SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended MARCH 31,SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended JUNE 30, 2001
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
Commission Registrant, State of Incorporation I.R. S. Employer
File Number Address, and Telephone Number Identification No.
- ----------- ----------------------------- ------------------
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
40 Franklin Road, Roanoke, Virginia 24011
Telephone (540) 985-2300
0-346 CENTRAL POWER AND LIGHT COMPANY (A Texas Corporation) 74-0550600
539 North Carancahua Street,
Corpus Christi, Texas 78401-2802
Telephone (361)881-5300
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
One Summit Square
P.O. Box 60, Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1701 Central Avenue, Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4154203
1 Riverside Plaza, Columbus,
Ohio 43215 Telephone (614) 223-1000
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
One Summit Square
P.O. Box 60, Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1701 Central Avenue, Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
301 Cleveland Avenue S.W., Canton, Ohio 44701
Telephone (330) 456-8173
0-343 PUBLIC SERVICE COMPANY OF OKLAHOMA 73-0410895
(An Oklahoma Corporation)
212 East 6th Street, Tulsa, Oklahoma 74119-1212
Telephone (918) 599-2000
1-3146 SOUTHWESTERN ELECTRIC POWER COMPANY 72-0323455
(A Delaware Corporation)
428 Travis Street, Shreveport, Louisiana 71156-0001
Telephone (318) 673-3000
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790
301 Cypress Street, Abilene, Texas
79601-5820 Telephone (915) 674-7000
AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company,
Public Service Company of Oklahoma and West Texas Utilities Company meet the
conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in
General Instruction H(2) to Form 10-Q.
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.
Yes X
--------
No --------
The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at April 30, 2001 was 322,151,975.
AMERICAN ELECTRIC POWER COMPANY INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended March72-0323455
(A Delaware Corporation)
428 Travis Street, Shreveport, Louisiana 71156-0001
Telephone (318) 673-3000
0-340 WEST TEXAS UTILITIES COMPANY (A Texas Corporation) 75-0646790
301 Cypress Street, Abilene, Texas 79601-5820
Telephone (915) 674-7000
AEP Generating Company, Columbus Southern Power Company, Kentucky Power Company,
Public Service Company of Oklahoma and West Texas Utilities Company meet the
conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in
General Instruction H(2) to Form 10-Q.
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Sections 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days.
Yes X No
------- ------
The number of shares outstanding of American Electric Power Company, Inc. Common
Stock, par value $6.50, at July 31, 2001 was 322,201,830.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June 30, 2001
CONTENTS
Page
Glossary of Terms i - iii
Forward-Looking Information iv
Part I. FINANCIAL INFORMATION
Items 1 and 2 Financial Statements and Management's Discussion and
Analysis of Results of Operations:
American Electric Power Company, Inc. and Subsidiary Companies:
Management's Discussion and Analysis of Results of Operations A-1 - A-2
Consolidated Financial Statements A-2A-3 - A-6A-7
AEP Generating Company:
Management's Narrative Analysis of Results of Operations B-1
Financial Statements B-2 - B-5
Appalachian Power Company, Inc. and Subsidiaries:
Management's Discussion and Analysis of Results of Operations C-1 - C-2
Consolidated Financial Statements C-3 - C-7
Central Power and Light Company and Subsidiary:
Management's Discussion and Analysis of Results of Operations D-1 - D-2
Consolidated Financial Statements D-2D-3 - D-5D-6
Columbus Southern Power Company and Subsidiaries:
Management's Narrative Analysis of Results of Operations E-1 - E-2
Consolidated Financial Statements E-3 - E-6
Indiana Michigan Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations F-1 - F-2
Consolidated Financial Statements F-2F-3 - F-6F-7
Kentucky Power Company
Management's Narrative Analysis of Results of Operations G-1 - G-2
Financial Statements G-2G-3 - G-6G-7
Ohio Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations H-1 - H-2
Consolidated Financial Statements H-3 - H-7
Public Service Company of Oklahoma and Subsidiaries:
Management's Narrative Analysis of Results of Operations I-1 - I-2
Consolidated Financial Statements I-2I-3 - I-5I-6
Southwestern Electric Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations J-1 - J-2
Consolidated Financial Statements J-2J-3 - J-5J-6
West Texas Utilities Company:
Management's Narrative Analysis of Results of Results of Operations K-1 - K-2
Financial Statements K-3 - K-2
Financial Statements K-3 - K-6
Footnotes to Financial Statements L-1 - L-14
L-12
Item 2. Registrants' Combined Management Discussion and Analysis of
Financial Condition, Contingencies and Other Matters M-1 - M-8
Item 3. Quantitative and Qualitative Disclosures About Market Risk N-1 - N-2
Part II. OTHER INFORMATION
Item 1. Legal Proceedings O-1
Item 4. Submission of Matters to a Vote of Security Holders O-1 - O-3
Item 5. Other Information O-3
Item 6. Exhibits and Reports on Form 8-K O-1O-4
(a) Exhibits
Exhibit 12
(b) Reports on Form 8-K
SIGNATURE P-1
This combined Form 10-Q is separately filed by American Electric Power
Company, Inc., AEP Generating Company, Appalachian Power Company, Central Power
and Light Company, Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Ohio Power Company, Public Service Company of
Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company.
Information contained herein relating to any individual registrant is filed by
such registrant on its own behalf. Each registrant makes no representation as to
information relating to the other registrants.
iii
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this
report, they have the meanings indicated below.
Term Meaning
2004 True-up Proceeding............ A filing to be made after January 10, 2004 under the Texas Legislation to finalize the
amount of stranded costs and the recovery of such costs.
AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP.
AEP................................ American Electric Power Company, Inc.
AEP Consolidated................... AEP and its majority owned subsidiaries consolidated.
AEP Credit....................,Inc.Credit......................... 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,companies.......................... APCo, CSPCo, I&M, KPCo and OPCo.
AEPR............................... AEP Resources, Inc.
AEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and
operated by AEP's electric utility subsidiaries.
AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale system sales of the member
companies.
AEP West electric operating
companies.......................... CPL, PSO, SWEPCo and WTU.
AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is
capitalized and recovered through depreciation over the service life of domestic
regulated electric utility plant.
Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
utilities.
Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and
OPCo.
APCo............................... Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................ Arkansas Public Service Commission.
Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation.
CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI............................... Corporate owned life insurance program.
Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................ Central Power and Light Company, an AEP electric utility subsidiary.
CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP.
CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit.
DHMV............................... Dolet Hills Mining Venture.
DOE................................ United States Department of Energy.
ECOM............................... Excess Cost Over Market.
ENEC............................... Expanded Net Energy Costs.
EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT.............................. The Electric Reliability Council of Texas.
EWGs............................... Exempt Wholesale Generators.
FASB............................... Financial Accounting Standards Board.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB ............................... First Mortgage Bond.
FUCOs.............................. Foreign Utility Companies.
i
GAAP............................... Generally Accepted Accounting Principles.
HPL................................ Houston Pipe Line Company.
I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPC................................ Installment Purchase Contract.
IRS................................ Internal Revenue Service.
IURC............................... Indiana Utility Regulatory Commission.
ISO................................ Independent system operator.
Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary.
KPSC............................... Kentucky Public Service Commission.
KWH................................ Kilowatthour.
LIG................................ Louisiana Intrastate Gas.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
Midwest ISO........................ An independent operator of transmission assets in the Midwest.
MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool......................... AEP System's Money Pool.
MPSC............................... Michigan Public Service Commission.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatthour.
NEIL............................... Nuclear Electric Insurance Limited.
Nox................................ Nitrogen oxide.
Nox Rule........................... A final rules issued by Federal EPA which requires NOx reductions in 22 eastern states
including seven of the states in which AEP companies operates.
NP................................. Notes Payable.
NRC................................ Nuclear Regulatory Commission.
Ohio Act........................... The Ohio Electric Restructuring Act of 1999.
Ohio EPA........................... Ohio Environmental Protection Agency.
OPCo.............................. Ohio Power Company, an AEP electric utility subsidiary.
OVEC............................... Ohio Valley Electric Corporation, an electric utility company in which AEP and CSPCo own a
44.2% equity interest.
PCBs............................... Polychlorinated Biphenyls.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
PRP.............................. Potentially Responsible Party.
PSO................................ Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PUCO............................... The Public Utilities Commission of Ohio.
PUCT............................... The Public Utility Commission of Texas.
PUHCA.............................. Public Utility Holding Company Act of 1935, as amended.
PURPA.............................. The Public Utility Regulatory Policies Act of 1978.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Registrant Subsidiaries............ AEP subsidiaries who are SEC registrants; AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
RTO................................ Regional Transmission Organization.
SEC................................ Securities and Exchange Commission.
SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
-------------------------------------
Types of Regulation.
-------------------
SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of
------------------------------------
Application of Statement 71.
ii
SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
--------------------------------
Long-Lived Assets and for Long-Lived Assets to be Disposed of.
--------------------------------------------------------------
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
-------------------------------------
and Hedging Activities.
-----------------------
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light
Company, an AEP electric utility subsidiary .
STPNOC............................. South Texas Project Nuclear Operating Company, a non-profit Texas corporation which operates
STP on behalf of its joint owners including CPL.
Superfund......................... The Comprehensive Environmental, Response, Compensation and Liability Act.
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Appeals Court................ The Third District of Texas Court of Appeals.
Texas Restructuring Legislation.... Legislation enacted in 1999 to restructure the electric utility industry in Texas.
Travis District Court.............. State District Court of Travis County, Texas.
TVA ............................... Tennessee Valley Authority.
U.K................................ The United Kingdom.
UN................................. Unsecured Note.
VaR................................ Value at Risk, a method to quantify risk exposure.
Virginia SCC....................... Virginia State Corporation Commission.
WV................................. West Virginia.
WVPSC.............................. Public Service Commission of West Virginia.
WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary.
Yorkshire.......................... Yorkshire Electricity Group plc, a U.K. regional electricity company owned jointly by AEP
and New Century Energies.
Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
iii
iv
FORWARD-LOOKING INFORMATION
This report made by AEP and certain of its subsidiaries contains
forward-looking statements within the meaning of Section 21E of the
Securities Exchange Act of 1934. Although AEP and each of its subsidiaries
believe that their expectations are based on reasonable assumptions, any
such statements may be influenced by factors that could cause actual
outcomes and results to be materially different from those projected. Among
the factors that could cause actual results to differ materially from those
in the forward-looking statements are:
o Electric load and customer growth.
o Abnormal weather conditions.
o Available sources and costs of fuels.
o Availability of generating capacity.
o The speed and degree to which competition is introduced to our power
generation business.
o The structure and timing of a competitive market and its impact on
energy prices or fixed rates.
o The ability to recover stranded costs in connection with
possible/proposed deregulation of generation.
o New legislation and government regulations.
o The ability of AEP to successfully control its costs.
o The success of new business ventures.
o International developments affecting AEP's foreign investments.
o The economic climate and growth in AEP's service territory.
o Inflationary trends.
o Electricity and gas market prices.
o Interest rates
o Other risks and unforeseen events.
iv
A-6
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRSTSECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
Net income increased by $126$241 million or 90%75 cents per share for the
quarter and by $367 million or $1.13 per share year-to-date predominately due predominately to a
strong performance from the wholesale business inclusive ofbusiness. Benefiting from an increased
contribution from wholesale natural gas trading activities and the favorable
impact of the return to service of the Cook Nuclear Plant. ThePlant, the earnings from our
wholesale business which consistsincreased 116 percent over the same quarter last year. The
effects of deregulation resulted in a $57 million unfavorable variance between
periods from extraordinary items, and this factor partially offsets our improved
wholesale electric and gas sales in the United States, the
generation component of domestic retail electricity sales, worldwide electric
and gas trading and other related businesses, contributed $103 million to the
increase.business results.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
-
Revenues $8,121 133
Fuel and Purchase Power
Expense 7,755 178
Maintenance and Other
Operation Expense 107 13
Income Taxes 93 121
Other Income, net (11) (26)
Interest and Preferred Dividends 16 6
Other 13 3
---------
Net Income $ 126 90
=======
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Revenues $6,391 78 $14,439 101
Fuel and Purchase Power Expense 6,049 96 13,804 129
Maintenance and Other Operation Expense 89 10 191 11
Writeoff of Merger-Related Costs (154) (96) (149) (93)
Other Income (Loss), net 27 N.M. 89 241
Interest and Preferred Dividends (28) (10) (12) (2)
Income Taxes 121 233 214 166
Extraordinary Items (57) N.M. (57) N.M.
N.M. = Not Meaningful
The increase in revenues iswas due to a substantial increase in electric
and gas trading volumes and wholesale energy salessales. Wholesale natural gas
trading volume for the quarter was 774 billion cubic feet, a 178 percent
increase from second-quarter 2000 volume of 278 million cubic feet. Electric
trading volume for the quarter increased 16 percent to 121 million MWH and the
average price per KWH increased 35%. In the first half of 2001, the average
price per KWH sold and purchased moved upward reflecting the return to
servicemarket conditions
during a period of the Cook Nuclear units.high volatility in prices, especially natural gas. The major
increase in electric trading volume is primarily from:
o continued expansion of our trading team
o increased liquidity in the markets where we trade
The increase in gas trading volume is from:
o continued expansion of our trading team
o HPL acquisition on June 1, 2001
o expansion into markets where we have not traded historically
Our fuel and purchased power expense was primarily
attributableincreased due to the increase inincreased trading
volume, particularly gas, and an increase in generation. NetOur generation
increased 4%3% in 2001 due mainly to the return to service in June 2000 and
December of 2000 of Cook Nuclear Plant's two generating units.
STP Nuclear plant
increased its net generation by 4%.
Maintenance
Our maintenance and other operation expense increased largely as a
result of materialadditional traders' incentive compensation and labor costs associated with
the development of Buckeye Power and
Dow Chemical gas-fired plants plus additional traders' incentive compensation.
These cost increases were partiallyplants. This increase was offset, in part, by the cessation of restartno
longer incurring expenditures forto prepare the Cook Nuclear Plant units for restart
following an extended Nuclear
Regulatory Commission (NRC) monitored outage. ProjectRevenues from project fees received for the
Buckeye Power and Dow Chemical projects are recognized in revenues using the
percentage of completion method. Consequently,offset the charges to expense for
material and labordevelopment costs didthus not adversely affectaffecting net income.
The increasewrite-off of deferred merger costs in 2000 included transaction and
transition costs not recoverable from ratepayers under regulatory commission
approved settlement agreements.
In March 2001, we completed the sale of Frontera, one of the generating
plants required to be divested under FERC - approved merger settlement
agreements. The sale resulted in a $73 million gain recorded in other income for
the year-to-date period.
Our interest and preferred dividends decreased primarily because of
lower average outstanding short-term debt balances and a decrease in average
short-term interest rates.
Our income taxes is predominatelyincreased due to an increase in pre-tax income.
Other income decreasedIn the second quarter of 2001 we recorded an extraordinary loss for $48
million net of tax to write-off stranded prepaid Ohio excise taxes (See Note 2).
We discontinued the application of regulatory accounting for generation in
Virginia and West Virginia during the second quarter primarily due to a
reductionof 2000 which resulted in
equity earnings from investments. The increasean after tax extraordinary gain of $9 million in interest
and preferred dividends was primarily due to an increase in average
outstanding short-term debt
balances and an increase in average short-term debt interest rates reflecting
increased short-term cash demands and short-term market conditions.2000.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
TOTAL REVENUES $14,238 $6,117
------- ------
EXPENSES:
Fuel and Purchased Power 12,102 4,347
Maintenance and Other Operation 958 851
Depreciation and Amortization 336 320
Taxes Other Than Income Taxes 168 171
--- ---
TOTAL EXPENSES 13,564 5,689
------ -----
OPERATING INCOME 674 428
OTHER INCOME, net 31 42
-- --
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES 705 470
INTEREST AND PREFERRED DIVIDENDS 269 253
--- ---
INCOME BEFORE INCOME TAXES 436 217
INCOME TAXES 170 77
--- --
NET INCOME $ 266 $ 140
========= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 322 322
=== ===
EARNINGS PER SHARE (Basic and Dilutive): $0.83 $0.43
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
REVENUES $14,528 $8,137 $28,693 $14,254
------- ------ ------- -------
EXPENSES:
Fuel and Purchased Power 12,367 6,318 24,469 10,665
Maintenance and Other Operation 959 870 1,912 1,721
Non-recoverable Merger Costs 7 161 12 161
Depreciation and Amortization 354 305 690 625
Taxes Other Than Income Taxes 169 175 337 346
--- --- --- ---
TOTAL EXPENSES 13,856 7,829 27,420 13,518
------ ----- ------ ------
OPERATING INCOME 672 308 1,273 736
OTHER INCOME (LOSS), net 22 (5) 126 37
-- -- --- --
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES 694 303 1,399 773
INTEREST AND PREFERRED DIVIDENDS 241 269 510 522
--- --- --- ---
INCOME BEFORE INCOME TAXES 453 34 889 251
INCOME TAXES 173 52 343 129
--- -- --- ---
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM 280 (18) 546 122
EXTRAORDINARY GAIN (LOSS):
EFFECTS OF DEREGULATION (48) 9 (48) 9
--- - --- -
NET INCOME (LOSS) $ 232 $ (9) $ 498 $ 131
======== ======== ======== =====
AVERAGE NUMBER OF SHARES OUTSTANDING 322 322 322 322
=== === === ===
EARNINGS (LOSS) PER SHARE:
Income (Loss) Before Extraordinary Item $ 0.87 $(0.06) $ 1.69 $0.38
Extraordinary Gain (Loss) (0.15) 0.03 (0.15) 0.03
------ ------ ----- ----
Earnings (Loss) Per Share (Basic and Dilutive) $0.72 $(0.03) $1.54 $0.41
===== ====== ===== =====
CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 $1.20 $1.20
===== ===== ===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in millions)
ASSETS
- ------
CURRENT ASSETS:
Cash and Cash Equivalents $ 275212 $ 437
Accounts Receivable (net) 3,1582,532 3,699
Energy Trading Contracts 9,48411,720 16,627
Other 1,3171,688 1,268
----- -----
TOTAL CURRENT ASSETS 14,23416,152 22,031
------ ------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 16,25916,553 16,328
Transmission 5,8046,145 5,609
Distribution 10,82710,973 10,843
Other (including gas and coal mining assets and nuclear fuel) 3,9684,192 4,077
Construction Work in Progress 1,068988 1,231
-------- -----
Total Property, Plant and Equipment 37,92638,851 38,088
Accumulated Depreciation and Amortization 15,82315,984 15,695
------ ------
NET PROPERTY, PLANT AND EQUIPMENT 22,10322,867 22,393
------ ------
REGULATORY ASSETS 3,8683,716 3,698
----- -----
INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS 822521 782
--- ---
GOODWILL (net of amortization) 1,3101,300 1,382
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 2,2713,166 1,620
----- -----
OTHER ASSETS 2,3022,505 2,642
----- -----
TOTAL $46,910$50,227 $54,548
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $2,058$1,252 $2,627
Short-term Debt 4,1084,055 4,333
Long-term Debt Due Within One Year 1,4651,024 1,152
Energy Trading Contracts 9,37911,394 16,801
Other 2,0331,925 2,154
----- -----
TOTAL CURRENT LIABILITIES 19,04319,650 27,067
------ ------
LONG-TERM DEBT 9,07610,609 9,602
----------- -----
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY
JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 333322 334
--- ---
DEFERRED INCOME TAXES 4,8654,914 4,875
----- -----
DEFERRED INVESTMENT TAX CREDITS 519510 528
--- ---
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 201199 203
--- ---
LONG-TERM ENERGY TRADING CONTRACTS 1,9732,965 1,381
----- -----
DEFERRED CREDITS AND REGULATORY LIABILITIES 991986 637
--- ---
OTHER NONCURRENT LIABILITIES 1,6911,763 1,706
----- -----
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 161 161
--- ---
COMMITMENTS AND
CONTINGENCIES (Note 8)
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2001 2000
---- ----
Shares Authorized. . . . . 600,000,000 600,000,000
Shares Issued. . . . . . . 331,095,028331,201,100 331,019,146
(8,999,992 shares were held in treasury at March 31,June 30, 2001
and December 31, 2000) 2,1522,153 2,152
Paid-in Capital 2,9142,916 2,915
Accumulated Other Comprehensive Income (Loss) (172)(131) (103)
Retained Earnings 3,1633,210 3,090
----- -----
TOTAL COMMON SHAREHOLDERS' EQUITY 8,0578,148 8,054
----- -----
TOTAL $46,910$50,227 $54,548
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,June 30,
2001 2000
---- ----
(in millions)
OPERATING ACTIVITIES:
OPERATING ACTIVITIES:
Net Income $ 266498 $ 140131
Adjustments for Noncash Items:
Depreciation and Amortization 352 349709 666
Deferred Federal Income Taxes 68 (34)19 19
Deferred Investment Tax Credits (9)(17) (17)
Amortization of Deferred Property Taxes 82 79
Amortization of Cook Plant Restart Costs 20 20
Deferred Costs Under Fuel Clause Mechanisms 50 (164)
Extraordinary Gain (Loss) - Effects of Deregulation 48 (9)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 615 341,154 (475)
Fuel, Materials and Supplies (13) 50(108) 73
Accrued Utility Revenues 39 29
Prepayments and Other (68) (4)(84) (108)
Accounts Payable (499) (4)(1,643) 311
Taxes Accrued 15 (23)
Interest Accrued 65 77
Rent Accrued - Rockport Plant Unit 2 37 37
Energy Trading Contracts (net) (279) (87)39 (205)
Customer Deposits (39) 7
Other (net) (5) 27
--(89) 41
--- --
Net Cash Flows From Operating Activities 584 582639 369
--- ---
INVESTING ACTIVITIES:
Construction Expenditures (315) (376)(819) (808)
Purchase of Houston Pipe Line (727) -
Sale of Yorkshire 383 -
Sale of Frontera 265 -
Other 109 (20)
---(276) (60)
---- ---
Net Cash Flows Used For Investing Activities (206) (396)
----(1,174) (868)
------ ----
FINANCING ACTIVITIES:
Issuance of Common Stock 3 19 12
Issuance of Long-term Debt 132 3311,388 751
Change in Short-term Debt (net) (266) (210)(233) 1,104
Retirement of Long-term Debt (209) (253)
Special Deposit for Reacquisition of Long-term Debt - 50(463) (1,239)
Dividends Paid on Common Stock (193) (209)(387) (419)
---- ----
Net Cash Flows Used ForFrom Financing Activities (533) (290)
---- ----314 209
--- ---
Effect of Exchange Rate Change on Cash (4) (7) (3)
-- --
Net Decrease in Cash and Cash Equivalents (162) (107)(225) (297)
Cash and Cash Equivalents at Beginning of Period 437 609
--- ---
Cash and Cash Equivalents at End of Period $ 275212 $ 502312
===== =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $115 million and $170
million and for income taxes was $178 million and $25 million in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $19 million and $17=======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $342 million and $471
million and for income taxes was $107 million and $206 million in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $21 million and $50
million in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(UNAUDITED)
Accumulated Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
(in millions)
JANUARY 1, 2000 $2,149 $2,898 $3,630 $(4) $8,673
Issuance of Common Stock 1 12 10 12
Common Stock Dividends (209) (209)
----
8,465(419) (419)
Other (46) (46)
---
8,220
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Currency Translation Adjustment (35) (35)(115) (115)
Unrealized Loss on Securities (7) (7)20 20
Minimum Pension Liability (2) (2)
Net Income 140 140131 131
---
Total Comprehensive Income 9834
-------- -------- -------- ----------- --
MARCH 31,JUNE 30, 2000 $2,149 $2,899 $3,561 $(46) $8,563$2,151 $2,862 $3,342 $(101) $8,254
====== ====== ====== ========= ======
JANUARY 1, 2001 $2,152 $2,915 $3,090 $(103) $8,054
Issuance of Common Stock 4 41 8 9
Common Stock Dividends (193) (193)(387) (387)
Other (5) (5)
--
7,860(7) 9 2
-
7,678
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Currency Translation Adjustment (82) (82)(53) (53)
Unrealized Gain on Hedged Derivatives 13 1331 31
Minimum Pension Liability (6) (6)
Net Income 266 266498 498
---
Total Comprehensive Income 197470
-------- -------- -------- ------- ------ MARCH 31,------
JUNE 30, 2001 $2,152 $2,914 $3,163 $(172) $8,057$2,153 $2,916 $3,210 $(131) $8,148
====== ====== ====== ===== ======
See Notes to Financial Statements beginning on page L-1.
B-5
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRSTSECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
Operating revenues are derived from the sale of Rockport Plant energy
and capacity to two affiliated companies pursuant to FERC approved long-term
unit power agreements. The unit power agreements provide for recovery of costs
including a FERC approved rate of return on common equity and a return on other
capitalcapital.
The increase in net income of temporary cash investments.$0.4 million or 25% for the quarter
resulted primarily from an adjustment to the power bills to reflect the
resolution of a tax issue. Net income for the year-to-date period declined $0.5$0.1
million or 19% for first quarter1% primarily as a result of a final true-up billing in January 2000
to an unaffiliated utility whose unit power purchase contract expired on
December 31, 1999.
Income statement line items which changed significantly were:
Increase (Decrease)
First Quarter
(in millions) %
------------- -
Operating Revenues $ 3.6 6
Fuel Expense 3.2 13
Maintenance Expense (0.6)
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $(4.7) (8) $(1.1) (1)
Fuel Expense (5.8) (22) (2.6) (5)
Other Operation Expense 0.4 21 0.3 5
Maintenance Expense 0.8 25 0.2 4
Taxes Other Than Federal Income Taxes (0.5) (43) 1.5 68
Interest Charges (0.3) (29) (0.4) (23)
Taxes Other Than Federal
Income Taxes 2.0 178
Federal Income Taxes (0.3) (46)
Interest Charges (0.1) (16)
The increasedecrease in operating revenues resulted primarily from an increasea decrease in
recoverable expenses as generation increasedespecially fuel. The Rockport Plant underwent scheduled
maintenance outages in the second quarter of 2001. In 2000, maintenance outages
occurred in the first quarter.
Fuel expense decreased due to an increasea decline in Rockport Plant's availability. Shortergeneration reflecting the
length of outages in the second quarter 2001 reflecting
management's policy to maximize generating capacity availability, allowed
the Rockport Plant units to generate 19% more electricity than in 2000.
Fueland lower average fuel cost.
Other operation and maintenance expense increased due to more extensive
outages during the increasesecond quarter 2001 for boiler maintenance and repair.
The decline in generation.
The reduction in the number of outages and the shorter length of
planned outages also accountedtaxes other than federal income taxes for the quarter
resulted from a decrease in maintenance expense.an accrual for state taxes as a result of a revised
taxable income estimate. Taxes other than federal income taxes for the
year-to-date period increased due to the accrual of state income taxes based on
an estimate of higher taxable income for 2001.
