPCo OPCo PSO SWEPCo WTU
----------------- ---- ---- --- ------ ---
(in thousands)
2001
March 31
Operating Revenues $100,681 $552,503 $255,080 $267,117 $141,649
Operating Income 12,604 64,756 8,340 33,986 5,392
Income Before Extraordinary Items 7,075 53,397 (1,560) 19,869 891
Net Income 7,075 53,397 (1,560) 19,869 891
June 30
Operating Revenues $89,541 $512,196 $265,360 $271,748 $139,228
Operating Income 8,364 47,067 21,942 32,649 12,428
Income Before Extraordinary Items 2,742 32,094 11,921 17,784 6,133
Net Income 2,742 10,579 11,921 17,784 6,133
September 30
Operating Revenues $96,197 $535,535 $325,373 $331,441 $181,433
Operating Income 12,587 69,668 59,914 60,194 17,745
Income Before Extraordinary Items 5,312 51,378 51,069 46,357 14,067
Net Income 5,312 51,378 51,069 46,357 14,067
December 31
Operating Revenues $92,606 $497,871 $141,187 $231,020 $94,148
Operating Income 14,123 59,219 6,793 19,378 (2,175)
Income (Loss) Before
Extraordinary Items 6,436 28,924 (3,670) 5,357 (8,781)
Net Income (Loss) 6,436 32,091 (3,670) 5,357 (8,781)
Quarterly Periods
Ended AEGCo APCo CPL CSPCo I&M
----------------- ----- ---- --- ----- ---
(in thousands)
2000
March 31
Operating Revenues $56,866 $442,646 $316,328 $290,587 $335,594
Operating Income 2,395 78,246 38,650 44,124 (15,251)
Income Before Extraordinary Items 2,445 47,664 8,139 27,471 (36,553)
Net Income 2,445 47,664 8,139 27,471 (36,553)
June 30
Operating Revenues $56,928 $401,830 $437,911 $315,853 $345,073
Operating Income 1,746 58,208 95,717 50,798 (18,599)
Income Before Extraordinary Items 1,653 30,240 67,553 35,335 (39,181)
Net Income 1,653 39,178 67,553 35,335 (39,181)
September 30
Operating Revenues $55,658 $448,563 $600,732 $375,112 $408,637
Operating Income 2,209 65,750 120,653 83,562 36,056
Income Before Extraordinary Items 1,972 36,112 89,974 65,542 15,190
Net Income 1,972 36,112 89,974 40,306 15,190
December 31
Operating Revenues $59,064 $466,214 $415,431 $322,857 $398,905
Operating Income 2,074 (1,050) 52,078 17,393 (36,908)
Income (Loss) Before
Extraordinary Items 1,914 (49,110) 23,901 (8,146) (71,488)
Net Income (Loss) 1,914 (49,110) 23,901 (8,146) (71,488)
Quarterly Periods
Ended KPCo OPCo PSO SWEPCo WTU
----------------- ---- ---- --- ------ ---
(in thousands)
2000
March 31
Operating Revenues $94,135 $533,834 $161,329 $207,756 $ 93,335
Operating Income 15,557 65,113 10,860 22,731 9,781
Income Before Extraordinary Items 8,052 46,216 1,165 7,663 3,833
Net Income 8,052 46,216 1,165 7,663 3,833
June 30
Operating Revenues $92,104 $515,445 $209,172 $272,409 $130,742
Operating Income 9,456 79,968 24,502 33,296 16,938
Income Before Extraordinary Items 2,449 58,233 14,700 18,786 8,070
Net Income 2,449 58,233 14,700 18,786 8,070
September 30
Operating Revenues $102,798 $558,737 $355,992 $374,654 $200,124
Operating Income 13,790 96,652 56,437 61,312 16,565
Income Before Extraordinary Items 6,761 77,061 54,329 47,537 10,670
Net Income 6,761 58,185 54,329 47,537 10,670
December 31
Operating Revenues $100,838 $532,315 $229,905 $263,455 $146,863
Operating Income 10,935 (14,906) 4,870 10,939 9,057
Income (Loss) Before
Extraordinary Items 3,501 (78,897) (3,531) (1,314) 4,877
Net Income (Loss) 3,501 (78,897) (3,531) (1,314) 4,877
I&M's fourth quarter 2001 earnings were also favorably impacted by the return to
service in December 2000 of Unit 1 of the Cook Plant after an extended outage.
18. Trust Preferred Securities:
The following Trust Preferred Securities issued by the wholly-owned statutory
business trusts of CPL, PSO and SWEPCo were outstanding at December 31, 2001 and
December 31, 2000. They are classified on the balance sheets as Certain
Subsidiaries Obligated, Mandatorily Redeemable Preferred Securities of
Subsidiary Trusts Holding Solely Junior Subordinated Debentures of Such
Subsidiaries. The Junior Subordinated Debentures mature on April 30, 2037. CPL
reacquired 490,000 and 60,000 trust preferred units during 2001 and 2000,
respectively.
Units issued/
Outstanding Description of
At 12/31/01 Underlying
Business Trust Security Amount at December 31, Debentures of Registrant
- -------------- -------- ---------------------- ------------------------
2001 2000
(in millions)
CPL Capital I 8.00%, Series A 5,450,000 $136 $149 CPL, $141 million,
8.00%, Series A
PSO Capital I 8.00%, Series A 3,000,000 75 75 PSO, $77 million,
8.00%, Series A
SWEPCo Capital I 7.875%, Series A 4,400,000 110 110 SWEPCO, $113 million,
---------- - --- - ---
12,850,000 $321 $334 7.875%, Series A
========== ==== ====
Each of the business trusts is treated as a subsidiary of its parent company.
The only assets of the business trusts are the subordinated debentures issued by
their parent company as specified above. In addition to the obligations under
their subordinated debentures, each of the parent companies has also agreed to a
security obligation which represents a full and unconditional guarantee of its
capital trust obligation.\
19. Jointly Owned Electric Utility Plant:
CPL, CSPCo, PSO, SWEPCo and WTU have generating units that are jointly owned
with unaffiliated companies. Each of the participating companies is obligated to
pay its share of the costs of any such jointly owned facilities in the same
proportion as its ownership interest. Each AEP registrant subsidiary's
proportionate share of the operating costs associated with such facilities is
included in its statements of income and the investments are reflected in its
balance sheets under utility plant as follows:
Company's Share
December 31,
2001 2000
-------------------------- ---------------------------
Percent Utility Construction Utility Construction
of Plant Work Plant Work
Ownership in Service in Progress in Service in Progress
--------- ------------ ------------- ------------ ------------
(in thousands) (in thousands)
CPL:
Oklaunion Generating Station
(Unit No. 1) 7.8 $ 37,728 $ 318 $ 37,236 $ 395
South Texas Project Generating
Station (Units No. 1 and 2) 25.2 2,360,452 41,571 2,373,575 19,292
---------- ------- ---------- -------
$2,398,180 $41,889 $2,410,811 $19,687
========== ======= ========== ========
CSP:
W.C. Beckjord Generating Station
(Unit No. 6) 12.5 $ 14,292 $ 884 $ 14,108 $ 178
Conesville Generating Station
(Unit No. 4) 43.5 81,697 494 80,103 261
J.M. Stuart Generating Station 26.0 193,760 27,758 191,875 10,086
Wm. H. Zimmer Generating Station 25.4 704,951 2,634 706,549 5,265
Transmission (a) 61,476 91 61,820 451
---------- ------- ---------- -------
$1,056,176 $31,861 $1,054,455 $16,241
========== ======= ========== =======
PSO:
Oklaunion Generating Station
(Unit No. 1) 15.6 $ 82,646 $ 634 $ 81,185 $ 817
========== ======= ========== ========
SWEPCo:
Dolet Hills Generating Station
(Unit No. 1) 40.2 $ 234,747 $ 675 $ 231,442 $ 1,984
Flint Creek Generating Station
(Unit No. 1) 50.0 83,953 213 82,899 852
Pirkey Generating Station
(Unit No. 1) 85.9 439,430 10,577 437,069 435
---------- ------- ---------- -------
$ 758,130 $11,465 $ 751,410 $ 3,271
========== ======= ========== ========
WTU:
Oklaunion Generating Station
(Unit No. 1) 54.7 $ 279,419 $ 1,651 $ 277,624 $ 3,295
========== ======= ========== =======
(a) Varying percentages of ownership.
The accumulated depreciation with respect to each AEP registrant subsidiary's
share of jointly owned facilities is shown below:
December 31,
2001 2000
---- ----
(in thousands)
CPL $863,130 $834,722
CSPCo 410,756 389,558
PSO 35,653 33,669
SWEPCo 392,728 367,558
WTU 100,430 98,045
20. Related Party Transactions
AEP System Power Pool
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Interconnection Agreement,
dated July 6, 1951, as amended (the Interconnection Agreement), defining how
they share the costs and benefits associated with their generating plants. This
sharing is based upon each company's "member-load-ratio," which is calculated
monthly on the basis of each company's maximum peak demand in relation to the
sum of the maximum peak demands of all five companies during the preceding 12
months. In addition, since 1995, APCo, CSPCo, I&M, KPCo and OPCo have been
parties to the AEP System Interim Allowance Agreement which provides, among
other things, for the transfer of SO2 Allowances associated with transactions
under the Interconnection Agreement. As part of AEP's restructuring settlement
agreement filed with FERC, CSPCo and OPCo would no longer be parties to the
Interconnection agreement and certain other modifications to its terms would
also be made.
