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
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 SEPTEMBER 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) 31-4271000
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 JulyOctober 31, 2001 was 322,201,830.322,235,005.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 30, 2001
CONTENTS
Page
Glossary of Terms i - iiiii
Forward-Looking Information iviii
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-3 - A-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-3 - D-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-3 - F-7
Kentucky Power Company
Management's Narrative Analysis of Results of Operations G-1 - G-2
Financial Statements G-3 - G-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-3 - I-6
Southwestern Electric Power Company and Subsidiaries:
Management's Discussion and Analysis of Results of Operations J-1 - J-2
Consolidated Financial Statements J-3 - J-6
West Texas Utilities Company:
Management's Narrative Analysis of Results of Operations K-1 - K-2
Financial Statements K-3 - K-6
Footnotes to Financial Statements L-1 - L-12L-14
Item 2. Registrants' Combined Management Discussion and Analysis of
Financial Condition, Contingencies and Other Matters M-1 - M-8M-7
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-4O-1
(a) Exhibits
Exhibit 12
(b) Reports on Form 8-K
SIGNATURE P-1
This combined Form 10-Q is separately filed by American Electric Power
Company, Inc., AEP Generating Company, Appalachian Power Company, Central Power
and Light Company, Columbus Southern Power Company, Indiana Michigan Power
Company, Kentucky Power Company, Ohio Power Company, Public Service Company of
Oklahoma, Southwestern Electric Power Company and West Texas Utilities Company.
Information contained herein relating to any individual registrant is filed by
such registrant on its own behalf. Each registrant makes no representation as to
information relating to the other registrants.
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.........................Credit, Inc.................... AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated and unaffiliated domestic electric utility companies.
AEP East electric operating
companies.......................... APCo, CSPCo, I&M, KPCo and OPCo.
AEPR............................... AEP Resources, Inc.
AEP System or the System........... The American Electric Power System, an integrated electric utility system, owned and
operated by AEP's electric utility subsidiaries.
AEPSC.............................. American Electric Power Service Corporation, a service subsidiary providing management and
professional services to AEP and its subsidiaries.
AEP Power Pool..................... AEP System Power Pool. Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the
generation, cost of generation and resultant wholesale system sales of the member
companies.
AEP West electric operating
companies.......................... CPL, PSO, SWEPCo and WTU.
AFUDC.............................. Allowance for funds used during construction, a noncash nonoperating income item that is
capitalized and recovered through depreciation over the service life of domestic
regulated electric utility plant.
Alliance RTO....................... Alliance Regional Transmission Organization, an ISO formed by AEP and four unaffiliated
utilities.
Amos Plant......................... John E. Amos Plant, a 2,900 MW generation station jointly owned and operated by APCo and
OPCo.
APCo............................... Appalachian Power Company, an AEP electric utility subsidiary.
Arkansas Commission................ Arkansas Public Service Commission.
Buckeye............................ Buckeye Power, Inc., an unaffiliated corporation.
CLECO.............................. Central Louisiana Electric Company, Inc., an unaffiliated corporation.
COLI............................... Corporate owned life insurance program.
Cook Plant......................... The Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CPL................................ Central Power and Light Company, an AEP electric utility subsidiary.
CSPCo.............................. Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW............................... Central and South West Corporation, a subsidiary of AEP.
CSW Energy......................... CSW Energy, Inc., an AEP subsidiary which invests in energy projects and builds power plants.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit.
DHMV............................... Dolet Hills Mining Venture.
DOE................................ United States Department of Energy.
EBIT............................... Earnings Before Interest Charges and Income Taxes.
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 ...............................FMB................................ First Mortgage Bond.
FUCOs.............................. Foreign Utility Companies.
i
Bonds
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.
LIBOR.............................. London InterBank Offered Rate.
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;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........................ 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.CSPCo.
iii
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
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
Net income increased by $241$62 million or 7520 cents per share for the
quarter and by $367$430 million or $1.13$1.33 per share year-to-date predominatelyyear-to-date. The results for the
quarter reflect a favorable variance from an extraordinary loss from
deregulation recorded in the third quarter of 2000 and an accounting change due
to strong performance fromnew accounting rules recorded in the wholesale business. Benefiting from an increased
contribution from wholesale natural gas trading activities and the favorable
impactthird quarter of the return to service of the Cook Plant, the earnings from our
wholesale business increased 116 percent over the same quarter last year. The
effects of deregulation resulted in a $57 million unfavorable variance between
periods from2001. Income before
extraordinary items and this factor partially offsets our improvedcumulative effect of the accounting change was unchanged
for the quarter. In the year-to-date period income before extraordinary items
and the cumulative effect of the accounting change increased by $425 million or
$1.31 per share. The impact on comparative net income from the extraordinary
items and the cumulative effect of the accounting change was $5 million
favorable for the year-to-date period.
Our wholesale business results.continued to perform well despite a slowing
economy that reduced both wholesale energy margins and energy use by industrial
customers. Our wholesale business, which includes generation, retail sales of
power and wholesale power and gas marketing and trading and gas pipeline and
storages services, continued to be a significant contributor to our earnings
despite lower market prices and reduced volatility. Although our power marketing
and trading operations had an adverse effect on the third quarter, our gas
marketing and trading more than offset the decline in power trading. For the
year-to-date period, earnings from both power and gas marketing and trading
improved.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
SecondThird Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Revenues $6,391 78 $14,439 101$6,777 58 $21,216 82
Fuel and PurchasePurchased Power Expense 6,049 96 13,804 1296,806 74 20,610 104
Maintenance and Other Operation Expense 89 10 191 11(43) (4) 148 5
Writeoff of Merger-Related Costs (154) (96) (149) (93)(16) (80) (165) (91)
Other Income, (Loss), net 27 N.M. 89 241(7) (30) 83 141
Interest and Preferred Dividends (28) (10) (12) (2)(22) (8) (34) (4)
Income Taxes 121 233 214 1664 2 218 63
Extraordinary Items (57)44 N.M. (57)(13) (37)
Cumulative Effect 18 N.M. 18 N.M.