The decrease in federal income taxes attributable to operations is
primarily due to a decrease in pre-tax income. Reductions in variable interest rates, reflecting market conditions,
wereproduced the primary reason for
the declinedecrease in interest charges.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ----
(in thousands)
OPERATING REVENUES $60,507 $56,866
------- -------
OPERATING EXPENSES:
Fuel 27,645 24,435
Rent - Rockport Plant Unit 2 17,071 17,071
Other Operation 2,958 3,098
Maintenance 1,926 2,515
Depreciation 5,586 5,505
Taxes Other Than Federal Income Taxes 3,128 1,126
Federal Income Taxes 386 721
--- ---
TOTAL OPERATING EXPENSES 58,700 54,471
------ ------
OPERATING INCOME 1,807 2,395
NONOPERATING INCOME 862 869
--- ---
INCOME BEFORE INTEREST CHARGES 2,669 3,264
INTEREST CHARGES 689 819
--- ---
NET INCOME $1,980 $2,445
====== ======
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000 ---- ----
(in thousands)
OPERATING REVENUES $52,217 $56,928 $112,724 $113,794
------- ------- -------- --------
OPERATING EXPENSES:
Fuel 20,261 26,048 47,906 50,483
Rent - Rockport Plant Unit 2 17,070 17,070 34,141 34,141
Other Operation 2,368 1,956 5,326 5,054
Maintenance 3,971 3,166 5,897 5,681
Depreciation 5,602 5,541 11,188 11,046
Taxes Other Than Federal Income Taxes 641 1,124 3,769 2,250
Federal Income Taxes 422 277 808 998
--- --- --- ---
TOTAL OPERATING EXPENSES 50,335 55,182 109,035 109,653
------ ------ ------- -------
OPERATING INCOME 1,882 1,746 3,689 4,141
NONOPERATING INCOME 887 900 1,749 1,769
--- --- ----- -----
INCOME BEFORE INTEREST CHARGES 2,769 2,646 5,438 5,910
INTEREST CHARGES 706 993 1,395 1,812
--- --- ----- -----
NET INCOME $ 2,063 $ 1,653 $ 4,043 $ 4,098
======= ======= ========== ==========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 9,722 $ 3,673
NET INCOME 1,980 2,445
CASH DIVIDENDS DECLARED 959 1,935
--- -----
BALANCE AT END OF PERIOD $10,743 $4,183 $ 9,722 $ 3,673
NET INCOME 2,063 1,653 4,043 4,098
CASH DIVIDENDS DECLARED 959 - 1,918 1,935
--- ------ ----- -----
BALANCE AT END OF PERIOD $11,847 $5,836 $11,847 $5,836
======= ====== ======= ======
The common stock of AEGCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $635,945 $635,215
General 2,973 2,795
Construction Work in Progress 3,676 4,292
----- -----
Total Electric Utility Plant 642,594 642,302
Accumulated Depreciation 320,991 315,566
------- -------
NET ELECTRIC UTILITY PLANT 321,603 326,736
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 4,768 2,757
Accounts Receivable:
Affiliated Companies 21,105 21,374
Miscellaneous 2,110 2,341
Fuel - at average cost 10,375 11,006
Materials and Supplies - at average cost 3,949 3,979
Prepayments 105 145
--- ---
TOTAL CURRENT ASSETS 42,412 41,602
------ ------
REGULATORY ASSETS 5,444 5,504
----- -----
DEFERRED CHARGES 3,379 760
----- ---
TOTAL ASSETS $372,838
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $636,583 $635,215
General 2,991 2,795
Construction Work in Progress 3,471 4,292
----- -----
Total Electric Utility Plant 643,045 642,302
Accumulated Depreciation 325,671 315,566
------- -------
NET ELECTRIC UTILITY PLANT 317,374 326,736
------- -------
OTHER PROPERTY AND INVESTMENTS 119 6
--- -
CURRENT ASSETS:
Cash and Cash Equivalents 791 2,757
Accounts Receivable:
Affiliated Companies 17,852 21,374
Miscellaneous 150 2,341
Fuel - at average cost 18,621 11,006
Materials and Supplies - at average cost 4,008 3,979
Prepayments 63 145
-- ---
TOTAL CURRENT ASSETS 41,485 41,602
------ ------
REGULATORY ASSETS 5,384 5,504
----- -----
DEFERRED CHARGES 2,392 754
----- ---
TOTAL ASSETS $366,754 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares $ 1,000 $1,000$ 1,000
Paid-in Capital 23,434 23,434
Retained Earnings 10,74311,847 9,722
------ -----
Total Common Shareowner's Equity 36,281 34,156
Long-term Debt 44,812 -
------ -
TOTAL CAPITALIZATION AND COMMON SHAREHOLDER'S EQUITY 35,17781,093 34,156
------ ------
OTHER NONCURRENT LIABILITIES 358
---
358
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 44,810- 44,808
Advances from Affiliates 15,165 28,068
219
Accounts Payable:
General 7,8799,313 6,109
Affiliated Companies 9,73711,372 7,724
Taxes Accrued 11,12410,826 4,993
Rent Accrued - Rockport Plant Unit 2 23,4274,963 4,963
Other 4,8182,077 4,443
----- -----
TOTAL CURRENT LIABILITIES 102,01453,716 101,108
------------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 120,796119,403 122,188
------- -------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 58,88158,045 59,718
Amounts Due to Customers for Income Taxes 23,32922,661 23,996
------ ------
TOTAL REGULATORY LIABILITIES 82,21080,706 83,714
------ ------
DEFERRED INCOME TAXES 32,13331,328 32,928
------ ------
DEFERRED CREDITS 150 150
--- ---
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $372,838$366,754 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
OPERATING ACTIVITIES:
Net Income $ 1,9804,043 $ 2,445
Adjustment4,098
Adjustments for Noncash Items:
Depreciation 5,586 5,50511,188 11,046
Deferred Federal Income Taxes (1,462) (1,374)(2,935) (2,769)
Deferred Investment Tax Credits (837) (837)(1,673) (1,674)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 (1,392) (1,393)(2,785) (2,785)
Deferred Property Taxes (2,737) (2,489)(1,829) (1,648)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable 500 5,6815,713 3,343
Fuel, Materials and Supplies 661 461(7,644) (1,593)
Accounts Payable 3,783 (4,686)6,852 (15,562)
Taxes Accrued 6,131 4,198
Rent Accrued - Rockport Plant Unit 2 18,464 18,4645,833 2,533
Other (net) 574 (1,735)
---(2,371) (1,270)
------ ------
Net Cash Flow From (Used For) Operating Activities 31,251 24,24014,392 (6,281)
------ ------
INVESTING ACTIVITIES - Construction Expenditures (432) (1,266)
----(1,537) (2,295)
------ ------
FINANCING ACTIVITIES:
Return of Capital to Parent Company - (2,000)(2,935)
Change in Short-term Debt (net) - (17,650)(24,700)
Change in Advances from Affiliates (net) (27,849) -(12,903) 37,870
Dividends Paid (959)(1,918) (1,935)
---------- ------
Net Cash Flows Used ForFrom (Used For) Financing Activities (28,808) (21,585)(14,821) 8,300
------- ------------
Net IncreaseDecrease in Cash and Cash Equivalents 2,011 1,389(1,966) (276)
Cash and Cash Equivalents at Beginning of Period 2,757 317
----- ---
Cash and Cash Equivalents at End of Period $ 4,768 $1,706
======== ======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $644,000 and $732,000 and
for income taxes was $1,349,000 and $678,000791 $ 41
========= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,143,000 and $1,619,000
and for income taxes was $1,350,000 and $3,129, 000 in 2001 and 2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
C-7
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST-------------------------------------------------------------
SECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
Net income increased $14.1 million or 30% mainly dueAND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of the generation,
marketing and trading of electricity; and energy delivery which consists of
transmission and distribution services. We belong to growth in and
strong performance by the trading operation. APCo, as a member of the AEP Power Pool sharesand
share in the revenues and costs of wholesale marketing and trading activities
conducted on itsour behalf by the AEP Power Pool.
Net income decreased $2.8 million or 7% for the quarter due to the
effect of an extraordinary gain recorded in 2000 for the discontinuance of
regulatory accounting partially offset by favorable wholesale business
performance. Net income increased $11.4 million or 13% for the year-to-date
period primarily due to growth in and strong performance by the wholesale
business.
Income statement line items which changed significantly were:
Increase (Decrease)
First-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $952 93$389 27 $1,341 54
Fuel Expense (3) (3)(8) (8) (11) (6)
Purchased Power Expense 927 141377 33 1,303 73
Other Operation Expense 5 96 10 12 10
Maintenance Expense 5 17 10 17
Depreciation and Amortization 5 13 11 14
Nonoperating Income 4 547127 9 205
Extraordinary Gain (9) N.M. (9) N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to a 60%increased wholesale
electricity prices and trading volume of our wholesale business. Expansion of
the wholesale business' trading operation and greater liquidity in the market
place resulted in an increase in electricthe number of forward electricity purchase and
sales contracts in AEP's traditional marketing area (up to two transmission
systems from AEP's service territory). Wholesale trading volume increased 33%
for the year-to-date period. The increase in wholesale prices is due to changes
in market conditions during a period of high volatility in prices.
Fuel expense of the wholesale business decreased due to a decline in
generation as a result of scheduled plant maintenance.
The increase in the wholesale business' purchased power expense is
attributable to increases in wholesale electricity prices and trading volume.
In
Other operation expense increased as a result of power trading incentive
compensation expense of the firstwholesale business and a reduction in transmission
equalization credits for the energy delivery business. APCo and certain
affiliates share, through the Transmission Agreement, the costs associated with
the ownership of the extra-high voltage transmission system and certain
facilities at lower voltages based upon each company's peak demand and
investment. An increase in APCo's peak demand relative to its affiliates' peak
demand was the main reason for the decrease in transmission equalization
credits.
The increase in maintenance expense is mainly attributable to increased
generating plant boiler maintenance repairs to the wholesale business' Amos,
Mountaineer and Glen Lyn Plants.
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 assets through regulated rates. Depreciation
and amortization expense increased due to the 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 increase in depreciation and amortization expense.
The increase in nonoperating income was due to an increase in net gains
from the wholesale business' trading transactions outside of the AEP System's
traditional marketing area and speculative financial transactions (options,
futures, swaps).
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,849,304 $1,460,774 $3,823,431 $2,482,452
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 85,049 92,663 180,525 191,220
Purchased Power 1,513,831 1,137,184 3,099,033 1,795,831
Other Operation 67,948 61,566 133,837 122,207
Maintenance 33,842 28,989 66,851 57,314
Depreciation and Amortization 44,056 38,899 87,773 77,237
Taxes Other Than Federal Income Taxes 29,975 28,817 61,843 59,462
Federal Income Taxes 15,241 14,448 46,055 42,727
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,789,942 1,402,566 3,675,917 2,345,998
--------- --------- --------- ---------
OPERATING INCOME 59,362 58,208 147,514 136,454
NONOPERATING INCOME 7,772 3,427 12,823 4,208
----- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 67,134 61,635 160,337 140,662
INTEREST CHARGES 30,715 31,395 62,131 62,758
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 36,419 30,240 98,206 77,904
EXTRAORDINARY GAIN - DISCONTINUANCE OF
SFAS 71 (INCLUSIVE OF TAX BENEFIT OF
$7,872,000) - 8,938 - 8,938
------ ----- ------ -----
NET INCOME 36,419 39,178 98,206 86,842
PREFERRED STOCK DIVIDEND REQUIREMENTS 503 632 1,006 1,265
--- --- ----- -----
EARNINGS APPLICABLE TO COMMON STOCK $ 35,916 $ 38,546 $ 97,200 $ 85,577
=========== =========== =========== ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $36,419 $39,178 $98,206 $86,842
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (212) - (629) -
---- ------ ---- ------
COMPREHENSIVE INCOME $36,207 $39,178 $97,577 $86,842
======= ======= ======= =======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $149,469 $191,232 $120,584 $175,854
NET INCOME 36,419 39,178 98,206 86,842
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 32,398 31,653 64,797 63,306
Cumulative Preferred Stock 360 525 721 1,050
Capital Stock Expense 143 106 285 214
--- --- --- ---
BALANCE AT END OF PERIOD $152,987 $198,126 $152,987 $198,126
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,073,004 $2,058,952
Transmission 1,208,519 1,177,079
Distribution 1,850,084 1,816,925
General 261,307 254,371
Construction Work in Progress 101,589 110,951
------- -------
Total Electric Utility Plant 5,494,503 5,418,278
Accumulated Depreciation and Amortization 2,241,639 2,188,796
--------- ---------
NET ELECTRIC UTILITY PLANT 3,252,864 3,229,482
--------- ---------
OTHER PROPERTY AND INVESTMENTS 57,550 56,967
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 611,424 322,688
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 5,176 5,847
Advances to Affiliates - 8,387
Accounts Receivable:
Customers 185,010 243,298
Affiliated Companies 48,832 63,919
Miscellaneous 19,058 16,179
Allowance for Uncollectible Accounts (1,868) (2,588)
Fuel - at average cost 41,505 39,076
Materials and Supplies - at average cost 59,945 57,515
Accrued Utility Revenues 18,492 66,499
Energy Trading Contracts 1,772,239 2,036,001
Prepayments 10,029 6,307
------ -----
TOTAL CURRENT ASSETS 2,158,418 2,540,440
--------- ---------
REGULATORY ASSETS 443,511 447,750
------- -------
DEFERRED CHARGES 35,074 48,826
------ ------
TOTAL ASSETS $6,558,841 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $260,458
Paid-in Capital 715,502 715,218
Accumulated Other Comprehensive Income (Loss) -
(629)
Retained Earnings 152,987 120,584
------- -------
Total Common Shareowner's Equity 1,128,318 1,096,260
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,431,344 1,430,812
--------- ---------
TOTAL CAPITALIZATION 2,588,312 2,555,722
--------- ---------
OTHER NONCURRENT LIABILITIES 92,322 105,883
------ -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 6 175,006
Short-term Debt - 191,495
Advances from Affiliates 301,890 -
Accounts Payable - General 167,195 153,422
Accounts Payable - Affiliated Companies 90,036 107,556
Taxes Accrued 73,696 63,258
Customer Deposits 14,960 12,612
Interest Accrued 27,479 21,555
Energy Trading Contracts 1,729,722 2,091,804
Other 67,177 85,378
------ ------
TOTAL CURRENT LIABILITIES 2,472,161 2,902,086
--------- ---------
DEFERRED INCOME TAXES 721,412 682,474
------- -------
DEFERRED INVESTMENT TAX CREDITS 40,881 43,093
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 550,037 259,438
------- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 93,716 97,457
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $6,558,841 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 98,206 $ 86,842
Adjustments for Noncash Items:
Depreciation and Amortization 87,829 77,293
Deferred Federal Income Taxes 29,279 15,054
Deferred Investment Tax Credits (2,212) (2,332)
Deferred Power Supply Costs (net) 594 (11,938)
Extraordinary Gain - Discontinuance of SFAS 71 - (8,938)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 69,776 (36,988)
Fuel, Materials and Supplies (4,859) 8,588
Accrued Utility Revenues 48,007 13,029
Accounts Payable (3,747) 27,567
Taxes Accrued 10,438 (764)
Interest Accrued 5,924 (903)
Net Change in Energy Trading Contracts (96,457) (19,438)
Other (net) (15,019) (17,509)
------- -------
Net Cash Flows From Operating Activities 227,759 129,563
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (107,876) (80,870)
Proceeds from Sale of Property 1,182 148
----- ---
Net Cash Flows Used For Investing Activities (106,694) (80,722)
-------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 74,787
Change in Short-term Debt (net) (191,495) 22,195
Change in Advance from Affiliates (net) 310,277 (12,857)
Retirement of Cumulative Preferred Stock - (210)
Retirement of Long-term Debt (175,000) (131,202)
Dividends Paid on Common Stock (64,797) (63,306)
Dividends Paid on Cumulative Preferred Stock (721) (1,053)
---- ------
Net Cash Flows Used For Financing Activities (121,736) (111,646)
-------- --------
Net Decrease in Cash and Cash Equivalents (671) (62,805)
Cash and Cash Equivalents at Beginning of Period 5,847 64,828
----- ------
Cash and Cash Equivalents at End of Period $ 5,176 $ 2,023
============= ===========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $54,957,000 and
$61,828,000 and for income taxes was $17,064,000 and $21,198,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $1,684,000
and $7,451,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2001 vs. SECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of generation,
marketing and trading of electricity; and energy delivery which consists of
transmission and distribution services. Since the merger of AEP and CSW, we
participate in power marketing and trading activities conducted on our behalf by
the AEP System.
Second quarter net income decreased $15 million or 22% while the
year-to-date net income increased $12 million or 16%. The lower second quarter
net income was the result of increased transmission expenses. Year-to-date net
income increased primarily from participation in the power marketing and trading
operations. Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $211 48 $498 66
Fuel Expense 6 5 69 30
Purchased Power Expense 186 532 380 686
Other Operation 22 40 22 17
Maintenance 3 16 3 11
Depreciation and Amortization 13 31 1 1
Taxes Other Than Federal Income Taxes 2 9 4 10
Federal Income Taxes (7) (20) 7 18
Nonoperating Income (3) (185) (2) (96)
The significant increase in operating revenues resulted from
participation in AEP's power marketing and trading operations, which added new
wholesale revenues, and higher fuel related revenues due to increased fuel and
purchased power expense. CPL began sharing in AEP's marketing and trading
transactions as a result of the merger of AEP and CSW in June 2000.
Fuel expense increased due primarily to an increase in the average unit
cost of fuel as a result of higher spot market natural gas prices.
The substantial rise in purchased power expense is attributable to post
merger participation in the marketing and trading operation.
Other operation expense increased due primarily to a favorable
adjustment recorded in the second quarter of 2000 for the energy delivery
business' transmission expenses that resulted from new transmission prices for
Electric Reliability Council of Texas (ERCOT) transmission grid usage. Each year
ERCOT establishes new rates to allocate the costs of the Texas transmission
system to Texas electric utilities. Additionally, generation expenses were up
due to power trading incentive compensation.
Maintenance expense for the quarter increased primarily due to two
non-nuclear plant outages. Year-to-date maintenance expense increased primarily
due to the wholesale business' STP nuclear plant refueling outage between March
7 and April 2, 2001.
The increase in depreciation and amortization expense for the quarter
is due primarily to higher depreciation expense associated with excess earning
provisions of the Texas deregulation legislation.
Taxes other than federal income taxes increased due primarily to an
increase in Texas Gross Receipts Tax and Ad Valorem taxes.
Federal income taxes attributable to operations for the quarter
decreased due to a decrease in pre-tax operating income. However, federal income
taxes attributable to operations for the year-to-date period increased due to an
increase in pre-tax operating income.
Nonoperating income decreased due to a reduction in allocated tax
savings resulting from the parent company loss tax benefit.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $648,499 $437,911 $1,251,911 $754,239
-------- -------- ---------- --------
OPERATING EXPENSES:
Fuel 147,179 140,841 299,032 230,238
Purchased Power 220,772 34,936 435,338 55,356
Other Operation 76,189 54,307 151,260 129,609
Maintenance 17,995 15,474 35,282 31,896
Depreciation and Amortization 53,587 40,887 95,978 95,085
Taxes Other Than Federal Income Taxes 21,711 19,922 41,199 37,456
Federal Income Taxes 28,715 35,827 47,319 40,232
------ ------ ------ ------
TOTAL OPERATING EXPENSES 566,148 342,194 1,105,408 619,872
------- ------- --------- -------
OPERATING INCOME 82,351 95,717 146,503 134,367
NONOPERATING INCOME (LOSS) (1,541) 1,815 98 2,362
------ ----- -- -----
INCOME BEFORE INTEREST CHARGES 80,810 97,532 146,601 136,729
INTEREST CHARGES 28,292 29,979 59,052 61,037
------ ------ ------ ------
NET INCOME 52,518 67,553 87,549 75,692
PREFERRED STOCK DIVIDEND REQUIREMENTS 61 61 121 121
-- -- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 52,457 $67,492 $ 87,428 $75,571
========== ======= ======== =======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $790,176 $727,973 $792,219 $758,894
NET INCOME 52,518 67,553 87,549 75,692
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 37,014 39,000 74,028 78,000
Preferred Stock 61 61 121 121
-- -- --- ---
BALANCE AT END OF PERIOD $805,619 $756,465 $805,619 $756,465
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,163,111 $3,175,867
Transmission 604,057 581,931
Distribution 1,250,224 1,221,750
General 240,386 237,764
Construction Work in Progress 195,948 138,273
Nuclear Fuel 240,151 236,859
------- -------
Total Electric Utility Plant 5,693,877 5,592,444
Accumulated Depreciation and Amortization 2,361,780 2,297,189
--------- ---------
NET ELECTRIC UTILITY PLANT 3,332,097 3,295,255
--------- ---------
OTHER PROPERTY AND INVESTMENTS 46,229 44,225
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 32,199 66,231
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 5,755 14,253
Accounts Receivable:
Customers 38,616 67,787
Affiliated Companies 12,818 31,272
Allowance for Uncollectible Accounts (1,638) (1,675)
Fuel Inventory - at LIFO cost 39,511 22,842
Materials and Supplies - at average cost 54,127 53,108
Under-recovered Fuel Costs 93,341 127,295
Energy Trading Contracts 112,483 481,206
Prepayments and Other Current Assets 6,151 3,014
----- -----
TOTAL CURRENT ASSETS 361,164 799,102
------- -------
REGULATORY ASSETS 178,299 202,440
------- -------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249
------- -------
NUCLEAR DECOMMISSIONING TRUST FUND 95,032 93,592
------ ------
DEFERRED CHARGES 45,115 18,402
------ ------
TOTAL ASSETS $5,043,384 $5,472,496
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 6,755,535 Shares $ 168,888 $168,888
Paid-in Capital 405,000 405,000
Retained Earnings 805,619 792,219
------- -------
Total Common Shareowner's Equity 1,379,507 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 136,750 148,500
Long-term Debt 942,863 1,254,559
------- ---------
TOTAL CAPITALIZATION 2,465,087 2,775,133
--------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 511,700 200,000
Advances from Affiliates 223,512 269,712
Accounts Payable - General 115,732 128,957
Accounts Payable - Affiliated Companies 26,657 40,962
Taxes Accrued 128,983 55,526
Interest Accrued 24,221 26,217
Energy Trading Contracts 111,536 489,888
Other 46,778 40,630
------ ------
TOTAL CURRENT LIABILITIES 1,189,119 1,251,892
--------- ---------
DEFERRED INCOME TAXES 1,221,213 1,242,797
--------- ---------
DEFERRED INVESTMENT TAX CREDITS 125,496 128,100
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 32,999 65,740
------- ------
DEFERRED CREDITS 9,470 8,834
----- -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,043,384 $5,472,496
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $87,549 $75,692
Adjustments for Noncash Items:
Depreciation and Amortization 95,978 95,085
Deferred Federal Income Taxes (17,699) (4,178)
Deferred Investment Tax Credits (2,604) (2,603)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 47,588 8,385
Fuel, Materials and Supplies (17,688) 4,575
Fuel Recovery 33,954 (25,227)
Accounts Payable (27,530) 24,785
Taxes Accrued 73,457 (17,148)
Transmission Coordination Agreement Settlement - 15,519
Deferred Property Taxes (21,563) -
Other (net) (17,628) 10,002
------- ------
Net Cash Flows From Operating Activities 233,814 184,887
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (109,638) (85,215)
Other (354) (4,067)
---- ------
Net Cash Flows Used For Investing Activities (109,992) (89,282)
-------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt 149,413
-
Retirement of Long-term Debt (11,971) (100,000)
Reacquisition of Long-term Debt - (50,000)
Change in Advances from Affiliates (net) (46,200) (68,379)
Special Deposit for Reacquisitions of Long-term Debt 50,000
-
Dividends Paid on Common Stock (74,028) (78,000)
Dividends Paid on Cumulative Preferred Stock (121) (127)
---- ----
Net Cash Flows Used For Financing Activities (132,320) (97,093)
-------- -------
Net Decrease in Cash and Cash Equivalents (8,498) (1,488)
Cash and Cash Equivalents at Beginning of Period 14,253 7,995
------ -----
Cash and Cash Equivalents at End of Period $ 5,755 $ 6,507
======== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $46,083,000 and
$46,981,000 and for income taxes was $11,307,000 and $48,141,000 in 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2001 vs. SECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of the generation,
marketing and trading of electricity; and energy delivery which consists of
transmission and distribution services. We belong to the AEP Power Pool grew itsand
share in the revenues and costs of wholesale marketing and trading businessactivities
conducted on our behalf by the AEP Power Pool.
Net income decreased $14 million or 41% in the second quarter of 2001
and $4 million or 7% in the year-to-date period due to an extraordinary loss
recorded in the second quarter to recognize a stranded asset resulting from
deregulation. Income before extraordinary item increased by $12 million or 34%
in the second quarter of 2001 and $22 million or 35% in the year-to-date period
versus last year. Income increased due to growth in and strong performance by
the wholesale business.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $181 19 $673 43
Fuel Expense (6) (13) - -
Purchased Power Expense 160 23 618 56
Other Operation Expense 4 8 13 14
Maintenance Expense 2 8 6 17
Depreciation and Amortization 6 26 13 27
Extraordinary Item 26 N.M. 26 N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to increases in electric
wholesale prices and volume of our wholesale business. Expansion of the
wholesale business' trading operation and greater liquidity in the market place
resulted in an increase in the number of forward electricity purchase and sales
contracts made in AEP's traditional marketing area (up to two transmission
systems from AEP's service territory). Wholesale trading volume increased 24%
for the year-to-date period. The increase in wholesale prices is due to changes
in market conditions during a period of high volatility in prices.
Fuel expense of the wholesale business decreased in the second quarter
of 2001 due to a declinedecrease in net generation as a resultpartially offset by an increase in
price and the discontinuance of scheduled plant maintenance.deferred fuel accounting because of deregulation
effective January 1, 2001.
The increase in purchased power expense was primarily attributable to the increase in trading volume.
Other operation expense increased as a result of the growth in AEP's
electricity marketing and trading operations. The increase in maintenance
expense is due to the effect of performing generating plant boiler
maintenance repairs to the Amos, Mountaineer and Glen Lyn Plants.
Depreciation and amortization expense increased due to the accelerated
amortization beginning in July 2000 of transition regulatory assets in
connection with the June 2000 discontinuance of SFAS 71increases in
the Company's
Virginia and West Virginia jurisdictions whereby net generation-related
regulatory assets were transferred to the distribution portion of thewholesale business commensurate with their recovery through regulated rates (see Note
5 for further discussion of the effects of restructuring). Additional
investments in distribution and transmission plant also contributed to the
increase in depreciation and amortization expense.
The increase in nonoperating income was due to an increase in net
gains from AEP Power Pool trading transactions outside of the AEP System's
traditional marketing area and speculative financial transactions (options,
futures, swaps). The AEP Power Pool enters into power trading transactions
for the forward purchase and sale of electricity and electricity options,
futures and swaps. The Company's share of the AEP Power Pool's gains and
losses from forward electricity trading transactions outside of the AEP
System traditional marketing area and for speculative financial
transactions (options, futures, swaps) is included in nonoperating income.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $1,974,127 $1,021,678
---------- ----------
OPERATING EXPENSES:
Fuel 95,476 98,557
Purchased Power 1,585,202 658,647
Other Operation 65,889 60,641
Maintenance 33,009 28,325
Depreciation and Amortization 43,717 38,338
Taxes Other Than Federal Income Taxes 31,868 30,645
Federal Income Taxes 30,814 28,279
------ ------
TOTAL OPERATING EXPENSES 1,885,975 943,432
--------- -------
OPERATING INCOME 88,152 78,246
NONOPERATING INCOME 5,051 781
----- ---
INCOME BEFORE INTEREST CHARGES 93,203 79,027
INTEREST CHARGES 31,416 31,363
------ ------
NET INCOME 61,787 47,664
PREFERRED STOCK DIVIDEND REQUIREMENTS 503 633
--- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 61,284 $ 47,031
============ ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
NET INCOME $61,787 $47,644
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (417) -
---- --
COMPREHENSIVE INCOME $61,370 $47,664
======= =======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $120,584 $175,854
NET INCOME 61,787 47,664
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 32,399 31,653
Cumulative Preferred Stock 361 525
Capital Stock Expense 142 108
--- ---
BALANCE AT END OF PERIOD $149,469 $191,232
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,058,100 $2,058,952
Transmission 1,193,606 1,177,079
Distribution 1,836,856 1,816,925
General 256,265 254,371
Construction Work in Progress 100,046 110,951
------- -------
Total Electric Utility Plant 5,444,873 5,418,278
Accumulated Depreciation and Amortization 2,218,992 2,188,796
--------- ---------
NET ELECTRIC UTILITY PLANT 3,225,881 3,229,482
--------- ---------
OTHER PROPERTY AND INVESTMENTS 51,879 56,967
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 572,406 322,688
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 7,571 5,847
Advances to Affiliates - 8,387
Accounts Receivable:
Customers 166,360 243,298
Affiliated Companies 58,465 63,919
Miscellaneous 15,907 16,179
Allowance for Uncollectible Accounts (1,995) (2,588)
Fuel - at average cost 32,994 39,076
Materials and Supplies - at average cost 60,506 57,515
Accrued Utility Revenues 15,207 66,499
Energy Trading Contracts 1,875,174 2,036,001
Prepayments 14,356 6,307
------ -----
TOTAL CURRENT ASSETS 2,244,545 2,540,440
--------- ---------
REGULATORY ASSETS 450,773 447,750
------- -------
DEFERRED CHARGES 45,921 48,826
------ ------
TOTAL ASSETS $6,591,405 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares $ 260,458 $260,458
Paid-in Capital 715,359 715,218
Accumulated Other Comprehensive Income (Loss) (417) -
Retained Earnings 149,469 120,584
------- -------
Total Common Shareowner's Equity 1,124,869 1,096,260
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 17,790 17,790
Subject to Mandatory Redemption 10,860 10,860
Long-term Debt 1,431,088 1,430,812
--------- ---------
TOTAL CAPITALIZATION 2,584,607 2,555,722
--------- ---------
OTHER NONCURRENT LIABILITIES 97,674 105,883
------ -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 75,006 175,006
Short-term Debt - 191,495
Advances from Affiliates 145,185 -
Accounts Payable - General 148,743 153,422
Accounts Payable - Affiliated Companies 118,321 107,556
Taxes Accrued 68,675 63,258
Customer Deposits 12,366 12,612
Interest Accrued 39,173 21,555
Energy Trading Contracts 1,889,898 2,091,804
Other 70,090 85,378
------ ------
TOTAL CURRENT LIABILITIES 2,567,457 2,902,086
--------- ---------
DEFERRED INCOME TAXES 710,796 682,474
------- -------
DEFERRED INVESTMENT TAX CREDITS 41,987 43,093
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 491,369 259,438
------- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 97,515 97,457
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $6,591,405 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 61,787 $47,664
Adjustments for Noncash Items:
Depreciation and Amortization 43,745 38,366
Deferred Federal Income Taxes 19,438 8,180
Deferred Investment Tax Credits (1,106) (1,166)
Deferred Power Supply Costs (net) 121 (8,157)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 82,071 7,003
Fuel, Materials and Supplies 3,091 9,557
Accrued Utility Revenues 51,292 15,298
Accounts Payable 6,086 (13,123)
Taxes Accrued 5,417 16,443
Interest Accrued 17,618 10,815
Net Change in Energy Trading Contracts (58,864) (9,253)
Other (net) (19,549) (25,046)
------- -------
Net Cash Flows From Operating Activities 211,147 96,581
------- ------
INVESTING ACTIVITIES:
Construction Expenditures (39,922) (39,901)
Proceeds from Sale of Property 1,182 16
----- --
Net Cash Flows Used For Investing Activities (38,740) (39,885)
------- -------
FINANCING ACTIVITIES:
Change in Short-term Debt (net) (191,495) 4,945
Change in Advance from Affiliates (net) 153,572 -
Retirement of Cumulative Preferred Stock - (164)
Retirement of Long-term Debt (100,000) (83,201)
Dividends Paid on Common Stock (32,399) (31,653)
Dividends Paid on Cumulative Preferred Stock (361) (528)
---- ----
Net Cash Flows Used For Financing Activities (170,683) (110,601)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents 1,724 (53,905)
Cash and Cash Equivalents at Beginning of Period 5,847 64,828
----- ------
Cash and Cash Equivalents at End of Period $ 7,571 $ 10,923
============= ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,156,000 and
$19,610,000 and for income taxes was $13,543,000 and $6,693,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $1,512,000
and $3,361,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
D-5
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $27 million, or 330%, primarily from
participation in AEP's power marketing and trading operations subsequent to
the AEP CSW merger and a reduction in depreciation and amortization
expense. CPL shares in the results of power marketing and trading
activities conducted on its behalf by the AEP System. Income statement line
items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $287 91
Fuel Expense 62 70
Purchased Power Expense 194 N.M.
Depreciation and Amortization (12) (22)
Taxes Other Than Federal
Income Taxes 2 11
Federal Income Taxes 14 322
N.M. = Not Meaningful
The significant increase in operating revenues resulted from higher
fuel related revenues due to increased fuel and purchased power expense,
increased energy sales to residential and commercial customers and the post
merger favorable impact of AEP's power marketing and trading operations,
which added new wholesale revenues.
Fuel expense increased due primarily to an increase in the average
unit cost of fuel as a result of higher spot market natural gas prices.