Power marketing and trading transactions (trading activities) are conducted by
the AEP Power Pool and shared among the parties under the Interconnection
Agreement. Trading activities involve the purchase and sale of electricity under
physical forward contracts at fixed and variable prices and the trading of
electricity contracts including exchange traded futures and options and
over-the-counter options and swaps. The majority of these transactions represent
physical forward contracts in the AEP System's traditional marketing area and
are typically settled by entering into offsetting contracts. The regulated
physical forward purchase and sale contracts are recorded in operating revenues
on a net basis in the month when the contract settles.
In addition, the AEP Power Pool enters into transactions for the purchase and
sale of electricity options, futures and swaps, and for the forward purchase and
sale of electricity outside of the AEP System's traditional marketing area.
CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Restated and
Amended Operating Agreement originally dated as of January 1, 1997 (CSW
Operating Agreement). The CSW Operating Agreement requires the operating
companies of the west zone to maintain specified annual planning reserve margins
and requires the subsidiaries that have capacity in excess of the required
margins to make such capacity available for sale to other AEP subsidiaries as
capacity commitments. The CSW Operating Agreement also delegates to AEP Service
Corporation the authority to coordinate the acquisition, disposition, planning,
design and construction of generating units and to supervise the operation and
maintenance of a central control center. The CSW Operating Agreement has been
accepted for filing and allowed to become effective by FERC.
AEP's System Integration Agreement provides for the integration and coordination
of AEP's east and west zone operating subsidiaries, joint dispatch of generation
within the AEP System, and the distribution, between the two operating zones, of
costs and benefits associated with the System's generating plants. It is
designed to function as an umbrella agreement in addition to the AEP
Interconnection Agreement and the CSW Operating Agreement, each of which will
continue to control the distribution of costs and benefits within each zone.
The following table shows the revenues derived from sales to the Pools and
direct sales to affiliates for years ended December 31, 2001, 2000 and 1999:
APCo CSPCo I&M KPCo OPCo AEGCo
Related Party Revenues (in thousands)
2001 Sales to East System Pool $ 91,977 $44,185 $239,277 $34,735 $431,637 $ -
Sales to West System Pool 24,892 13,971 15,596 6,117 19,797 -
Direct Sales To East Affiliates 54,777 - - - 55,450 227,338
Direct Sales To West Affiliates (3,133) (1,705) (1,905) (744) (2,590) -
Other 2,772 11,060 2,071 2,258 7,072 -
-------- ------- -------- ------- -------- --------
Total Revenues $171,285 $67,511 $255,039 $42,366 $511,366 $227,338
======== ======= ======== ======= ======== ========
2000 Sales to East System Pool $ 81,013 $36,884 $200,474 $36,554 $502,140 $ -
Sales to West System Pool 7,697 4,095 4,614 1,829 6,356 -
Direct Sales To East Affiliates 59,106 - - - 66,487 227,983
Direct Sales To West Affiliates 4,092 2,262 2,510 972 3,421 -
Other 2,770 6,124 2,710 2,466 4,043 -
-------- ------- -------- ------- -------- --------
Total Revenues $154,678 $49,365 $210,308 $41,821 $582,447 $227,983
======== ======= ======== ======= ======== ========
1999 Sales to East System Pool $ 41,869 $15,136 $50,624 $43,157 $337,699 $ -
Direct Sales To East Affiliates 57,201 - - - 50,968 152,559
Other 1,162 4,582 345 1,145 825 -
-------- ------- -------- ------- -------- --------
Total Revenues $100,232 $19,718 $50,969 $44,302 $389,492 $152,559
======== ======= ======= ======= ======== ========
CPL PSO SWEPCo WTU
Related Party Revenues (in thousands)
2001 Sales to East System Pool $ - $ 4 $ - $ -
Sales to West System Pool 19,865 3,317 8,073 322
Direct Sales To East Affiliates 3,697 2,833 3,238 1,228
Direct Sales To West Affiliates 12,617 30,668 67,930 9,350
Other 5,583 (51) (3) 7,781
------- ------- ------- -------
Total Revenues $41,762 $36,771 $79,238 $18,681
======= ======= ======= =======
2000 Sales to East System Pool $ - $ - $ - $ -
Sales to West System Pool 23,421 7,323 5,546 194
Direct Sales To East Affiliates (3,348) (1,990) (3,008) (1,116)
Direct Sales To West Affiliates 12,516 21,995 62,178 7,645
Other 5,163 (12,680) (1,592) 11,931
------- ------- ------- -------
Total Revenues $37,752 $14,648 $63,124 $18,654
======= ======= ======= =======
1999 Sales to West System Pool $ 6,124 $ 3,097 $ 4,527 $ 401
Direct Sales To West Affiliates 7,470 7,968 49,542 2,576
Other 14,177 2,652 48 11,790
------- ------- ------- -------
Total Revenues $27,771 $13,717 $54,117 $14,767
======= ======= ======= =======
The following table shows the purchased power expense incurred from purchases
from the Pools and affiliates for the years ended December 31, 2001, 2000, and
1999:
APCo CSPCo I&M KPCo OPCo
Related Party Purchases (in thousands)
2001 Purchases from East System Pool $346,582 $292,034 $ 79,030 $ 61,816 $62,350
Purchases from West System Pool 296 165 185 72 235
Direct Purchases from East Affiliates - - 159,022 68,316 -
Direct Purchases from West Affiliates - - - - -
-------- -------- -------- -------- -------
Total Purchases $346,878 $292,199 $238,237 $130,204 $62,585
======== ======== ======== ======== =======
2000 Purchases from East System Pool $355,305 $287,482 $106,644 $ 58,150 $50,339
Purchases from West System Pool 455 260 285 108 390
Direct Purchases from East Affiliates - - 158,537 69,446 -
Direct Purchases from West Affiliates 14 8 9 3 12
-------- -------- -------- -------- -------
Total Purchases $355,774 $287,750 $265,475 $127,707 $50,741
======== ======== ======== ======== =======
1999 Purchases from East System Pool $130,991 $199,574 $112,350 $19,502 $ 20,864
Direct Purchases from East Affiliates - - 88,022 64,498 -
-------- -------- -------- ------- ---------
Total Purchases $130,991 $199,574 $200,372 $84,000 $ 20,864
======== ======== ======== ======= ========
CPL PSO SWEPCo WTU
Related Party Purchases (in thousands)
2001 Purchases from East System Pool $ - $ 1,327 $ - $ 4
Purchases from West System Pool 415 5,877 3,810 11,689
Direct Purchases from East Affiliates 12,657 37,445 27,744 4,614
Direct Purchases from West Affiliates 45,569 34,603 9,696 40,349
------- ------- ------- -------
Total Purchases $58,641 $79,252 $41,250 $56,656
======= ======= ======= =======
2000 Purchases from East System Pool $ - $20,100 $ - $ -
Purchases from West System Pool 1,696 5,386 4,379 18,444
Direct Purchases from East Affiliates 251 2,117 695 71
Direct Purchases from West Affiliates 30,644 33,185 8,264 39,258
------- ------- ------- -------
Total Purchases $32,591 $60,788 $13,338 $57,773
======= ======= ======= =======
1999 Purchases from West System Pool $ 895 $ 6,992 $1,295 $ 7,266
Direct Purchases from West Affiliates 15,778 27,627 6,256 19,325
------- ------- ------ -------
Total Purchases $16,673 $34,619 $7,551 $26,591
======= ======= ====== =======
The above summarized related party revenues and expenses are presented as
operating revenues affiliated and purchased power affiliated on the income
statement of each AEP Power Pool member.
AEP System Transmission Pool
APCo, CSPCo, I&M, KPCo and OPCo are parties to the Transmission Agreement, dated
April 1, 1984, as amended (the Transmission Agreement), defining how they share
the costs associated with their relative ownership of the extra-high-voltage
transmission system (facilities rated 345 kv and above) and certain facilities
operated at lower voltages (138 kv and above). Like the Interconnection
Agreement, this sharing is based upon each company's "member-load-ratio."
The following table shows the net (credits) or charges allocated among the
parties to the Transmission Agreement during the years ended December 31, 1998,
1999 and 2000:
1999 2000 2001
---- ---- ----
(in thousands)
APCo $ (8,300) $ (3,400) $ (3,100)
CSPCo 39,000 38,300 40,200
I&M (43,900) (43,800) (41,300)
KPCo (4,300) (6,000) (4,600)
OPCo 17,500 14,900 8,800
CPL, PSO, SWEPCo, WTU and AEP Service Corporation are parties to a Transmission
Coordination Agreement originally dated as of January 1, 1997 (TCA). The TCA
established a coordinating committee, which is charged with the responsibility
of overseeing the coordinated planning of the transmission facilities of the
west zone operating subsidiaries, including the performance of transmission
planning studies, the interaction of such subsidiaries with independent system
operators (ISO) and other regional bodies interested in transmission planning
and compliance with the terms of the Open Access Transmission Tariff (OATT)
filed with the FERC and the rules of the FERC relating to such tariff.