N.M. = Not Meaningful
The increaseincreases in revenues waswere due to a substantial increaseincreases in electric
and gas trading volumes and wholesale energy sales.volumes. Wholesale natural gas trading volume for the quarter
was 7741,337 billion cubic feet, a 178265 percent increase from second-quarterthird-quarter 2000
volume of 278 million366 billion cubic feet. Electric trading volume for the quarter
increased 1666 percent to 121148 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 market conditions
during a period of high volatility in prices, especially natural gas. The
increase in electric trading volume is primarily from:
o continued expansion of our trading team
o increased liquidity in the markets where we tradeMWH.
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 new markets
where we have not traded historically
The increase in electric trading volume is primarily from:
o continued expansion of our trading team
o increased liquidity in markets
While trading and marketing volumes rose, sales to industrial customers
decreased and, in the third quarter, sales to wholesale customers also declined.
We also experienced lower wholesale prices. The slowing economy has reduced
demand and wholesale prices.
Our fuel and purchased power expense increased due to increased trading
volume, particularly gas, and an increase in nuclear generation. Our generation
increased 3%Cook Plant's
two nuclear generating units were out of service in 20012000 through June 2000 and
December 2000.
Maintenance and other operation expense declined in the third quarter
due mainly to the return to service of the Cook Nuclear units in June 20002000. Partially
offsetting this decrease were accruals for severance related to corporate
restructuring. In the year-to-date period, additional traders' incentive
compensation, costs associated with the construction of gas-fired plants for
non-affiliates and December 2000 of Cook Plant's two generating units.
Ourthe accruals for severance costs caused maintenance and other
operation expense increased largely as a
result of additional traders' incentive compensation and costs associated with
the development of gas-fired plants. Thisto rise. The increase was offset, in part, by no
longernot incurring
expenditures to preparerestart costs for the Cook Plant units for restart
following an extended outage.Plant. Revenues from project fees more than offset
the charges for development costs thus not adversely affecting net income.third party construction.
The write-off of deferred merger costs in 2000 included transaction and
transition costs not recoverable from ratepayers under regulatory commission
approved settlement agreements.
InThe completion in March 2001 we completedof the sale of Frontera, one of the
generating plants required to be divested under FERC - approved merger
settlement agreements. The sale resulted inagreements, produced a $73 million gain recorded in other income for
the year-to-date period.
Our interest and preferred dividends decreased primarily because of
lowerLower average outstanding short-term debt balances and a decrease in
average short-term interest rates.
Our income taxes increased due to anrates accounted for the reduction in interest and
preferred dividends.
An increase in pre-tax income.income caused the increase in income taxes.
In the second quarter of 2001 we recorded an extraordinary loss forof $48
million net of tax to write-off stranded prepaid Ohio excise taxes (Seestranded by Ohio
deregulation (see Note 2). We discontinued theThe application of regulatory accounting for
generation was discontinued in 2000 which resulted in after tax extraordinary
items of:
o a $9 million gain in June of 2000 for the Virginia and West Virginia
during the second quarterjurisdictions and
o $44 million loss in September of 2000 for the Ohio jurisdiction
New accounting rules that became effective July 1, 2001 required us to
mark to market certain fuel supply contracts that qualify as financial
derivatives. The effect of initially adopting the new rules at July 1, 2001 was
$18 million, net of tax, which resulted in
an after tax extraordinary gainis reported as a cumulative effect of $9 million in 2000.accounting
change on the income statement.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
REVENUES $14,528 $8,137 $28,693 $14,254$18,385 $11,608 $47,078 $25,862
------- ------------- ------- -------
EXPENSES:
Fuel and Purchased Power 12,367 6,318 24,469 10,66516,008 9,202 40,477 19,867
Maintenance and Other Operation 959 870 1,912 1,721971 1,014 2,883 2,735
Non-recoverable Merger Costs 7 161 12 1614 20 16 181
Depreciation and Amortization 354 305 690 625340 322 1,030 947
Taxes Other Than Income Taxes 169 175 337 346200 177 537 523
--- --- --- ---
TOTAL EXPENSES 13,856 7,829 27,420 13,51817,523 10,735 44,943 24,253
------ ----------- ------ ------
OPERATING INCOME 672 308 1,273 736862 873 2,135 1,609
OTHER INCOME, (LOSS), net 22 (5) 126 3716 23 142 59
-- -- --- --
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES 694 303 1,399 773878 896 2,277 1,668