The rise in purchased power expense was primarily attributable to
participation in AEP's trading operation. The decrease in depreciation and
amortization is due primarily to a decrease in depreciation associated with
the cessation in July 2000 of accelerated ECOM depreciation on STP and
reduced accruals for excess earnings.
Taxes other than federal income taxes increased due to a favorable
accrual adjustment in 2000 for ad valorem taxes. The increase in federal
income tax expense attributable to operations in 2001 was primarily due to
an increase in pre-tax operating income.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $603,412 $316,328
-------- --------
OPERATING EXPENSES:
Fuel 151,853 89,397
Purchased Power 214,566 20,420
Other Operation 75,071 75,301
Maintenance 17,287 16,422
Depreciation and Amortization 42,391 54,198
Taxes Other Than Federal Income Taxes 19,488 17,534
Federal Income Taxes 18,604 4,406
------ -----
TOTAL OPERATING EXPENSES 539,260 277,678
------- -------
OPERATING INCOME 64,152 38,650
NONOPERATING INCOME 1,639 547
----- ---
INCOME BEFORE INTEREST CHARGES 65,791 39,197
INTEREST CHARGES 30,760 31,058
------ ------
NET INCOME 35,031 8,139
PREFERRED STOCK DIVIDEND REQUIREMENTS 60 60
-- --
EARNINGS APPLICABLE TO COMMON STOCK $ 34,971 $ 8,079
======== =======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $792,219 $758,894
NET INCOME 35,031 8,139
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 37,014 39,000
Preferred Stock 60 60
Other 1 2
--- ------
BALANCE AT END OF PERIOD $790,175 $727,971
======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,161,904 $3,175,867
Transmission 585,157 581,931
Distribution 1,234,153 1,221,750
General 239,473 237,764
Construction Work in Progress 168,726 138,273
Nuclear Fuel 237,499 236,859
-------- -------
Total Electric Utility Plant 5,626,912 5,592,444
Accumulated Depreciation and Amortization 2,316,202 2,297,189
--------- ---------
NET ELECTRIC UTILITY PLANT 3,310,710 3,295,255
---------- ---------
OTHER PROPERTY AND INVESTMENTS 45,357 44,225
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 19,908 66,231
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 4,849 14,253
Accounts Receivable:
Customers 54,545 66,112
Affiliated Companies 34,636 31,272
Fuel Inventory - at LIFO cost 38,423 22,842
Materials and Supplies - at average cost 52,994 53,108
Under-recovered Fuel Costs 125,223 127,295
Energy Trading Contracts 40,155 481,206
Prepayments and Other Current Assets 2,910 3,014
----- -----
TOTAL CURRENT ASSETS 353,735 799,102
------- -------
REGULATORY ASSETS 197,711 202,440
------- -------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249
-------- -------
NUCLEAR DECOMMISSIONING TRUST FUND 90,563 93,592
------- ------
DEFERRED CHARGES 47,251 18,402
------ ------
TOTAL ASSETS $5,018,484 $5,472,496
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 6,755,535 Shares $ 168,888 $168,888
Paid-in Capital 405,000 405,000
Retained Earnings 790,175 792,219
------- -------
Total Common Shareowner's Equity 1,364,063 1,366,107
Preferred Stock 5,967 5,967
CPL - Obligated, Mandatorily
Redeemable Preferred Securities of
Subsidiary Trust Holding Solely Junior
Subordinated Debentures of CPL 148,000 148,500
Long-term Debt 942,861 1,254,559
------- ---------
TOTAL CAPITALIZATION 2,460,891 2,775,133
--------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 511,700 200,000
Advances from Affiliates 312,868 269,712
Accounts Payable - General 108,821 128,957
Accounts Payable - Affiliated Companies 42,982 40,962
Taxes Accrued 83,097 55,526
Interest Accrued 23,189 26,217
Energy Trading Contracts 39,500 489,888
Other 36,439 40,630
------ ------
TOTAL CURRENT LIABILITIES 1,158,596 1,251,892
--------- ---------
DEFERRED INCOME TAXES 1,243,439 1,242,797
--------- ---------
DEFERRED INVESTMENT TAX CREDITS 126,798 128,100
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 19,493 65,740
------- ------
DEFERRED CREDITS 9,267 8,834
----- -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,018,484 $5,472,496
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $35,031 $ 8,139
Adjustments for Noncash Items:
Depreciation and Amortization 42,391 54,198
Deferred Federal Income Taxes 2,579 (15,670)
Deferred Investment Tax Credits (1,302) (1,302)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 8,203 1,847
Fuel, Materials and Supplies (15,468) 3,448
Fuel Recovery 2,073 (616)
Accounts Payable (18,115) 9,969
Taxes Accrued 27,571 (2,807)
Transmission Coordination Agreement Settlement - 15,519
Deferred Property Taxes (29,292) -
Other (net) (29,779) 22,658
------- ------
Net Cash Flows From Operating Activities 23,892 95,383
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (38,873) (44,406)
Other - (1,721)
------ ------
Net Cash Flows Used For Investing Activities (38,873) (46,127)
------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 149,426
Retirement of Long-term Debt (505) (50,000)
Change in Advances from Affiliates (net) 43,156 (162,266)
Special Deposit for Reacquisitions 50,000
-
Dividends Paid on Common Stock (37,014) (39,000)
Dividends Paid on Cumulative Preferred Stock (60)
---
(60)
Net Cash Flows From (Used For) Financing Activities 5,577 (51,900)
----- -------
Net Decrease in Cash and Cash Equivalents (9,404) (2,644)
Cash and Cash Equivalents at Beginning of Period 14,253 7,995
------ -----
Cash and Cash Equivalents at End of Period $ 4,849 $ 5,351
======== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $24,938,000 and
$15,348,000 and for income taxes was $6,071,000 and $-0- in 2001 and 2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
E-6
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $10.2 million or 37% due to increased trading
volume and improved performance of the wholesale marketing and trading
operations. CSPCo, as a member of the AEP Power Pool, shares in the revenues and
costs of wholesale marketing and trading activities conducted on its behalf by
the AEP Power Pool
Income statement line items which changed significantly were:
Increase
(in millions) %
------------- -
Operating Revenues $492 78
Fuel Expense 6 15
Purchased Power Expense 457 110
Other Operation Expense 9 20
Maintenance Expense 4 28
Depreciation and
Amortization 7 28
Federal Income Taxes 4 23
Nonoperating Income 6 N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to a 47% increase in electric trading volume. In the first quarter of 2001 the AEP Power Pool
was able to expand the number of forward electricity contracts made in
AEP's traditional marketing area (up to two transmission systems from AEP's
service territory) resulting in the increase in trading volume.
Fuel expense increased in the first quarter of 2001 due to the
discontinuance of deferred fuel accounting on January 1, 2001 as a result
of the restructuring of the electric utility industry in Ohio to provide
customers with choice of generation supplier. Under deferred fuel
accounting, changes in fuel costs were deferred until they were reflected
in rates. In the three months ended March 31, 2000, the Company amortized
over collections of fuel costs thereby reducing fuel expense commensurate
with refunds of the over-collection to customers.
The substantial increase in purchased power expense is primarily
attributable to the increase in tradingprices and volume.
Other operation expense increased due to power trading expenses and incentives,increases in uncollectible
accounts, factored customer accounts receivable expenses, and the cessationeffect of amortizing deferred gains in
2000 from salesthe disposition of emission allowances to income as a result of the
discontinuations of SFAS 71.and higher power trading
expenses and trading incentive compensation.
Maintenance expenses increased in the first quarter of 2001 due to planned outages at twoseveral of the
wholesale business' plants for steam boiler overhauloverhauls and inspections.
The commencement of the amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
electricity under the deregulation of our retail supply business accounted for
the increase in depreciation and amortization expense.
An increaseThe extraordinary loss was recorded in pre-tax operating income caused the Federal incomeJune 2001 to recognize stranded
prepaid Ohio excise taxes attributable to operations to increase. The increase in nonoperating
income was due to an increase in net gains from AEP Power Pool trading
transactions outside of the AEP System's traditional marketing area. The
AEP Power Pool enters into power trading transactions for the purchase and
sale of electricity and for options, futures and swaps. The Company's share
of the AEP Power Pool's gains and losses from forward electricity trading
transactions outside of the AEP System traditional marketing area and for
speculative financial transactions (options, futures, swaps) is included in
nonoperating income. The increase reflects growth in and improved
performance of the trading operations.
The decline in interest charges was due to a decrease in the
outstanding balance of long-term debt.(See Note 2).
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,125,573 $633,305$1,109,095 $928,332 $2,234,668 $1,561,637
---------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 47,030 40,74842,368 48,581 89,398 89,329
Purchased Power 871,911 414,702845,860 685,411 1,717,771 1,100,113
Other Operation 54,548 45,28954,510 50,332 109,058 95,621
Maintenance 18,780 14,69619,729 18,228 38,509 32,924
Depreciation and Amortization 31,482 24,54431,379 24,896 62,861 49,440
Taxes Other Than Federal Income Taxes 31,907 31,47732,909 31,084 64,816 62,561
Federal Income Taxes 21,800 17,72519,446 19,002 37,429 36,727
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,077,458 589,1811,046,201 877,534 2,119,842 1,466,715
--------- ------- --------- ---------
OPERATING INCOME 48,115 44,12462,894 50,798 114,826 94,922
NONOPERATING INCOME 7,289 1,684(LOSS) 3,012 2,497 6,484 4,181
----- ----- ----- -----
INCOME BEFORE INTEREST CHARGES 55,404 45,80865,906 53,295 121,310 99,103
INTEREST CHARGES 17,733 18,33718,488 17,960 36,221 36,297
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 47,418 35,335 85,089 62,806
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION (INCLUSIVE OF TAX
BENEFIT OF $8,353,000) (26,407) - (26,407) -
------- ----- ------- -
NET INCOME 37,671 27,47121,011 35,335 58,682 62,806
PREFERRED STOCK DIVIDEND REQUIREMENTS 302 533301 532 603 1,065
--- --- --- -----
EARNINGS APPLICABLE TO COMMON STOCK $ 37,36920,710 $ 26,93834,803 $ 58,079 $ 61,741
============ ======== ============ ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $115,486 $249,872 $ 99,069 $246,584
NET INCOME 37,671 27,47121,011 35,335 58,682 62,806
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 20,738 23,650 41,476 47,300
Cumulative Preferred Stock 262 437263 438 525 875
Capital Stock Expense 254 96253 95 507 191
--- -- --- ---
BALANCE AT END OF PERIOD $115,486 $249,872$115,243 $261,024 $115,243 $261,024
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,571,778$1,569,118 $1,564,254
Transmission 368,817392,383 360,302
Distribution 1,110,0061,124,668 1,096,365
General 150,267148,224 156,534
Construction Work in Progress 93,94179,612 89,339
------ ------
Total Electric Utility Plant 3,294,8093,314,005 3,266,794
Accumulated Depreciation and Amortization 1,325,1561,337,358 1,299,697
--------- ---------
NET ELECTRIC UTILITY PLANT 1,969,6531,976,647 1,967,097
--------- ---------
OTHER PROPERTY AND INVESTMENTS 42,30443,283 39,848
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 312,852333,816 172,167
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 8,29710,030 11,600
Accounts Receivable:
Customers 64,26478,089 73,711
Affiliated Companies 60,79282,426 49,591
Miscellaneous 27,12019,463 18,807
Allowance for Uncollectible Accounts (659) (659)
Fuel - at average cost 16,53220,648 13,126
Materials and Supplies - at average cost 39,03637,333 38,097
Accrued Utility Revenues - 9,638
Energy Trading Contracts 1,021,733966,617 1,085,989
Prepayments and Other Current Assets 57,31127,334 46,735
------ ------
TOTAL CURRENT ASSETS 1,294,4261,241,281 1,346,635
--------- ---------
REGULATORY ASSETS 280,975273,528 291,553
------- -------
DEFERRED CHARGES 58,11736,923 77,634
------ ------
TOTAL ASSETS $3,958,327$3,905,478 $3,894,934
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 573,607 573,354
Retained Earnings 115,486 99,069
------- ------
Total Common Shareowner's Equity 730,119 713,449
Cumulative Preferred Stock - Subject
to Mandatory Redemption 15,000 15,000
Long-term Debt 899,745 899,615
------- -------
TOTAL CAPITALIZATION 1,644,864 1,628,064
--------- ---------
OTHER NONCURRENT LIABILITIES 44,061 47,584
------ ------
CURRENT LIABILITIES:
Advances from Affiliates 102,209 88,732
Accounts Payable - General 88,530 89,846
Accounts Payable - Affiliated Companies 91,414 72,493
Taxes Accrued 124,400 162,904
Interest Accrued 24,491 13,369
Energy Trading Contracts 1,032,236 1,115,967
Other 55,625 60,701
------ ------
TOTAL CURRENT LIABILITIES 1,518,905 1,604,012
--------- ---------
DEFERRED INCOME TAXES 427,368 422,759
------- -------
DEFERRED INVESTMENT TAX CREDITS 40,398 41,234
------ ------
DEFERRED CREDITS 14,170 12,861
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 268,561 138,420
------- -------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $3,958,327
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares $ 41,026 $ 41,026
Paid-in Capital 573,861 573,354
Retained Earnings 115,243 99,069
------- ------
Total Common Shareowner's Equity 730,130 713,449
Cumulative Preferred Stock - Subject to Mandatory Redemption 15,000 15,000
Long-term Debt 899,874 899,615
------- -------
TOTAL CAPITALIZATION 1,645,004 1,628,064
--------- ---------
OTHER NONCURRENT LIABILITIES 40,662 47,584
------ ------
CURRENT LIABILITIES:
Advances from Affiliates 115,302 88,732
Accounts Payable - General 92,461 89,846
Accounts Payable - Affiliated Companies 98,033 72,493
Taxes Accrued 117,277 162,904
Interest Accrued 15,808 13,369
Energy Trading Contracts 944,778 1,115,967
Other 49,943 60,701
------ ------
TOTAL CURRENT LIABILITIES 1,433,602 1,604,012
--------- ---------
DEFERRED INCOME TAXES 431,000 422,759
------- -------
DEFERRED INVESTMENT TAX CREDITS 39,563 41,234
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 15,108 12,861
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 300,539 138,420
------- -------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $3,905,478 $3,894,934
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,
(in thousands)June 30,
2001 2000
---- ----
OPERATING ACTIVITIES:(in thousands)
OPERATING ACTIVITIES:
Net Income $ 37,671 $27,47158,682 $62,806
Adjustments for Noncash Items:
Depreciation and Amortization 25,835 24,66952,392 49,709
Amortization of Regulatory Assets 5,80311,294 -
Deferred Federal Income Taxes 6,957 5,07218,384 6,783
Deferred Investment Tax Credits (836) (847)(1,671) (1,694)
Deferred Fuel Cost (net) - (5,408)(1,835)
Amortization of Deferred Property Taxes 35,416 33,721
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (10,067) 24,057(37,869) 83,720
Fuel, Materials and Supplies (4,345) 89(6,758) 1,447
Accrued Utility Revenues 9,638 7,39046,416
Prepayments and Other Current Assets 19,401 (11,899)
Accounts Payable 17,605 (10,440)28,155 12,174
Taxes Accrued (38,504) (29,554)
Interest Accrued 11,122 8,700(45,627) (53,895)
Energy Trading Contracts (net) (51,347) (5,321)
Other (net) (23,652) 9,925
-------(9,981) 3,047
------ -----
Net Cash Flows From Operating Activities 37,227 61,12480,109 225,179
------ -------------
INVESTING ACTIVITIES:
Construction Expenditures (33,007) (27,022)(67,532) (59,372)
Proceeds from Sale of Property - 3301,284 463
----- ---
Net Cash Flows Used For Investing Activities (33,007) (26,692)(66,248) (58,909)
------- -------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 13,477 -26,570 (61,504)
Change in Short-term Debt (net) - (6,025)(45,500)
Retirement of Long-term Debt - (1,976)(6,879)
Dividends Paid on Common Stock (20,738) (23,650)(41,476) (47,300)
Dividends Paid on Cumulative Preferred Stock (262) (437)(525) (875)
---- ----
Net Cash Flows Used For Financing Activities (7,523) (32,088)
------(15,431) (162,058)
------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (3,303) 2,344(1,570) 4,212
Cash and Cash Equivalents at Beginning of Period 11,600 5,107
------ -----
Cash and Cash Equivalents at End of Period $ 8,29710,030 $ 7,451
=========== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $6,127,000 and $8,684,000
and for income taxes was $17,485,000 and $6,607,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $84,000 and
$1,377,0009,319
========== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $32,812,000 and
$34,547,000 and for income taxes was $17,579,000 and $35,539,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $734,000 and
$3,233,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
F-6
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRSTSECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of the
generation, marketing and trading of electricity; and energy delivery
which consists of transmission and distribution services. We belong to
the AEP Power Pool and share in the revenues and costs of wholesale
marketing and trading activities conducted on our behalf by the AEP
Power Pool.
Net income increased $69$67 million in the quarter and $135 million
in the year-to-date period primarily due to the return to service of
both of I&M's Cook Plant nuclear units which were on an extended
outage throughout 1999 and for a significant portion of 2000 because of
questions regarding the operability of certain safety systems.in 2000. Unit 2 and Unit 1
returned to service in June and December 2000, respectively.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
econd Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $583 82$248 25 $832 48
Fuel Expense 16 3417 38 33 36
Purchased Power Expense 522 116191 26 713 60
Other Operation Expense (36)(41) (27) (77) (27)
Maintenance Expense (27) (49)(24) (44) (52) (46)
Federal Income Taxes 3534 N.M. 69 N.M.
N.M. = Not Meaningful
The significant increase in operating revenues resulted from
increased wholesale sales as sales to the AEP Power Pool increased by a multiple of
13prices and volumes. I&M's share of the AEP System's
sales to and forward trades with other utility systems and power
marketers byand sales to the AEP Power Pool increased 53%. As a
member of the AEP Power Pool, I&M sharesrose in 2001. In 2001 both
price and volume in the revenues and costs of the
AEP Power Pool's wholesale sales and forward trades. In the first quarter
of 2001 the AEP Power Pool grew its trading operations resulting in an
increase in theoperation increased. The number of
forward electricity contracts made in AEP's traditional marketing area
(up to two transmission systems from AEP's service territory) resultinggrew due
to the expansion of our trading operation and increased liquidity in
the increasemarkets. Wholesale prices increased reflecting market conditions
during a period of high volatility in trading volume. AEP Power
Pool members are also compensated for the out-of-pocket costs of energy
delivered to the AEP Power Pool and charged for energy received from the
AEP Power Pool.prices. With the return to
service of the nuclear units in 2000, I&M's available generation
increased resulting in additional power being delivered to the AEP
Power Pool in 2001.
Fuel expense increased primarily due to increased generation
reflecting the return to service of the nuclear units following the
extended outage.
The increase in purchased power expense resulted mainly from
the
increaseincreases in wholesale prices and sales and trading volume.
Other operation and maintenance expenses decreased primarily
due to the cessation of expenses related to work to restart the Cook
Plant units.
The significant increase in federal income tax expense
attributable to operations was primarily due to a major increaseincreases in
pre-tax operating income.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,291,538 $708,150$1,259,874 $1,011,706 $2,551,412 $1,719,856
---------- ------------------ ---------- ----------
OPERATING EXPENSES:
Fuel 63,973 47,86060,491 43,844 124,464 91,704
Purchased Power 971,587 449,270936,454 745,656 1,908,041 1,194,926
Other Operation 97,363 133,551110,197 151,328 207,560 284,879
Maintenance 28,175 55,38431,506 55,841 59,681 111,225
Depreciation and Amortization 40,723 38,21140,840 38,499 81,563 76,710
Taxes Other Than Federal Income Taxes 20,332 17,20920,316 16,787 40,648 33,996
Federal Income Tax Expense (Credit) 16,687 (18,084)12,730 (21,650) 29,417 (39,734)
------ ------- ------ -------
TOTAL OPERATING EXPENSES 1,238,840 723,4011,212,534 1,030,305 2,451,374 1,753,706
--------- ---------------- --------- ---------
OPERATING INCOME (LOSS) 52,698 (15,251)47,340 (18,599) 100,038 (33,850)
NONOPERATING INCOME 4,445 5654,411 2,637 8,856 3,202
----- -------- ----- -----
INCOME (LOSS) BEFORE INTEREST CHARGES 57,143 (14,686)51,751 (15,962) 108,894 (30,648)
INTEREST CHARGES 24,780 21,86724,377 23,219 49,157 45,086
------ ------ ------ ------
NET INCOME (LOSS) 32,363 (36,553)27,374 (39,181) 59,737 (75,734)
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,155 1,1601,156 1,153 2,311 2,313
----- ----- ----- -----
EARNINGS (LOSS) APPLICABLE TO COMMON
STOCK $ 31,20826,218 $ (37,713)(40,334) $ 57,426 $ (78,047)
============ ============ ============ =========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME (LOSS) $32,363 $(36,553)$27,374 $(39,181) $59,737 $(75,734)
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (1,919)(903) - (2,822) -
---- ------ ------ ------
COMPREHENSIVE INCOME (LOSS) $30,444 $(36,553)$26,471 $(39,181) $56,915 $(75,734)
======= ======== ======= ========
The common stock of I&M is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $ 3,443 $166,389
NET INCOME (LOSS) 32,363 (36,553)
DEDUCTIONS:
Cash Dividends Declared:
Common Stock - 26,290
Cumulative Preferred Stock 1,122 1,125
Capital Stock Expense 33 57
-- --
BALANCE AT END OF PERIOD $34,651 $102,364 $ 3,443 $166,389
NET INCOME (LOSS) 27,374 (39,181) 59,737 (75,734)
DEDUCTIONS:
Cash Dividends Declared:
Common Stock - - - 26,290
Cumulative Preferred Stock 1,122 2,243 2,244 3,368
Capital Stock Expense 34 10 67 67
-- -- -- --
BALANCE AT END OF PERIOD $60,869 $ 60,930 $60,869 $ 60,930
======= ======== ======= ========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,733,347$2,738,228 $2,708,436
Transmission 947,946950,648 945,709
Distribution 873,271878,487 863,736
General (including nuclear fuel) 246,591231,786 257,152
Construction Work in Progress 97,95998,130 96,440
------ ------
Total Electric Utility Plant 4,899,1144,897,279 4,871,473
Accumulated Depreciation and Amortization 2,341,9472,379,292 2,280,521
--------- ---------
NET ELECTRIC UTILITY PLANT 2,557,1672,517,987 2,590,952
--------- ---------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRAUSTTRUST FUNDS
792,140801,760 778,720
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 354,629380,005 194,947
------- -------
OTHER PROPERTY AND INVESTMENTS 129,246133,032 131,417
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 13,92212,069 14,835
Accounts Receivable:
Customers 73,87689,393 106,832
Affiliated Companies 43,80747,644 48,706
Miscellaneous 21,51835,595 27,491
Allowance for Uncollectible Accounts (734) (759)
Fuel - at average cost 19,41726,906 16,532
Materials and Supplies - at average cost 87,68487,955 84,471
Energy Trading Contracts 1,203,262 1,229,6831,130,779 1,230,041
Prepayments 11,974 6,424
------3,888 6,066
----- -----
TOTAL CURRENT ASSETS 1,474,7261,433,495 1,534,215
--------- ---------
REGULATORY ASSETS 528,340500,879 552,140
------- -------
DEFERRED CHARGES 40,03230,071 36,156
------ ------
TOTAL ASSETS $5,876,280$5,797,229 $5,818,547
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
arch 31,June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares $ 56,584 $ 56,584
Paid-in Capital 733,106733,139 733,072
Accumulated Other Comprehensive Income (Loss) (1,919)(2,822) -
Retained Earnings 34,65160,869 3,443
------ -----
Total Common Shareowner's Equity 822,422847,770 793,099
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,302,3081,349,874 1,298,939
--------- ---------
TOTAL CAPITALIZATION 2,198,4112,271,325 2,165,719
--------- ---------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 568,432576,267 560,628
Other 104,977101,000 108,600
------- -------
TOTAL OTHER NONCURRENT LIABILITIES 673,409677,267 669,228
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 90,000- 90,000
Advances from Affiliates 258,460302,030 253,582
Accounts Payable:
General 94,00699,800 119,472
Affiliated Companies 79,31453,775 75,486
Taxes Accrued 96,58299,671 68,416
Interest Accrued 23,99322,919 21,639
Obligations Under Capital Leases 10,3419,141 100,848
Energy Trading Contracts 1,195,1721,092,357 1,275,097
Other 90,47777,955 97,070
------ ------
TOTAL CURRENT LIABILITIES 1,938,3451,757,648 2,101,610
--------- ---------
DEFERRED INCOME TAXES 479,679472,626 487,945
------- -------
DEFERRED INVESTMENT TAX CREDITS 111,905110,037 113,773
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 80,37279,445 81,299
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 304,482345,216 156,736
------- -------
DEFERRED CREDITS 89,67783,665 42,237
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,876,280$5,797,229 $5,818,547
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
OPERATING ACTIVITIES:
Net Income (Loss) $32,363$59,737 $ (36,553)(75,734)
Adjustments for Noncash Items:
Depreciation and Amortization 41,589 39,19183,090 81,423
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) 316 2,035(771) 3,722
Unrecovered Fuel and Purchased Power Costs (net) 9,375 9,37518,751 18,751
Amortization of Nuclear Outage Costs 10,000 10,00020,000 20,000
Deferred Federal Income Taxes (2,462) (7,801)(4,256) (12,038)
Deferred Investment Tax Credits (1,868) (1,887)
Deferred Property Taxes (9,731) (10,241)(3,736) (3,773)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 43,803 12,71010,372 61,510
Fuel, Materials and Supplies (6,098) 4,609(13,858) (1,464)
Accrued Utility Revenues - 2,43644,428
Accounts Payable (21,638) (18,932)(41,383) (14,093)
Taxes Accrued 28,166 3,794
Rent Accrued - Rockport Plant Unit 2 18,464 18,46431,255 (28,268)
Net Change in Energy Trading Contracts (80,056) (8,935)
Regulatory Liability - Current (net) (53,504) (12,638)Trading Gains 38,159 3,284
Other (net) 17,413 (8,688)12,261 (23,988)
------ -------------
Net Cash Flows From Operating Activities 106,188 5,874129,565 64,825
------- -----------
INVESTING ACTIVITIES:
Construction Expenditures (18,241) (51,435)(41,321) (93,002)
Buyout of Nuclear Fuel Leases (92,616) -
Other - 250
------324 587
--- ---
Net Cash Flows Used For Investing Activities (110,857) (51,185)(133,613) (92,415)
-------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (44,922) (48,000)
Retirement of Cumulative Preferred Stock (314)
-
Change in Short-term Debt (net) (224,262)
-
Change in Advances from Affiliates (net) 4,878 -
Change in Short-term Debt (net) - 124,131
Retirement of Long-term Debt - (48,000)
Retirement of Cumulative Preferred Stock - (149)48,448 331,852
Dividends Paid on Common Stock (26,290)
- (26,290)
Dividends Paid on Cumulative Preferred Stock (1,122) -(2,244) (2,249)
------ ------
Net Cash Flows From Financing Activities 3,756 49,6921,282 30,737
----- ------
Net Increase (Decrease) in Cash and Cash Equivalents (913) 4,381(2,766) 3,147
Cash and Cash Equivalents at Beginning of Period 14,835 3,863
------ -----
Cash and Cash Equivalents at End of Period $ 13,92212,069 $ 8,2447,010
======== =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $21,610,000$46,243,000 and
$17,965,000$39,686,000 and for income taxes was $7,471,000$11,073,000 and $(8,966,000)$(2,365,000) in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $991,000$1,020,000
and $1,184,000$15,423,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
G-6
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRSTSECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of the generation,
marketing and trading of electricity; and energy delivery which consists of
transmission and distribution service. We belong to the AEP Power Pool and share
in the revenues and costs of wholesale marketing and trading activities
conducted on our behalf by the AEP Power Pool.
Although revenues rose 98% forsignificantly, net income increased slightly in
the quarter net incomeand declined by less than $1.0 million or 12%, as increases in operating expenses more than offset7% for the revenue
increase.year-to-date
period. Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $228 98
Fuel Expense 1 7$96 28 $324 56
Purchased Power Expense 226 13598 35 324 72
Other Operation Expense 4 422 20 7 29
Maintenance Expense (1) (15)(3) (39) (4) (28)
Federal Income Taxes - N.M. (2) (31)
Nonoperating Income 1 85 2 335
Interest Charges (1) (11) (1) (8)
N.M. = Not Meaningful
The significant increase in operating revenues resulted from increased
wholesale prices and volumes. Our wholesale sales to and forward trades with
other utility systems and power marketers rose by 15% in the quarter and 37% for
the year-to-date period. The number of forward electricity contracts in AEP's
traditional marketing area (up to two transmission systems from AEP's service
territory) grew due to the expansion of our trading operation and increased
liquidity in the markets. Wholesale prices increased reflecting market
conditions during a period of high volatility in prices.
Purchased power expense for the wholesale business increased due to
higher wholesale prices and increased sales and trading volume.
Other operation expense increased due to an increase in trading
incentive compensation for the wholesale business, a decline in AEP transmission
equalization credits for the energy delivery business and the cost of accounts
receivable factoring for both businesses. 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.
The effect of the costs of outages at our wholesale business' Big Sandy
Plant in 2000 caused maintenance expense to decrease.
Federal income taxes attributable to operations decreased due to a
decline in pre-tax income.
The increase in nonoperating income was due to an increase in net gains
from non-regulated trading transactions outside of the AEP System's traditional
marketing area and speculative financial transactions (options, futures, swaps)
for the wholesale business.