Under the TCA, the west zone operating subsidiaries have delegated to AEP
Service Corporation the responsibility of monitoring the reliability of their
transmission systems and administering the OATT on their behalf. The TCA also
provides for the allocation among the west zone operating subsidiaries of
revenues collected for transmission and ancillary services provided under the
OATT.
AEP's System Transmission Integration Agreement provides for the integration and
coordination of the planning, operation and maintenance of the transmission
facilities of AEP's east and west zone operating subsidiaries. Like the System
Integration Agreement, the System Transmission Integration Agreement functions
as an umbrella agreement in addition to the AEP Transmission Agreement and the
Transmission Coordination Agreement. The System Transmission Integration
Agreement contains two service schedules that govern:
o The allocation of transmission costs and revenues.
o The allocation of third-party transmission costs and revenues and System
dispatch costs.
The Transmission Integration Agreement anticipates that additional service
schedules may be added as circumstances warrant.
Unit Power Agreements and Other
A unit power agreement between AEGCo and I&M (the I&M Power Agreement) provides
for the sale by AEGCo to I&M of all the power (and the energy associated
therewith) available to AEGCo at the Rockport Plant. I&M is obligated, whether
or not power is available from AEGCo, to pay as a demand charge for the right to
receive such power (and as an energy charge for any associated energy taken by
I&M) such amounts, as when added to amounts received by AEGCo from any other
sources, will be at least sufficient to enable AEGCo to pay all its operating
and other expenses, including a rate of return on the common equity of AEGCo as
approved by FERC, currently 12.16%. The I&M Power Agreement will continue in
effect until the expiration of the lease term of Unit 2 of the Rockport Plant
unless extended in specified circumstances.
Pursuant to an assignment between I&M and KPCo, and a unit power agreement
between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy
associated therewith) available to AEGCo from both units of the Rockport Plant.
KPCo has agreed to pay to AEGCo in consideration for the right to receive such
power the same amounts which I&M would have paid AEGCo under the terms of the
I&M Power Agreement for such entitlement. The KPCo unit power agreement expires
on December 31, 2004.
APCo and OPCo, jointly own two power plants. The costs of operating these
facilities are apportioned between the owners based on ownership interests. Each
company's share of these costs is included in the appropriate expense accounts
on each company's consolidated statements of income. Each company's investment
in these plants is included in electric utility plant on its consolidated
balance sheets.
I&M provides barging services to AEGCo, APCo and OPCo. I&M records revenues from
barging services as nonoperating income. AEGCo, APCo and OPCo record costs paid
to I&M for barging services as fuel expense. The amount of affiliated revenues
and affiliated expenses were:
Year Ended December 31,
2001 2000 1999
---- ---- ----
Company (in millions)
I&M - revenues $30.2 $23.5 $28.1
AEGCo - expense 8.5 8.8 8.5
APCo - expense 11.5 7.8 10.5
OPCo - expense 10.2 6.9 9.1
American Electric Power Service Corporation (AEPSC) provides certain managerial
and professional services to AEP System companies. The costs of the services are
billed to its affiliated companies by AEPSC on a direct-charge basis, whenever
possible, and on reasonable bases of proration for shared services. The billings
for services are made at cost and include no compensation for the use of equity
capital, which is furnished to AEPSC by AEP Co., Inc. Billings from AEPSC are
capitalized or expensed depending on the nature of the services rendered. AEPSC
and its billings are subject to the regulation of the SEC under the 1935 Act.
21. Subsequent Events - Affecting APCo, CPL, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo and WTU
During 2002, the EITF discussed Issue No. 02-3, "Recognition and
Reporting of Gains and Losses on Energy Contracts under Issues No. 98-10 and
00-17" (EITF 02-3) and reached consensus on certain issues. EITF 98-10,
"Accounting for Contracts Involving Energy Trading and Risk Management
Activities," requires that energy trading contracts be accounted for at fair
value. EITF 02-3 rescinds Issue No. 98-10 effective for any new contracts
entered into after October 25, 2002. For energy trading contracts entered into
through October 25, 2002, such contracts will continue to be accounted for at
fair value through December 31, 2002. Effective January 1, 2003, such contracts
are required to be accounted for at historical cost and we will report this as a
cumulative effect of an accounting change. Our energy contracts that qualify as
derivatives will continue to be accounted for at fair value under SFAS 133.
EITF 02-3 requires that all derivatives held for trading purposes,
whether settled financially or physically, be reported in the income statement
on a net basis effective January 1, 2003. Previous guidance in EITF 98-10
permitted non-financial settled energy trading contracts to be reported either
gross or net in the income statement. Prior to the third quarter of 2002, we
recorded and reported upon settlement, sales under forward trading contracts as
revenues and purchases under forward trading contracts as purchased energy
expenses. Effective July 1, 2002, we reclassified such forward trading activity
to a net basis of reporting, as permitted by EITF 98-10, which resulted in a
substantial reduction in both operating revenues and purchased energy as well as
nonoperating income and expense for APCo, CSPCo, OPCo, KPCo, and I&M. In
addition, for PSO and SWEPCo a reclassification was made for 2001 between
Electricity Marketing and Trading Purchased Power and AEP Affiliates Purchase
Power in order for its presentation to be consistent with the new net basis
presentation that was adopted. These reclassifications did not have any impact
on our financial conditions, results of operations or cash flows.
22. Subsequent Events (Unaudited) - Affecting CPL and WTU
Plant Closings and Staff Reductions - Affecting CPL and WTU
In September 2002 AEP proposed closing 16 gas-fired power plants in the
ERCOT control area of Texas (8 WTU plants and 8 CPL plants). ERCOT indicated
that it may designate some of those plants as "reliability must run" (RMR)
status. In October ERCOT designated seven RMR plants (3 WTU plants and 4 CPL
plants) and approved AEP's plan to inactivate nine other plants (5 WTU plants
and 4 CPL plants). The process of moving the plants to inactive status will take
up to two months. Employees of the plants to become inactive (approximately 183)
will be eligible for severance and outplacement services.
RMR plants are required to ensure the reliability of the power grid,
even if electricity from those plants is not required to meet market needs.
ERCOT and AEP negotiated interim contracts for the remainder of 2002 for the
seven RMR plants. It is expected that 2003 RMR requirements will be announced
before the end of 2002.
As a result of the decision to inactivate WTU plants, a write-down of
utility assets of approximately $34 million (pre-tax) was recorded in Other
Operation expense during the third quarter. The decision to inactivate the CPL
plants resulted in a write-down of utility assets of approximately $100 million
which was deferred and recorded in Regulatory Assets.
Inventory on hand to service the 16 plants is being evaluated for use
at other plants within the AEP System as part of the closing process. A
write-down, if any, associated with inventory becoming obsolete as a result of
the plant closings will be recorded as identified during the closing process.
Severance benefit arrangements for employees at these plants are expected to be
finalized in the fourth quarter of 2002.
Wind Project - Affecting WTU
WTU is assessing recoverability of certain wind generating assets due
to performance concerns. The net book value of these assets is approximately $5
million as of December 31, 2001.
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's
registrant subsidiaries. Management's discussion and analysis of results of
operations for each of AEP's subsidiary registrants is presented with their
financial statements earlier in this document. The following is a list of
sections of management's discussion and analysis of financial condition,
contingencies and other matters and the registrant to which they apply:
Financial Condition APCo, CPL,
I&M, OPCo, SWEPCo
Market Risks AEGCo, APCo,
CPL, CSPCo, I&M,
KPCo, OPCo, PSO,
SWEPCo, WTU
Industry Restructuring APCo, CPL,
CSPCo, I&M, OPCo,
PSO, SWEPCo, WTU
Litigation AEGCo, APCo,
CPL, CSPCo, I&M,
KPCo, OPCo, PSO,
SWEPCo, WTU
Environmental Concerns
and Issues APCo, CPL,
CSPCo, I&M, OPCo,
SWEPCo
Other Matters AEGCo, APCo,
CPL, CSPCo, I&M,
KPCo, OPCo, PSO,
SWEPCo, WTU
Financial Condition - Affecting APCo, CPL, I&M, OPCo and SWEPCo
We measure our financial condition by the strength of the balance sheet
and the liquidity provided by cash flows and earnings.
Balance sheet capitalization ratios and cash flow ratios are principal
determinants of our credit quality.
Year-end ratings of AEP's subsidiaries' first mortgage bonds are listed
in the following table:
Company Moody's S&P Fitch
APCo A3 A A-
CPL A3 A- A
CSPCo A3 A- A
I&M Baa1 A- BBB+
KPCo Baa1 A- BBB+
OPCo A3 A- A-
PSO A1 A A+
SWEPCO A1 A A+
WTU A2 A- A
The ratings at the end of the year for senior unsecured debt are listed
in the following table:
Company Moody's S&P Fitch
APCo Baa1 BBB+ BBB+
CPL Baa1 BBB+ A-
CSPCo A3 BBB+ A-
I&M Baa2 BBB+ BBB
KPCo Baa2 BBB+ BBB
OPCo A3 BBB+ BBB+
PSO A2 BBB+ A
SWEPCO A2 BBB+ A
o The rating is for a series of senior notes issued
with a Support
Agreement from AEP.