INTEREST AND PREFERRED DIVIDENDS 241 269 510 522252 274 762 796
--- --- --- ---
INCOME BEFORE INCOME TAXES 453 34 889 251626 622 1,515 872
INCOME TAXES 173 52 343 129223 219 566 348
--- ----- --- ---
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM
280 (18) 546 122AND CUMULATIVE EFFECT 403 403 949 524
EXTRAORDINARY GAIN (LOSS):LOSS - EFFECTS
OF DEREGULATION - net of tax (See note 2) - (44) (48) 9 (48) 9
---(35)
CUMULATIVE EFFECT OF ACCOUNTING CHANGE - ---net of tax
(See note 2) 18 - 18 -
-- ------ -- ------
NET INCOME (LOSS) $ 232421 $ (9)359 $ 498919 $ 131
======== ======== ======== =====489
======= ====== ======= =======
AVERAGE NUMBER OF SHARES OUTSTANDING 322 322 322 322
=== === === ===
EARNINGS (LOSS) PER SHARE:
Income (Loss) Before Extraordinary Item and
Cumulative Effect $1.25 $ 0.87 $(0.06)1.25 $ 1.69 $0.382.94 $ 1.63
Extraordinary Gain (Loss)Loss - (0.14) (0.15) 0.03 (0.15) 0.03
------ ------(0.11)
Cumulative Effect .06 - .06 -
--- ----- ------- -----
Earnings (Loss) Per Share (Basic and Dilutive) $0.72 $(0.03) $1.54 $0.41$1.31 $ 1.11 $ 2.85 $ 1.52
===== ====== ===== =========== ======
CASH DIVIDENDS PAID PER SHARE $0.60 $0.60 $1.20 $1.20$1.80 $1.80
===== ===== ===== =====
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in millions)
ASSETS
- ------
CURRENT ASSETS:
Cash and Cash Equivalents $ 212379 $ 437
Accounts Receivable (net) 2,5322,824 3,699
Energy Trading Contracts 11,72013,114 16,627
Other 1,6881,690 1,268
----- -----
TOTAL CURRENT ASSETS 16,15218,007 22,031
------ ------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production 16,55316,533 16,328
Transmission 6,1455,824 5,609
Distribution 10,97311,169 10,843
Other (including gas and coal mining assets and nuclear fuel) 4,1924,538 4,077
Construction Work in Progress 988949 1,231
--- -----
Total Property, Plant and Equipment 38,85139,013 38,088
Accumulated Depreciation and Amortization 15,98415,941 15,695
------ ------
NET PROPERTY, PLANT AND EQUIPMENT 22,86723,072 22,393
------ ------
REGULATORY ASSETS 3,7163,542 3,698
----- -----
INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS 521563 782
--- ---
GOODWILL (net of amortization) 1,3001,360 1,382
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 3,1663,375 1,620
----- -----
OTHER ASSETS 2,5052,900 2,642
----- -----
TOTAL $50,227$52,819 $54,548
======= =======
See Notes to Financial Statements beginning on page L-1.
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts Payable $1,252 $2,627$ 1,847 $ 2,627
Short-term Debt 4,0553,575 4,333
Long-term Debt Due Within One Year 1,0241,550 1,152
Energy Trading Contracts 11,39412,542 16,801
Other 1,9252,461 2,154
----- -----
TOTAL CURRENT LIABILITIES 19,65021,975 27,067
------ ------
LONG-TERM DEBT 10,6099,925 9,602
------ ----- -----
LONG-TERM ENERGY TRADING CONTRACTS 3,229 1,381
----- -----
DEFERRED INCOME TAXES 4,930 4,875
----- -----
DEFERRED INVESTMENT TAX CREDITS 502 528
--- ---
DEFERRED CREDITS AND REGULATORY LIABILITIES 1,019 617
----- ---
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 197 203
--- ---
OTHER NONCURRENT LIABILITIES 1,413 1,706
----- -----
CONTINGENCIES (Note 8)
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY
JUNIOR SUBORDINATED DEBENTURES OF SUCH SUBSIDIARIES 322321 334
--- ---
DEFERRED INCOME TAXES 4,914 4,875
----- -----
DEFERRED INVESTMENT TAX CREDITS 510 528MINORITY INTEREST IN SUBSIDIARIES 773 20
--- ---
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 199 203
--- ---
LONG-TERM ENERGY TRADING CONTRACTS 2,965 1,381
----- -----
DEFERRED CREDITS AND REGULATORY LIABILITIES 986 637
--- ---
OTHER NONCURRENT LIABILITIES 1,763 1,706
----- -------
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES 161156 161
--- ---
CONTINGENCIES (Note 8)
COMMON SHAREHOLDERS' EQUITY Common Stock-Par Value $6.50:
2001 2000
---- ----
Shares Authorized. . . . . 600,000,000 600,000,000
Shares Issued. . . . . . . 331,201,100331,202,497 331,019,146
(8,999,992 shares were held in treasury at JuneSeptember 30, 2001
and December 31, 2000) 2,153 2,152
Paid-in Capital 2,916 2,915
Accumulated Other Comprehensive Income (Loss) (131)(128) (103)
Retained Earnings 3,2103,438 3,090
----- -----
TOTAL COMMON SHAREHOLDERS' EQUITY 8,1488,379 8,054
----- -----
TOTAL $50,227$52,819 $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)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in millions)
OPERATING ACTIVITIES:
Net Income $ 498919 $ 131489
Adjustments for Noncash Items:
Depreciation and Amortization 709 6661,054 976
Deferred Federal Income Taxes 19 19131 40
Deferred Investment Tax Credits (17) (17)(26) (26)
Amortization of Deferred Property Taxes 82 79142 138
Amortization of Cook Plant Restart Costs 20 2030 30
Deferred Costs Under Fuel Clause Mechanisms 50 (164)240 (276)
Miscellaneous Accrued Expenses (238) 191
Extraordinary Gain (Loss)Loss - EffectsDiscontinuance of DeregulationSFAS 71 48 (9)35
Cumulative Effect of Accounting Change (18) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 1,154 (475)921 (927)
Fuel, Materials and Supplies (108) 73(114) 88
Accrued Utility Revenues (84) (108)(4) (134)