Interest charges declined due to lower outstanding debt balances and
lower interest rates in 2001.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES: $439,131 $342,660 $898,288 $574,114
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 17,418 17,871 35,374 34,673
Purchased Power 381,913 283,653 775,778 451,385
Other Operation 14,470 12,103 29,198 22,487
Maintenance 5,185 8,438 10,614 14,805
Depreciation and Amortization 8,080 7,676 16,107 15,279
Taxes Other Than Federal Income Taxes 3,102 2,659 6,836 5,493
Federal Income Taxes 599 804 3,413 4,979
--- --- ----- -----
TOTAL OPERATING EXPENSES 430,767 333,204 877,320 549,101
------- ------- ------- -------
OPERATING INCOME 8,364 9,456 20,968 25,013
NONOPERATING INCOME 1,243 671 2,718 625
----- --- ----- ---
OME BEFORE INTEREST CHARGES 9,607 10,127 23,686 25,638
INTEREST CHARGES 6,865 7,678 13,869 15,137
----- ----- ------ ------
NET INCOME $ 2,742 $ 2,449 $ 9,817 $10,501
========== ======= ======= =======
STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $2,742 $2,449 $ 9,817 $10,501
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (68) - (1,422) -
--- ------- ------ --
COMPREHENSIVE INCOME $2,674 $2,449 $ 8,395 $10,501
====== ====== ======= =======
The common stock of KPCo is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $57,027 $67,572 $57,513 $67,110
NET INCOME 2,742 2,449 9,817 10,501
CASH DIVIDENDS DECLARED:
Common Stock 7,561 7,590 15,122 15,180
----- ----- ------ ------
BALANCE AT END OF PERIOD $52,208 $62,431 $52,208 $62,431
======= ======= ======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 270,699 $ 271,107
Transmission 368,978 360,563
Distribution 395,660 387,499
General 66,695 67,476
Construction Work in Progress 11,018 16,419
------ ------
Total Electric Utility Plant 1,113,050 1,103,064
Accumulated Depreciation and Amortization 372,856 360,648
------- -------
NET ELECTRIC UTILITY PLANT 740,194 742,416
------- -------
OTHER PROPERTY AND INVESTMENTS 6,139 6,559
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 150,630 76,657
------- ------
CURRENT ASSETS:
Cash and Cash Equivalents 2,513 2,270
Accounts Receivable:
Customers 29,029 34,555
Affiliated Companies 20,891 22,119
Miscellaneous 9,157 6,419
Allowance for Uncollectible Accounts (278) (282)
Fuel - at average cost 4,690 4,760
Materials and Supplies - at average cost 16,150 15,408
Accrued Utility Revenues - 6,500
Energy Trading Contracts 434,802 483,537
Prepayments 951 766
--- ---
TOTAL CURRENT ASSETS 517,905 576,052
------- -------
REGULATORY ASSETS 98,800 98,515
------ ------
DEFERRED CHARGES 7,334 11,817
----- ------
TOTAL ASSETS $1,521,002 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $50,450
Paid-in Capital 158,750 158,750
Accumulated Other Comprehensive Income (Loss) (1,422) -
Retained Earnings 52,208 57,513
------ ------
Total Common Shareowner's Equity 259,986 266,713
Long-term Debt 270,996 270,880
Long-term Debt - Affiliated Company 75,000 -
------ -
TOTAL CAPITALIZATION 605,982 537,593
------- -------
OTHER NONCURRENT LIABILITIES 15,347 18,348
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 60,000
Advances from Affiliates 47,231 47,636
Accounts Payable:
General 37,529 32,043
Affiliated Companies 35,265 37,506
Customer Deposits 4,676 4,389
Taxes Accrued 5,279 11,885
Interest Accrued 5,740 5,610
Energy Trading Contracts 428,052 496,884
Other 10,269 14,517
------ ------
TOTAL CURRENT LIABILITIES 574,041 710,470
------- -------
DEFERRED INCOME TAXES 173,197 165,935
------- -------
DEFERRED INVESTMENT TAX CREDITS 11,063 11,656
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 135,967 61,632
------- ------
DEFERRED CREDITS 5,405 6,382
----- -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,521,002 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $9,817 $ 10,501
Adjustments for Noncash Items:
Depreciation and Amortization 16,107 15,279
Deferred Federal Income Taxes 7,921 2,563
Deferred Investment Tax Credits (593) (596)
Deferred Fuel Costs (net) (1,241) 910
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 4,012 14,948
Fuel, Materials and Supplies (672) 342
Accrued Utility Revenues 6,500 13,737
Accounts Payable 3,245 776
Taxes Accrued (6,606) (4,004)
Net Change in Energy Trading Contracts (19,735) (3,955)
Other (3,289) (84)
------ ---
Net Cash Flows From Operating Activities 15,466 50,417
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (14,912) (14,188)
Proceeds from Sales of Property 216 -
--- ------
Net Cash Flow Used for Investing Activities (14,696) (14,188)
------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - Affiliated Company 75,000 -
Retirement of Long-term Debt (60,000) (25,000)
Change in Short-term Debt (net) - (39,665)
Change in Advances from Affiliates (net) (405) 43,634
Dividends Paid (15,122) (15,180)
------- -------
Net Cash Flows Used For Financing Activities (527) (36,211)
---- -------
Net Increase in Cash and Cash Equivalents 18
243
Cash and Cash Equivalents at Beginning of Period 2,270 674
----- ---
Cash and Cash Equivalents at End of Period $2,513 $ 692
====== =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,692,000 and
$15,046,000 and for income taxes was $6,010,000 and $5,921,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $760,000 and
$1,836,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2001 vs. SECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of the generation,
marketing and trading of electricity; and energy delivery which consists of
transmission and distribution services. We belong to the AEP Power Pool and
share in the revenues and costs of wholesale marketing and trading activities
conducted on our behalf by the AEP Power Pool.
Net income decreased $48 million or 82% for the second quarter of 2001
and $40 million or 39% for the year-to-date period due to an extraordinary loss
recorded in the second quarter to recognize a stranded asset resulting from
deregulation. Income before extraordinary item decreased by $26 million or 45%
in the second quarter of 2001 and $19 million or 18% in the year-to-date period
because of implementation of customer choice. In connection with the start of
customer choice on January 1, 2001, the generation portion of residential rates
was reduced by 5% and the amortization of transition regulatory assets began.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $191 13 $843 34
Purchased Power Expense 204 22 845 57
Other Operation 10 12 14 8
Maintenance Expense 3 8 10 17
Depreciation and Amortization 19 48 40 52
Taxes Other Than Federal Income taxes 5 13 2 3
Federal Income Taxes (20) (55) (24) (34)
Nonoperating Income 7 N.M. 15 N.M.
Extraordinary Item 22 N.M. 22 N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to a 64% increaseincreases in electric
trading volume. Inwholesale prices and volume of our wholesale business. Expansion of the
first quarter of 2001wholesale business' trading operation and greater liquidity in the AEP Power Pool
grew its electric trading business resultingmarketplace
resulted in a significantan increase in the number of forward electricity purchase and sales
contracts made in AEP's traditional marketing area (up to two transmission
systems from AEP's service territory). Wholesale trading volume increased 19%
for the year-to-date period. The Company, asincrease in wholesale prices reflects market
conditions during a memberperiod of the AEP Power Pool, shares with
other Pool membershigh volatility in the revenues and costs of the AEP Power Pool's
wholesale sales to and forward trades with other utility systems and power
marketers.
Fuel expense increased in the quarter due to increased generation from
the Company's generating facilities as planned outages were reduced in 2001
compared with 2000. The Big Sandy Plant Unit 2 began a planned outage on
March 11, 2000 for boiler inspections and repairs and returned to service
late in April in 2000.prices.
The increase in purchased power expense was primarily attributable to the increase
in the wholesale business' electric trading volume.volume and prices.
Other operation expense increased due to an increaseincreases in trading
overhead expenseuncollectible
accounts and factored customer accounts receivable expenses of both the
cost of factoring of accounts receivable.
The effect of the costs of the outages at Big Sandy Plant in 2000
caused maintenance expense to decrease in the quarter. The increase in
nonoperating income was due to an increase in net gains from non-regulated
AEP Power Pool trading transactions outside of the AEP System's traditional
marketing areawholesale business and speculative financial transactions (options, futures,
swaps). The AEP Power Pool enters into power trading transactions including
the forward purchase and sale of electricity and electricity options,
futures and swaps. The Company's share of the AEP Power Pool's gains and
losses from forward electricity trading transactions outside of the AEP
System traditional marketing area and for speculative financial
transactions (options, futures, swaps) is included in nonoperating income.
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
(in thousands)
OPERATING REVENUES: $459,157 $231,454
-------- --------
OPERATING EXPENSES:
Fuel 17,956 16,802
Purchased Power 393,865 167,732
Other Operation 14,728 10,384
Maintenance 5,429 6,367
Depreciation and Amortization 8,027 7,603
Taxes Other Than Federal Income Taxes 3,734 2,834
Federal Income Taxes 4,149 4,175
----- -----
TOTAL OPERATING EXPENSES 447,888 215,897
------- -------
OPERATING INCOME 11,269 15,557
NONOPERATING INCOME (LOSS) net 2,810 (46)
----- ----
INCOME BEFORE INTEREST CHARGES 14,079 15,511
INTEREST CHARGES 7,004 7,459
----- -----
NET INCOME $ 7,075 $ 8,052
========== =======
STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
NET INCOME $ 7,075 $8,052
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (1,354) -
------ --
COMPREHENSIVE INCOME $ 5,721 $8,052
======= ======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
(in thousands)
BALANCE AT BEGINNING OF PERIOD $57,513 $67,110
NET INCOME 7,075 8,052
CASH DIVIDENDS DECLARED:
Common Stock 7,561 7,590
----- -----
BALANCE AT END OF PERIOD $57,027 $67,572
======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- ----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 270,651 $ 271,107
Transmission 364,356 360,563
Distribution 391,261 387,499
General 67,857 67,476
Construction Work in Progress 12,481 16,419
------ ------
Total Electric Utility Plant 1,106,606 1,103,064
Accumulated Depreciation and Amortization 365,951 360,648
------- -------
NET ELECTRIC UTILITY PLANT 740,655 742,416
------- -------
OTHER PROPERTY AND INVESTMENTS 6,300 6,559
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 141,170 76,657
------- ------
CURRENT ASSETS:
Cash and Cash Equivalents 1,291 2,270
Accounts Receivable:
Customers 27,918 34,555
Affiliated Companies 20,181 22,119
Miscellaneous 4,763 6,419
Allowance for Uncollectible Accounts (278) (282)
Fuel - at average cost 4,425 4,760
Materials and Supplies - at average cost 16,093 15,408
Accrued Utility Revenues 3,257 6,500
Energy Trading Contracts 465,526 483,537
Prepayments 901 766
--- ---
TOTAL CURRENT ASSETS 544,077 576,052
------- -------
REGULATORY ASSETS 99,474 98,515
------ ------
DEFERRED CHARGES 9,835 11,817
----- ------
TOTAL ASSETS $1,541,511 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- ----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares $ 50,450 $50,450
Paid-in Capital 158,750 158,750
Accumulated Other Comprehensive Income (Loss) (1,354) -
Retained Earnings 57,027 57,513
------ ------
Total Common Shareowner's Equity 264,873 266,713
Long-term Debt 270,941 270,880
------- -------
TOTAL CAPITALIZATION 535,814 537,593
------- -------
OTHER NONCURRENT LIABILITIES 17,065 18,348
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 60,000 60,000
Advances from Affiliates 39,603 47,636
Accounts Payable:
General 34,389 32,043
Affiliated Companies 38,338 37,506
Customer Deposits 4,153 4,389
Taxes Accrued 8,194 11,885
Interest Accrued 7,976 5,610
Energy Trading Contracts 466,993 496,884
Other 10,415 14,517
------ ------
TOTAL CURRENT LIABILITIES 670,061 710,470
------- -------
DEFERRED INCOME TAXES 169,453 165,935
------- -------
DEFERRED INVESTMENT TAX CREDITS 11,360 11,656
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 122,250 61,632
------- ------
DEFERRED CREDITS 15,508 6,382
------ -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,541,511 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
(in thousands)
OPERATING ACTIVITIES:
Net Income $7,075 $8,052
Adjustments for Noncash Items:
Depreciation and Amortization 8,029 7,605
Deferred Federal Income Taxes 4,194 1,961
Deferred Investment Tax Credits (297) (298)
Deferred Fuel Costs (net) (1,271) (1,580)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 10,227 (105)
Fuel, Materials and Supplies (350) (797)
Accrued Utility Revenues 3,243 3,274
Accounts Payable 3,177 (2,334)
Taxes Accrued (3,691) 713
Interest Accrued 2,366 2,356
Change in Energy Trading Contracts (net) (15,775) 5,041
Other 3,218 (5,950)
----- ------
Net Cash Flows From Operating Activities 20,145 17,938
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (5,746) (7,573)
Proceeds from Sales of Property 216 -
--- ------
Net Cash Flow Used for Investing Activities (5,530) (7,573)
------ ------
FINANCING ACTIVITIES:
Change in Short-term Debt (net) - (2,065)
Change in Advances from Affiliates (net) (8,033) -
Dividends Paid (7,561) (7,590)
------ ------
Net Cash Flows Used For Financing Activities (15,594) (9,655)
------- ------
Net Increase (Decrease) in Cash and Cash Equivalents (979) 710
Cash and Cash Equivalents at Beginning of Period 2,270 674
----- ---
Cash and Cash Equivalents at End of Period $1,291 $ 1,384
====== =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $4,529,000 and $5,029,000
and for income taxes was $4,354,000 and $2,001,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $661,000 and
$374,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
H-7
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2001 vs. FIRST QUARTER 2000
Net income increased $7.2 million or 16% in the first quarter of 2001
mainly due to strong performance by the trading operation offset in part by
the commencement of accelerated amortization of transition regulatory
assets. OPCo, as a member of the AEP Power Pool, shares in the revenues and
costs of wholesale marketing and trading activities conducted on its behalf
by the AEP Power Pool.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
(in millions) %
------------- -
Operating Revenues $652 62
Fuel Expense (15) (7)
Purchased Power Expense 641 119
Maintenance Expense 7 26
Depreciation and
Amortization 22 56
Taxes Other Than Federal
Income taxes (3) (7)
Federal Income Taxes 3 7
Nonoperating Income 15 N.M.
N.M. = Not Meaningful
The significant increase in revenues is due to a 41% increase in
electric trading volume. In the first quarter of 2001 the AEP Power Pool
grew its trading operations resulting in the expension of the number of
forward electricity contracts made in AEP's traditional marketing area (up
to two transmission systems from AEP's service territory).
Fuel expense decreased in the first quarter of 2001 due mainly to a
drop in the cost per ton of fuel and decreased shutdown costs for
affiliated mining operations. The Company discontinued the practice of
deferred fuel accounting due to the deregulation of the electric utility
industry on January 1, 2001 as a result of the restructuring the electric
utility industry in Ohio to provide customers with a choice of generation
supplier. Under deferred fuel accounting, changes in fuel costs were
deferred until they were reflected in rates. As a result of the cessation
of deferred fuel cost accounting commensurate with the termination of the
Ohio fuel clause, the Company is subject toenergy delivery business, the effect of changesgains in 2000
from the pricedisposition of fuel it uses to generate electricity.
The increase in purchased power expense was primarily attributable toemission allowances, and trading incentive compensation
of the increase in trading volume.wholesale business.
Maintenance expenses increased due to steamplanned outages at several of the
wholesale business' plants for boiler inspectionsoverhauls and overhauls at various plants.inspections.
The commencement of
accelerated amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
electricity under Ohio deregulation accounted for the increase in depreciation
and amortization expense.
A decline in the gross receipts tax caused taxes other than federal
income taxes to decrease. The gross receipts tax decreased due to an
increase from $1 per ton to $3 per ton in a state tax credit for the use of
Ohio coal. The increase in Federal income taxes attributable to operations was primarilydecreased due to changes in certain book/tax timing differences
accounted for on a flow-through basis offset in part by a
decrease in pre-tax operating book income. The increase in nonoperating
income was due to an increase in net gains from AEP Power Poolthe wholesale business'
trading
transactions outside of the AEP System's traditional marketing area and
speculative financial transactions (options, futures and swaps).
The AEP Power Pool enters into power trading transactions
including the forward purchase and sale of electricity and electricity
options, futures and swaps. The Company's share of the AEP Power Pool's
gains and losses from forward electricity trading transactions outside of
the AEP System's traditional marketing area and for speculative financial
transactions (options, futures, swaps) is includedAn extraordinary loss was recorded in nonoperating income.June 2001 to recognize stranded
prepaid Ohio excise taxes (See Note 2).
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,699,665 $1,047,837$1,627,177 $1,436,330 $3,326,842 $2,484,167
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 200,561 215,248180,057 177,314 380,618 392,562
Purchased Power 1,178,906 537,7281,146,655 943,060 2,325,561 1,480,788
Other Operation 88,406 84,45296,623 86,244 185,029 170,696
Maintenance 35,400 28,03036,448 33,595 71,848 61,625
Depreciation and Amortization 60,059 38,48957,666 38,843 117,725 77,332
Taxes Other Than Federal Income Taxes 40,861 43,73246,193 41,055 87,054 84,787
Federal Income Taxes 37,608 35,04516,468 36,251 47,184 71,296
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,641,801 982,7241,580,110 1,356,362 3,215,019 2,339,086
--------- ---------------- --------- ---------
OPERATING INCOME 57,864 65,11347,067 79,968 111,823 145,081
NONOPERATING INCOME 18,000 2,9007,809 1,250 18,917 4,150
----- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 75,864 68,01354,876 81,218 130,740 149,231
INTEREST CHARGES 22,467 21,79722,782 22,985 45,249 44,782
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 32,094 58,233 85,491 104,449
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION (INCLUSIVE OF TAX BENEFIT
OF $11,585,000) (21,515) - (21,515) -
------- ----- ------- -
NET INCOME 53,397 46,21610,579 58,233 63,976 104,449
PREFERRED STOCK DIVIDEND REQUIREMENTS 314 321316 315 630 636
--- --- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 53,08310,263 $ 45,89557,918 $ 63,346 $103,813
=========== ======== ============ ========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $53,397 $46,216$10,579 $58,233 $63,976 $104,449
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (220)(104) - ---(325) -
---- ------ ---- ------
COMPREHENSIVE INCOME $53,177 $46,216$10,475 $58,233 $63,651 $104,449
======= ======= ======= ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $398,086 $587,424
NET INCOME 53,397 46,216
CASH DIVIDENDS DECLARED:
Common Stock 35,744 37,703
Cumulative Preferred Stock 314 317
--- ---
BALANCE AT END OF PERIOD $415,425 $595,620 $398,086 $587,424
NET INCOME 10,579 58,233 63,976 104,449
CASH DIVIDENDS DECLARED:
Common Stock 35,744 37,703 71,488 75,406
Cumulative Preferred Stock 315 316 629 633
--- --- --- ---
BALANCE AT END OF PERIOD $389,945 $615,834 $389,945 $615,834
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
arch 31,June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,774,742$2,955,482 $2,764,155
Transmission 875,190884,720 870,033
Distribution 1,053,0301,059,174 1,040,940
General (including mining assets) 604,638523,987 707,417
Construction Work in Progress 212,40183,461 195,086
------------- -------
Total Electric Utility Plant 5,520,0015,506,824 5,577,631
Accumulated Depreciation and Amortization 2,708,3322,670,874 2,764,130
--------- ---------
NET ELECTRIC UTILITY PLANT 2,811,6692,835,950 2,813,501
--------- ---------
OTHER PROPERTY AND INVESTMENTS 106,925114,811 109,124
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 449,630479,759 256,455
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 21,37828,943 31,393
Advances to Affiliates 16,536- 92,486
Accounts Receivable:
Customers 128,106174,891 139,732
Affiliated Companies 135,780141,778 126,203
Miscellaneous 39,79226,188 39,046
Allowance for Uncollectible Accounts (1,025)(1,026) (1,054)
Fuel - at average cost 88,505100,400 82,291
Materials and Supplies - at average cost 106,97075,692 96,053
Energy Trading Contracts 1,471,3351,389,132 1,617,660
Prepayments and Other 55,41917,766 33,146
------ ------
TOTAL CURRENT ASSETS 2,062,7961,953,764 2,256,956
--------- ---------
REGULATORY ASSETS 703,119674,099 714,710
------- -------
DEFERRED CHARGES 79,10559,384 101,690
------ -------
TOTAL ASSETS $6,213,244$6,117,767 $6,252,436
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares $ 321,201 $321,201
Paid-in Capital 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (220)(325) -
Retained Earnings 415,425389,945 398,086
------- -------
Total Common Shareholder's Equity 1,198,8891,173,304 1,181,770
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 16,648 16,648
Subject to Mandatory Redemption 8,850 8,850
Long-term Debt 1,078,1711,078,354 1,077,987
--------- ---------
TOTAL CAPITALIZATION 2,302,5582,277,156 2,285,255
--------- ---------
OTHER NONCURRENT LIABILITIES 537,423515,450 542,017
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 75,000- 117,506
Advances from Affiliates 252,323 -
Accounts Payable - General 151,028160,578 179,691
Accounts Payable - Affiliated Companies 115,08177,477 121,360
Customer Deposits 129,3587,368 39,736
Taxes Accrued 171,681184,079 223,101
Interest Accrued 31,56424,299 20,458
Obligations Under Capital Leases 29,18914,057 32,716
Energy Trading Contracts 1,483,8651,358,005 1,662,315
Other 136,314140,792 151,934
------- -------
TOTAL CURRENT LIABILITIES 2,323,0802,218,978 2,548,817
--------- ---------
DEFERRED INCOME TAXES 617,096609,885 621,941
------- -------
DEFERRED INVESTMENT TAX CREDITS 24,41323,644 25,214
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 385,975431,934 206,187
------- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 22,69940,720 23,005
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $6,213,244$6,117,767 $6,252,436
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
OPERATING ACTIVITIES:
Net Income $ 53,397 $46,21663,976 $ 104,449
Adjustments for Noncash Items:
Depreciation 52,853 60,29493,161 100,439
Amortization of Transition Assets 19,25636,705 -
Deferred Federal Income Taxes (1,068) (14,957)116 (6,387)
Deferred Fuel Costs (net) - (3,961)(8,844)
Amortization of Deferred Property Taxes 19,992 19,66640,596 39,944
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 1,274 (64,270)(37,904) (88,341)
Fuel, Materials and Supplies (17,131) 13,7142,252 47,680
Accrued Utility Revenues 264 12,51945,575
Prepayments (22,537) (4,941)and Other Current Assets 15,116 (6,219)
Accounts Payable (34,942) 19,615(62,996) 129,756
Customer Deposits (32,368) (1,209)
Taxes Accrued (51,420) (18,324)(39,022) (44,129)
Interest Accrued 11,106 6,549
Operating Reserves (1,042) 22,6943,841 1,334
Energy Trading Contract (net) (73,339) (8,546)
Other (net) 21,815 16,082
------(24,345) 10,864
------- ------
Net Cash Flows From (Used For) Operating Activities 51,817 110,896
------(13,947) 316,366
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (65,103) (40,684)(151,314) (91,118)
Proceeds from Sale of Property and Other 5,8857,626 -
----- -------------
Net Cash Flows Used For Investing Activities (59,218) (40,684)
-------(143,688) (91,118)
-------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 74,748
Change in Advances to Affiliates (net) 75,950 -344,809 (148,965)
Change in Short-term Debt (net) - 46,506(194,918)
Retirement of Cumulative Preferred Stock - (46)(160)
Retirement of Long-term Debt (42,506) (8,883)(117,506) (11,752)
Dividends Paid on Common Stock (35,744) (37,733)(71,488) (75,406)
Dividends Paid on Cumulative Preferred Stock (314) (317)(630) (633)
---- ----
Net Cash Flows Used ForFrom (Used For) Financing Activities (2,614) (473)
------ ----155,185 (357,086)
------- --------
Net Increase (Decrease)Decrease in Cash and Cash Equivalents (10,015) 69,739(2,450) (131,838)
Cash and Cash Equivalents at Beginning of Period 31,393 157,138
------ -------
Cash and Cash Equivalents at End of Period $ 21,37828,943 $ 226,87725,300
=========== =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $10,887,000 and
$15,043,000 and for income taxes was $50,242,000 and $20,652,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $319,000 and
$2,791,000========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $40,580,000 and
$40,791,000 and for income taxes was $54,694,000 and $64,597,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $522,000 and
$8,422,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
I-5
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRSTSECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
The Company hadAND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of generation,
power marketing and trading of electricity; and energy delivery which consists
of transmission and distribution services. Since the merger of AEP and CSW, we
participate in power marketing and trading activities conducted on our behalf by
the AEP System.
Although revenues increased substantially, operating expenses increased
by a loss of $1.6greater amount causing net income to decrease by $2.8 million foror 19% in the
second quarter and $5.5 million or 35% in the first quarterhalf of 2001
compared with net income of $1.2 million for the first quarter of 2000. The
loss was primarily a result of increased maintenance expense due to damage
caused by a large winter ice storm and increased interest costs.2001.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $195 121$189 90 $384 104
Fuel Expense 40 5670 92 110 75
Purchased Power Expense 146 706118 373 264 505
Other Operation Expense 11 45
Maintenance Expense 1 146 21 17 32
Federal Income Taxes (2) 542
Interest Charges 1 6(3) (40) (5) (61)
The significant increase in operating revenues was due to participation
in the AEP System's power marketing and trading activities conducted on its
behalf bysubsequent to June
2000. Revenues for the AEP System. Revenues wereyear-to-date period also impacted byincreased as a result of the
absence of a 2000 adjustment of the Company's portion ofdue to a FERC-approved Transmission Coordination
Agreement, which had decreased revenues in 2000 and decreased other operation expenses in 2000. The
transmission coordination agreement provides the means by which the AEP West
electric operating companies plan, operate and maintain their four separate
transmission systems as a single unit. The agreement also established the method
by which these companies allocate revenues and costs received under open access
transmission tariffs.
Fuel expense increased due primarily to a rise in the average unit fuel
cost reflecting an increase in natural gas prices.
The increase in purchased power expense was primarily attributable to
participation in the increase inAEP System's power marketing and trading volume.activities.
Other operation expenses increased in the second quarter due to
increased transmission expenses, public liability insurance premiums, and power
trading incentive compensation. Expenses increased for the first half of 2001
due mainly to the absence of a 2000 favorable adjustment fordue to the
FERC-approved Transmission Coordination Agreement mentioned above, along with
increased incentive compensation for power trading and transmission expenses.
Maintenance expense increased for the quarter due primarily to
increased expenses to repair damage to overhead lines caused by a winter
storm.
Income
Federal income tax expense associated with utility operations decreased
as a result of a decreasedecline in pre-tax book income. Interest charges increased
reflecting the issuance of one year floating rate notes in November 2000
and additional short-term borrowings.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $356,139 $161,329$398,194 $209,172 $754,333 $370,501
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 111,801 71,586145,927 75,808 257,728 147,394
Purchased Power 166,546 20,666149,261 31,541 315,807 52,207
Other Operation 34,557 23,75734,332 28,476 68,889 52,232
Maintenance 9,830 8,58612,859 13,408 22,689 21,995
Depreciation and Amortization 19,471 18,91319,673 18,926 39,144 37,838
Taxes Other Than Federal Income Taxes 7,373 7,2399,550 8,819 16,923 16,058
Federal Income Taxes (1,779) (277)
------ ----4,650 7,692 2,871 7,415
----- ----- ----- -----
TOTAL OPERATING EXPENSES 347,799 150,470376,252 184,670 724,051 335,139
------- ------- ------- -------
OPERATING INCOME 8,340 10,85921,942 24,502 30,282 35,362
NONOPERATING INCOME 603 22392 494 695 716
-- --- --- ---
INCOME BEFORE INTEREST CHARGES 8,943 11,08222,034 24,996 30,977 36,078
INTEREST CHARGES 10,503 9,91710,113 10,296 20,616 20,213
------ ----------- ------ ------
NET INCOME (LOSS) (1,560) 1,16511,921 14,700 10,361 15,865
PREFERRED STOCK DIVIDEND REQUIREMENTS 53 53 106 106
-- -- --- ---
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK $(1,613) $1,112$ 11,868 $ 14,647 $10,255 $ 15,759
======== ======== ======= ==============
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $123,015 $123,348 $137,688 $139,237$139,236
NET INCOME (LOSS) (1,560) 1,16511,921 14,700 10,361 15,865
CASH DIVIDENDS DECLARED:
Common Stock 13,060 17,000 26,120 34,000
Preferred Stock 53 53 106 106
-- -- --- ---
BALANCE AT END OF PERIOD $123,015 $123,349$121,823 $120,995 $121,823 $120,995
======== ======== ======== ========
The common stock of PSO is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 914,325914,958 $914,096
Transmission 399,558415,083 396,695
Distribution 946,944960,152 938,053
General 208,536209,171 206,731
Construction Work in Progress 160,620157,452 149,095
------- -------
Total Electric Utility Plant 2,629,9832,656,816 2,604,670
Accumulated Depreciation and Amortization 1,162,7401,167,875 1,150,253
--------- ---------
NET ELECTRIC UTILITY PLANT 1,467,2431,488,941 1,454,417
--------- ---------
OTHER PROPERTY AND INVESTMENTS 39,14139,749 38,211
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 16,46326,801 52,629
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 14,09210,906 11,301
Accounts Receivable:
Customers 60,70532,105 59,957
Affiliated Companies 6,72313,817 3,453
Fuel - at LIFO costs 21,30020,078 28,113
Materials and Supplies - at average costs 30,59131,583 29,642
Under-recovered Fuel Costs 45,99111,519 43,267
Energy Trading Contracts 33,20793,037 382,380
Prepayments 3,8902,816 1,559
----- -----
TOTAL CURRENT ASSETS 216,499215,861 559,672
------- -------
REGULATORY ASSETS 23,15023,106 29,338
------ ------
DEFERRED CHARGES 28,41122,116 7,889
------ -----
TOTAL ASSETS $1,790,907$1,816,574 $2,142,156
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
rch 31,June 30, 2001 December 31, 2000
------------------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000 Shares
Issued Shares: 10,482,000 shares and
Outstanding Shares: 9,013,000 Shares $ 157,230 $157,230
Paid-in Capital 180,000 180,000
Retained Earnings 123,015121,823 137,688
------- -------
Total Common Shareholder's Equity 460,245459,053 474,918
Cumulative Preferred Stock Not Subject to Mandatory Redemption 5,283 5,283
PSO-Obligated, Mandatorily Redeemable Preferred Securities of Subsidiary
Trust Holding Solely Junior Subordinated Debentures of PSO 75,000 75,000
Long-term Debt 450,899450,975 450,822
------- -------
TOTAL CAPITALIZATION 991,427990,311 1,006,023
------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 20,000
Advances from Affiliates 178,993147,447 81,120
Accounts Payable - General 67,30660,949 104,379
Accounts Payable - Affiliated Companies 66,20555,104 64,556
Customers Deposits 18,80022,497 19,294
Taxes Accrued 6,39729,665 1,659
Interest Accrued 11,0857,389 8,336
Energy Trading Contracts 32,66592,367 389,279
Other 10,16912,615 12,137
------ ------
TOTAL CURRENT LIABILITIES 391,620428,033 700,760
------- -------
DEFERRED INCOME TAXES 318,754302,746 312,060
------- -------
DEFERRED INVESTMENT TAX CREDITS 35,33534,888 35,783
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 37,65132,342 35,292
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 16,12028,254 52,238
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,790,907$1,816,574 $2,142,156
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
OPERATING ACTIVITIES:
Net Income (Loss) $ (1,560) $ 1,16510,361 $15,865
Adjustments for Noncash Items:
Depreciation and Amortization 19,471 18,91339,144 37,838
Deferred Income Taxes 5,750 2,137(10,754) 18,715
Deferred Investment Tax Credits (448) (448)(895) (896)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (4,018) 6,85917,488 (2,608)
Fuel, Materials and Supplies 5,864 6576,094 1,932
Accounts Payable (35,424) 14,359(52,882) 48,788
Taxes Accrued 4,738 (11,953)28,006 (22,413)
Other Property and Investments (930) 2,998(1,178) 2,391
Transmission Coordination Agreement Settlement - (15,063)
Deferred Property Taxes (20,730)(14,951) -
Fuel Recovery (2,724) 9,26731,748 (25,571)
Other (net) (3,362) 6,062(5,276) 796
------ --------
Net Cash Flows From (Used For) Operating Activities (33,373) 34,953
-------46,905 59,774
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (28,595) (34,760)(67,042) (80,997)
Other - (3,543)
------(359) (4,694)
---- ------
Net Cash Flows Used For Investing Activities (28,595) (38,303)(67,401) (85,691)
------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (20,000) (10,000)
Retirement of Cumulative Preferred Stock - (1)
Change in Advances from Affiliates (net) 97,872 31,03466,327 69,690
Dividends Paid on Common Stock (13,060) (17,000)(26,120) (34,000)
Dividends Paid on Cumulative Preferred Stock (53) (53)
--- ---(106) (108)
---- ----
Net Cash Flows From Financing Activities 64,759 3,98120,101 25,581
------ -----------
Net Increase in Cash and Cash Equivalents 2,791 631(395) (336)
Cash and Cash Equivalents at Beginning of Period 11,301 3,173
------ -----
Cash and Cash Equivalents at End of Period $ 14,092 $3,804
=========$10,906 $2,837
======= ======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $5,736,000$19,011,000 and
$4,238,000$16,754,000 and for income taxes was $1,978,000 and $2,850,000$11,725,000 in 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
J-5
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
FIRSTSECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
Net income increased $12.2 million, or 159%, for the first quarterAND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of 2001. The increase for the quarter resulted primarily from increased
average wholesale prices and the favorable impact of AEP'sgeneration,
power marketing and trading operations. SWEPCo participatesof electricity; and energy delivery which consists
of transmission and distribution services. Since the merger of AEP and CSW, we
participate in power marketing and trading activities conducted on itsour behalf by
the AEP System.