Rating agencies have become more focused in their evaluation of credit
quality as a result of the Enron bankruptcy. They are focusing especially on the
composition of the balance sheet (off-balance sheet leases, debt and special
purpose financing structures), the cash liquidity profile and the impact of
credit quality downgrades on financing transactions. We have worked closely with
the agencies to provide them with all the information they need, but we are
unable to predict what actions, if any, they may take regarding our current
ratings.
Cash from operations and short-term borrowings provide working capital
and meet other short-term cash needs. We generally use short-term borrowings to
fund property acquisitions and construction until long-term funding mechanisms
are arranged. Sources of long-term funding include long-term debt and
sale-leaseback or leasing arrangements. The electric subsidiaries generally
issue short-term debt to provide for interim financing of capital expenditures
that exceed internally generated funds and periodically reduce their outstanding
short-term debt through issuances of long-term debt and additional capital
contributions from their parent company. AEP operates a money pool and sells
accounts receivables to provide liquidity for the electric subsidiaries.
For the AEP subsidiary registrants' contractual obligations please see
each registrant's schedules of capitalization and long-term debt included with
each registrants' financial statements in sections B through J for the timing of
debt payment obligations and the lease footnote (Note 15) in section L for the
timing of rent payments.
Special purpose entities have been employed for certain contractual cash
obligations. The lease of Rockport Plant Unit 2 and the Gavin Plant's flue gas
desulfurization system (Gavin Scrubbers) use special purpose entities. Neither
the AEP System companies nor any related parties have an ownership interest in
the special purpose entities or provides a guarantee for the debt of these
entities. These special purpose entities are not consolidated in any AEP System
companies' financial statements in accordance with generally accepted accounting
principles. As a result, neither the assets nor the debt of the special purpose
entities is included on any AEP System company balance sheet.
Certain AEP subsidiaries make commitments in the normal course of
business. These commitments include standby letters of credit, guarantees for
the payment of obligation performance bonds, and other commitments.
SWEPCo guarantanees an unaffiliated mine operator's obligations
(payable upon their default) of $111 million at December 31, 2001, and OPCo has
obligations under a power purchase agreement of $6 million in 2002 and $16
million each year in 2003 through 2005.
OPCo has entered into a purchased power agreement to purchase
electricity pro-duced by an unaffiliated entity's three-unit natural gas fired
plant that is under construction. The first unit is anticipated to be completed
in October 2002 and the agree-ment will terminate 30 years after the third unit
begins operation. Under the terms of the agreement OPCo has the option to run
the plant until December 31, 2005 taking 100% of the power generated. For the
remainder of the 30 year contract term, OPCo will pay the variable costs to
generate the electricity it pur-chases which could be up to 20% of the plant's
capacity. The estimated fixed pay-ments through December 2005 are $55 million
and are included in the Other Commercial Commitments table shown above.
Construction expenditures for the registrant subsidiaries for the next three
years excluding AFUDC are:
Construction
Projected Expenditures
Construction Financed with
Expenditures Internal Funds
(in millions)
APCo $ 815.5 92%
CPL 573.1 80%
I&M 556.9 ALL
OPCo 1,008.0 68%
SWEPCo 321.4 92%
Financing Activity
In 2001 CSPCo and OPCo, AEP's Ohio subsidiaries, reacquired $295.5
million and $175.6 million, respectively, of first mortgage bonds in preparation
for corporate separation.
AEP Credit purchases, without recourse, the accounts receivable of most
of the domestic utility operating companies and certain non-affiliated electric
utility companies.
In February 2002 CPL issued $797 million of securitization notes that
were approved by the PUCT as part of Texas restructuring to help decrease rates
and recover regulatory assets. The proceeds were used to reduce CPL's debt and
equity.
In 2002 AEP plans to continue restructuring its debt for corporate
separation assuming receipt of all necessary regulatory approvals. Corporate
separation will require the transfer of assets between legal entities. With
corporate separation, a newly created holding company for the unregulated
business is expected to issue all debt needed to fund the wholesale business and
unregulated generating companies. The size and maturity lengths of the original
offering is presently being determined.
The regulated holding company is expected to issue the debt needed by
the wires companies in Ohio and Texas. The regulated integrated utility
companies will continue their current debt structure until the regulatory
commissions approve changes. At that time, the regulated holding company may
also issue the debt for the regulated companies' funding needs.
We have requested credit ratings for the holding companies consistent
with our existing credit quality, but we cannot predict what the outcome will
be.
AEP uses a money pool to meet the short-term borrowings for certain of
its subsidiaries, primarily the electric utility operations. Following corporate
separation, the current money pool which was approved by the appropriate
regulatory authorities will continue to service the regulated business
subsidiaries.
Market Risks - Affecting AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo
and WTU
As a major power producer and trader of wholesale electricity, we have
certain market risks inherent in our business activities. These risks include
com-modity price risk, interest rate risk, foreign exchange risk and credit
risk. They represent the risk of loss that may impact us due to changes in the
underlying market prices or rates.
Policies and procedures are established to identify, assess, and manage
market risk exposures in our day to day operations. Our risk policies have been
reviewed with the Board of Directors, approved by a Risk Management Committee
and administered by a Chief Risk Officer. The Risk Management Committee
establishes risk limits, approves risk policies, assigns responsibilities
regarding the oversight and management of risk and monitors risk levels. This
committee receives daily, weekly, and monthly reports regarding compliance with
policies, limits and procedures. The committee meets monthly and consists of the
Chief Risk Officer, Chief Credit Officer, V.P. Market Risk Oversight, and senior
financial and operating managers.
We use a risk measurement model which calculates Value at Risk (VaR) to
measure our commodity price risk. 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. Based on this VaR
analysis, at December 31, 2001 a near term typical change in commodity prices is
not expected to have a material effect on our results of operations, cash flows
or financial condition. The following table shows the high, average, and low
market risk as measured by VaR at:
December 31,
2001 2000
---- ----
High Average Low High Average Low
(in millions)
APCo $4 $1 - $6 $2 -
CPL 3 1 - 4 1 -
CSPCo 2 1 - 3 1 -
I&M 3 1 - 4 1 -
KPCo 1 - - 1 - -
OPCo 3 1 - 5 2 -
PSO 2 1 - 3 1 -
SWEPCo 3 1 - 4 1 -
WTU 1 1 - 1 - -
We also utilize a VaR model to measure interest rate market risk
exposure. The interest rate VaR model is based on a Monte Carlo simulation with
a 95% confidence level and a one year holding period. The volatilities and
correlations were based on three years of weekly prices. The risk of potential
loss in fair value attributable to our exposure to interest rates, primarily
related to long-term debt with fixed interest rates, is detailed in the table
below. However, since we would not expect to liquidate our entire debt portfolio
in a one year holding period, a near term change in interest rates should not
materially affect results of operations or consolidated financial position.
The following table shows the potential loss in fair value as measured
by VaR allocated to the AEP registrant subsidiaries based upon debt outstanding:
VaR for Registrant Subsidiaries:
December 31,
2001 2000
(in millions)
Company
AEGCo $5 $4
APCo 100 149
CPL 80 135
CSPCo 60 84
I&M 86 129
KPCo 16 31
OPCo 59 112
PSO 17 44
SWEPCo 36 60
WTU 20 24
AEGCo is not exposed to risk from changes in interest rates on
short-term and long-term borrowings used to finance operations since financing
costs are recovered through the unit power agreements.
We are exposed to risk from changes in the market prices of coal and
natural gas used to generate electricity where generation is no longer regulated
or where existing fuel clauses are suspended or frozen. The protection afforded
by fuel clause recovery mechanisms has either been eliminated by the
implementation of customer choice in Ohio (effective January 1, 2001 for CSPCo
and OPCo) and in the ERCOT area of Texas (effective January 1, 2002 for CPL and
WTU) or frozen by settlement agreements in Indiana, Michigan and West Virginia.
To the extent the fuel supply of the generating units in these states is not
under fixed price long-term contracts we our subject to market price risk. We
continue to be protected against market price changes by active fuel clauses in
Oklahoma, Arkansas, Louisiana, Kentucky, Virginia and the SPP area of Texas.
We employ physical forward purchase and sale contracts, over-the-counter
options, swaps, and other derivative contracts to offset price risk where
appropriate. However, we engage in trading of electricity, and to a lesser
degree coal, and emission allowances and as a result are subject to price risk.
The amount of risk taken by the traders is controlled by the management of the
trading operations and the Chief Risk Officer and his staff. When the risk from
trading activities exceeds certain pre-determined limits, the positions are
modified or hedged to reduce the risk to the limits unless specifically approved
by the Risk Management Committee.
We employ fair value hedges, cash flow hedges and swaps to mitigate
changes in interest rates or fair values on short and long-term debt when
management deems it necessary. We do not hedge all interest rate risk.
We employ cash flow forward hedge contracts to lock-in prices on
transactions denominated in foreign currencies where deemed necessary.