Prepayments and Other (83) (280)
Accounts Payable (1,643) 311(1,108) 445
Taxes Accrued 39 (205)
Customer Deposits (39) 7163 (3)
Revenue Refunds Accrued 2 (15)
Energy Trading Contracts (net) (653) (23)
Other (net) (89) 41
--- --(209) (220)
---- ----
Net Cash Flows From Operating Activities 639 369
---1,197 528
----- ---
INVESTING ACTIVITIES:
Construction Expenditures (819) (808)(1,303) (1,204)
Purchase of Houston Pipe Line (727) -
Sale of Yorkshire 383 -
Sale of Frontera 265 -
Other (276) (60)
----(54) (29)
--- ---
Net Cash Flows Used For Investing Activities (1,174) (868)(1,436) (1,233)
------ ----------
FINANCING ACTIVITIES:
Issuance of Common Stock 9 12
Issuance of Minority Interest 750 -
Issuance of Long-term Debt 1,388 7511,766 948
Change in Short-term Debt (net) (233) 1,104(717) 1,406
Retirement of Cumulative Preferred Stock (5) (20)
Retirement of Long-term Debt (463) (1,239)(1,033) (1,400)
Dividends Paid on Common Stock (387) (419)(580) (612)
---- ----
Net Cash Flows From Financing Activities 314 209190 334
--- ---
Effect of Exchange Rate Change on Cash (4) (7)(9) 7
-- ---
Net Decrease in Cash and Cash Equivalents (225) (297)(58) (364)
Cash and Cash Equivalents at Beginning of Period 437 609659
--- ---
Cash and Cash Equivalents at End of Period $ 212379 $ 312
=====295
======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $342$469 million and $471$685
million and for income taxes was $107$208 million and $206$242 million in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $21$39 million and $50$79
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 Accumulated Other
Comprehensive
Stock Capital Earnings Income (Loss) Total
----- ------- -------- ------------- -----
(in millions)
JANUARY 1, 2000 $2,149 $2,898 $3,630 $(4)$ (4) $8,673
Issuance of Common Stock 2 10 12
Common Stock Dividends (419) (419)(612) (612)
Other (46) (46)
---
8,2207 (1) 6
-
8,079
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Currency Translation Adjustment (115) (115)(171) (171)
Unrealized Loss on Securities 20 20
Minimum Pension Liability (2) (2)
Net Income 131 131489 489
---
Total Comprehensive Income 34338
---------- ---------- ----------- -------- -------- -------- ------ --
JUNE---
SEPTEMBER 30, 2000 $2,151 $2,862 $3,342 $(101) $8,254$2,915 $3,506 $(155) $8,417
====== ====== ============= ===== ======
JANUARY 1, 2001 $2,152 $2,915 $3,090 $(103) $8,054
Issuance of Common Stock 1 8 9
Common Stock Dividends (387) (387)(580) (580)
Other (7) 9 2
-
7,6787,485
Comprehensive Income:
Other Comprehensive Income, Net of Taxes
Currency Translation Adjustment (53) (53)(21) (21)
Unrealized Gain on Hedged Derivatives 31 312 2
Minimum Pension Liability (6) (6)
Net Income 498 498919 919
---
Total Comprehensive Income 470894
---------- ---------- ----------- --------- --------
-------- -------- ------ ------
JUNESEPTEMBER 30, 2001 $2,153 $2,916 $3,210 $(131) $8,148$3,438 $(128) $8,379
====== ====== ====== ===== ======
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD 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
capital.
The increase in net income of $0.4$0.1 million or 25%4% for the quarter
resulted primarily from an adjustment to the power bills to reflect the
resolution ofincrease in capital on which a tax issue.return is earned. Net
income for the year-to-date period declined $0.1
million or 1% 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.was virtually unchanged.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
SecondThird Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $(4.7) (8) $(1.1) (1)$1.8 3 $0.7 N.M.
Fuel Expense (5.8) (22) (2.6) (5)2.8 11 0.3 N.M.
Other Operation Expense 0.4 21 0.3 50.7 37 1.0 14
Maintenance Expense 0.8 25 0.2 4(0.6) (31) (0.4) (5)
Taxes Other Than Federal Income Taxes (0.5) (43) 1.5 681.0 30
Interest Charges (0.3) (29) (0.4) (23)(0.6) (52) (1.0) (34)
N.M. = Not Meaningful
The decreaseincrease in operating revenues resulted primarily from a decreasean increase
in recoverable expenses especially fuel. Thefuel and other operation expense. Recoverable
expenses rose as Rockport Plant generation increased in 2001 compared with last
year when the plant underwent scheduled maintenance outages in the secondthird quarter
of 2001. In 2000, maintenance outages
occurred in the first quarter.2000.
Fuel expense decreasedincreased due to a declinean increase in generation reflecting the
length of outages in the secondthird quarter 20012000.
The increase in other operation expense resulted from increased
employee benefits, insurance and lower average fuel cost.
Other operation and maintenanceregulatory commission costs.
Maintenance expense increaseddeclined due to more extensive outages during
the secondthird quarter 20012000 for boiler maintenance and repair.
The decline in taxes other than federal income taxes for the quarter
resulted from a decrease in 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.
Reductions in variable interest rates, reflecting market conditions, and
lower average short-term borrowing balances outstanding produced the decrease in
interest charges.