Net income increased $11.2 million, or 42%, for the first half of 2001
despite a small decrease in the quarter of $1 million, or 5%. The increase for
the first half of 2001 resulted from the favorable impact of our power marketing
and trading operations. Income statement line items which changed significantly
were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $214 101$162 60 $376 78
Fuel Expense 29 3210 9 39 19
Purchased Power Expense 157 N.M.149 776 307 991
Other Operation Expense 5 13
Maintenance Expense(3) (9) 1 2
Depreciation and Amortization 6 21 7 12
Taxes Other Than Federal Income Taxes 4 342 11 5 21
Federal Income Taxes - - 6 N.M.
N.M. = Not Meaningful73
The significant increase in operating revenues resulted from higher fuel related
revenues due to increased fuel and purchased power
expense for the quarter and first half of 2001 resulted from increased trading
volumes of the wholesale business due to the fuel
clause mechanism, increased retail energy sales due to increased usage and the post merger favorable impact of
AEP's power marketing and trading operations, which added newoperations. SWEPCo began sharing in AEP's
marketing and trading transactions as a result of the merger of AEP and CSW in
June 2000.
Fuel expense for the wholesale revenues.
Fuel expensebusiness increased due primarily to an
increase in the average unit cost of fuel as a result of higher spot market
natural gas prices.
Other operation expense decreased for the quarter due to the reversal
of a $4 million environmental reserve originally recorded in the fourth quarter
of 1999. The increase in purchased power expensereserve was primarily caused byset up for expected remediation work at a site on which
a manufactured gas plant previously resided. In June 2001, the participation in AEP's trading operation, an increase in economy energy
purchases and increased firm energy contract purchases.site was donated
to a city for use as a major civic complex. As part of the donation, the city
agreed to hold us harmless from any future liability arising from the site.
Other operation expense increased for the quarteryear-to-date period as a result of an
unfavorable accounts receivablea
bad debt write-off, SWEPCo'sour share of power trading expenses that did not exist prior toincentive compensation incurred
since the June 2000 merger and increased transmission services expense.
Maintenance expense forpartially
offset by the first quarterreversal of 2001the $4 million environmental reserve.
Depreciation and amortization expenses increased as a
result of severe ice storms, offset in part by reduced overhead line
maintenance and tree-trimmings.
Thedue to an increase in
taxesexcess earnings accruals under the Texas restructuring legislation.
Taxes other than federal income taxes wasincreased during the second
quarter due to increased state income taxes reflecting higher state taxable
income. The increase for the first six months of 2001 is due to a favorable
adjustment of ad valorem taxes recorded in the first quarter of
2000.2000 and increased state income taxes
due to increased state taxable income.
The increase in federal income tax expense attributable to operations
was primarily due to an increase in pre-tax operating income.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $425,689 $212,156
-------- --------
OPERATING EXPENSES:
Fuel 118,246 89,352
Purchased Power 168,857 11,698
Other Operation 39,268 34,698
Maintenance 15,236 14,306
Depreciation and Amortization 28,130 27,357
Taxes Other Than Federal Income Taxes 14,266 10,661
Federal Income Taxes 7,700 1,353
----- -----
TOTAL OPERATING EXPENSES 391,703 189,425
------- -------
OPERATING INCOME 33,986 22,731
NONOPERATING INCOME (LOSS) 247 (233)
--- ----
INCOME BEFORE INTEREST CHARGES 34,233 22,498
INTEREST CHARGES 14,364 14,835
------ ------
NET INCOME 19,869 7,663
PREFERRED STOCK DIVIDEND REQUIREMENTS 57 57
-- --
EARNINGS APPLICABLE TO COMMON STOCK $ 19,812 $ 7,606
========= =======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
2001 2000
---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $293,989 $283,546
NET INCOME 19,869 7,663
CASH DIVIDENDS DECLARED:
Common Stock 18,553 15,501
Preferred Stock 57 57
-- --
BALANCE AT END OF PERIOD $295,248 $275,651
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $434,795 $272,409 $860,484 $484,565
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 124,151 113,773 242,397 203,125
Purchased Power 168,671 19,252 337,528 30,950
Other Operation 34,071 37,362 73,339 72,060
Maintenance 20,431 20,906 35,667 35,212
Depreciation and Amortization 33,328 27,525 61,458 54,882
Taxes Other Than Federal Income Taxes 14,986 13,455 29,252 24,116
Federal Income Taxes 6,508 6,840 14,208 8,193
----- ----- ------ -----
TOTAL OPERATING EXPENSES 402,146 239,113 793,849 428,538
------- ------- ------- -------
OPERATING INCOME 32,649 33,296 66,635 56,027
NONOPERATING INCOME 30 678 277 445
-- --- --- ---
INCOME BEFORE INTEREST CHARGES 32,679 33,974 66,912 56,472
INTEREST CHARGES 14,895 15,188 29,259 30,023
------ ------ ------ ------
NET INCOME 17,784 18,786 37,653 26,449
PREFERRED STOCK DIVIDEND REQUIREMENTS 58 57 115 114
-- -- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 17,726 $ 18,729 $ 37,538 $ 26,335
========= =========== ========= ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $295,248 $275,652 $293,989 $283,546
NET INCOME 17,784 18,786 37,653 26,449
CASH DIVIDENDS DECLARED:
Common Stock 18,552 15,500 37,105 31,000
Preferred Stock 58 57 115 114
-- -- --- ---
BALANCE AT END OF PERIOD $294,422 $278,881 $294,422 $278,881
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31, 2001 December 31, 2000
-------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,425,061 $1,414,527
Transmission 523,948 519,317
Distribution 1,007,999 1,001,237
General 326,967 325,948
Construction Work in Progress 49,587 57,995
------ ------
Total Electric Utility Plant 3,333,562 3,319,024
Accumulated Depreciation and Amortization 1,474,266 1,457,005
--------- ---------
NET ELECTRIC UTILITY PLANT 1,859,296 1,862,019
--------- ---------
OTHER PROPERTY AND INVESTMENTS 40,731 39,627
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 19,916 63,028
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 2,515 1,907
Accounts Receivable:
Customers 10,507 41,399
Affiliated Companies 20,642 11,419
Fuel Inventory - at average cost 39,677 40,024
Under-recovered Fuel 42,106 35,469
Materials and Supplies - at average cost 26,146 25,137
Energy Trading Contracts 40,171 457,936
Prepayments 15,730 16,780
------ ------
TOTAL CURRENT ASSETS 197,494 630,071
------- -------
REGULATORY ASSETS 53,503 57,082
------ ------
DEFERRED CHARGES 34,511 10,707
------ ------
TOTAL ASSETS $2,205,451 $2,662,534
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,472,831 $1,414,527
Transmission 531,793 519,317
Distribution 1,024,442 1,001,237
General 327,976 325,948
Construction Work in Progress 48,381 57,995
------ ------
Total Electric Utility Plant 3,405,423 3,319,024
Accumulated Depreciation and Amortization 1,500,099 1,457,005
--------- ---------
NET ELECTRIC UTILITY PLANT 1,905,324 1,862,019
--------- ---------
OTHER PROPERTY AND INVESTMENTS 41,443 39,627
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 32,212 63,028
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 1,954 1,907
Accounts Receivable:
Customers 50,532 41,399
Affiliated Companies - 11,419
Fuel Inventory - at average cost 43,194 40,024
Under-recovered Fuel 44,916 35,469
Materials and Supplies - at average cost 30,004 25,137
Energy Trading Contracts 112,529 457,936
Prepayments 18,562 16,780
------ ------
TOTAL CURRENT ASSETS 301,691 630,071
------- -------
REGULATORY ASSETS 52,123 57,082
------ ------
DEFERRED CHARGES 83,774 10,707
------ ------
TOTAL ASSETS $2,416,567 $2,662,534
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares $ 135,660 $135,660
Paid-in Capital 245,000 245,000
Retained Earnings 295,248294,422 293,989
------- -------
Total Common Shareowner's Equity 675,908675,082 674,649
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 494,897494,876 645,368
------- -------
TOTAL CAPITALIZATION 1,285,5091,284,662 1,434,721
--------- ---------
OTHER NONCURRENT LIABILITIES 11,82432,377 11,290
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 150,595 595
Advances from Affiliates 60,305136,483 16,823
Accounts Payable - General 65,56263,892 107,747
Accounts Payable - Affiliated Companies 28,88434,650 36,021
Customer Deposits 16,86820,471 16,433
Taxes Accrued 43,34352,382 11,224
Interest Accrued 11,83413,466 13,198
Energy Trading Contracts 39,518111,582 466,198
Other 12,41920,487 15,064
------ ------
TOTAL CURRENT LIABILITIES 429,328604,008 683,303
------- -------
DEFERRED INCOME TAXES 398,258396,364 399,204
------- -------
DEFERRED INVESTMENT TAX CREDITS 52,05450,955 53,167
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 8,97715,189 18,288
----------- ------
LONG-TERM ENERGY TRADING CONTRACTS 19,50133,012 62,561
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $2,205,451$2,416,567 $2,662,534
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
OPERATING ACTIVITIES:
Net Income $ 19,869 $ 7,66337,653 $26,449
Adjustments for Noncash Items:
Depreciation and Amortization 28,130 27,35761,458 54,882
Deferred Income Taxes (1,930) 5,544(4,546) 9,960
Deferred Investment Tax Credits (1,113) (1,121)(2,212) (2,241)
Deferred Property Taxes (17,703) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 21,669 7,9722,286 8,375
Fuel, Materials and Supplies (662) 1,488(4,266) (5,890)
Accounts Payable (49,324) 1,507(45,226) 29,989
Taxes Accrued 32,119 (7,719)41,158 (8,474)
Transmission Coordination Agreement Settlement - (24,406)
Deferred Property Taxes (24,531) -
Fuel Recovery (6,637) -(9,447) (18,218)
Other (20,092) 6,983
------- -----(5,553) 647
------ ---
Net Cash Flows From (Used For) Operating Activities (2,502) 25,26853,602 71,073
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (21,638) (28,062)(49,418) (61,879)
Purchase of Dolet Hills (85,716) -
Other 326 (2,645)
---(411) (4,338)
---- ------
Net Cash Flows Used For Investing Activities (21,312) (30,707)
-------(135,545) (66,217)
-------- -------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 149,515149,367
Retirement of Long-term Debt (450) (450)(45,451)
Change in Advances from Affiliates (net) 43,482 (127,608)119,660 (77,655)
Dividends Paid on Common Stock (18,553) (15,501)(37,105) (31,000)
Dividends Paid on Cumulative Preferred Stock (57) (57)
--- ---(115) (119)
---- ----
Net Cash Flows From (Used For) Financing Activities 24,422 5,89981,990 (4,858)
------ -----------
Net Increase (Decrease) in Cash and Cash Equivalents 608 46047 (2)
Cash and Cash Equivalents at Beginning of Period 1,907 3,043
----- -----
Cash and Cash Equivalents at End of Period $ 2,5151,954 $ 3,503
========= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,877,000 and $7,172,000
and for income taxes was $3,164,000 and $1,205,0003,041
========= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $25,743,000 and
$20,711,000 and for income taxes was $4,144,000 and $14,270,000 in 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
K-6
WEST TEXAS UTILITIES COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
--------------------------------------------------------
FIRSTSECOND QUARTER 2001 vs. FIRSTSECOND QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of
generation, power marketing and trading of electricity; and energy
delivery which consists of transmission and distribution services. Since
the merger of AEP and CSW, we participate in power marketing and trading
activities conducted on our behalf by the AEP System.
Net income decreased $2.9$1.9 million or 77%24% for the quarter. This
decreasequarter and
was $4.9 million, or 41%, lower for the six months ended June 30, 2001.
The decreases were primarily due to the absence of an excess earnings adjustment
madeincreased operating expenses
primarily higher transmission related expenses offset in 2000 which had increased net incomepart by $2.1 million in 2000. This
adjustment was made to true up the 1999 excess earnings accrual to the
actual report filed in March 2000. No such adjustment was required in 2001.trading
related activities and nonoperating income. Income statement line items
which changed significantly were:
Increase (Decrease)
-------------------
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $98 102$62 47 $161 71
Fuel Expense - - 31 11041
Purchased Power Expense 67 44958 258 125 334
Other Operation Expense 5 27
Taxes Other Than10 61 15 42
Maintenance Expense 2 40 2 17
Federal Income Taxes 1 22
Federal Income Taxes (2) (106)(3) (56) (5) (69)
Nonoperating Income 2 N.M.
N.M. = Not Meaningful3 82 4 127
The significant increase in operating revenues was primarily
due mostly to the post merger favorable impact of AEP'sparticipation in the AEP System's power marketing and trading
operations, which added new wholesale revenues. Revenues were also impacted
by the absence of aactivities subsequent to June 2000 adjustmentand higher fuel related revenues due
to increased fuel and purchased power expense of the Company's portion of a
FERC-approved Transmission Coordination Agreement, which had decreased
revenueswholesale business.
WTU began sharing in 2000AEP's marketing and decreased other operation expenses in 2000. The
transmission coordination agreement provides the means by which the AEP
West electric operating companies plan, operate and maintain their four
separate transmission systemstrading transactions as a single unit. The agreement also
establishedresult
of the method by which these companies allocate revenuesmerger of AEP and costs
received under open access transmission tariffs.
The increaseCSW in fuelJune 2000.
Fuel expense wasincreased due primarily to an increase in the
average unit cost of fuel as a result of higher spot market natural gas
prices.
ThePurchased power expense's significant rise in purchased power expense was primarily
attributable to participation in AEP's trading operation and the impact
of natural gas prices on wholesale purchased power prices.
The increase in otherOther operation expense wasincrease is due mainlyprimarily to a 2000
reduction in energy delivery's transmission expenses that resulted from
new prices for the absence
in 2001Electric Reliability Council of Texas (ERCOT)
transmission grid. Other operation expense also increased year-to-date
due to a favorable adjustment made in January 2000 related to the FERC-approvedFERC
approved Transmission Coordination Agreement.
The increase in taxes other than federal income taxes for the quarter
was primarilyMaintenance expense increased due to higher ad valorem taxes.a scheduled overhaul in
2001 of Oklaunion Power Plant of our wholesale business.
Federal income taxes attributable to operations decreased due primarily to a
decrease in pre-tax income. The increase in nonoperating income was due
primarily from interest
income on under-recovered fuel. WTU has been experiencing natural gas fuel
price increases which have resultedto a loss provision recorded in under-recoveriesthe second quarter of fuel costs2000 for the
termination of merchandise sales and the need to seek increases in fuel rates and surcharges including
accumulated interest on under-recovered balances. On January 1, 2002cost of phasing out the fuel recovery mechanism will cease in Texas subjecting WTU to the risk of
changes in the market price of gas used to generate electricity.merchandising
sales program.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
ree Months Ended March 31,
2001 2000
---- ----
(in thousands)
OPERATING REVENUES $195,006 $96,535
-------- -------
OPERATING EXPENSES:
Fuel 59,905 28,580
Purchased Power 81,692 14,893
Other Operation 25,756 20,304
Maintenance 4,562 4,862
Depreciation and Amortization 11,771 11,241
Taxes Other Than Federal Income Taxes 6,038 4,963
Federal Income Taxes 1,911
-----
(110)
TOTAL OPERATING EXPENSES 189,614 86,754
------- ------
OPERATING INCOME 5,392 9,781
NONOPERATING INCOME (LOSS) 1,431 (91)
----- ---
INCOME BEFORE INTEREST CHARGES 6,823 9,690
INTEREST CHARGES 5,932 5,857
----- -----
NET INCOME 891 3,833
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26
--- --
EARNINGS APPLICABLE TO COMMON STOCK $ 865 $ 3,807
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $192,839 $130,742 $387,845 $227,277
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 46,848 47,207 106,753 75,787
Purchased Power 80,485 22,455 162,177 37,348
Other Operation 25,355 15,751 51,111 36,055
Maintenance 7,046 5,045 11,608 9,907
Depreciation and Amortization 11,529 11,292 23,300 22,533
Taxes Other Than Federal Income Taxes 6,775 6,653 12,813 11,616
Federal Income Taxes 2,373 5,401 2,263 7,312
----- ----- ----- -----
TOTAL OPERATING EXPENSES 180,411 113,804 370,025 200,558
------- ------- ------- -------
OPERATING INCOME 12,428 16,938 17,820 26,719
NONOPERATING INCOME (LOSS) (553) (3,149) 878 (3,239)
---- ------ --- ------
INCOME BEFORE INTEREST CHARGES 11,875 13,789 18,698 23,480
INTEREST CHARGES 5,742 5,719 11,674 11,577
----- ----- ------ ------
NET INCOME 6,133 8,070 7,024 11,903
PREFERRED STOCK DIVIDEND REQUIREMENTS 26 26 52 52
-- -- -- --
EARNINGS APPLICABLE TO COMMON STOCK $ 6,107 $ 8,044 $ 6,972 $11,851
========= ======= ========= =======
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended March 31,
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $122,588 $113,242
NET INCOME 891 3,833
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 7,206 4,500
Preferred Stock 26 26
--- --
BALANCE AT END OF PERIOD $116,247 $112,549 $122,588 $113,242
NET INCOME 6,133 8,070 7,024 11,903
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 7,206 4,500 14,412 9,000
Preferred Stock 26 26 52 52
-- -- -- --
BALANCE AT END OF PERIOD $115,148 $116,093 $115,148 $116,093
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 436,816437,880 $ 431,793
Transmission 236,149236,532 235,303
Distribution 419,923424,258 416,587
General 111,852112,139 110,832
Construction Work in Progress 33,81135,156 34,824
------ ------
Total Electric Utility Plant 1,238,5511,245,965 1,229,339
Accumulated Depreciation and Amortization 523,888531,411 515,041
------- -------
NET ELECTRIC UTILITY PLANT 714,663714,554 714,298
------- -------
OTHER PROPERTY AND INVESTMENTS 23,68124,100 23,154
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 10,705 20,944
------ 6,619------
CURRENT ASSETS:
Cash and Cash Equivalents 6,941
3,7443,982
Accounts Receivable:
Customers 25,92919,111 36,217
Affiliated Companies 13,8228,271 16,095
Allowance for Uncollectible Accounts (108)(299) (288)
Fuel Inventory - at average cost 12,60714,861 12,174
Materials and Supplies - at average cost 11,12811,099 10,510
Underrecovered Fuel 69,883 67,65559,129 68,107
Energy Trading Contracts 13,35137,398 152,174
Prepayments and Other Current Assets 851
---
232811
TOTAL CURRENT ASSETS 150,588 302,329154,363 302,781
------- -------
REGULATORY ASSETS 21,64719,075 24,808
------ ------
DEFERRED CHARGES 11,521 3,39910,188 2,947
------ -----
TOTAL ASSETS $ 928,719932,985 $1,088,932
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
March 31,June 30, 2001 December 31, 2000
--------------------------- -----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares $ 137,214 $137,214
Paid-in Capital 2,236
2,236
Retained Earnings 116,247115,148 122,588
------- -------
Total Common Shareowner's Equity 255,697254,598 262,038
Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,482
2,482
Long-term Debt 255,874255,905 255,843
------- -------
TOTAL CAPITZALIZATION 514,053512,985 520,363
------- -------
CURRENT LIABILITIES:
Advances from Affiliates 67,81671,953 58,578
Accounts Payable - General 41,10432,073 45,562
Accounts Payable - Affiliated Companies 30,68412,896 42,212
Customer Deposits 2,659
4,3214,614
Taxes Accrued 23,94532,206 18,901
Interest Accrued 3,717
6,0153,119
Energy Trading Contracts 13,13337,083 154,919
Other 7,906
-----
7,2698,895
TOTAL CURRENT LIABILITIES 194,287202,839 334,454
------- -------
DEFERRED INCOME TAXES 157,090152,232 157,038
------- -------
DEFERRED INVESTMENT TAX CREDITS 23,73423,416 24,052
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 6,481 20,789
------
------10,972
REGULATORY LIABILITIES AND DEFERRED CREDITS 33,07430,541 32,236
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $ 928,719932,985 $1,088,932
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
ThreeSix Months Ended March 31,June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
OPERATING ACTIVITIES:
Net Income $ 891 $ 3,8337,024 $11,903
Adjustments for Noncash Items:
Depreciation and Amortization 11,771 11,24123,300 22,959
Deferred Income Taxes 85 (5,946)(4,738) (1,220)
Deferred Investment Tax Credits (318) (318)(636) (636)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 12,381 7,43124,941 8,644
Fuel, Materials and Supplies (1,051) (720)(3,276) 5,682
Accounts Payable (15,986) (4,277)(42,805) 11,627
Taxes Accrued 5,044 18913,305 (1,981)
Transmission Coordination Agreement Settlement - 15,465
Deferred Property Taxes (8,616)(6,200) -
Fuel Recovery (2,228) 5,3618,978 (5,818)
Other (net) 3,586 4,722
----- -----(1,324) (894)
------ ----
Net Cash Flows From Operating Activities 5,559 36,981
-----18,569 65,731
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (10,762) (15,284)(20,312) (32,470)
Other - (982)
---(127) (1,878)
---- ------
Net Cash Flows Used For Investing Activities (10,762) (16,266)(20,439) (34,348)
------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (40,000)
Change in Advances from Affiliates (net) 9,238 (16,806)13,375 19,048
Dividends Paid on Common Stock (7,206) (4,500)(14,412) (9,000)
Dividends Paid on Cumulative Preferred Stock (26)(52) (55)
--- (26)---
Net Cash Flows From (Used For)Used For Financing Activities 2,006 (21,332)
-----(1,089) (30,007)
------ -------
Net DecreaseIncrease (Decrease) in Cash and Cash Equivalents (3,197) (617)(2,959) 1,376
Cash and Cash Equivalents at Beginning of Period 6,941 6,074
----- -----
Cash and Cash Equivalents at End of Period $ 3,7443,982 $ 5,457
=======7,450
======= Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,162,000 and
$1,214,000 and for income taxes was ($2,957,000) and $-0-=======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $10,139,000 and
$9,053,000 and for income taxes was ($2,957,000) and $5,442,000 in 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
L-14
NOTES TO FINANCIAL STATEMENTS
MARCH 31,JUNE 30, 2001
(UNAUDITED)
The notes to financial statements that follow are a combined presentation for AEP and its
subsidiary registrants. The following list of footnotes shows the
registrant to which they apply:registrants as follows:
1. General AEP, AEGCo, APCo, CSPCo, CPL, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
2. Financial Instruments,
Credit and Risk
Management AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
2. Extraordinary Items AEP, CSPCo, OPCo
3. Acquisitions and Sales
of Assets AEP, OPCo, SWEPCo
4. Rate Matters AEP, CPL, SWEPCo, WTU
5. Industry Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO, SWEPCo, WTU
6. Business Segments AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo,
WTU
7. Financing and Related
Activities AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
8. Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 2000 Annual Report as incorporated in and filed
with the Form 10-K.
The AEP System operating companies have reclassified certain
settled forward energy transactions of their trading operation from a
net to a gross basis of presentation in order to better reflect the
scope and nature of the AEP System's energy sales and purchases. All
financially net settled trading transactions, such as swaps, futures,
and unexercised options, continue to be reported on a net basis,
reflecting the financial nature of these transactions. The following
expenseprior year amounts were reclassified from revenues to purchased power
expense to present the prior period on a comparable basis.
Three Months Ended
March 31, 2000
Company (in thousands)
AEP $3,100,000
APCo 566,083
CSPCo 334,999
I&M 364,164
KPCo 134,250
OPCo 502,426basis:
Three Months Ended Six Months Ended
June 30, 2000 June 30, 2000
Company (in thousands)
-------
AEP $4,968,235 $8,064,527
APCo 1,030,774 1,596,856
CSPCo 597,406 932,417
I&M 649,433 1,013,598
KPCo 244,901 379,152
OPCo 896,008 1,398,435
In the opinion of management, the unaudited financial statements
reflect all normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for
interim periods.
2. RISK MANAGEMENT AND RELATED ACCOUNTING
Risk Management
AEPEXTRAORDINARY ITEMS
OPCo and its registrant subsidiaries are subject to market riskCSPCo Recognize Loss from the Stranding of Ohio Gross Receipts Tax
OPCo and CSPCo recognized an extraordinary loss for stranded Ohio
Public Utility Excise Tax (commonly known as a
resultthe Gross Receipts Tax -
GRT) net of changes in commodity prices, foreign currency exchange rates,
and interest rates. AEP has wholesale electricity and gas trading and
marketing operations that manageallowable Ohio coal credits during the exposure to commodity price
movements while entering into physical forward purchase and sale
contracts at fixed and variable prices, and financial derivative
instruments including exchange traded futures and options,
over-the-counter options, swaps and other financial derivative contracts
at both fixed and variable prices to create shareholder value.
Risks of foreign currency fluctuations arisequarter ended June
30, 2001. This loss resulted from investments in
foreign energy companies and projects and equipment purchases
denominated in foreign currencies. AEP does not presently utilize
derivatives to manage its exposures to foreign currency exchange rate
movements for its investments in foreign energy companies and projects.
For equipment purchases and energy trading transactions denominated in
foreign currencies, forward contracts have been utilized to manage the
exposure to fluctuations in foreign currency exchange rates. AEP, APCo,
and OPCo have entered into foreign currency hedge contracts to manage
the exposure to changes in foreign currency rates on assets purchased.
Short and long-term borrowings used to fund business operations
expose AEP and its registrant subsidiaries to risk from changes in
interest rates. AEP, KPCo, and I&M have entered into cash flow hedge
contracts to manage the exposure to changes in interest rates on
variable interest rate debt and the changes in interest rates on fixed
rate debt issuances.
Certain of AEP's foreign subsidiaries employ hedging transactions
in order to mitigate the risks of commodity market prices, foreign
currency and interest rate fluctuations. CitiPower utilizes interest
rate swaps and forward commodity contracts to hedge the risks of market
price and interest rate fluctuations. Certain of CitiPower's commodity
contracts are not designated as hedges and are marked-to-market.
Currency swaps are used by CSW International to hedge debt transactions
issued in foreign currencies. The majority of SEEBOARD's power and gas
contracts are considered as normal purchases and sales.
Accounting
In the first quarter of 2001, AEP adopted Statement of Financial
Accounting Standard No. 133, "Accounting for Derivative Instruments and
Hedging Activities," as amended by SFAS 137 and SFAS 138. SFAS 133
requires that entities recognize all derivatives as either assets or
liabilities and measure such derivatives at fair value. Changes in the
fair value of derivatives that are effective cash flow hedges are
included in other comprehensive income. AEP recorded a favorable
transition adjustment to accumulated other comprehensive income of $27
million at January 1, 2001regulatory decisions in connection
with Ohio deregulation which stranded the adoptionrecovery of the GRT. The
components of the extraordinary loss by company were:
CSPCo OPCo Total
----- ---- -----
(in thousands)
Gross Receipts Tax $42,493 $50,461 $92,954
Less Coal Credits 7,733 17,361 25,094
------- ------- -------
Net Liability for Ohio
Gross Receipts Tax 34,760 33,100 67,860
Less Income Tax Benefit 8,353 11,585 19,938
------- ------- -------
Extraordinary Loss $26,407 $21,515 $47,922
======= ======= =======
As discussed in Note 7 of the 2000 Annual Report, CSPCo and OPCo
appealed to the Ohio Supreme Court a PUCO order on Ohio restructuring
that the companies believe failed to provide for recovery for the final
year of the GRT. Effective May 1, 2001, the PUCO order reduced the
companies' rates by the annual level of GRT. Effective with the
liability affixing on May 1, 2001, the PUCO's decision to deny recovery
in the final year of the GRT resulted, under SFAS 133.101, in an
extraordinary impairment of the prepaid asset due to the deregulation of
the companies' generation business.