We limit credit risk by extending unsecured credit to entities based on
internal ratings. In addition, we use Moody's Investor Service, Standard and
Poor's and qualitative and quantitative data to independently assess the
financial health of counterparties on an ongoing basis. This data, in
conjunction with the ratings information, is used to determine appropriate risk
parameters. We also require cash deposits, letters of credit and
parental/affiliate guarantees as security from certain below investment grade
counterparties in our normal course of business.
We trade electricity contracts with numerous counterparties. Since our
open energy trading contracts are valued based on changes in market prices of
the related commodities, our exposures change daily. We believe that our credit
and market exposures with any one counterparty is not material to financial
condition at December 31, 2001. At December 31, 2001 less than 5% of the
counterparties were below investment grade as expressed in terms of Net Mark to
Market Assets. Net Mark to Market Assets represents the aggregate difference
(either positive or negative) between the forward market price for the remaining
term of the contract and the contractual price. The following table approximates
counterparty credit quality that is generally consistent for all registrant
subsidiaries.
Futures,
Forward and
Swap
Counterparty Contracts Options Total
Credit Quality:
December 31, 2001
(in millions)
AAA/Exchanges $ 147 $- $ 147
AA 140 4 144
A 304 7 311
BBB 932 34 966
Below Investment
Grade 23
------- --- --
56 79
--
Total $1,579 $68 $1,647
====== === ======
We enter into transactions for electricity as part of wholesale
trading operations. Electric transactions are executed over the counter with
counterparties or through brokers. Brokers and counterparties require cash or
cash related instruments to be deposited on these transactions as margin against
open positions. We can be subject to further margin requirements should related
commodity prices change.
We recognize the net change in the fair value of all open trading
contracts, a practice commonly called mark-to-market accounting, in accordance
with generally accepted accounting principles and include the net change in
mark-to-market amounts on a net discounted basis in revenues. The fair values of
open short-term trading contracts are based on exchange prices and broker
quotes. The fair value of open long-term trading contracts are based mainly on
internally developed valuation models. The valuation models produce an estimated
fair value for open long-term trading contracts. This fair value is present
valued and reduced by appropriate reserves for counterparty credit risks and
liquidity risk. The models are derived from internally assessed market prices.
Forward price curves are developed for inclusion in the model based on broker
quotes and other available market data. The curves are within the range between
the bid and ask prices. The end of the month liquidity reserve is based on the
difference in price between the price curve and the bid price of the bid ask
prices if we have a long position and the ask side if we have a short position.
This provides for a conservative valuation net of the reserves.
The use of these models to fair value open trading contracts has
inherent risks relating to the underlying assumptions employed by such models.
Independent controls are in place to evaluate the reasonableness of the price
curve models. Significant adverse or favorable effects on future results of
operations and cash flows could occur if market risks, at the time of
settlement, do not correlate with the internally developed price models.
The effect on the statements of income of marking to market open
electricity trading contracts in the Company's regulated jurisdictions is
deferred as regulatory assets or liabilities since these transactions are
included in cost of service on a settlement basis for ratemaking purposes.
Unrealized mark-to-market gains and losses from trading are reported as assets
or liabilities.
The table "Energy Trading Contracts" disaggregates realized and
unrealized changes in fair value; identifies changes in fair value as a result
of changes in valuation methodologies; and reconciles the net fair value of
energy trading contracts at the beginning of the year to the end of the year.
Contracts realized/settled during the period include both sales and purchase
contracts. The table "Energy Trading Contract Maturities" shows exposures to
changes in fair values and realization periods over time for each method used to
determine fair value.
Energy Trading Contracts
(in thousand)
APCo CPL CSPCo
Net Fair Value of Energy Trading
Contracts at December 31, 2000 $ 7,447 $(8,191) $ 3,769
Loss/(Gain) from Contracts
Realized/settled during period (a) (12,478) 4,221 (11,522)
Fair Value of new open Contracts
when entered into during period (b) 13,441 9,635 8,245
Adjustments for Contracts Entered
into and settled during period 40,755 2,602 24,998
Net option premium payments 1,072 - 658
Change in fair value due to Valuation
Methodology changes (c) (220) (158) (135)
Changes in market value of Contracts (d) 25,684 (4,252) 22,436
-------- ------- --------
Net Fair Value of Energy Trading
Contracts at December 31, 2001 (e) $ 75,701 $ 3,857 $ 48,449
======== ======= ========
Energy Trading Contracts
(in thousands)
I&M KPCo OPCo
Net Fair Value of Energy Trading
Contracts at December 31, 2000 $ (6,845) $ 1,678 $ 5,613
Loss/(Gain) from Contracts
Realized/settled during period (a) (10,982) (3,298) (10,861)
Fair Value of new open Contracts
when entered into During period (b) 8,921 3,315 11,213
Adjustments for Contracts Entered
into and settled During period 27,049 10,051 34,001
Net option premium payments 712 264 894
Change in fair value due to Valuation
Methodology changes (c) (146) (54) (183)
Changes in market value of Contracts (d) 42,636 773 24,769
------- ------- --------
Net Fair Value of Energy Trading
Contracts at December 31, 2001 (e) $ 61,345 $12,729 $ 65,446
======== ======= ========
Energy Trading Contracts
(in thousands)
PSO SWEPCo WTU
Net Fair Value of Energy Trading
Contracts at December 31, 2000 $(6,508) $(7,795) $(2,590)
Loss/(Gain) from Contracts
Realized/settled during period (a) 2,483 2,938 5,881
Fair Value of new open Contracts
when entered into During period (b) 7,338 8,422 2,861
Adjustments for Contracts Entered
into and settled during period 1,981 2,274 773
Net option premium payments - - -
Change in fair value due to Valuation
Methodology changes (c) (120) (138) (46)
Changes in market value of Contracts (d) (2,740) (2,801) (5,964)
------- ------- -------
Net Fair Value of Energy Trading
Contracts at December 31, 2001 (e) $ 2,434 $ 2,900 $ 915
======= ======= =======
(a) Loss/(Gains) from Contracts Realized/Settled During the Period"
include realized gains from energy trading contracts that settled
during 2001 that were entered into prior to 2001, as well as during
2001. "Adjustment for Contracts Entered into and Settled During the
Period" discloses the realized gains from settled energy trading
contracts that were both entered into and closed within 2001 that are
included in the total gains, but not included in the ending balance of
open contracts.
(b) The "Fair Value of New Open Contracts When Entered Into during period"
represents the fair value of long-term contracts entered into with
customers during 2001. The fair value is calculated as of the
execution of the contract. Most of the fair value comes from longer
term fixed price contracts with customers that seek to limit their
risk against fluctuating energy prices. The contract prices are valued
against market curves representative of the delivery location.
(c) The Company changed its methodology for calculating and reporting load
based transactions. The previous methodology estimated a baseload
volume based on historical takes and sold a call option for potential
load increases from the baseload. The current methodology uses a
modified version of a straddle load follow model to estimate the
baseload volume and call option volume. This methodogy change more
accurately estimates the load volume forecast.
(d) "Changes in market Value of Contracts" represents the fair value
change in the trading portfolio due to market fluctuations during the
current period. Market fluctuations are attributable to various
factors such as supply/demand, weather, storage, etc.
(e) The net change in the fair value of energy trading contracts for 2001
represents the balance sheet change. The net mark-to-market gain on
energy trading contracts represents the impact on earnings. The
difference is related primarily to regulatory deferrals of certain
mark-to-market gains that were recorded as regulatory liabilities and
not reflected in the income statement for those companies that operate
in regulated jurisdictions, and deferrals of option premiums included
in the above analysis, which do not have a mark-to-market income
statement impact.