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $52,217 $56,928 $112,724 $113,794$57,417 $55,658 $170,141 $169,452
------- ------- -------- --------
OPERATING EXPENSES:
Fuel 20,261 26,048 47,906 50,48328,143 25,308 76,049 75,791
Rent - Rockport Plant Unit 2 17,070 17,070 34,141 34,14117,071 17,071 51,212 51,212
Other Operation 2,368 1,956 5,326 5,0542,529 1,840 7,855 6,894
Maintenance 3,971 3,166 5,897 5,6811,415 2,042 7,312 7,723
Depreciation 5,602 5,541 11,188 11,0465,613 5,558 16,801 16,604
Taxes Other Than Federal Income Taxes 641 1,124 3,769 2,250662 1,164 4,431 3,414
Federal Income Taxes 422 277 808 998369 466 1,177 1,464
--- --- --- -------- -----
TOTAL OPERATING EXPENSES 50,335 55,182 109,035 109,65355,802 53,449 164,837 163,102
------ ------ ------- -------
OPERATING INCOME 1,882 1,746 3,689 4,1411,615 2,209 5,304 6,350
NONOPERATING INCOME 887 900 1,749 1,769965 869 2,714 2,638
--- --- ----- -----
INCOME BEFORE INTEREST CHARGES 2,769 2,646 5,438 5,9102,580 3,078 8,018 8,988
INTEREST CHARGES 706 993 1,395 1,812529 1,106 1,924 2,918
--- -------- ----- -----
NET INCOME $ 2,0632,051 $ 1,6531,972 $ 4,0436,094 $ 4,0986,070
======= ======= ========== ================== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $10,743 $4,183$11,847 $5,836 $ 9,722 $ 3,673$3,673
NET INCOME 2,063 1,653 4,043 4,0982,051 1,972 6,094 6,070
CASH DIVIDENDS DECLARED 959 - 1,9182,877 1,935
--- ------ ----- -----
BALANCE AT END OF PERIOD $11,847 $5,836 $11,847 $5,836$12,939 $7,808 $12,939 $7,808
======= ====== ======= ======
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)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $636,583$637,433 $635,215
General 2,9912,943 2,795
Construction Work in Progress 3,4713,979 4,292
----- -----
Total Electric Utility Plant 643,045644,355 642,302
Accumulated Depreciation 325,671331,268 315,566
------- -------
NET ELECTRIC UTILITY PLANT 317,374313,087 326,736
------- -------
OTHER PROPERTY AND INVESTMENTS 119 6
--- -
CURRENT ASSETS:
Cash and Cash Equivalents 791188 2,757
Advances to Affiliates 3,478 -
Accounts Receivable:
Affiliated Companies 17,85218,823 21,374
Miscellaneous 150 2,341
Fuel - at average cost 18,62115,487 11,006
Materials and Supplies - at average cost 4,0084,093 3,979
Prepayments 63396 145
----- ---
TOTAL CURRENT ASSETS 41,48542,615 41,602
------ ------
REGULATORY ASSETS 5,3845,267 5,504
----- -----
DEFERRED CHARGES 2,3923,340 754
----- ---
TOTAL ASSETS $366,754$364,428 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
JuneSeptember 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
Paid-in Capital 23,434 23,434
Retained Earnings 11,84712,939 9,722
------ -----
Total Common Shareowner's Equity 36,28137,373 34,156
Long-term Debt 44,81244,791 -
------ -
TOTAL CAPITALIZATION 81,09382,164 34,156
------ ------
OTHER NONCURRENT LIABILITIES 135 358
--- 358---
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 44,808
Advances from Affiliates 15,165- 28,068
Accounts Payable:
General 9,3139,033 6,109
Affiliated Companies 11,3726,785 7,724
Taxes Accrued 10,82612,194 4,993
Rent Accrued - Rockport Plant Unit 2 4,96323,427 4,963
Other 2,0772,806 4,443
----- -----
TOTAL CURRENT LIABILITIES 53,71654,245 101,108
------ -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 119,403118,010 122,188
------- -------
REGULATORY LIABILITIES:
Deferred Investment Tax Credit 58,04557,209 59,718
Amounts Due to Customers for Income Taxes 22,66121,994 23,996
------ ------
TOTAL REGULATORY LIABILITIES 80,70679,203 83,714
------ ------
DEFERRED INCOME TAXES 31,32830,521 32,928
------ ------
DEFERRED CREDITS 150 150
--- ---
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $366,754$364,428 $374,602
======== ========
See Notes to Financial Statements beginning on page L-1.
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 4,0436,094 $ 4,0986,070
Adjustments for Noncash Items:
Depreciation 11,188 11,04616,801 16,604
Deferred Federal Income Taxes (2,935) (2,769)(4,409) (4,225)
Deferred Investment Tax Credits (1,673) (1,674)(2,509) (2,511)
Amortization of Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2 (2,785) (2,785)(4,178) (4,178)
Deferred Property Taxes (1,829) (1,648)(922) (807)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable 5,713 3,3434,742 (15,521)
Fuel, Materials and Supplies (7,644) (1,593)(4,595) (731)
Accounts Payable 6,852 (15,562)1,985 (15,631)
Taxes Accrued 5,833 2,5337,201 4,622
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Other (net) (2,371) (1,270)(3,700) 1,056
------ -----------
Net Cash Flow From (Used For) Operating Activities 14,392 (6,281)34,974 3,212
------ -----------
INVESTING ACTIVITIES - Construction Expenditures (1,537) (2,295)(3,120) (3,413)
------ ------
FINANCING ACTIVITIES:
Return of Capital to Parent Company - (2,935)(4,866)
Change in Short-term Debt (net) - (24,700)
Change in Advances from Affiliates (net) (12,903) 37,870(31,546) 31,574
Dividends Paid (1,918)(2,877) (1,935)
------ ------
Net Cash Flows From (Used For) Financing Activities (14,821) 8,300(34,423) 73
------- -------
Net Decrease in Cash and Cash Equivalents (1,966) (276)(2,569) (128)
Cash and Cash Equivalents at Beginning of Period 2,757 317
----- ---
Cash and Cash Equivalents at End of Period $ 791188 $ 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 $3,129,189
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,489,000 and $2,671,000
and for income taxes was $1,352,000 and $3,101, 000 in 2001 and 2000,
respectively.