CSPCo and OPCo continue to seek recovery at the Ohio Supreme
Court where a decision is expected in 2002.
3. ACQUISITIONS AND SALES OF ASSETS
Acquisition of Houston Pipe Line Company - Affecting AEP
On June 1, 2001, AEP, through a wholly owned subsidiary,
purchased Houston Pipe Line Company and Lodisco LLC for $727 million.
The acquired assets include 4,200 miles of gas pipeline, a 30-year
sublease of a gas storage facility and certain gas marketing contracts.
The purchase method of accounting was used to record the acquisition.
AEP may adjust the allocation of purchase price for changes in its
preliminary evaluations and assumptions based on review of additional
information. The purchase method results in the assets and earnings of
the acquired operations being included in AEP's consolidated financial
statements from the purchase date.
Acquisition of Lignite Mining Operations - Affecting AEP and SWEPCo
On June 1, 2001, SWEPCo assumed mining operations at its registrant subsidiaries have significant domestic
energy trading contracts that have been marked-to-market and accounted
for under EITF 98-10, "Accounting for Contracts Involvedjointly
owned lignite reserves in Energy
Trading and Risk Management Activities". Therefore, the adoption of SFAS
133 did not require transition adjustments for AEP and its registrant
subsidiaries' open energy trading contracts.
AEP contracts identified in the SFAS 133 transition adjustment,
include interest rate swaps, foreign currency swaps, and commodity
swaps, options and futures, the vast majority of which were designated
as cash flow hedges and relate to foreign operations.
Subsequent to recording the transition adjustment FASB approved
guidance indicating that contracts with option features cannot qualify
for the normal purchases and normal sales exception under SFAS 133, as
amended. This guidance,Louisiana. To settle litigation, which is
effectivediscussed in Note 8, SWEPCo paid $86 million to purchase the third quartermining
assets and rights of 2001,
is expectedthe previous mine operator and assumed existing
mine reclamation liabilities. The lignite from the mine will continue to
supply SWEPCo's jointly owned power plant. Management expects the
acquisition to have a favorable effectminimal impact on earnings assuming that market
prices do not decline.
The FASB recently issued tentative guidance on two issues with
significant impacts on the electric industry. Such tentative guidance
states that energy capacity contracts that include certain
characteristicsresults of purchased and written options and that derivative
contracts which do not result in physical delivery of power because of
transmission scheduling, referred to as bookouts, cannot meet the normal
purchases and normal sales exception. While AEP believes that the
majority of its electricity capacity contracts qualify as normal
purchases and sales and that bookouts result in simultaneous delivery,
passage of title, and settlement on a gross basis and are, therefore,
physical normal purchase and sale transactions, the ultimate resolution
of these electric industry issues could have a material effect on
reported earnings. The electric industry and AEP are activity working
with the FASB to resolve these issues.
Contracts that qualify as derivatives under SFAS 133 are reported
on the consolidated balance sheets at fair value. Open derivative
contracts are fair valued with unrealized gains reported as assets and
unrealized losses reported as liabilities.
Cash flows from both derivative instruments and trading activities
are included in net cash flows from operating activities.
Certain derivatives may be designated for accounting purposes as a
hedge of either the fair value of an asset, liability or firm
commitment, or a hedge of the variability of cash flows related to a
variable-priced asset, liability, commitment or forecasted transaction.
To qualify for hedge accounting, the relationship between the hedging
instrument and the hedged item must be documented to include the risk
management objective and strategy for use of the hedge instrument. At
the inception of the hedge and on an ongoing basis, the effectiveness of
the hedge is assessed as to whether the hedge is highly effective in
offsetting changes in fair value or cash flows. Changes in the fair
value that result from ineffectiveness under SFAS 133 are recognized
currently in earnings.
Changes in the fair value of fair value hedges offset changes in
the fair value of the hedged items to the extent the hedge is effective.
Changes in the fair value of effective cash flows hedges are reported in
accumulated other comprehensive income if documented at inception. Gains
and losses from cash flow hedges in other comprehensive income are
reclassified to earnings in periods in which the variability of cash
flows of the hedged items affect earnings.
The following chart represents the various cash flow hedge
derivative positions of AEP and its registrant companies at March 31,
2001:
Hedging Assets Hedging Liabilities Other Comprehensive
Income (Loss) After Tax
-----------------------
(in thousands)
AEP Consolidated
Power $33,185 $ (1,058) $ 36,527
Gas 20 (10,193) (7,111)
Interest Rate 394 (32,330) (14,866)
Foreign Currency (1,471) (1,128)
--------
$ 13,422
APCo
Foreign Currency - (642) (417)
KPCo
Interest Rate - (2,083) (1,354)
I&M
Interest Rate 394 (3,346) (1,919)
OPCo
Foreign Currency - (338) (220)
The following table represents the activity in Other Comprehensive
Income related to the effect of adopting SFAS 133 for derivative
contracts that qualify as cash flow hedges during the first quarter of
2001 (in thousands):
AEP consolidated
Transition Adjustment, January 1, 2001 $26,795
Effective portion of change in fair value 9,462
Reclass from OCI to net income (22,835)
-------
Accumulated OCI derivative gain $13,422
=======
APCo
Transition Adjustment, January 1, 2001 $ -
Effective portion of change in fair value (417)
Reclass from OCI to net income -
-----
Accumulated OCI derivative loss $(417)
=====
KPCo
Transition Adjustment, January 1, 2001 $ (557)
Effective portion of change in fair value (764)
Reclass from OCI to net income (33)
-------
Accumulated OCI derivative loss $(1,354)
=======
I&M
Transition Adjustment, January 1, 2001 $ (317)
Effective portion of change in fair value (1,405)
Reclass from OCI to net income (197)
-------
Accumulated OCI derivative loss $(1,919)
=======
OPCo
Transition Adjustment, January 1, 2001 $ -
Effective portion of change in fair value (220)
Reclass from OCI to net income -
-----
Accumulated OCI derivative loss $(220)
=====
Approximately $2 million of net gains from hedge derivatives in
accumulated other comprehensive income at March 31, 2001 is expected to
be reclassified to net income in the next twelve months by AEP. KPCo and
I&M estimate that approximately $0.6 million and $1.9 million,
respectively, of net losses in accumulated other comprehensive income
will be reclassified to net income in the next twelve months. The actual
amounts reclassified from accumulated other comprehensive income to net
income can differ as a result of market price changes. The maximum term
for which the exposure to the variability of future cash flows is being
hedged is up to 5 years for AEP and up to one year for APCo and OPCo.
3. SALES OF ASSETSoperations.
Sale of Generating Assets - Affecting AEP
As discussed in Note 3 of the Notes to Financial Statements in
the 2000 Annual Report, the divestiture of 1,904 MW of generating
capacity was required by the FERC and the PUCT as part of the approval
of the merger. In MarchJuly 2001, AEP, completed the sale of Frontera, one of
thethrough a wholly owned subsidiary, sold its
50% interest in a 120-megawatt generating plants required to be divested under the settlement
agreements approved by the FERC.plant located in Mexico. The
sale proceeds were $265 million and
resulted in ana third quarter after tax gain of $46approximately $11
million.
Sale of Yorkshire Investment - Affecting AEP
In December 2000 AEP entered into negotiations to sell its 50%
investment in Yorkshire, a U.K. electricity supply and distribution
company. On February 26, 2001, an agreement to sell AEP's interest in
Yorkshire was signed and resulted in a $30 million after tax net loss
from the expected sale being recorded in 2000. On April 2, 2001,
following the approval of the buyer's shareholders, the sale was
completed without further impact on AEP's consolidated earnings.
Proposed
Sale of Affiliated Coal Mines - Affecting AEP and OPCo
On April 30,In July 2001 AEP announced that it had entered into a
memorandum of understanding regarding a proposed sale of OPCo's
affiliatedand OPCo sold coal mines in Ohio and West
Virginia. In addition, OPCo would
enter into coal supply agreementsVirginia and agreed to purchase approximately 34 million tons of coal
from the purchaser of the mines through 2008. The terms of the sale are being negotiated
and management will continueis expected to
evaluate the transaction. Management is
unable to estimate thehave a nominal impact of the proposed sale on results of operations.operations and cash flows.
4. RATE MATTERS
Texas Fuel Costs - Affecting AEP, CPL, SWEPCo and WTU
As discussed in Note 5 of the Notes to Financial Statements in the 2000 Annual Report, AEP's Texas
electric operating companies have been
experiencingexperienced natural gas fuel price increases
which have resulted in under-recoveries of fuel costs.
Fuel recovery for Texas utilities is a multi-step procedure. When
fuel costs and the need to seek increases in fuel
rates and surcharges to recover these amounts.
In January 2001 CPL filed with the PUCT an application to implement
an increase in fuel factors of $175.9 million, effective with the March
2001 billing month over the ten months March 2001 through December 2001.
Additionally, CPL proposed to implement an interim fuel surcharge of $51.8
million, including accumulated interest, over a nine-month period
beginning in April 2001 to collect its under-recovered fuel costs. In
March 2001, pursuant to an interim order of an Administrative Law Judge
adopting a settlement of the fixed fuel factor portion of the application,
CPL implemented a $170.5 million increase in fixed fuel factors. In April
2001 the PUCT approved the settlement fixed fuel factors. In addition, in
April 2001 the PUCT voted to defer implementation of the requested fuel
surcharge until CPL's final fuel reconciliation as part of a 2004 true-up
proceeding. CPL has requested a rehearing on the surcharge denial.
In January 2001 WTU filed an application with the PUCT to implement
an increase in fuel factors of $46.5 million effective with the March 2001
billing month. In March 2001 pursuant to an interim order of an
Administrative Law Judge adopting a settlement of the fixed fuel factor
portion of the application, WTU implemented the increase in fixed fuel
factors. In April 2001, the PUCT approved the new WTU fixed fuel factors.
In March 2001 WTU filed a requestchange, utilities file with the PUCT for authority to implementadjust
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 cost under-recoveries totaling $59.5 million
including interest. The under-recoveries werecosts
incurred and collected during the reconciliation period July 2000 through January 2001. The request is seeking to surcharge the
under-recoveredwere reasonable
and necessary. All fuel costs duringincurred since the period May 2001 through December
2001. A decision on the WTU fuel surcharge request is pending. Based upon
the decisionprior 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.
Fuel cost in the CPL fuel surcharge proceeding, management expects the
PUCT may defer recovery of the WTU fuel surcharge until the 2004 true-up
proceeding when WTU would have a final fuel reconciliation.
In June 2000 SWEPCo had filed with the PUCT an application to
reconcile fuel costs and to request authorization to carry the unrecovered
balance forward into the next reconciliation period. As discussed in the
2000 Annual Report, a settlement was reached in December 2000 and approved
by the PUCT in FebruaryTexas jurisdiction after 2001 which did not have a material effect on
results of operations.
In November 2000 SWEPCo filed an application with the PUCT for
authority to implement an increase in fuel factor revenues effective with
the January 2001 billing month. SWEPCo also proposed to implement an
interim fuel surcharge to collect its under-recovered fuel costs including
accumulated interest, over a six-month period beginning in January 2001.
The PUCT approved SWEPCo's application in January 2001. The order allows
an increase in fuel factors of $12 million on an annual basis beginning in
January 2001 and a surcharge of $11.8 million including accumulated
interest for the billing months of February through July 2001.
In May 2001 SWEPCo filed to increase fixed fuel factors by $4.3
million and to surcharge fuel under-recoveries for the period October 2000
through March 2001 of $18.3 million, including interest. Based upon the
decision in the CPL fuel surcharge proceeding, management expects the PUCT
may defer recovery of the SWEPCo fuel surcharge until the 2004 true-up
proceeding when SWEPCo would have a final fuel reconciliation.
Beginning January 1, 2002, fuel costs will no longer be
subject to PUCT fuel reconciliation proceedings under the Texas Restructuring
Legislation. Consequently,review and reconciliation. During 2002 CPL, SWEPCo, and
WTU will file a final fuel reconciliation with the PUCT to reconcile their
fuel costs through the period ending December 31, 2001. Fuel costs have been reconciled by CPL,
SWEPCo and WTU through June 30, 1998, December 31, 1999 and June 30, 1997,
respectively. WTU is currently reconciling its fuel through June 2000. At
March 31, 2001, CPL's, SWEPCo's and WTU's Texas jurisdictional unrecovered
deferred fuel balances were $125 million, $25.4 million and $66.8 million,
respectively. As discussed above, the remaining balances on CPL, SWEPCo,
and WTU current fuel surcharges at March 31, 2001 are $45 million, $6.5
million and $9.5 million, respectively. FinalThe unrecovered
deferred fuel balances at December 31, 2001 will be included in each
company's 2004 true-up proceeding. If the final under-recovered fuel
balances or any amountamounts incurred but not yet reconciled are not recovered,disallowed, it
would have a negative impact on results of operations.
The following table lists the Texas jurisdictional reconciliation
status, total fuel cost subject to reconciliation, under-recovered fuel
balances and the remaining fuel surcharge for the companies:
Fuel cost subject to Under-recovered
Reconciliation reconciliation at fuel balances at Remaining authorized
Company completed through June 30, 2001 June 30, 2001 fuel surcharge
------- ----------------- ------------- ------------- --------------
CPL June 30, 1998 $1.4 billion $93 million $25 million
SWEPCo December 31, 1999 240 million 29 million 13 million
WTU June 30, 1997 581 million 57 million 6 million
Under Texas restructuring, newly organized retail electric providers
will make sales to consumers beginning in 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. The
filings are pending at the PUCT.
Status of Rate Filings
Central Power and Light
In January 2001 CPL filed an application with the PUCT to implement
a $175.9 million increase in fuel factors over the ten months March 2001
through December 2001. In addition, to collect its under-recovered fuel
costs, CPL proposed to implement an interim fuel surcharge of $51.8
million, which includes accumulated interest on unrecovered amounts. The
PUCT approved in April 2001 the implementation of a $170.5 million
increase in fixed fuel factors. The PUCT voted to defer implementation of
the requested fuel surcharge until the final fuel reconciliation, which
occurs as part of the 2004 true-up proceeding.
Southwestern Electric Power Company
In November 2000 SWEPCo filed with the PUCT to increase its fuel
factors effective January 2001 and to collect previously under-recovered
fuel costs over a six-month period through a proposed interim fuel
surcharge, which includes accumulated interest on previous unrecovered
fuel costs. The PUCT approved an increase in SWEPCo's fuel factors of $12
million and the implementation of a fuel surcharge of $11.8 million from
February to July 2001.
In May 2001 SWEPCo filed an application to increase its fuel factors
by $4.3 million. The application also proposed a fuel surcharge of $18.3
million, which includes accumulated interest on previous unrecovered fuel
costs. The PUCT approved in August 2001 a unanimous stipulation, requiring
SWEPCo to withdraw its fuel factors request and to implement a surcharge
of $10.7 million for unrecovered fuel. The PUCT deferred the remaining
$6.8 million balance of unrecovered fuel until a later proceeding.
West Texas Utilities
In April 2001 the PUCT approved new fuel factors for WTU to collect
$43.4 million of increased fuel costs from March through December 2001.
WTU implemented the increase in its fuel factors in March 2001 after an
Administrative Law Judge approved a settlement of WTU's application. WTU's
original application, in January 2001, had requested a $46.5 million
increase in its fuel factors.
In March 2001 WTU filed with the PUCT to implement a fuel surcharge
for under-recovered fuel costs of $59.5 million including interest on
previous unrecovered fuel costs. WTU requested that the surcharge be
effective May 2001 through December 2001. A decision on the WTU fuel
surcharge request is pending. Management expects the PUCT to defer WTU's
recovery until the 2004 true-up proceeding.
Texas Transmission Rates - Affecting AEP, CPL and WTU
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.
Excess Earnings - Affecting AEP, CPL, SWEPCo and WTU
In March 2001 CPL, SWEPCo and WTU filed their Annual Report of
Excess Earnings for 2000 with the PUCT. In July 2001 the companies
received official notice of certain disagreements with the reports as
filed from the Staff of the PUCT and the Office of Public Utility Counsel
(OPC). The Staff and OPC took exception to certain adjustments made by the
companies, and OPC also took exception to the application of certain
sections of the law as it pertains to the calculation of revenue within
the report.
The table below shows the amounts of excess earnings calculated by
each company, the PUCT Staff and the OPC:
2000 Excess Earnings
As filed As calculated As calculated
by company by PUCT Staff by the OPC
---------- ------------- ----------
(in millions)
CPL $12.6 $21.7 $42.4
SWEPCo (3.7) 1.4 1.2
WTU 10.2 16.6 15.3
The companies believe that the calculations in their reports are
proper and believe the ultimate amount of excess earnings finally approved
by the PUCT will not have a materially adverse effect on their results of
operations or cash flows. A PUCT decision is due in late August 2001.
5. INDUSTRY RESTRUCTURING
As discussed in the 2000 Annual Report, restructuring legislation
has been enacted in seven of theAEP's eleven state retail jurisdictions in
which the AEP domestic electric
utility companies operate.jurisdictions. The legislation provides for a transition from cost-based
regulation of bundled electric service to customer choice and market
pricing for the supplygeneration of electricity. The following paragraphs discuss significant
events occurring in 2001 related to industry restructuring.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001, customer choice of electricity supplier
began under the Ohio Act. In February 2001, one supplier
announced its plan to offer service to CSPCo's residential customers.
Currently for residential customers of OPCo, noThe PUCO approved alternative suppliers have registered with the PUCO under the Ohio Act. Alternative suppliers
have been approved(many of
whom remain inactive) to compete for CSPCo's and OPCo's commercial and
industrial customers.
Presently, virtuallyVirtually all customers continue to be served by CSPCo and OPCo.
In accordance with the Ohio Act, CSPCo and OPCo with a legislatively required residentialimplemented rate
reductionreductions of 5% for the generation portion of residential rates and frozen
transitioneffective
January 1, 2001. The generation portion of retail rates, including fuel,
rates from January 1, 2001
towill remain frozen until December 31, 2005 for all classesor the PUCO determines that a
competitive market exists.
On January 16, 2001, Shell Energy Services Company filed a Notice of
customers.
As discussed in Note 7 of the Notes to Financial Statements in the
2000 Annual Report, CSPCo and OPCo filed an appealAppeal with the Ohio Supreme Court related to a tax expense issue which would result in duplicate
expense of $40 million and $50 million, respectively, for a twelve month
period beginning on May 1, 2001. One of the items CSPCo and OPCo
requested was a stay of the PUCO ordered implementation date (May 1,
2001) for an excise tax credit rider. On April 13, 2001, the Ohio
Supreme Court denied the companies' stay request. Management does not
expect the Ohio Supreme Court to hear arguments on the merits of this
case until the fourth quarter of 2001.
One of the intervenors at the hearings forchallenging PUCO's approval of aour
transition settlement agreement (whose request for rehearing was denied
by the PUCO) has filed with the Ohio Supreme Court for review of the
settlement agreement including CSPCo's and OPCo's recovery of their
transition generation-related regulatory assets.
Management is unable to predict the outcome of this litigation. The
resolution of this matter could negatively impact future results of
operation.operations and cash flows.
Virginia Restructuring - Affecting AEP and APCo
In connectionaccordance with aits restructuring law, the Virginia law that provides forjurisdiction
will begin a transition to choice of electricity supplier for retail
customers beginning on January 1, 2002 (which is described in Note 72002. The Virginia restructuring law requires
filings to be made that outline the functional separation of the Notes to Financial
Statements in the 2000 Annual Report), APCo was required to make a
filing with the Virginia SCC to unbundle rates and separate generation
from transmission and distribution. On January 3, 2001,distribution and a rate unbundling plan. APCo filed
its
corporate separation plan and rate unbundling plan with the Virginia SCC, which included a 1999 cost of service study required by the
Virginia SCC's regulations. That filing indicated that additional
information about APCo's proposed corporate separation plan would be
filed at a later date.
On April 11, 2001, the Virginia SCC directed APCoSCC.
Hearings are scheduled for October 2001. Presently, capped rates are
sufficient to file the
additional information required to complete its corporate separation
filing when that information becomes available. APCo was also directed
to file, by May 15, 2001, all information necessary for the Virginia SCC
to fully consider a functional separation of APCo, by divisions. If in
connection with the transition process, the Virginia SCC were to reduce
APCo's rates or deny recovery ofrecover generation-related regulatory assets,
it would have an adverse effect on resultsassets. Management is
unable to predict if the outcome of operations.the hearings will result in the
ability to recover generation-related regulatory assets.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 Arkansas enacted legislation was enacted in Arkansas that will ultimatelyto restructure theits electric utility
industry. In February 2001 the Arkansas General Assembly passed
legislation that was signed into law by the Governor thatto delay
restructuring. The legislation extended the date for the start of retail
electric retail competition to October 1, 2003 and provided the Arkansas
Commission with the authority to delay that date for up to two additional
years.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
The Texas Restructuring Legislation gives Texas customers of
investor-owned utilities the opportunity
to choose their electric provider and eliminates the fuel clause
reconciliation process beginning January 1, 2002. A 2004 true-up
proceeding will determine the amount of stranded costs if any, including the
final fuel recovery, net regulatory asset recovery, certain environmental costs, accumulated excess earnings
offsets and other issues.
As discussed in the 2000 Annual Report, the method used to
determine initial stranded costs to be recovered beginning on January 1,
2002 has been controversial. Duringis still subject to challenge. In March 2000 CPL submitted estimatesa $1.1
billion estimate of stranded costs andcosts. After hearing on the submission, the
PUCT held hearings. Inissued in February 2001 the PUCT
issued an interim decision determining an initial
amount of stranded costs for CPL of negative $580 million. In April 2001
the PUCT ruled that its current estimate of CPL's stranded costs was
negative $615 million. CPL disagrees with the ruling that it has a stranded benefit and has requested a
rehearing.
In April 2001 the PUCT issued an order requiring CPL to reduce
future distribution rates by $54.8 million over a five-year period in
order to return estimated excess earnings for 1999, 2000 and 2001. The
Texas Restructuring Legislation intended that excess earnings would be
used to reduce
stranded cost.costs. Final stranded cost amounts and the treatment of excess
earnings will be determined in the 2004 true-up proceeding. TheCurrently
the PUCT currently estimates that CPL will have no stranded costcosts and has ordered
the rate reduction to return excess earnings,
pending the outcome of the 2004 true-up proceeding.earnings. Management believes that
CPL will have stranded costs in 2004, and that the current treatment of
excess earnings will be amended at that time. CPL expensed excess
earnings amounts in 1999, 2000 and 2000.2001. Consequently, the April order
has no effect on reported net income.
As discussed in Note 7 of the 2000 Annual Report, the PUCT
authorized the issuance of up to $797 million of bonds to securitize
certain of CPL's regulatory assets. The PUCT's order that authorized the
securization was appealed to the Supreme Court of Texas. On June 6,
2001, the Supreme Court upheld the PUCT's securitization order. The
plaintiffs have requested a rehearing. We expect the court to dismiss
this request. Management plans to issue the securitization bonds prior
to January 1, 2002.
On August 3, 2001, the Staff of the PUCT filed a Petition
seeking a determination of whether electric operations in the SPP are
ready for competition. This Petition affects SWEPCo and part of WTU.
Under the Texas Restructuring Legislation, the PUCT can delay the start
of competition if the market and its participants are not prepared for
competition. Under the law, certain situations indicate this lack of
preparedness, and in Staff's opinion, those indicators are present for
the SPP area. The Petition seeks an expedited process to achieve a final
PUCT determination by November 1, 2001. Management is evaluating the
ramifications of a potential delay in the January 1, 2002 start date of
competition for SWEPCo's and WTU's Texas operations in the SPP.
A Texas settlement agreement in connection with the AEP and
CSW merger permits CPL to apply for regulatory purposes up to $20 million of previously
identified STP ECOM plant assets a year in 2000 and 2001 to reduce any
excess earnings, if any. For book purposes,earnings. STP ECOM plant assets will be depreciated in accordance
with GAAP, on a systematic and rational basis unless impaired.basis. To the extent excess
earnings exceed $20 million in 2001, CPL will establish a regulatory
liability or reduce regulatory assets by a charge to earnings.
Beginning January 1, 2002, fuel costs will not be subject to
PUCT fuel reconciliation proceedings. Consequently, CPL, SWEPCo and WTU
will file a final fuel reconciliation with the PUCT which reconciles
their fuel costs through the period ending December 31, 2001. These
final fuel balances will be included in each company's 2004 true-up
proceeding. The elimination of the fuel clause recoveries in 2002 in
Texas will subject AEP, CPL, SWEPCo and WTU to the risk of fuel market
price increases and could adversely affect future results of operations
beginning in 2002.
In the event CPL, SWEPCo, and WTU are unable after the 2004
true-up proceeding to recover all or a portion of their generation-related regulatory
assets, unrecovered fuel balances, stranded costs and other
restructuring related costs, it could have a material adverse effect on
results of operations, cash flows and possibly financial condition.
Michigan Restructuring - Affecting AEP and I&M
As discussed in the 2000 Annual Report, the Michigan
Legislation gave the MPSC broad powers to implement customer choice. In
compliance with MPSC orders, on June 5, 2001, I&M filed its proposed
unbundled rates, open access tariffs and terms of service. MPSC action
on the filing is expected in 2001 with competition commencing on January
1, 2002.
Management does not expect that I&M will incur material
tangible asset impairments or regulatory asset write-offs. If I&M is not
permitted to recover all or a portion of its generation-related
regulatory assets, unrecorded decommissioning obligation, stranded costs
and other implementation costs, it could have a material adverse effect
on results of operations, cash flows and possibly financial condition.
Oklahoma Restructuring - Affecting AEP and PSO
In June 2001 the Oklahoma Governor signed into law a bill that
delayed retail electric competition indefinitely. Under previously
approved legislation, the start date for Oklahoma customer choice had
been July 1, 2002.
6. BUSINESS SEGMENTS
AEP hasAEP's three principal business segments: wholesale, energy
delivery,segments and other investments. The wholesale segment is comprised of
the generation componenttheir respective
activities are:
o Wholesale
o Generation of electricity salesfor sale to domestic retail and wholesale customers, worldwide electriccustomers.
o Trading of electricity and gas trading and otherworldwide.
o Other energy supply related businesses.
o Energy delivery includes theDelivery
o Domestic electric transmission and distribution operations of the domestictransmission.
o Domestic electric operating companies.distribution.
o Other Investments
in foreigno Foreign electricity generation investments.
o Foreign electric distribution and supply companies, generation facilities outside of the United States and
telecommunication services make up the other investments segment.
All of the registrant subsidiaries except AEGCo have two business
segments, wholesale and energy delivery. AEGCo has one segment, a
wholesale generation business.
The presentation of wholesale and energy delivery segments
reflects management intention, announced in the fourth quarter of 2000,
to functionally and structurally separate its operations into
non-regulated and regulated businesses. Separation of AEP's regulated
bundled generation, transmission and distribution operations into an
unbundled non-regulated wholesale business and a regulated unbundled
energy delivery business will not be completed until the required
regulatory approvals are obtained. The electric operating subsidiaries
operating in states that are deregulating the supply business will be
structurally separated and the remaining subsidiaries will be
functionally separated. The amountssupply.
o Telecommunication services.
Amounts reported for 2000 have been
reclassified to conform to the current period's presentation.
The amounts shownbelow for the three business segments reported by AEP include
certain estimates and allocations where necessary.
Energy Other Reconciling
Wholesale Delivery Investments Adjustments Consolidated
March 31,June 30, 2001 (in millions)
Revenues from:
Revenues from:
External customers $12,879$22,877 $ 7881,637 $1,881 $ 571 $- $14,2382,298 $28,693
Transactions with other operating segments 192 (192)1,067 10 30 (1,107) -
Segment EBIT 352 245 113 (5) 705845 483 142 (71) 1,399
Total assets 25,392 13,405 8,113 46,910
March 31,29,566 14,379 7,539 (1,257) 50,227
June 30, 2000 Revenues from:
External customers 4,776 724 617 6,11711,731 1,508 1,078 (63) 14,254
Transactions with other operating segments 92 (92)734 1 50 (785) -
Segment EBIT 126 233 87 24 470302 513 155 (197) 773
Total assets 17,802 10,717 7,283 35,80221,033 12,370 7,709 (713) 40,399
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.