Energy Trading Contract Maturities
Fair Value of Contracts at December 31,2001
Maturities
(in thousands)
Less than In Excess Total Fair
Source of Fair Value 1 year 1-3 years 4-5 years Of 5 years Value
- -------------------- ------ --------- --------- ---------- -----
APCo
Other External Sources 13,366 9,588 - - 22,954
Models/Other Valuation 3,215 34,318 8,413 6,801 52,747
------ ------ ----- ----- ------
Total 16,581 43,906 8,413 6,801 75,701
====== ====== ===== ===== ======
CPL
Other External Sources (5,245) 1,681 - - (3,564)
Models/Other Valuation (1,262) 6,016 1,475 1,192 7,421
------- ----- ----- ----- ------
Total (6,507) 7,697 1,475 1,192 3,857
======= ===== ===== ===== ======
CSP
Other External Sources 9,867 5,872 - - 15,739
Models/Other Valuation 2,373 21,018 5,153 4,166 32,710
------ ------ ----- ----- ------
Total 12,240 26,890 5,153 4,166 48,449
====== ====== ===== ===== ======
KEPCo
Other External Sources (1,475) 2,361 - - 886
Models/Other Valuation (355) 8,451 2,072 1,675 11,843
------- ------ ----- ----- ------
Total (1,830) 10,812 2,072 1,675 12,729
======= ====== ===== ===== ======
I&M
Other External Sources 17,237 6,481 - - 23,718
Models/Other Valuation 4,146 23,197 5,687 4,597 37,627
------ ------ ----- ----- ------
Total 21,383 29,678 5,687 4,597 61,345
====== ====== ===== ===== ======
OPCo
Other External Sources 13,058 7,987 - - 21,045
Models/Other Valuation 3,141 28,587 7,008 5,665 44,401
------ ------ ----- ----- ------
Total 16,199 36,574 7,008 5,665 65,446
====== ====== ===== ===== ======
PSO
Other External Sources (4,400) 1,280 - - (3,120)
Models/Other Valuation (1,058) 4,581 1,123 908 5,554
------- ----- ----- --- ------
Total (5,458) 5,861 1,123 908 2,434
======= ===== ===== === ======
SWEPCo
Other External Sources (4,965) 1,469 - - (3,496)
Models/Other Valuation (1,194) 5,259 1,289 1,042 6,396
------- ----- ----- ----- ------
Total (6,159) 6,728 1,289 1,042 2,900
======= ===== ===== ===== ======
WTU
Other External Sources (1,743) 499 - - (1,244)
Models/Other Valuation (419) 1,786 438 354 2,159
------- ----- --- --- ------
Total (2,162) 2,285 438 354 915
======= ===== === === ======
"Other External Sources" represents positions in power and coal at points where
over-the-counter broker quotes are available. Prices for these various
commodities can generally be obtained on the over-the-counter market through
2003. Some prices from external sources are quoted as strips (one bid/ask for
Nov-Mar, Apr-Oct, etc). Such transactions have also been included in this
category. "Models/Other Valuation" contain the following: the value of
adjustments for liquidity and counterparty credit exposure, the value of
contracts not quoted by an exchange or an over-the-counter broker, the value of
transactions for which an internally developed price curve was developed as a
result of the long dated nature of certain transactions, and the value of
certain structured transactions.
We have investments in debt and equity securities which are held in
nuclear trust funds. The trust investments and their fair value are discussed in
Note 12, "Risk Management, Financial Instruments and Derivatives." Financial
instruments in these trust funds have not been included in the market risk
calculation for interest rates as these instruments are marked-to-market and
changes in market value of these instruments are reflected in a corresponding
decommissioning liability. Any differences between the trust fund assets and the
ultimate liability are expected to be recovered through regulated rates from our
regulated customers.
Inflation affects our cost of replacing utility plant and the cost of
operating and maintaining plant. The rate-making process limits recovery to the
historical cost of assets, resulting in economic losses when the effects of
inflation are not recovered from customers on a timely basis. However, economic
gains that result from the repayment of long-term debt with inflated dollars
partly offset such losses.
Industry Restructuring
In 2000 California's deregulated electricity market suffered problems
including high energy prices mainly due to short energy supplies and financial
difficulties for retail distribution companies. This energy crisis has
highlighted the importance of risk management and has contributed to certain
state regulatory and legislative actions which have delayed the start of
customer choice and the transition to competitive, market based pricing for
retail electricity supply in some of the states in which AEP System companies
operate. Seven of the eleven state retail jurisdictions in which the AEP
electric utility companies operate have enacted restructuring legislation. In
general, the legislation provides for a transition from cost-based regulation of
bundled electric service to customer choice and market pricing for the supply of
electricity. As legislative and regulatory proceedings evolved, six AEP electric
operating companies (APCo, CPL, CSPCo, OPCo, SWEPCo and WTU) doing business in
five of the seven states that have passed restructuring legislation have
discontinued the application of SFAS 71 regulatory accounting for the generation
business. The seven states in various stages of restructuring to transition
power generation and supply to market based pricing are Arkansas, Michigan,
Ohio, Oklahoma, Texas, Virginia, and West Virginia. Regulatory accounting has
not been discontinued for subsidiaries doing business in Michigan and Oklahoma
pending the effective implementation of the legislation. Restructuring
legislation, the status of the transition plans and the status of the electric
utility companies' accounting to comply with the changes in the seven state
regulatory jurisdictions affected by restructuring legislation is presented in
the Note 7 of the Notes to Financial Statements.
RTO Formation
FERC Order No. 2000 and many of the settlement agreements with the FERC
and state regulatory commissions to approve the AEP-CSW Merger have provisions
for the transfer of functional control of our transmission system to an RTO.
Certain AEP registrant subsidiaries are participating in the formation of the
Alliance RTO. Other subsidiaries are a member of ERCOT or SPP.
In 2001 the Alliance companies and MISO entered into a settlement
addressing transmission pricing and other "seam" issues between the two RTOs.
The FERC subsequently expressed its opinion that four large RTO regions serving
the continental US would best support competition and reliability of electric
service. Certain state regulatory commissions have taken exception to the FERC's
RTO actions. Louisiana's commission ordered utilities it regulates, including
SWEPCo, to show the advantage of large RTOs to their customers.
On December 19, 2001 the FERC approved the proposal of the Midwest ISO
for a regional transmission organization and told the Alliance companies, which
had submitted a separate RTO proposal, to explore joining the Midwest ISO
organization. The FERC's order is intended to facilitate the establishment of a
single RTO in the Midwest and to support the establishment of viable, for-profit
transmission companies under an RTO umbrella and concluded that the RTO proposed
by Alliance companies lacks sufficient scope to exist as a stand-alone RTO and
thus directed the Alliance companies to explore how their business plan can be
accommodated within the Midwest ISO.
Management is unable to predict the outcome of these transmission
regulatory actions and proceedings or their impact on the timing and operation
of RTOs, AEP System companies transmission operations or future results of
operations and cash flows.
Litigation
AEP System companies are involved in various litigation. The details of
significant litigation contingencies are disclosed in Note 8 and summarized
below.
COLI - Affecting APCo, CSPCo, I&M, KPCo and OPCo
A decision by U.S. District Court for the Southern District of Ohio in
February 2001 that denied AEP's deduction of interest claimed on AEP's
consolidated federal income tax returns related to its COLI program resulted in
a reduction in net income for 2000. AEP had filed suit to resolve the IRS'
assertion that interest deductions for AEP's COLI program should not be allowed.
In 1998 and 1999 AEP and the impacted subsidiaries paid the disputed taxes and
interest attributable to COLI interest deductions for taxable years 1991-98 for
APCo, CSPCo, I&M and OPCo and 1992-98 for KPCo to avoid the potential assessment
by the IRS of additional interest on the contested tax. The payments were
included in other property and investments on the balance sheets pending the
resolution of this matter. AEP has appealed the Court's decision.
The earnings reductions for affected registrant subsidiaries are as follows:
(in millions)
APCo $ 82
CSPCo 41
I&M 66
KPCo 8
OPCo 118
FERC Wholesale Fuel Complaints - Affecting WTU
In November 2001 certain WTU wholesale customers filed a complaint with
FERC alleging that WTU has overcharged them since 1997 through the fuel
adjustment clause. The customers allege inappropriate costs related to purchased
power were included in the fuel adjustment clause. Management is working to
compute if any overcharges occurred and is unable to predict their impact on
results of operations, cash flow and financial condition.
Municipal Franchise Fee Litigation - Affecting CPL
In 2001 CPL paid $11 million to settle class action litigation regarding
municipal franchise fees in Texas. The City of San Juan, Texas had filed a class
action lawsuit in 1996 seeking $300 million in damages.
Texas Base Rate Litigation - Affecting CPL
In 2001 the Texas Supreme Court denied CPL's request for the court to
review a 1997 PUCT base rate order. Subsequently the Court also denied CPL's
rehearing request.
The primary issues CPL requested the Court to review were:
o the classification of $800 million of invested capital in STP
as ECOM and assigning it a lower return on equity than other
generation property;
o and an $18 million disallowance of affiliated service billings.
Lignite Mining Agreement Litigation - Affecting SWEPCo
In 2001 SWEPCo settled litigation concerning lignite mining in
Louisiana. Since 1997 SWEPCo has been involved in litigation concerning the
mining of lignite from jointly owned lignite reserves. SWEPCo and CLECO, an
unaffiliated utility, are each a 50% owner of the Dolet Hills Power Station Unit
1 and jointly own lignite reserves in the Dolet Hills area of northwestern
Louisiana. Under terms of a settlement, SWEPCo purchased an unaffiliated mine
operator's interest in the mining operations and related debt and other
obligations for $86 million.
Merger Litigation - Affecting all AEP Subsidiary Registrants
In January 2002, a federal court ruled that the SEC failed to prove that
the June 15, 2000 merger of AEP with CSW meets the requirements of the PUHCA and
sent the case back to the SEC for further review. Management believes that the
merger meets the requirements of the PUHCA and expects the matter to be resolved
favorably.
Other - Affecting all AEP Subsidiary Registrants
AEP registrant subsidiaries are involved in a number of other legal
proceedings and claims. While management is unable to predict the outcome of
such litigation, it is not expected that the ultimate resolution of these
matters will have a material adverse effect on the results of operations, cash
flows or financial condition.
Environmental Concerns and Issues
The U.S. continues to debate an array of environmental issues affecting
the electric utility industry including new emission limitations recommended by
the Bush Administration in February 2002. Most of the policies are aimed at
reducing air emissions citing alleged impacts of such emissions on public
health, sensitive ecosystems or the global climate.