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
-------------------------------------------------------------
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of the generation,
regulated retail power sales and wholesale power marketing and trading of electricity;trading; 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 $2.8$5.8 million or 7%16% for the quarter due to the
effect of an extraordinary gain recordeda
decline in 2000 for the discontinuance of
regulatory accounting partially offset by favorable wholesale business performance.performance as a slowing economy reduced demand
and lowered wholesale electricity prices. Net income increased $11.4$5.6 million or
13%5% for the year-to-date period primarily due to growth in and strong performance
by the wholesale business.business during the first half of 2001.
Income statement line items which changed significantly were:
Increase (Decrease)
-------------------
Second
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $479 31 $1,820 45
Fuel Expense 3 3 (8) (3)
Purchased Power Expense 475 40 1,778 60
Other Operation Expense 4 5 16 8
Maintenance Expense 2 8 12 14
Depreciation and Amortization 3 8 14 12
Federal Income Taxes (2) (13) 1 2
Nonoperating Income (3) (138) 5 80
Interest Charges (3) (9) (4) (4)
Extraordinary Gain - - ------------- -
Operating Revenues $389 27 $1,341 54
Fuel Expense (8) (8) (11) (6)
Purchased Power Expense 377 33 1,303 73
Other Operation Expense 6 10 12 10
Maintenance Expense 5 17 10 17
Depreciation and Amortization 5 13 11 14
Nonoperating Income 4 127 9 205
Extraordinary Gain (9) N.M. (9) N.M.
N.M. = Not Meaningful
The significant increase in revenues for the quarter is due to increaseda 69%
increase in trading volume partially offset by lower wholesale electricity
prices and trading volume of our wholesale business. The significant year-to-date period increase
is due to a 44% increase in trading volume and an increase in wholesale
electricity prices due to changes in market conditions. 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 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 increased for the quarter due to
a decrease in deferred fuel expense as compared to the previous quarter. The
decrease in deferred fuel expense is due to a lower average unit cost of fuel.
Fuel expense decreased for the year-to-date period due to a decline in
generation as a result of scheduled plant maintenance.
The
For the quarter the increase in the wholesale business' purchased power
expense is attributable to increasesan increase in trading volume partly offset by a
decrease in wholesale electricity pricesprices. For the year-to-date period the
increase is attributable to increases in trading volume and trading volume.
Otherwholesale
electricity prices.
For the quarter other operation expense increased as a result of energy
delivery severance accruals and power trading incentive compensation expense of
the wholesale 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 relativeYear-to-date other operation expense increased due to
its affiliates' peak
demand was the main reason for the decrease in transmission equalization
credits.wholesale power trading incentive compensation expense.
The increase in maintenance expense is mainly attributable to increased
generating plant boiler maintenance repairs to the wholesale business' Amos,
MountaineerGlen Lyn and Glen LynMountaineer 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 increasedecrease in nonoperatingfederal income wastaxes for the quarter is due to an increasea
decrease in pre-tax operating income.
Nonoperating income decreased for the quarter due to a net gainsloss from the
wholesale business' trading transactions outside of the AEP System's traditional
marketing area and speculative financial transactions (options, futures, swaps).
Due to significant net gains in the first six months of 2001 on these wholesale
trading transactions, nonoperating income increased in the year-to-date period.