The following tables present the business segments being reported
for APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, and WTU:
Wholesale Segment March 31,June 30, 2001 March 31,June 30, 2000
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $1,822,030 $62,766 $3,684,595 $874,876$3,523,410 $107,415 $3,666,392 $2,198,766 $ 43,019 $2,476,29874,080 $2,970,385
CPL 493,082 52,080 2,945,850 217,387 30,832 2,794,2741,008,450 133,445 2,935,249 535,881 100,597 2,789,432
CSPCo 1,026,577 60,163 2,624,371 543,028 46,830 1,890,6282,016,002 119,544 2,499,506 1,370,892 100,274 2,107,087
I&M 1,213,601 39,733 4,172,159 633,819 (66,008) 3,316,2502,394,505 86,108 3,994,291 1,569,142 (123,565) 3,517,833
KPCo 422,830 1,021 840,123 198,183 2,500 556,073831,124 4,162 772,669 509,991 2,425 605,132
OPCo 1,567,816 69,236 4,193,940 932,886 59,264 3,296,0503,061,833 125,565 3,927,606 2,255,604 147,781 3,657,373
PSO 307,722 713 845,308 120,664 3,102 729,950644,622 12,124 859,240 267,225 14,203 747,576
SWEPCo 347,632 17,220 1,146,835 139,869 (1,071) 1,093,677696,457 32,036 1,184,118 324,673 3,608 1,048,972
WTU 156,364 (2,546) 442,070 59,808 (582) 398,227306,515 1,336 400,251 149,959 241 360,295
Energy Delivery March 31,Segment June 30, 2001 March 31,June 30, 2000
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $152,097 $63,189 $2,906,810 $146,802 $63,481 $1,953,573$300,021 $115,711 $2,892,449 $283,686 $113,629 $2,343,363
CPL 110,330 32,372 2,072,634 98,941 12,527 1,965,988243,461 65,612 2,108,135 218,358 75,334 2,003,407
CSPCo 98,996 14,762 1,333,956 90,277 16,778 960,998218,666 44,065 1,405,972 190,745 36,605 1,185,236
I&M 77,937 36,114 1,704,121 74,331 33,450 1,354,524156,907 61,410 1,802,938 150,714 55,592 1,587,875
KPCo 36,327 16,636 701,388 33,271 17,176 464,24567,164 27,246 748,333 64,123 30,337 586,072
OPCo 131,849 34,077 2,019,304 114,951 36,532 1,586,987265,009 58,512 2,190,161 228,563 67,336 2,039,469
PSO 48,417 6,344 945,599 40,665 7,602 816,554109,711 23,187 957,334 103,276 28,855 832,922
SWEPCo 78,057 24,660 1,058,616 72,287 24,874 1,009,548164,027 51,909 1,232,449 159,892 60,994 1,091,788
WTU 38,642 9,540 486,649 36,727 12,100 438,38481,330 21,041 532,734 77,318 28,508 479,553
Registrant
Subsidiaries
Company Total March 31,June 30, 2001 March 31,June 30, 2000
Revenues Revenues
From From
External Total Assets External
Customers EBIT Total Assets Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $1,974,127 $125,955 $6,591,405 $1,021,678 $106,500 $4,429,871$3,823,431 $223,126 $6,558,841 $2,482,452 $187,709 $5,313,748
CPL 603,412 84,452 5,018,484 43,359 4,760,262
316,3281,251,911 199,057 5,043,384 754,452 175,931 4,792,839
CSPCo 1,125,573 74,925 3,958,327 63,608 2,851,626
633,3052,234,668 163,609 3,905,478 1,561,637 136,879 3,292,323
I&M 1,291,538 75,847 5,876,280 (32,558) 4,670,774
708,1502,551,412 147,518 5,797,229 1,719,856 (67,973) 5,105,708
KPCo 459,157 17,657 1,541,511 19,676 1,020,318
231,454898,288 31,408 1,521,002 574,114 32,762 1,191,204
OPCo 1,699,665 103,313 6,213,244 1,047,837 95,796 4,883,0373,326,842 184,077 6,117,767 2,484,167 215,117 5,696,842
PSO 356,139 7,057 1,790,907 10,704 1,546,504
161,329754,333 35,311 1,816,574 370,501 43,058 1,580,498
SWEPCo 425,689 41,880 2,205,451 23,803 2,103,225
212,156860,484 83,945 2,416,567 484,565 64,602 2,140,760
WTU 195,006 6,994 928,719 11,518 836,611
96,535387,845 22,377 932,985 227,277 28,749 839,848
Management's intention is to structurally and functionally
separate operations into regulated and non-regulated businesses. The
vertically integrated generation-transmission-distribution operations
of the utility companies in Ohio and Texas (CSPCo, OPCo, CPL and WTU)
will be unbundled into non-regulated wholesale and regulated energy
delivery businesses. The remaining utility subsidiaries are expected to
be grouped with AEP's regulated business. Management is currently in
the process of obtaining the necessary regulatory approvals to support
this new business structure.
7. FINANCING AND RELATED ACTIVITIES
Long-term debt and other securities issuances and retirements
during the first six months of 2001 were:
Type Principal Interest
Company of Debt Amount Rate Due Date
------- ------- --------- -------- --------
Issuances (in millions) (%)
---------
AEP Senior Unsecured Notes $ 250 5.50 2003
AEP Senior Unsecured Notes 1,000 6.125 2006
Other AEP Subs. Various 152 4.00-6.00 2001-2004
------
Total AEP System $1,402
======
Retirements
APCo First Mortgage Bonds $100 6-3/8 2001
APCo Senior Unsecured Notes 75 4.00-6.00 2001
CPL Trust Preferred Securities 1 8.00 2037
I&M First Mortgage Bonds 40 7.63 2001
KPCo First Mortgage Bonds 20 8.95 2001
KPCo First Mortgage Bonds 40 8.90 2001
OPCo Senior Unsecured Notes 75 4.00-6.00 2001
OPCo Notes Payable 30 6.20 2001
OPCo Finance Obligation 13 6.98 2001
PSO First Mortgage Bonds 6 5.91 2001
PSO First Mortgage Bonds 5 6.02 2001
PSO First Mortgage Bonds 9 6.02 2001
Other AEP Subs. Various 43 4.00-6.00 2001
----
Total AEP System $457
====
In addition to the first quarter of 2001,transactions reported in the AEP System issued $40 million
of notes payable due in 2004 with an interest rate of 6.73% and
increasedtable above,
the level of borrowing under the SEEBOARD Revolving Credit
Facility by $89 million. Retirements of debt were: first mortgage bonds
totaling $120 million with interest rates ranging from 5.91% to 6-3/8%
due in 2001 and $61 million notes payable with interest rates ranging
from 6.20% to 7.5625% due in 2001.
The following table lists long-term debt retirements during the
first quarter of 2001 by the registrant subsidiaries:
Principal
Type Amount Interest Due
Company of Debt Retired Rate Date
------- ------- ----------- -------- ----
(in millions) (%)
APCo FMB $100 6-3/8 March 1, 2001
OPCo NP 30 6.20 January 31, 2001
PSO FMB 6 5.91 March 1, 2001
PSO FMB 5 6.02 March 1, 2001
PSO FMB 9 6.02 March 1, 2001
In March 2001 I&M paid $92.6 million to purchase leased nuclear
fuel from an unaffiliated company reflecting management's decision to
discontinue its policy of leasing all nuclear fuel for the Cook Plant.
The purchase was financed with funds from operations.
CPL redeemed $500,000 of its 8.00% trust preferred securities on
February 1, 2001.
On May 10, 2001, AEP issued $1.25 billionintercompany issuances of debt consisting of
$1 billion of senior notes and $250 million of putable callable notes.
The interest rate on the senior notes is 6.125% and they are due in May
2006. The putable callable notes (Series B notes) have a fixed interest
rate of 5.5% until May 2003. At that date the Series B notes may be
subject to call by a third party for purchase and remarketing, in which
case the maturity would extend until May 2013. In the event the Series B
notes are not called for remarketing, AEP must redeem them.
In January 2001 APCo became a participant in AEP's money pool and
retired all outstanding short-term debt. The Money Pool coordinates
short-term borrowings for certain AEP System subsidiaries, primarily the
domestic electric utility operating companies. The operation of the
Money Pool is designed to match on a daily basis the available cash and
borrowing requirements of the participants, thereby minimizing the need
for short-term borrowings from external sources and increasing the
interest income for participants with available cash. Participants with
excess cash loan funds to the Money Pool reducing the amount of external
funds AEP needs to borrow to meet the short-term cash requirements of
other participants whose short-term cash requirements are met through
advances from the Money Pool. AEP borrows the funds on a daily basis,
when necessary, to meet the net cash requirements of the Money Pool
participants. A weighted average daily interest rate which is calculated
based on the outstanding short-term debt borrowings made by AEP is
applied to each Money Pool participant's daily outstanding investment or
debt position to determine interest income or interest expense. Money
Pool participants include interest income in nonoperating income and
interest expense in interest charges. APCo reports its borrowings from
the Money Pool as Advances from Affiliates.
In March 2001 APCo commenced factoring customer accounts
receivable and accrued utility revenue balances to an affiliate, AEP
Credit, Inc. Under the factoring arrangement APCo sells without recourse
certain of its customer accounts receivable and accrued utility revenue
balances to
AEP Credit,Co., Inc.
and is charged a fee based on AEP Credit,
Inc.'s financing costs, uncollectible accounts experience for APCo's
receivables and administrative costs. The cost of factoring is included
in other operation expense. At March 31, 2001 the amount of APCo's
factored accounts receivable and accrued utility revenues was $78
million.
Interest
Company Type of Debt Principal Amount Rate Due Date
------- ------------ ---------------- ---- --------
Issuances (in millions) (%)
---------
KPCo Note Payable $ 60 6.501 2006
KPCo Note Payable 15 4.336 2003
Non-Registrant
AEP Subsidiaries Note Payable 644 4.336-6.501 2001-2006
----
Total AEP System $719
====
8. CONTINGENCIES
Litigation
Shareholders' Litigation - Affecting AEP
On June 23,In 2000 a complaint wasfive complaints were filed in the U.S. District
Court for the Eastern District of New Yorkagainst AEP seeking
unspecified compensatory damages against AEP and four former or present officers.
The individual plaintiff also seeks certification asfor alleged violations of federal
securities laws. A court order consolidated the representative
ofcases. However, the
court has not determined if the plaintiffs represent a class consisting
of all persons and entities who purchased or
otherwise acquired AEP common stock between July
25, 1997 and June 25, 1999. The complaint alleges that the defendants knowingly violated
federal securities laws by disseminating materially false and misleading
statements concerning, among other things, the undisclosed materially
impaired condition of the Cook Plant, AEP's inability to properly
monitor, manage, repair, supervise and report on operations at the Cook
Plant and the materially adverse conditions these problems were having,
and would continue to have, on AEP's deteriorating financial condition,
and ultimately on AEP's operations, liquidity and stock price. Four
other similar class action complaints have been filed and the court has
consolidated the five cases. The plaintiffs filed a consolidated
complaint pursuant to this court order. This case has been transferred
to the U.S. District Court for the Southern District of Ohio. On March 5, 2001, AEP and the individual defendants filed a comprehensive motion to
dismiss all claims against all defendents in the consolidated cases. The Court has setAll parties presented oral arguments of theon AEP's motion
forto dismiss on June 7, 2001. Although managementManagement believes these shareholder
actionscomplaints are without merit and intends to continue to oppose them vigorously, management cannot
predict thethem. The
outcome of this litigation or its impact on results of operations, cash
flows or financial condition.condition cannot be predicted.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
CPL has been involved in litigation regarding municipal franchise
fees in Texas as a result of a class action suit filed by the City of
San Juan, Texas in 1996. The City of San Juan claims CPL underpaid
municipal franchise fees and seeks damage of up to $300 million plus
attorney's fees. CPL filed a counterclaim for overpayment of franchise
fees.
During 1997, 1998 and 1999 theThe litigation moved procedurally through the Texas Court System
and was sent to mediation without resolution. In 1999 a class notice was mailed to eachCPL notified the cities it
serves of the pending class action suit. If a final decision determines
an underpayment of franchise fees, CPL has pledged to extend that final
decision to cities served by
CPL. Over 90 of the 128 citieswho declined to participate in the lawsuit.
However, CPL has pledged that if any final, non-appealable court
decision in the litigation awards a judgement against CPL for a
franchise underpayment, CPL will extend the principles of that decision,
with regard to any franchise underpayment, to the cities that declined
to participate in the litigation. In December 1999, thesuit. The court
ruled that the class of plaintiffs would consist of approximately 30
cities. Acities and set a trial date for October 2001 has been set.
Although management2001.
Management believes that it has substantial defenses to
the cities' claims and intends to defend itself against the
cities' claims and plans to pursue its counterclaims vigorously,counterclaims. However,
management cannot predict the outcome of this litigation or its impact
on results of operations, cash flows or financial condition.
Texas Base Rate Litigation - Affecting AEP and CPL
In November 1995 CPL filed with the PUCT a request to increase
its retail base rates by $71 million. In October 1997 the PUCT issued a
final order which lowered CPL's annual retail base rates by $19 million
from the rate level which existed prior to May 1996. The PUCT also
included a "glide path" rate methodologyAs discussed in the final order pursuant to
which annual rates were reduced by $13 million beginning May 1, 1998
with an additional annual reduction of $13 million commencing on May 1,
1999.2000 Annual Report, CPL appealedis involved in
litigation concerning a 1997 PUCT base rate order. A request for review
is pending before the final order to the Travis DistrictTexas Supreme Court.
The primary issues being appealed include: the classificationare:
o Classification of $800 million of invested capital inat STP as
ECOM and assigning itexcess cost over market (ECOM) earning a lower return on equity than
other generationgenerating property; the use of the "glide
path" rate reduction methodology; and
ano An $18 million disallowance of service billings from an affiliate, CSW Services. As part of the appeal,
CPL sought a temporary injunction to prohibit the PUCT from implementing
the "glide path" rate reduction methodology. The temporary injunction
was denied and the "glide path" rate reduction was implemented. In
February 1999 the Travis District Court affirmed the PUCT order in
regard to the three major items discussed above.
CPL appealed the Travis District Court's findings to the Texas
Appeals Court which in July 2000, issued its opinion upholding the
Travis District Court except for the disallowance of affiliated service company billings. Under Texas law, specific findings regarding affiliate
transactions must be made by PUCT. In regards to the affiliate service
billing issue, the findings were not complete in the opinion of the
Texas Appeals Court who remanded the issue back to PUCT.
CPL has sought a rehearing of the Texas Appeals Court's opinion.
The Texas Appeals Court has requested briefs related to CPL's rehearing
request from interested parties.
Management is unable to predict the final resolution of this
litigation or its appeal. If the appeal is unsuccessful the PUCT's
1997 order will continue to adversely affectimpact on results of operations and cash flows.
As part of the AEP/CSW merger approval process in Texas, a
stipulation agreement was approved which resulted in the withdrawal of
the appeal related to the "glide path" rate methodology. CPL will
continue its appeal of the ECOM classification for STP property and the
disallowed affiliated service billings.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo
In May 2001 SWEPCo settled ongoing litigation concerning lignite
mining in Louisiana. As discussed in Note 8 of the Notes to Financial Statements in the 2000 Annual Report,
SWEPCo has been involved in litigation concerning the mining of lignite
from jointly owned lignite reserves. SWEPCo and CLECO are each a 50% ownerjoint owners
of Dolet Hills Power Station Unit 1 and own lignite reserves in the
Dolet Hills area of northwestern Louisiana. In 1982 SWEPCo and CLECO
entered into a lignite mining agreement with DHMV, a partnership for the
mining and delivery of lignite from these reserves. Since 1997 SWEPCo
and CLECO have been involved in litigation with DHMV and its partners in U.S. District Court
for the Western District of Louisiana.partners.
In April 2000 the parties agreed to settle the litigation. As part of the
settlement, a subsidiary of
SWEPCo will purchasepurchased DHMV's interest in the mining assets and
will
assumemining rights for $86 million and assumed the related obligations for
mine reclamation.reclamation (See Note 3). The settlement agreement would givegives CLECO the
option beginning July 1, 2002, to acquire up to a 50% interest in the mining assets. The litigation has
been stayed to provide the parties a reasonable period of time to
complete the settlement process. Management believes that the resolution
of this matter will not have a material effect on results of operations,
cash flows or financial condition.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo,
CSPCo, I&M, and OPCo
As discussed in the 2000 Annual Report, Federal EPA and a number
of states alleged that AEP, APCo, CSPCo, I&M and OPCo modified certain
generating units in violation of the Clean Air Act. The Federal EPA
filed complaints against the companies in U.S. District Court for the
Southern District of Ohio in 1999. 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. AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. In 1999
Notices of Violation were issued and complaints were filed by Federal
EPA in various U.S. District Courts alleging APCo, CSPCo, I&M, OPCo and
a number of unaffiliated utilities made modifications to generating
units at certain of their coal-fired generating plants over the course
of the past 25 years that extended unit operating lives or increased
unit generating capacity without a preconstruction permit in violation
of the Clean Air Act. The complaint was amended in March 2000 to add
allegations for certain generating units previously named in the
complaint and to include additional generating units previously named
only in the Notices of Violation in the complaint.
A number of northeastern and eastern states were granted leave to
intervene in the Federal EPA's action against the AEP System under the
Clean Air Act. A lawsuit against power plants owned by certain AEP
System operating companies alleging similar violations to those in the
Federal EPA complaint and Notices of Violation was filed by a number of
special interest groups and has been consolidated with the Federal EPA
action.
The Clean Air Act
authorizes civil penalties of up to $27,500 per day per violation at
each generating unit ($25,000 per day prior to January 30, 1997).
Civil penalties, if ultimately imposed by the court,
and the cost of any required new pollution control equipment, if the
court accepts Federal EPA's contentions, could be substantial.
In May 2000 the AEP System companies filed motions to dismiss all
or portions of the complaints. On March 28 and 30, 2001 the Court
issued orders granting the motions in part and denying them in part. TheDistrict Court ruled claims for civil penalties
based on activities that occurred more than five years before the filing
date of the complaints, were filed cannot be imposed. ClaimsThere is no time limit on
claims for injunctive relief are not subject to a time limit.
Onrelief.
In February 23, 2001 the plaintiffs filed a motion for partial
summary judgment seekingrequested a determination that
four projects undertaken on units at Sporn, Cardinal and Clinch River
plants do not constitute "routine maintenance, repair and replacement"
as used in the Clean Air Act. On April 9, 2001, theThe AEP System companies filed a motion
requestingcompanies' request to allow
time for additional discovery before responding to the Court deny plaintiffs'
motion as premature, and issue an
order allowing discovery to continue.action was granted. Management believes its maintenance, repair and
replacement activities were in conformity with the Clean Air Act and
intends to vigorously pursue its defense.
In the event the AEP System companies do not prevail, any capital
and operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated rates,
and where states are deregulating generation, unbundled transition
period generation rates, stranded cost wires charges and future market
prices for electricity.condition.
In December 2000 Cinergy Corp., an unaffiliated utility, which
operates certain plants jointly owned bywith CSPCo, reached a tentative
agreement with Federal EPA and other parties to settle litigation regarding generating plant emissions
under the Clean Air Act. Negotiations are continuing between the parties in an attempt to
reach final settlement terms. Cinergy's settlement could impact the
operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6
which are
owned(owned 25.4% and 12.5%, respectively, by CSPCo.CSPCo). Until a final
settlement is reached, CSPCo will be unable to determine the
settlement's impact on its jointly owned facilities and its future
earnings and cash flows.
NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo
and SWEPCo
Federal EPA issued a rule (the NOx rule that requiredRule) 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. A number of utilities, including several AEP System companies, filed
petitions seeking a review of the final rule inThe NOx
Rule was upheld by the D.C. Circuit Court. In March 2000,The U.S. Supreme Court denied
a petition requesting its review of the D.C. Circuit Court issued a decision generally
upholdinglower court decision. The
compliance date for the NOx rule. The D.C. Circuit Court issued an order in August
2000 which extended the final compliance date toRule is May 31, 2004.
In
September 2000 following denial by the D.C. Circuit Court of a request
for rehearing, the industry petitioners, including the AEP System
companies, petitioned the U.S. Supreme Court for review, which was
denied.
In December 2000The NOx Rule required states to submit plans to comply with its
mandates. Federal EPA ruled that eleven states, including states in
which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating
units are located, failed to submit plans to comply with the
mandates of the NOx rule.compliance plans. This determinationruling means
that those states could face stringent sanctions within the next 24 months including limits on
construction of new sources of air emissions, loss of federal highway
funding and possible Federal EPA takeover of state air quality
management programs. In January 2000AEP and other utilities requested the D.C. Circuit
Court review this ruling.
Federal EPA also adopted a revised rule (the Section 126 Rule)
granting petitions filed by certain northeastern states under Section 126 of the Clean
Air Act seeking significant reductions in nitrogen oxide emissions
from utility and industrial sources.Act. The rule imposes emissions reduction requirements comparable to
the NOx ruleRule beginning May 1, 2003, for most of AEP's coal-fired
generating units. CertainAfter review, the D.C. Circuit Court upheld the
Section 126 Rule.
The D.C. Circuit Court instructed Federal EPA for both the NOx
Rule and the Section 126 Rule to justify methods used to allocate
allowances and project growth. AEP operating
companies and other utilities filed petitions for review inrequested the
D.C. Circuit Court. Briefing has been completed and oral argument was held in
December 2000.
In a related matter, on April 19, 2000,Court vacate the Section 126 Rule or suspend its May 2003
compliance date. They also asked the D.C. Circuit Court to retain
jurisdiction until Federal EPA complied with the Court's instructions.
The Texas Natural Resource Conservation Commission adopted rules
requiring significant reductions in NOx emissions from utility sources,
including those owned by CPL and SWEPCo. The rule's compliance date is May 2003
for CPL and May 2005 for SWEPCo.
In June 2000 OPCo announced that it was beginning a $175 million
installation ofMay 2001 selective catalytic reduction (SCR) technology (expected
to be operational in 2001) to
reduce NOx emissions on its two-unit 2,600
MWOPCo's Gavin Plant.Plant began operation. Construction
of SCR technology on Amos Plant Unit 3, which is jointly owned by OPCo
and APCo, and APCo's Mountaineer Plant is
scheduled to beginbegan in 2001. The Amos and
Mountaineer projects (expected to be completed in 2002) are estimated to
cost a total of $230 million ($145 million for APCo and $85 million for
OPCo). Construction of SCR technology on KPCo's Big Sandy Plant Unit 2
is scheduled for completion in May 2003 at an estimated cost of $107
million.
Preliminary estimates indicate that compliance for the AEP System
with the NOx rule
upheld by the D.C. Circuit Court as well as compliance withRule, the Texas Natural Resource Conservation Commission
rule and the Section 126 petitionsRule could result in required capital
expenditures oftotaling approximately $1.6 billion, including the amounts discussed in the previous paragraph,
for AEP Consolidated.billion. Estimated compliance
costs by registrant subsidiaries are as follows:
(in millions)
AEGCo $125
APCo 365
CPL 57
CSPCo 106
I&M 202
KPCo 140
OPCo 606
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the
actual cost to comply could be significantly different than the
preliminary estimates depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless any capital and
operating costs for additional pollution control equipment are recovered
from customers, through regulated rates and/or future market prices for
electricity where generation is deregulated, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
Other
AEP and its subsidiary registrants continue to be involved in
certain other matters discussed in the 2000 Annual Report.
M-8
REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS
The followingThis is aour combined presentation of management's discussion and
analysis of financial condition, contingencies and other matters forrelated to AEP
and certain of itsour subsidiary registrants. Management's discussion and analysis of results
of operations for AEPthe three and each of its subsidiary registrants for the
first quarter March 31,six month periods ended June 30, 2001 is
presented with theireach registrants' financial statements earlierelsewhere in this
document.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
year-to-date period were $336 million for AEP Consolidated. The following table
shows the additions by certain AEP subsidiary registrants.
Company Amount
------- ------
(in millions)
APCo $41
CPL 39
I&M 19
OPCo 65
SWEPCo 22
During the first three months of 2001, the AEP System issued $40 million
of notes payable due in 2004 with an interest rate of 6.73% and increased the
level of borrowing under the SEEBOARD Revolving Credit Facility by $89 million.
Retirements of debt were: first mortgage bonds totaling $120 million with
interest rates ranging from 5.91% to 6 3/8% due in 2001, $61 million of notes
payable with interest rates ranging from 6.20% to 7.5625% due in 2001 and a
decrease in short-term debt of $225 million.
The following table shows the retirements by certain AEP subsidiary
registrants:
Principal
Type Amount Interest Due
Company of Debt Retired Rate Date
------- ------- ----------- -------- ----
(in millions) (%)
APCo FMB $100 6-3/8 March 1, 2001
OPCo NP 30 6.20 January 31, 2001
PSO FMB 6 5.91 March 1, 2001
PSO FMB 5 6.02 March 1, 2001
PSO FMB 9 6.02 March 1, 2001
CPL redeemed $500,000 of its 8.00% trust preferred securities on
February 1, 2001.Financing Activity
On May 10, 2001, AEP issued $1.25 billion of debt consisting of $1
billion of senior notes and $250 million of putable callable notes. The interest
rate on the senior notes (due May 2006) is 6.125% and they are due in May. Additionally, AEP entered
into an interest rate swap for a portion of the proceeds, which effectively
converts a portion of this interest rate into LIBOR based floating rate through
2006. The putable callable notes (Series B notes) have a fixed interest rate of
5.5% until May 2003. At that date the Series B notes may be subject to call by a
third party for purchase and remarketing, in which case the maturity would
extend until May 2013. In the eventIf the Series B notes are not called for remarketing,
they will be redeemed.
On May 24, 2001, AEP must
redeem them.renewed its existing $2.5 billion 364-day revolving
credit facility. AEP renews this facility annually and uses it, together with an
existing $1 billion 5-year revolving credit which matures May 30, 2005 as a
backstop for AEP's commercial paper program.
On May 30, 2001, AEP Credit ceased to issue commercial paper and allowed
its $2 billion unsecured revolving credit facility to mature. A $1.5 billion
364-day note purchase agreement, which closed on May 30, 2001, replaced Credit's
funding needs. Bank-sponsored conduits are funding this facility.
Acquisitions
We continue to pursue a strategy of aligning assets with our wholesale
business model. The strategy is to selectively purchase assets which enhance
information flow from energy markets and support our trading and marketing
activity. The June 2001 purchase of Houston Pipe Line Company (HPL) complements
our existing Louisiana natural gas assets and will contribute to continued
growth in natural gas marketing and trading. The HPL acquisition includes 4,200
miles of pipeline with capacity of approximately 2.4 billion cubic feet per day
(Bcf/d), the operation of the Bammel Storage Facility, one of the largest
storage facilities in North America with a capacity of approximately 118 billion
cubic feet, and certain gas marketing contracts.
We used short-term borrowings of $727 million for the interim financing
of this acquisition. In the third quarter, we plan to replace this short-term
borrowing with long-term financing through a limited liability company. The
limited liability company expects to sell a non-controlling, preferred interest
to a third party for $750 million. The preferred interest will receive a
preferred return equal to an adjusted floating reference rate. The results of
operations, cash flows and financial position of the limited liability company
will be consolidated with AEP and treated as minority interests.
We announced our plan to acquire the MEMCO Barge Line. This acquisition
will continue our growth strategy to create value at various points along the
energy chain. With the addition of MEMCO, we will triple the size of our barge
fleet and become a full-service carrier throughout the U.S. inland waterways. We
expect this acquisition to add to both earnings and meaningful operational
insight into the fuel transportation portion of our business.
Total consolidated plant and property additions including capital leases
for the year-to-date period were $865 million. The following table shows the
additions by certain subsidiary registrants:
Company Amount
------- ------
(in millions)
APCo $108
CPL 110
I&M 41
OPCo 151
SWEPCo 96
Corporate Separation
On July 24, 2001, we filed an application with the FERC requesting
approval of proposed transactions necessary to complete a restructuring of our
regulated and unregulated operations. These transactions will enable us to
implement our plans for corporate separation and allow us to meet the
requirements of Texas and Ohio restructuring legislation. As part of the filed
plan, AEP intends to transfer the generation assets from the integrated business
for Ohio and Texas operating companies, which includes CSPCo, OPCo, CPL and WTU,
to unregulated companies. The filed plan also proposes amendments of the power
pooling agreements that affects all operating companies. Only those operating
companies that continue to exist as integrated utilities would be included in
the amended power pooling agreements, which would govern energy exchanges among
members and off system purchases and sales. In order to execute this separation,
we anticipate retiring first mortgage bonds at CSPCo, OPCo, CPL and WTU using
various methods including:
o call provisions for bonds that have an optional redemption
o open market purchases
o exchange offers
o tender offers
o defeasance
To date, we have not made decisions relating to securities other than
first mortgage bonds.
OTHER MATTERS
Industry Restructuring
As discussed in theour 2000 Annual Report, restructuring legislation has
been enacted in seven of theour eleven state
retail jurisdictions in which the AEP
domestic electric utility companies operate.enacted restructuring legislation. The legislation provides
for a transition from cost-based regulation of bundled electric service to
unbundled customer choice and market pricing for the supplygeneration of electricity. The following
paragraphs discuss significant events occurring in 2001 related to industry
restructuring.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001, customer choice of electricity supplier
began under the Ohio Act. In February 2001, one supplier announced its plan to
offer service to CSPCo's residential customers. Currently for residential
customers of OPCo, noThe PUCO approved alternative suppliers have registered with the PUCO under
the Ohio Act. Alternative suppliers have been approved(many of whom
remain inactive) to compete for CSPCo's and OPCo's commercial and industrial customers. Presently, virtually all
customers continue to be served by CSPCo and OPCo
continue to serve virtually all customers.
In accordance with a legislatively required
residentialthe Ohio Act, CSPCo and OPCo implemented rate
reductionreductions of 5% for the generation portion of residential rates and frozen
transition generationeffective
January 1, 2001. Retail rates, including fuel, rates from January 1, 2001 towill remain frozen until December
31, 2005 for all classesor the PUCO determines that a competitive market exists.
On January 16, 2001, Shell Energy Services Company filed a Notice of
customers.
As discussed in Note 7 of the Notes to Financial Statements in the 2000
Annual Report, CSPCo and OPCo filed an appealAppeal with the Ohio Supreme Court related to a tax expense issue which would result in duplicate expense of $40
million and $50 million, respectively, for a twelve month period beginning on
May 1, 2001. One of the items CSPCo and OPCo requested was a stay of the PUCO
ordered implementation date (May 1, 2001) for an excise tax credit rider. On
April 13, 2001, the Ohio Supreme Court denied the companies' stay request.
Management does not expect the Ohio Supreme Court to hear arguments on the
merits of this case until the fourth quarter of 2001.
One of the intervenors at the hearings forchallenging PUCO's approval of aour transition
settlement agreement (whose request for rehearing was denied by the PUCO) has
filed with the Ohio Supreme Court for review of the settlement agreement
including OPCo's and CSPCo's recovery of their transition generation-related regulatory assets. Management is
unable to predict the outcome of this litigation. The resolution of this matter
could negatively impact our future results of operations.operations and cash flows.
Virginia Restructuring - Affecting AEP and APCo
In connectionaccordance with aits restructuring law, the Virginia law that provides forjurisdiction
will begin a transition to choice of electricity supplier for retail customers
beginning on January 1, 2002
(which is described in Note 72002. The Virginia restructuring law requires filings to be made
that outline the functional separation of the Notes to Financial Statements in the 2000
Annual Report), APCo was required to make a filing with the Virginia SCC to
unbundle rates and separate generation from transmission and
distribution. On
January 3, 2001,distribution and a rate unbundling plan. APCo filed its corporate separation plan and rate
unbundling plan with the Virginia SCC, which included a 1999 costSCC. Hearings are scheduled for October 2001.