AEP's subsidiaries policy on the environment continues to be the
development and application of long-term economically feasible measures to
improve air and water quality, limit emissions and protect the health of
employees, customers, neighbors and others impacted by their operations. In
support of this policy, we continue to invest in research through groups like
the Electric Power Research Institute and directly through demonstration
projects for new technology for the capture and storage of carbon dioxide,
mercury, NOx and other emissions. The AEP System companies intend to continue in
a leadership role to protect and preserve the environment while providing vital
energy commodities and services to customers at fair prices.
AEP's registrant subsidiaries have a proven record of efficiently
producing and delivering electricity and gas while minimizing the impact on the
environment. AEP's registrant subsidiaries have spent billions of dollars to
equip their facilities with the latest cost effective clean air and water
technologies and to research new technologies. We are proud of our award winning
efforts to reclaim our mining properties.
The introduction of multi-pollutant control legislation is being
discussed by members of Congress and the Bush Administration. The legislation
being considered may regulate carbon dioxide, NOx, sulfur dioxide, mercury and
other emissions from electric generating plants. Management will continue to
support solutions which are based on sound science, economics and demonstrated
control technologies. Management is unable to predict the timing or magnitude of
additional pollution control laws or regulations. If additional control
technology is required on facilities owned by the electric utility companies and
their costs were not recoverable from ratepayers or through market based prices
or volumes of product sold, they could adversely affect future results of
operations and cash flows. The following discussions explains existing control
efforts, litigation and other pending matters related to environmental issues
for AEP System companies.
Federal EPA Complaint and Notice of Violation - Affecting APCo, CSPCo,
I&M and OPCo
Since 1999 APCo, CSPCo, I&M and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. Federal EPA, a
number of states and certain special interest grups alleged that APCo, CSPCo,
I&M and OPCo modified certain generating units over a 20 year period in
violation of the Clean Air Act.
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. We
believe our maintenance, repair and replacement activities were in conformity
with the Clean Air Act and intend to vigorously pursue our defense.
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). In March 2001 the District Court ruled that claims for civil penalties
based on activities that occurred more than five years before the filing date of
the complaints cannot be imposed. There is no time limit on claims for
injunctive relief.
Management is unable to estimate a loss or predict the timing of the
resolution of these matters due to the number of alleged violations and the
significant number of issues yet to be determined by the Court. If we 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.
An unaffiliated utility which operates certain plants jointly owned by
CSPCo reached a tentative agreement to settle litigation regarding generating
plant emissions under the Clean Air Act. Negotiations are continuing and a
settlement could impact the operation of Zimmer Plant and W.C. Beckjord
Generating Station Unit 6 (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 results of
operations and cash flows.
NOx Reduction - Affecting APCo, CPL, I&M, OPCo and SWEPCo
Federal EPA issued a NOx rule (the NOx Rule) and granted petitions filed
by certain northeastern states (the Section 126 Rule) requiring substantial
reductions in NOx emissions in a number of eastern states, including certain
states in which the AEP System's generating plants are located.
Federal EPA ruled that eleven states, including certain states in which
AEP's generating units are located, failed to submit approvable plans to comply
with the NOx Rule. This ruling means that those states could face stringent
sanctions 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. A request for the D.C. Circuit Court to review this
ruling is pending. The compliance date for the NOx Rule is May 31, 2004.
The D.C. Circuit Court instructed Federal EPA to justify methods used to
allocate allowances and project growth for both the NOx Rule and the Section 126
Rule. In response to AEP and other utilities request for the D.C. Circuit Court
to suspend the May 2003 compliance date of the Section 126 Rule, the D.C.
Circuit Court issued an order tolling the compliance schedule until Federal EPA
responds to the Court's remand.
In April 2000 the Texas Natural Resource Conservation Commission adopted
rules requiring significant reductions in NOx emissions from utility sources,
including CPL and SWEPCo. The compliance date is May 2003 for CPL and May 2005
for SWEPCo.
In 2001 selective catalytic reduction (SCR) technology to reduce NOx
emissions on OPCo's Gavin Plant commenced operation. Construction of SCR
technology at certain other generating units continues with completion scheduled
in 2002 through 2006.
Our estimates indicate that compliance with the NOx Rule, the Texas
Natural Resource Conservation Commission rule and the Section 126 Rule could
result in required capital expenditures for certain of AEP's registrant
subsidiaries.
Estimated Amounts
Compliance Costs Spent
---------------- -------
(in millions)
Company
APCo $365 $130
CPL 57 4
I&M 202 -
OPCo 606 277
SWEPCo 28 21
Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the estimates depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital and operating costs of additional pollution
control equipment are recovered from customers, they will have an adverse effect
on future results of operations, cash flows and possibly financial condition.
Superfund - Affecting APCo, CPL, CSPCo, I&M, OPCo and SWEPCo
By-products from the generation of electricity include materials such as
ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion
by-products, which constitute the overwhelming percentage of these materials,
are typically disposed of or treated in captive disposal facilities or are
beneficially utilized. In addition, our generating plants and transmission and
distribution facilities have used asbestos, PCBs and other hazardous and
non-hazardous materials. We are currently incurring costs to safely dispose of
these substances. Additional costs could be incurred to comply with new laws and
regulations if enacted.
Superfund addresses clean-up of hazardous substances at disposal sites
and authorized Federal EPA to administer the clean-up programs. As of year-end
2001, certain AEP registrant subsidiaries have been named by the Federal EPA as
a PRP for five sites. APCo, CSPCo, and OPCo each have one PRP site and I&M has
two PRP sites. There are four additional sites for which APCo, CSPCo, I&M, OPCo
and SWEPCo have received information requests which could lead to PRP
designation. CPL, OPCo and SWEPCo have also been named a PRP at two sites under
state law. Our liability has been resolved for a number of sites with no
significant effect on results of operations. In those instances where certain
AEP registrant subsidiaries have been named a PRP or defendant, their disposal
or recycling activities were in accordance with the then-applicable laws and
regulations. Unfortunately, Superfund does not recognize compliance as a
defense, but imposes strict liability on parties who fall within its broad
statutory categories.
While the potential liability for each Superfund site must be evaluated
separately, several general statements can be made regarding certain AEP
registrant subsidiaries' potential future liability. Disposal of materials at a
particular site is often unsubstantiated and the quantity of materials deposited
at a site was small and often nonhazardous. Although liability is joint and
several, typically many parties are named as PRPs for each site and several of
the parties are financially sound enterprises. Therefore, our present estimates
do not anticipate material cleanup costs for identified sites for which we have
been declared PRPs. If significant cleanup costs are attributed to certain AEP
registrant subsidiaries in the future under Superfund, results of operations,
cash flows and possibly financial condition would be adversely affected unless
the costs can be recovered from customers.
Global Climate Change - Affecting all AEP Registrant Subsidiaries
At the Third Conference of the Parties to the United Nations Framework
Convention on Climate Change held in Kyoto, Japan in December 1997 more than 160
countries, including the U.S., negotiated a treaty requiring legally-binding
reductions in emissions of greenhouse gases, chiefly carbon dioxide, which many
scientists believe are contributing to global climate change. Although the U.S.
signed the Kyoto Protocol on November 12, 1998, the treaty was not submitted to
the Senate for its advice and consent by President Clinton. In March 2001
President Bush announced his opposition to the treaty and its U.S. ratification.
At the Seventh Conference of the Parties in November 2001, the parties finalized
the rules, procedures and guidelines required to facilitate ratification of the
protocol. The protocol is expected to become effective by 2003. U.S.
representatives attended the Seventh Conference but they did not take any
positions on issues being negotiated or attempt to block the approval of any
issue. AEP does not support the Kyoto Protocol but intends to work with the Bush
Administration and U.S. Congress to develop responsible public policy on this
issue. Management expects due to President Bush's opposition to legislation
mandating greenhouse gas emissions controls, any policies developed and
implemented in the near future are likely to encourage voluntary measures to
reduce, avoid or sequester such emissions.
Costs for Spent Nuclear Fuel and Decommissioning - Affecting CPL and I&M
I&M, as the owner of the Cook Plant, and CPL, as a partial owner of STP,
have a significant future financial commitment to safely dispose of SNF and
decommission and decontaminate the plants. The Nuclear Waste Policy Act of 1982
established federal responsibility for the permanent off-site disposal of SNF
and high-level radioactive waste. By law CPL and I&M participate in the DOE's
SNF disposal program which is described in Note 8 of the Notes to Financial
Statements. Since 1983 I&M has collected $288 million from customers for the
disposal of nuclear fuel consumed at the Cook Plant. $116 million of these funds
have been deposited in external trust funds to provide for the future disposal
of SNF and $172 million has been remitted to the DOE. CPL has collected and
remitted to the DOE, $49 million for the future disposal of SNF since STP began
operation in the late 1980s. Under the provisions of the Nuclear Waste Policy
Act, collections from customers are to provide the DOE with money to build a
permanent repository for spent fuel. However, in 1996, the DOE notified the
companies that it would be unable to begin accepting SNF by the January 1998
deadline required by law. To date DOE has failed to comply with the requirements
of the Nuclear Waste Policy Act.