The interest charge decrease is due to the retirement of first mortgage
bonds in 2000.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,849,304 $1,460,774 $3,823,431 $2,482,452$2,017,159 $1,538,340 $5,840,590 $4,020,792
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 85,049 92,663 180,525 191,22091,594 88,769 272,119 279,989
Purchased Power 1,513,831 1,137,184 3,099,033 1,795,8311,666,443 1,191,737 4,765,476 2,987,568
Other Operation 67,948 61,566 133,837 122,20776,197 72,297 210,034 194,504
Maintenance 33,842 28,989 66,851 57,31431,812 29,369 98,663 86,683
Depreciation and Amortization 44,056 38,899 87,773 77,23746,177 42,798 133,950 120,035
Taxes Other Than Federal Income Taxes 29,975 28,817 61,843 59,46229,275 30,088 91,118 89,550
Federal Income Taxes 15,241 14,448 46,055 42,72715,280 17,532 61,335 60,259
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,789,942 1,402,566 3,675,917 2,345,9981,956,778 1,472,590 5,632,695 3,818,588
--------- --------- --------- ---------
OPERATING INCOME 59,362 58,208 147,514 136,45460,381 65,750 207,895 202,204
NONOPERATING INCOME 7,772 3,427 12,823 4,208
-----(LOSS) (918) 2,399 11,905 6,607
---- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 67,134 61,635 160,337 140,66259,463 68,149 219,800 208,811
INTEREST CHARGES 30,715 31,395 62,131 62,75829,146 32,037 91,277 94,795
------ ------ - ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 36,419 30,240 98,206 77,90430,317 36,112 128,523 114,016
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 86,84230,317 36,112 128,523 122,954
PREFERRED STOCK
DIVIDEND REQUIREMENTS 503 632 1,006 1,265502 750 1,508 2,015
--- --- ----- -----
EARNINGS APPLICABLE TO
COMMON STOCK $ 35,91629,815 $ 38,54635,362 $ 97,200127,015 $ 85,577
=========== =========== =========== ========120,939
==========- ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $36,419 $39,178 $98,206 $86,842$30,317 $36,112 $128,523 $122,954
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (212)673 - (629)44 -
---- ------ ---- --------- ------- -- -
COMPREHENSIVE INCOME $36,207 $39,178 $97,577 $86,842$30,990 $36,112 $128,567 $122,954
======= ======= ======= =============== ========
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 JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $149,469 $191,232$152,987 $198,126 $120,584 $175,854
NET INCOME 36,419 39,178 98,206 86,84230,317 36,112 128,523 122,954
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 32,39832,399 31,653 64,797 63,30697,196 94,959
Cumulative Preferred Stock 360 525 721 1,050361 375 1,082 1,425
Capital Stock Expense 143 106 285 214141 375 426 589
--- --- --- ---
BALANCE AT END OF PERIOD $152,987 $198,126 $152,987 $198,126$150,403 $201,835 $150,403 $201,835
======== ======== ======== ========
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)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,073,004$2,072,425 $2,058,952
Transmission 1,208,5191,214,697 1,177,079
Distribution 1,850,0841,862,101 1,816,925
General 261,307258,285 254,371
Construction Work in Progress 101,589151,705 110,951
------- -------
Total Electric Utility Plant 5,494,5035,559,213 5,418,278
Accumulated Depreciation and Amortization 2,241,6392,271,949 2,188,796
--------- ---------
NET ELECTRIC UTILITY PLANT 3,252,8643,287,264 3,229,482
--------- ---------
OTHER PROPERTY AND INVESTMENTS 57,55055,992 56,967
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 611,424370,807 322,688
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 5,17628,766 5,847
Advances to Affiliates - 8,387
Accounts Receivable:
Customers 185,010132,169 243,298
Affiliated Companies 48,83268,088 63,919
Miscellaneous 19,05817,285 16,179
Allowance for Uncollectible Accounts (1,868) (2,588)
Fuel - at average cost 41,50547,862 39,076
Materials and Supplies - at average cost 59,94560,891 57,515
Accrued Utility Revenues 18,49219,844 66,499
Energy Trading Contracts 1,772,239918,417 2,036,001
Prepayments 10,02913,364 6,307
------ -----
TOTAL CURRENT ASSETS 2,158,4181,304,818 2,540,440
--------- ---------
REGULATORY ASSETS 443,511439,075 447,750
------- -------
DEFERRED CHARGES 35,07426,940 48,826
------ ------
TOTAL ASSETS $6,558,841$5,484,896 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 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 $260,458$ 260,458
Paid-in Capital 715,502715,644 715,218
Accumulated Other Comprehensive Income (Loss)44 -
(629)
Retained Earnings 152,987150,403 120,584
------- -------
Total Common Shareowner's Equity 1,128,3181,126,549 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 1,431,3441,506,285 1,430,812
--------- ---------
TOTAL CAPITALIZATION 2,588,3122,661,484 2,555,722
--------- ---------
OTHER NONCURRENT LIABILITIES 92,32289,099 105,883
------ -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 650,007 175,006
Short-term Debt - 191,495
Advances from Affiliates 301,890209,538 -
Accounts Payable - General 167,195139,439 153,422
Accounts Payable - Affiliated Companies 90,03686,989 107,556
Taxes Accrued 73,69677,888 63,258
Customer Deposits 14,96017,225 12,612
Interest Accrued 27,47940,659 21,555
Energy Trading Contracts 1,729,722863,309 2,091,804
Other 67,17780,355 85,378
------ ------
TOTAL CURRENT LIABILITIES 2,472,1611,565,409 2,902,086
--------- ---------
DEFERRED INCOME TAXES 721,412720,630 682,474
------- -------
DEFERRED INVESTMENT TAX CREDITS 40,88139,775 43,093
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 550,037319,544 259,438
------- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 93,71688,955 97,457
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $6,558,841$5,484,896 $6,646,153
========== ==========
See Notes to Financial Statements beginning on page L-1.