Presently, capped rates are sufficient to recover generation-related regulatory
assets. We are unable to predict if the outcome of service study required
by the Virginia SCC's regulations. That filing indicated that additional
information about APCo's proposed corporate separation plan would be filed at a
later date.
On April 11, 2001,hearings will result in
the Virginia SCC directed APCoability to file the
additional information required to complete its corporate separation filing when
that information becomes available. APCo was also directed to file, by May 15,
2001, all information necessary for the Virginia SCC to fully consider a
functional separation of APCo, by divisions. If in connection with the
transition process, the Virginia SCC were to reduce APCo's rates or deny
recovery of generation relatedrecover generation-related regulatory assets, it would have an adverse
effect on results of operations.assets. Arkansas
Restructuring - Affecting AEP and SWEPCo
In 1999 Arkansas enacted legislation was enacted in Arkansas that will ultimatelyto restructure theits electric
utility industry. In February 2001 the Arkansas General Assembly passed
legislation that was signed into law by the Governor thatto delay restructuring. The
legislation extended the date for the start of retail electric retail competition to
October 1, 2003 and provided the Arkansas Commission with the authority to delay
that date for up to two additional years.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
The Texas Restructuring Legislation gives Texas customers of
investor-owned utilities the opportunity to
choose their electric provider and eliminates the fuel clause reconciliation
process beginning January 1, 2002. A 2004 true-up proceeding will determine the
amount of stranded costs if any,
including the final fuel recovery, net regulatory asset
recovery, certain
environmental costs, accumulated excess earnings offsets and other issues.
As discussed in theour 2000 Annual Report, the method used to determine
initial stranded costs to be recovered beginning on January 1, 2002 has been
controversial. Duringis still
subject to challenge. In March 2000 CPL submitted estimatesa $1.1 billion estimate of
stranded costs andcosts. After hearing on the submission, the PUCT held hearings. Inissued in February
2001 the PUCT issued an interim decision determining an initial amount of stranded costs for CPL
of negative $580 million. In April 2001 the PUCT ruled that its current estimate
of CPL's stranded costs was negative $615 million. CPL disagreesWe disagree with the ruling
that it
has a stranded benefit and hashave requested a rehearing.
In April 2001 the PUCT issued an order requiring CPL to reduce future
distribution rates by $54.8 million over a five-year period in order to return
estimated excess earnings for 1999, 2000 and 2001. The Texas Restructuring
Legislation intended that excess earnings would be used to reduce stranded cost.costs. Final stranded
cost amounts and the treatment of excess earnings will be determined in the 2004
true-up proceeding. TheCurrently the PUCT currently estimates that CPL will have no stranded
costcosts and has ordered the rate reduction to return excess earnings, pending the outcome of the 2004 true-up proceeding. Management
believesearnings. We believe
that CPL will have stranded costs in 2004, and that the current treatment of
excess earnings will be amended at that time. CPL expensed excess earnings
amounts in 1999, 2000 and 2000.2001. Consequently, the April order has no effect on
reported net income.
As discussed in Note 7 of our 2000 Annual Report, the PUCT authorized
the issuance of up to $797 million of bonds to securitize certain of CPL's
regulatory assets. The PUCT's order that authorized the securization was
appealed to the Supreme Court of Texas. On June 6, 2001, the Supreme Court
upheld the PUCT's securitization order. The plantiffs have requested a
rehearing. We expect the court to dismiss this request. We plan to issue the
securitization bonds prior to January 1, 2002.
On August 3, 2001, the Staff of the PUCT filed a Petition seeking a
determination of whether electric operations in the SPP are ready for
competition. This Petition affects SWEPCo and part of WTU. Under the Texas
Restructuring Legislation, the PUCT can delay the start of competition if the
market and its participants are not prepared for competition. Under the law,
certain situations indicate this lack of preparedness, and in Staff's opinion,
those indicators are present for the SPP area. The Petition seeks an expedited
process to achieve a final PUCT determination by November 1, 2001. We are
evaluating the ramifications of a potential delay in the January 1, 2002 start
date of competition for SWEPCo's and WTU's Texas operations in the SPP.
A Texas settlement agreement in connection with the AEP andour merger with CSW merger
permits CPL to apply for regulatory purposes up to $20 million of previously identified STP ECOM plant
assets a year in 2000 and 2001 to reduce any excess earnings, if any. For book purposes,earnings. STP ECOM plant
assets will be depreciated in accordance with GAAP, on a systematic and rational
basis unless impaired.basis. To the extent excess earnings exceed $20 million in 2001, CPL will
establish a regulatory liability or reduce regulatory assets by a charge to
earnings.
Beginning January 1, 2002, fuel costs will no longer be subject to PUCT
fuel reconciliation proceedings under the Texas Restructuring Legislation.
Consequently, CPL, SWEPCo and WTU will file a final fuel reconciliation with the
PUCT to reconcile their fuel costs through the period ending December 31, 2001.
These final fuel balances will be included in each company's 2004 true-up
proceeding. Fuel costs have been reconciled by CPL, SWEPCo and WTU through June
30, 1998, December 31, 1999 and June 30, 1997, respectively. WTU is currently
reconciling its fuel through June 2000. At March 31, 2001, CPL's, SWEPCo's and
WTU's Texas jurisdictional unrecovered deferred fuel balances were $125 million,
$25.4 million and $66.8 million, respectively. The elimination of the fuel
clause recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to the
risk of fuel market price increases and could adversely affect future results of
operations beginning in 2002.
In response to CPL's request to implement an interim fuel surcharge to
collect underrecovered fuel costs, the PUCT voted in April 2001 to defer
implementation of the requested fuel surcharge until CPL's final fuel
reconciliation as part of its 2004 true-up proceeding. CPL has requested a
rehearing on the surcharge denial. Based upon the decision in the CPL fuel
surcharge proceeding, management expects that the PUCT may also defer recovery
of requested fuel surcharges for SWEPCo and WTU currently pending before PUCT
until their 2004 true-up proceedings. Final unrecovered deferred fuel balances
at December 31, 2001 will be included in each company's 2004 true-up proceeding.
If the final fuel balances or any amount incurred but not yet reconciled are not
recovered, it would have a negative impact on results of operations.
In the event CPL, SWEPCo, and WTU are unable, after the 2004 true-up
proceeding, to recover all or a portion of their generation-related regulatory assets, unrecovered
fuel balances, stranded costs and other restructuring related costs, it could
have a material adverse effect on results of operations, cash flows and possibly
financial condition.
LitigationMichigan Restructuring - ----------Affecting AEP and I&M
As discussed in the 2000 Annual Report, the Michigan Legislation gave
the MPSC broad powers to implement customer choice. In compliance with MPSC
orders, on June 5, 2001, I&M filed its proposed unbundled rates, open access
tariffs and terms of service. MPSC action on the filing is expected in 2001 with
competition commencing on January 1, 2002.
We do not expect to incur material tangible asset impairments or
regulatory asset write-offs. If we are not permitted to recover all or a portion
of our generation-related regulatory assets, unrecorded decommissioning
obligation, stranded costs and other implementation costs, it could have a
material adverse effect on our results of operations, cash flows and possibly
financial condition.
Oklahoma Restructuring - Affecting AEP and PSO
In June 2001 the Oklahoma Governor signed into law a bill that delayed
retail electric competition indefinitely. Under previously approved legislation,
the start date for Oklahoma customer choice had been July 1, 2002.
Litigation
Shareholders' Litigation - Affecting AEP
On June 23,In 2000 a complaint wasfive complaints were filed in the U.S. District Court for
the Eastern District of New Yorkagainst us seeking unspecified
compensatory damages against AEP and four former or present officers. The individual plaintiff also
seeks certification as the representativefor alleged violations of a class consisting of all persons
and entities who purchased or otherwise acquired AEP common stock between July
25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly
violated federal securities laws by disseminating materially false and
misleading statements concerning, among other things, the undisclosed materially
impaired condition of the Cook Plant, AEP's inability to properly monitor,
manage, repair, supervise and report on operations at the Cook Plant and the
materially adverse conditions these problems were having, and would continue to
have, on AEP's deteriorating financial condition, and ultimately on AEP's
operations, liquidity and stock price. Four other similar class action
complaints have been filed and the court has consolidated the five cases. The
plaintiffs filed a consolidated complaint pursuant to this court order. This
case has been transferred to the U.S. District Court for the Southern District
of Ohio. On March 5, 2001, AEP and the individual defendants filed a
comprehensive motion to dismiss all claims against all defendents in the
consolidated cases. The Court has set oral arguments of the motion for June 7,
2001. Although management believes(see Note
8). We believe these shareholder actionscomplaints are without merit and intendsintend to
continue to oppose them vigorously, management cannot predict thethem. The outcome of this litigation or its impact on our
results of operations, cash flows or financial condition.condition cannot be predicted.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
CPL hasWe have been involved in litigation regarding municipal franchise fees
in Texas as a result of a class action suit filed by the City of San Juan, Texas
in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and
seeks damage of up to $300 million plus attorney's fees. CPL filed a
counterclaim for overpayment of franchise fees.
During 1997, 1998 and 1999 theThe litigation moved procedurally through the Texas Court System and was
sent to mediation without resolution. In 1999 a class notice was mailed to eachCPL notified the cities it serves of the
pending class action suit. If a final decision determines an underpayment of
franchise fees, CPL has pledged to extend that final decision to cities served by CPL.
Over 90 of the 128 citieswho
declined to participate in the lawsuit. However, CPL
has pledged that if any final, non-appealable court decision in the litigation
awards a judgement against CPL for a franchise underpayment, CPL will extend the
principles of that decision, with regard to the franchise underpayment, to the
cities that declined to participate in the litigation. In December 1999, thesuit. The court ruled that the class of
plaintiffs would consist of approximately 30 cities. Acities and set a trial date for
October 2001 has been set.
Although management believes2001.
We believe that it haswe have substantial defenses to the
cities' claims and intends to defend itself against the cities' claims
and plan to pursue its counterclaims vigorously, managementour counterclaims. However, we cannot predict the outcome of
this litigation or its impact on our results of operations, cash flows or
financial condition.
Lignite Mining Agreement Litigation - Affecting AEP and SWEPCo
In May 2001 SWEPCo settled ongoing litigation concerning lignite mining
in Louisiana. As discussed in Note 8 of the Notes to Financial Statements in the 2000 Annual Report, SWEPCo has been
involved in litigation concerning the mining of lignite from jointly owned
lingitelignite reserves. SWEPCo and CLECO are each a 50%
ownerjoint owners of Dolet Hills Power Station
Unit 1 and own lignite reserves in the Dolet Hills area of northwestern
Louisiana. In 1982 SWEPCo and CLECO entered into a lignite mining agreement with
DHMV, a partnership for the mining and delivery of lignite from these reserves.
Since 1997 SWEPCo and CLECO have been involved in litigation with DHMV and its
partners in U.S. District Court for the Western
District of Louisiana.partners. In April 2000 the parties agreed to settle the litigation. As part of the
settlement, a subsidiary of SWEPCo will purchasepurchased DHMV's interest in the mining assets and will assumemining
rights for $86 million and assumed the related obligations for mine reclamation.reclamation
(See Note 3). The settlement agreement would givegives CLECO the option
beginning July 1, 2002, to acquire up to a
50% interest in the mining assets.
The litigation has been stayed to provide the parties a reasonable period of
time to complete the settlement process. Management believes that the resolution
of this matter will not have a material effect on results of operations, cash
flows or financial condition.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, I&M,
and OPCo
As discussed in our 2000 Annual Report, Federal EPA and a number of
states alleged that AEP, APCo, CSPCo, I&M, and OPCo modified certain generating
units in violation of the Clean Air Act. The Federal EPA filed complaints
against the companies in U.S. District Court for the Southern District of Ohio
in 1999. 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. AEP, APCo, CSPCo, I&M, and OPCo have been involved in litigation
regarding generating plant emissions under the Clean Air Act. In 1999 Notices of
Violation were issued and complaints were filed by Federal EPA in various U.S.
District Courts alleging APCo, CSPCo, I&M, OPCo and a number of unaffiliated
utilities made modifications to generating units at certain of their coal-fired
generating plants over the course of the past 25 years that extended unit
operating lives or increased unit generating capacity without a preconstruction
permit in violation of the Clean Air Act. The complaint was amended in March
2000 to add allegations for certain generating units previously named in the
complaint and to include additional generating units previously named only in
the Notices of Violation in the complaint.
A number of northeastern and eastern states were granted leave to
intervene in the Federal EPA's action against the AEP System under the Clean Air
Act. A lawsuit against power plants owned by certain AEP System operating
companies alleging similar violations to those in the Federal EPA complaint and
Notices of Violation was filed by a number of special interest groups and has
been consolidated with the Federal EPA action.
The
Clean Air Act authorizes civil penalties of up to $27,500 per day per violation
at each generating unit ($25,000 per day prior to January 30, 1997).
Civil penalties, if ultimately imposed by the court, and the cost of any
required new pollution control equipment, if the court accepts Federal EPA's
contentions, could be substantial.
In May 2000 the AEP System companies filed motions to dismiss all or
portions of the complaints. On March 28 and 30, 2001 the Court issued orders
granting the motions in part and denying them in part. TheDistrict Court ruled claims for civil penalties based
on activities that occurred more than five years before the filing date of the
complaints, were filed cannot be imposed. ClaimsThere is no time limit on claims for injunctive
relief are not subject to a time limit.
Onrelief.
In February 23, 2001 the plaintiffs filed a motion for partial summary
judgment seekingrequested a determination that four
projects undertaken on units at Sporn, Cardinal and Clinch River plants do not
constitute "routine maintenance, repair and replacement" as used in the Clean
Air Act. On April 9, 2001,Our request to allow time for additional discovery before responding to
the AEP
System companies filed a motion requesting the Court deny plaintiffs' motion as
premature, and issue an order allowing discovery to continue. Management
believes itsaction was granted. We believe our maintenance, repair and
replacement activities were in conformity with the Clean Air Act and intendsintend to
vigorously pursue itsour defense.
In the event the AEP System companiesIf 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 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.condition.
In December 2000 Cinergy Corp., an unaffiliated utility, which operates
certain plants jointly owned by CSPCo, reached a tentative agreement with Federal
EPA and other parties to settle
litigation regarding generating plant emissions under the Clean Air Act.
Negotiations are continuing between the parties in an attempt to reach final settlement terms.
Cinergy's settlement could impact the operation of Zimmer Plant and W.C.
Beckjord Generating Station Unit 6 which are
owned(owned 25.4% and 12.5%, respectively, by
CSPCo.CSPCo). Until a final settlement is reached, CSPCo will be unable to determine
the settlement's impact on its jointly owned facilities and its future earnings
and cash flows.
NOx Reductions - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo
Federal EPA issued a rule (the NOx rule that requiredRule) 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. A number of utilities, including
several AEP System companies, filed petitions seeking a review of the final rule
inThe NOx Rule was
upheld by the D.C. Circuit Court. In March 2000,The U.S. Supreme Court denied a petition
requesting its review of the D.C. Circuit Court issued a
decision generally upholdinglower court decision. The compliance date for the
NOx rule. The D.C. Circuit Court issued an
order in August 2000 which extended the final compliance date toRule is May 31, 2004.
In September 2000 following denial by the D.C. Circuit Court of a request for
rehearing, the industry petitioners, including the AEP System companies,
petitioned the U.S. Supreme Court for review, which was denied.
In December 2000The NOx Rule required states to submit plans to comply with its
mandates. Federal EPA ruled that eleven states, including states in which
AEGCo's, APCo's, CSPCo's, I&M's KPCo's and OPCo's generating units are located, failed to submit
plans to comply with the mandates of the NOx rule.compliance plans. This determinationruling means that those states could face stringent
sanctions within
the next 24 months including limits on construction of new sources of air emissions, loss
of federal highway funding and possible Federal EPA takeover of state air
quality management programs. In January 2000AEP and other utilities requested the D.C. Circuit
Court review this ruling.
Federal EPA also adopted a revised rule (the Section 126 Rule) granting
petitions filed by certain northeastern states under Section 126 of the Clean Air Act
seeking significant reductions in nitrogen oxide emissions from utility and
industrial sources.Act. The rule
imposes emissions reduction requirements comparable to the NOx ruleRule beginning
May 1, 2003, for most of AEP'sour coal-fired generating units. CertainAfter review, the D.C.
Circuit Court upheld the Section 126 Rule.
The D.C. Circuit Court instructed Federal EPA for both the NOx Rule and
the Section 126 Rule to justify methods used to allocate allowances and project
growth. AEP operating companies and other utilities filed petitions for
review inrequested the D.C. Circuit Court. Briefing has been completed and oral argument
was held in December 2000.
In a related matter, on April 19, 2000,Court vacate the
Section 126 Rule or suspend its May 2003 compliance date. They also asked the
D.C. Circuit Court to retain jurisdiction until Federal EPA complied with the
Court's instructions.
The Texas Natural Resource Conservation Commission adopted rules
requiring significant reductions in NOx emissions from utility sources,
including those owned by CPL and SWEPCo. The rule's compliance date is May 2003 for CPL
and May 2005 for SWEPCo.
In June 2000 OPCo announced that it was beginning a $175 million
installation ofMay 2001 selective catalytic reduction (SCR) technology (expected to be
operational in 2001) to reduce NOx
emissions on its two-unit 2,600 MWOPCo's Gavin Plant.Plant began operation. Construction of SCR technology
on Amos Plant Unit 3, which is jointly owned by OPCo and APCo, and APCo's
Mountaineer Plant is scheduled to beginbegan in 2001. The Amos and Mountaineer projects (expected to
be completed in 2002) are estimated to cost a total of $230 million ($145
million for APCo and $85 million for OPCo). Construction of SCR technology on
KPCo's Big Sandy Plant Unit 2 is scheduled for completion in May 2003 at an
estimated cost of $107 million.
Preliminary estimates indicate that our compliance with the NOx rule upheld
by the D.C. Circuit Court as well as compliance withRule,
the Texas Natural Resource Conservation Commission rule and the Section 126 petitionsRule
could result in required capital expenditures oftotaling approximately $1.6
billion, including the
amounts discussed in the previous paragraph, for AEP Consolidated.billion.
The following table shows the estimated compliance cost for certain of
AEP's subsidiary registrants.
Company Amount
------- ------
(in millions)
APCo $365
CPL 57
I&M 202
OPCo 606
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the preliminary estimates
depending upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless any capital or operating costs for additional pollution
control equipment are recovered from customers, through regulated rates and/or
future market prices for electricity where generation is deregulated, they will have an adverse effect
on future results of operations, cash flows and possibly financial condition.
N-1
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCoNew Accounting Standards
FASB's Derivative Implementation Group (DIG) Guidance for SFAS 133
"Accounting for Derivative Instruments and WTU
AEPHedging Activities"
DIG guidance for fuel supply (for example, coal and gas) and electricity
contracts becomes effective in the third quarter. DIG guidance concluded that
fuel supply contracts with volumetric optionality cannot qualify as a major power producernormal
purchase or sale and provided guidance for determining when electricity
contracts can qualify as a tradernormal purchase or sale.
Predominantly all of wholesale electricity and
natural gas has certain market risks inherent in its business activities. The
trading of electricity and naturalAEP's contracts for coal, gas and relatedelectricity which
are recorded on a settlement basis do not meet the criteria of a financial
derivative instrument and are thereby exempt from DIG guidance described above.
The few contracts that qualify as financial derivative instruments exposesare not
expected to materially affect AEP's results of operations, cash flows or
financial condition.
SFAS 141 and SFAS 142
In July 2001 the FASB 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 and other intangible
assets with indefinite lives be tested for impairment annually and not be
subjected to amortization. The provisions of SFAS 142 will apply to us beginning
January 1, 2002. The amortization of goodwill reduced our net income by $23
million for the six months ended June 30, 2001. We have not quantified the
impact of adopting other provisions of these standards.
QUALITATIVE AND QUANTITATIVE DISCLOSURES ON RISK
RISK MANAGEMENT
AEP and its registrant subsidiaries are subject to risks in
their day to day operations. The risks and correlating strategies are:
Risk Description Strategy
- ---- ----------- --------
Market Risk Volatility in commodity prices Trading and hedging
Interest Rate Risk Changes in Interest rates Hedging
Foreign Exchange Risk Fluctuations in foreign currency rates Hedging
Credit Risk Non-performance on contracts with Guarantees, Collateral
counter parties
AEP's strategies of trading, hedging and credit risk management to
mitigate various risks have not materially
changed since December 31, 2000.
Commodity Price Risk
We employ physical forward purchase and sale contracts, exchange futures
and options, over-the-counter options, swaps, and other derivative contracts to
offset market risk. MarketAEP's internationally based electric distribution utilities
hedge market risk represents the risk of loss
that may occur due tothrough forward commodity contracts.
Interest Rate Risk
Fair value and cash flow hedge contracts mitigate changes in commodityinterest
rates on short and long-term debt of AEP, KPCo, and I&M. CitiPower uses
interest rate swaps for the same purpose.
Foreign Exchange Risk
AEP, KPCo, and OPCo employ cash flow forward hedge contracts to lock-in
prices on purchased assets denominated in foreign currencies. International
subsidiaries use currency swaps to hedge fluctuations in debt transactions. We
do not hedge all foreign currency exposure.
Credit Risk
AEP limits credit risk by accepting primarily investment grade counter
parties. We also require cash deposits, letters of credit and affiliate
guarantees as collateral from certain counter parties in case of adverse market
pricesconditions.
QUANTITATIVE MARKET RISK
We employ policies and rates. Policies and
procedures have been established to identify, assess and manage market
risk exposures includingexposure. One procedure is the use of a risk measurement model which calculates Value at Risk (VaR).
The VaR is basedused daily to measure and monitor trading risk. VaR operates on the
variance - covariance method using historical prices to estimate volatilitiesvolatility and
correlationscorrelation and assumingassumes a 95% confidence level and a one-day holding period.
Throughout
The following table represents the year ending
December 31, 2000 thehigh, average high, and low VaRs in the wholesale electricity
and gas trading portfolio were $10 million, $32 million, and $1 million,
respectively. The average, high, and low VaRs for the quarter ending March 31,
2001 were $14 million, $25 million,AEP's
electric and $6 million, respectively. Based on this
VaR analysis, at March 31, 2001 a near term typical change in commodity prices
is not expected to have a material effect on AEP's results of operations, cash
flows or financial condition. The following table shows the high and average
U.S. electricity market risk as measured by VaR allocated to the AEP registrant
subsidiaries based upon the AEP System'sgas trading activities in the U.S. Low VaR
is excludedand electric trading for December 31, 2000 because all companies are under $1 million.its registrant
subsidiaries. VaR for AEP and Registrant Subsidiaries:
March 31Six Months Ended Year Ending
June 30, December 31,
2001 2000
---- ----
High Average Low High Average High AverageLow
(in millions) (in millions)
AEP $25 $14 $6 $32 $10 $1
APCo $1 $6 $3 $2 $66 2 1 6 2 -
CPL - 1 - - 4 1 4-
CSPCo 3 1 - 3 2 1 3-
I&M 4 1 - 4 2 1 4-
KPCo - 1 1 - 1 - -
OPCo 5 2 1 5 2 2 5-
PSO - 1 - 1- 3
SWEPCo - 1 -
SWEPCo 1 - - 4 1 -
WTU - - - 1 - 1
Investments in foreign ventures expose AEP to risk of foreign currency
fluctuations. AEP's exposure to-
Near term changes in foreign currency exchange rates
related to these foreign ventures and investments iscommodity prices are not expected to be
significant for the foreseeable future.
AEP is exposed to changes in interest rates primarily due to short-and
long-term borrowings to fund its business operations. The potential loss in fair
value asmaterially
affect our results of March 31, 2001 has not materially changed since year end.operations, cash flows and financial conditions.
O-1
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
AEP
On May 15, 2001, the Louisiana Department of Environmental Quality
issued a Compliance Order and WTUNotice of Potential Penalty to LIG's Plaquemine
Gas Processing Plant alleging violations of regulations and finding certain
deficiencies with respect to the Risk Management Plan developed for the plant.
Reference is made to pages 28 and 29 of the Annual Report on Form 10-K
for the year ended December 31, 2000 for a discussion of hazardous air
pollutants. On July 26, 2001, upon motion by Federal EPA, the U.S. Court of
Appeals for the District of Columbia Circuit dismissed the petition for review
filed by utility industry groups in February 2001 relating to Federal EPA's
action classifying coal-fired electric generating units as "major sources" of
hazardous air pollutants.
AEP and SWEPCo
On May 22, 2001, Federal EPA, Region 6, issued Findings of Violation and
an Order for Compliance to SWEPCo's Wilkes Power Plant alleging violations of
waste water discharge permit limits and directing SWEPCo to undertake corrective
action.
Item 4. Submission of Matters to a Vote of Security Holders.
---------------------------------------------------
AEP
The annual meeting of shareholders was held in Corpus Christi, Texas on
April 25, 2001. The holders of shares entitled to vote at the meeting or their
proxies cast votes at the meeting with respect to the following two matters, as
indicated below:
1. Election of fourteen directors to hold office until the next
annual meeting and until their successors are duly elected. Each
nominee for director received the votes of shareholders as
follows:
Number of Shares Number of
Nominee Voted For Votes Withheld
E. R. Brooks 262,469,347 3,811,294
Donald M. Carlton 262,727,287 3,553,354
John P. DesBarres 262,695,391 3,585,250
E. Linn Draper, Jr. 262,682,299 3,598,342
Robert W. Fri 262,558,070 3,722,571
William R. Howell 215,949,995 50,330,646
Lester A. Hudson, Jr. 262,626,424 3,654,217
Leonard J. Kujawa 262,546,000 3,734,641
James L. Powell 257,694,138 8,586,503
Richard L. Sandor 262,658,024 3,622,617
Thomas V. Shockley, III 262,622,071 3,658,570
Donald G. Smith 262,633,432 3,647,209
Linda Gillespie Stuntz 262,613,798 3,666,843
Kathryn D. Sullivan 262,429,116 3,851,525
2. Approve the appointment by the Board of Directors of Deloitte & Touche LLP as independent auditors of AEP
for the year 2001. The proposal was approved by a vote of the shareholders as follows:
Votes FOR 262,196,889
Votes AGAINST 2,151,465
Votes ABSTAINED 1,932,287
Broker NON-VOTES* 0
*A non-vote occurs when a nominee holding shares
for a beneficial owner votes on one proposal, but does not vote on
another proposal because the nominee does not have discretionary voting
power and has not received instructions from the beneficial owner.
APCo
The annual meeting of stockholders was held on April 24, 2001 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR
each of the following seven persons for election as directors and there were no
votes withheld and such persons were elected directors to hold office for one
year or until their successors are elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley, III
Henry W. Fayne Susan Tomasky
William J. Lhota J. H. Vipperman
Armando A. Pena
No other business was transacted at the meeting.
CPL
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 12, 2001, the Texas Natural Resource Conservation Commission
("TNRCC")following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley III
Henry W. Fayne Susan Tomasky
William J. Lhota J. H. Vipperman
Armando A. Pena
I&M
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 24, 2001, the following thirteen persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
Karl G. Boyd Thomas V. Shockley, III
E. Linn Draper, Jr. Jackie S. Siefker
Henry W. Fayne David B. Synowiec
Marc E. Lewis Susan Tomasky
William J. Lhota J. H. Vipperman
Susanne M. Moorman W. E. Walters
John R. Sampson
OPCo
The annual meeting of shareholders was held on May 1, 2001 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,473 votes were cast FOR
each of the following seven persons for election as directors and there were no
votes withheld and such persons were elected directors to hold office for one
year or until their successors are elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley, III
Henry W. Fayne Susan Tomasky
William J. Lhota J. H. Vipperman
Armando A. Pena
No other business was transacted at the meeting.
SWEPCo
Pursuant to action by written consent in lieu of an annual meeting of
the sole shareholder dated April 11, 2001, the following seven persons were
elected directors to hold office for one year or until their successors are
elected and qualify:
E. Linn Draper, Jr. Thomas V. Shockley III
Henry W. Fayne Susan Tomasky
William J. Lhota J. H. Vipperman
Armando A. Pena
Item 5. Other Information.
AEP and APCo
Reference is made to pages 17 and 18 of the Annual Report on Form 10-K
for the year ended December 31, 2000 for a discussion of APCo's proposed
transmission facilities. On May 31, 2001, the Virginia SCC issued an order
approving the Wyoming-Jacksons Ferry Project. On August 6, 2001, the U.S. Forest
Service published in the Federal Register a Notice of Enforcement ActionIntent to WTU's Oak Creek Power Station
alleging violations of limits containedprepare a
Supplemental Draft Environmental Impact Statement (SDEIS). The Forest Service
has scheduled three public meetings in August 2001 in the water discharge permit applicableVirginia area to be
crossed by the plant.route to Jacksons Ferry. The notice referencesForest Service expects to file the
potentialSDEIS with Federal EPA for corrective action,
administrative penalties, or both. A meeting has been scheduledpublic review by April 2002. Following public
comment, the Forest Service expects to file the final EIS with the TNRCC
to explore resolutionFederal EPA in
October 2002 and then issue a Record of this matter.Decision.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
EhibitExhibit 12 - Computation of Consolidated Ratio of Earnings to
Fixed Charges.
(b) Reports on Form 8-K:
Companies Reporting Date of Report Item Reported
AEP April 24, 2001 Item 7. Financial Statements and
Exhibits
AEP May 3, 2001 Item 7. Financial Statements and
Exhibits
AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
No reports on Form 8-K were filed during the quarter ended March 31,June 30,
2001.
P-1
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto
---------------------- --------------------------------------------------- -----------------------------------
Armando A. Pena Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer
AEP GENERATING COMPANY
APPALACHIAN POWER COMPANY
CENTRAL POWER AND LIGHT COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
WEST TEXAS UTILITIES COMPANY
By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto
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Armando A. Pena Joseph M. Buonaiuto
Vice President andTreasurer Controller and Chief Accounting Officer
Treasurer
Date: May 11,August 10, 2001