As a result of DOE's failure to make sufficient progress toward a
permanent repository or otherwise assume responsibility for SNF, AEP on behalf
of I&M and STPNOC on behalf of CPL and the other STP owners, along with a number
of unaffiliated utilities and states, filed suit in the D.C. Circuit Court
requesting, among other things, that the D.C. Circuit Court order DOE to meet
its obligations under the law. The D.C. Circuit Court ordered the parties to
proceed with contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear waste will not
be ready until at least 2010. In 1998, AEP and I&M filed a complaint in the U.S.
Court of Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits were filed by
other utilities. In August 2000, in an appeal of related cases involving other
unaffiliated utilities, the U.S. Court of Appeals for the Federal Circuit held
that the delays clause of the standard contract between utilities and the DOE
did not apply to DOE's complete failure to perform its contract obligations, and
that the utilities' suits against DOE may continue in court. AEP's and I&M's
suit has been stayed pending further action by the U.S. Court of Federal Claims.
As long as the delay in the availability of a government approved storage
repository for SNF continues, the cost of both temporary and permanent storage
and the cost of decommissioning will continue to increase.
In January 2001, I&M and STPNOC, on behalf of STP's joint owners, joined
a lawsuit against DOE, filed in November 2000 by unaffiliated utilities, related
to DOE's nuclear waste fund cost recovery settlement with PECO Energy
Corporation. The settlement allows PECO to skip two payments to the DOE for
disposal of SNF due to the lack of progress towards development of a permanent
repository for SNF. The companies believe the settlement is unlawful as the
settlement would force other utilities to make up any shortfall in DOE's SNF
disposal funds.
The cost to decommission nuclear plants is affected by both NRC
regulations and the delayed SNF disposal program. Studies completed in 2000
estimate the cost to decommission the Cook Plant ranges from $783 million to
$1,481 million in 2000 non-discounted dollars. External trust funds have been
established with amounts collected from customers to decommission the plant. At
December 31, 2001, the total decom-missioning trust fund balance for Cook Plant
was $598 million which includes earnings on the trust investments. Studies
completed in 1999 for STP estimate CPL's share of decommissioning cost to be
$289 million in 1999 non-discounted dollars. Amounts collected from customers to
decommission STP have been placed in an external trust. At December 31, 2001,
the total decommission-ing trust fund for CPL's share of STP was $99 million
which includes earnings on the trust investments. Estimates from the
decommissioning studies could continue to escalate due to the uncertainty in the
SNF disposal program and the length of time that SNF may need to be stored at
the plant site. We will work with regulators and customers to recover the
remaining estimated costs of decommissioning Cook Plant and STP. However, CPL's
and I&M's future results of operations, cash flows and possibly their financial
conditions would be adversely affected if the cost of SNF disposal and
decommissioning continues to increase and cannot be recovered.
AEP's registrant subsidiaries are exposed to other environmental
concerns which are not considered to be material or potentially material at this
time. Should they become significant or should any new concerns be uncovered
that are material they could have a material adverse effect on results of
operations and possibly financial condition. We perform environmental reviews
and audits on a regular basis for the purpose of identifying, evaluating and
addressing environmental concerns and issues.
APCo operates in Virginia and West Virginia, and has been seeking
regulatory approval to build a new high voltage transmission line for over a
decade. Through December 31, 2001 we have invested approximately $40 million in
this effort. If the required regulatory approvals are not obtained and the line
is not constructed, the $40 million investment would be written off adversely
affecting APCo's future results of operations and cash flows.
OTHER MATTERS
Enron Bankruptcy - Affecting APCo, CSPCo, I&M, KPCo and OPCo
At the date of Enron's bankruptcy certain electric operating companies
had open trading contracts and trading accounts receivables and payables with
Enron.
The amounts for certain subsidiary registrants were:
Amounts
Amounts Net of
Registrant Provided Tax
-------- -- ---
(in millions)
APCo $5.2 3.4
CSPCo 3.2 2.1
I&M 3.4 2.2
KPCo 1.3 0.8
OPCo 4.3 2.8
The amounts provided were based on an analysis of contracts where AEP
and Enron are counterparties, the offsetting of receivables and payables, and
the application of deposits from Enron. If there are any adverse unforeseen
developments in the bankruptcy proceedings, our future results of operations,
cash flows and possibly financial condition could be adversely impacted.
New Accounting Standards - Affecting AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
PSO, SWEPCo and WTU
The FASB recently issued SFAS 141, "Business Combinations" and SFAS 142,
"Goodwill And Other Intangible Assets." SFAS 141 requires that the purchase
method of accounting be used to account for all business combinations entered
into after June 30, 2001. SFAS 142 requires that goodwill amortization cease and
that goodwill and other intangible assets with indefinite lives be tested for
impairment upon SFAS 142 implementation and annually thereafter. The registrant
subsidiaries did not have significant goodwill at December 31, 2001.
SFAS 143, "Accounting for Asset Retirement Obligations," will become
effective for us beginning January 1, 2003. SFAS 143 established accounting and
reporting for legal obligations associated with the retirement of tangible
long-lived assets and the related asset retirement costs. We are currently in
the process of evaluating the provisions of the standard and determining its
impact on future results of operations and financial condition. To the extent
AEP's registrant subsidiaries are regulated entities, we anticipate that the
cumulative effect of this accounting change on future results of operations will
be significantly offset by a regulatory asset representing the right to recover
legal asset retirement obligations (ARO) relative to regulated long lived assets
included in rate base. The impact on future results of operations from the
implementation of this new standard on non-regulated long lived assets has not
yet been determined. We anticipate that the considerable effort to identify all
long lived assets with legal ARO and to determine the required discounted legal
ARO will take the remainder of 2002.
In August 2001 the FASB issued SFAS 144, "Accounting for the Impairment
or Disposal of Long-lived Assets" which sets forth the accounting to recognize
and measure an impairment loss. This standard replaces the previous standard,
SFAS 121, "Accounting for the Long-lived Assets and for Long-lived Assets to be
Disposed Of." SFAS 144 will apply to us beginning January 1, 2002. We do not
expect that the imple-mentation of SFAS 144 will materially affect results of
operations or financial condition.
The FASB recently revised its prior guidance related to SFAS 133,
"Accounting for Deriviative Instruments and Hedging Activities" with regard to
certain power option and forward contracts. The revised guidance states that
power contracts, including both forward and option contracts, that include
certain qualitative characteristics are considered capacity contracts, and
qualify for the normal purchases and normal sales exception from being marked to
market even if they are subject to being booked out, or scheduled to be booked
out. As normal purchases and sales these open energy contracts are not marked to
market. Rather they are accounted for on a settlement basis. Most of AEP System
companies' power contracts that are not marked to market as trading transactions
do not qualify as derivatives and thus are not subject to the revised guidance.
The few contracts that are derivatives qualified for the exception under the
previous guidance and will continue to qualify under the new guidance.
Item 7. Financial Statements and Exhibits.
(c) Exhibits
23.1 Consent of Deloitte & Touche LLP for APCo
23.2 Consent of Deloitte & Touche LLP for CPL
23.3 Consent of Deloitte & Touche LLP for CSP
23.4 Consent of Deloitte & Touche LLP for I&M
23.5 Consent of Deloitte & Touche LLP for KPCo
23.6 Consent of Deloitte & Touche LLP for OPCo
23.7 Consent of Deloitte & Touche LLP for PSO
23.8 Consent of Deloitte & Touche LLP for SWEPCo
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 signature for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
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/Joseph M. Buonaiuto
----------------------------
Joseph M. Buonaiuto
Controller and Chief Accounting Officer
Date: November 18, 2002
Exhibit 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
333-100451 of Appalachian Power Company on Form S-3 of our report dated February
22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of
Appalachian Power Company.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002
Exhibit 23.2
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-49577 and 33-52759 of Central Power and Light Company on Form S-3 of our
report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in
this Form 8-K of Central Power and Light Company.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002
Exhibit 23.3
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-50447 and 333-54025 of Columbus Southern Power Company on Form S-3 of our
report dated February 22, 2002 (November 18, 2002 as to Note 21), appearing in
this Form 8-K of Columbus Southern Power Company.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002
Exhibit 23.4
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
333-58656 of Indiana Michigan Power Company on Form S-3 of our report dated
February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K
of Indiana Michigan Power Company.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002
Exhibit 23.5
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement No.
333-87216 of Kentucky Power Company on Form S-3 of our report dated February 22,
2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K of Kentucky
Power Company.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002
Exhibit 23.6
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-50373 and 33-53133 of Ohio Power Company on Form S-3 of our report dated
February 22, 2002 (November 18, 2002 as to Note 21), appearing in this Form 8-K
of Ohio Power Company.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002
Exhibit 23.7
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
333-33284, 333-00973 and 333-100623 of Public Service Company of Oklahoma on
Form S-3 of our report dated February 22, 2002 (November 18, 2002 as to Note
21), appearing in this Form 8-K of Public Service Company of Oklahoma.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002
Exhibit 23.8
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
333-87834, 333-96213 and 333-100632 of Southwestern Electric Power Company on
Form S-3 of our report dated February 22,2002 (November 18, 2002 as to Note 21),
appearing in this Form 8-K of Southwestern Electric Power Company.
Deloitte & Touche LLP
Columbus, Ohio
November 18, 2002