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 98,206128,523 $ 86,842122,954
Adjustments for Noncash Items:
Depreciation and Amortization 87,829 77,293134,034 120,119
Deferred Federal Income Taxes 29,279 15,05427,227 14,059
Deferred Investment Tax Credits (2,212) (2,332)(3,318) (3,446)
Deferred Power Supply Costs (net) 594 (11,938)131 (80,232)
Amortization of Deferred Property Taxes 13,480 13,051
Extraordinary Gain - Discontinuance of SFAS 71 - (8,938)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 69,776 (36,988)105,134 (99,426)
Fuel, Materials and Supplies (4,859) 8,588(12,162) 8,919
Accrued Utility Revenues 48,007 13,02946,655 12,948
Accounts Payable (3,747) 27,567(34,550) 101,571
Taxes Accrued 10,438 (764)14,630 14,084
Interest Accrued 5,924 (903)19,104 16,345
Net Change in Energy Trading Contracts (96,457) (19,438)(98,924) (13,446)
Rate Stabilization Deferral - 75,601
Other (net) (15,019) (17,509)(10,782) (24,757)
------- -------
Net Cash Flows From Operating Activities 227,759 129,563329,182 269,406
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (107,876) (80,870)(185,185) (132,290)
Proceeds from Sale of Property 1,182 148160
----- ---
Net Cash Flows Used For Investing Activities (106,694) (80,722)(184,003) (132,130)
-------- ---------------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 74,787124,588 74,788
Change in Short-term Debt (net) (191,495) 22,195(23,455)
Change in Advance from Affiliates (net) 310,277 (12,857)217,925 (8,626)
Retirement of Cumulative Preferred Stock - (210)(9,905)
Retirement of Long-term Debt (175,000) (131,202)
Dividends Paid on Common Stock (64,797) (63,306)(97,196) (94,959)
Dividends Paid on Cumulative Preferred Stock (721) (1,053)
----(1,082) (1,578)
------ ------
Net Cash Flows Used For Financing Activities (121,736) (111,646)(122,260) (194,937)
-------- --------
Net DecreaseIncrease (Decrease) in Cash and Cash Equivalents (671) (62,805)22,919 (57,661)
Cash and Cash Equivalents at Beginning of Period 5,847 64,828
----- ------
Cash and Cash Equivalents at End of Period $ 5,17628,766 $ 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 $7,451,0007,167
========== =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $70,286,000 and
$75,938,000 and for income taxes was $21,521,000 and $30,503,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $2,576,000
and $11,312,000 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
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of generation, retail
electricity sales, power marketing and trading of electricity; and energy
delivery, which consists of transmission and distribution services. Since the
merger of AEP and CSW in June 2000, we participate in the AEP System's power
marketing and trading activities conducted on our behalf by
the AEP System.
Secondactivities.
Third quarter net income decreased $15$6 million or 22%7% while the year-to-date
net income increased $12$6 million or 16%3%. The lower secondthird quarter net income was
the result of increased transmission expenses.due to weak performance from marketing and trading. 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 fromour participation in AEP's power marketing and trading
operations which added newduring the first half of 2001 compared with 2000 when we did not
share in AEP's power marketing and trading.
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $440 55 $938 61
Fuel Expense (60) (33) 9 2
Purchased Power Expense 526 195 906 278
Other Operation Expense (28) (27) (6) (3)
Maintenance 1 8 4 10
Depreciation and Amortization (9) (21) (8) (6)
Taxes Other Than Federal Income Taxes 21 107 25 43
Federal Income Taxes (3) (7) 4 4
Nonoperating Income 3 333 - -
The significant increase in revenues for the quarter resulted from
increased trading volumes of the wholesale business. In the year-to-date period,
the increase in revenues is also attributable to our participation in AEP's
power marketing and trading operations and higher fuel related revenues due to
increased costs of fuel and purchased power expense. CPL began sharingpower.
Fuel expense decreased for the quarter primarily due to a significant
decrease in AEP's marketing and trading
transactionsthe average unit cost of fuel as a result of the merger of AEP and CSW in June 2000.
Fuellower spot market
natural gas prices. Year-to-date fuel expense increasedwas up due primarily to an
increase in the average unit cost of fuel as a result of higher spot market
natural gas prices.prices in the first and second quarters.
The substantial rise in purchased power expense isfor both the quarter
and year-to-date periods was attributable to post
mergerour participation in theAEP's power
marketing and trading operation.
Other operation expense increasedfor the quarter decreased due primarily to a
favorable
adjustment recordeddecrease 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.expenses. Additionally, generationproduction expenses were updown
due to decreased power trading incentive compensation.compensation expense.
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'preparatory expenses
for an October STP Unit 1 nuclear plantrefueling outage. A nuclear refueling outage
for STP Unit 2 between March 7 and April 2, 2001 also contributed to the
increase in year-to-date maintenance expense. STP Unit 1 completed its refueling
outage and returned to service October 25, 2001.
The increasedecrease in depreciation and amortization expense for the quarter
is due primarily to higherlower excess earnings provisions under Texas Restructuring
Legislation. Year-to-date depreciation and amortization expense associated with excess earning
provisions of the Texas deregulation legislation.also decreased
due to accelerated ECOM depreciation on STP ceasing in July 2000.
Taxes other than federal income taxes increased due primarily to an
increase in franchise related taxes, including a settlement of disputed
franchise fees (see Note 8), and Texas Gross Receipts Tax and Ad Valorem taxes.assessment taxes, a new tax levied by the
PUCT.
Federal income taxes attributable to operations decreased for the
quarter decreasedand increased for the year-to-date period 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 anand
increase, respectively, in pre-tax operating income.
Nonoperating income decreasedfor the quarter increased due to interest income on
underrecovered fuel costs and was partially offset by a reductiondecrease in allocated tax
savings resulting frominterest
income on the parent company loss tax benefit.Decommissioning Trust Fund.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $648,499 $437,911 $1,251,911 $754,239
--------$1,235,941 $795,794 $2,487,852 $1,550,033
---------- -------- ---------- ------------------
OPERATING EXPENSES:
Fuel 147,179 140,841 299,032 230,238121,933 181,827 420,965 412,065
Purchased Power 220,772 34,936 435,338 55,356795,448 269,823 1,230,786 325,179
Other Operation 76,189 54,307 151,260 129,60973,543 101,116 224,803 230,725
Maintenance 17,995 15,474 35,282 31,89613,827 12,780 49,109 44,676
Depreciation and Amortization 53,587 40,887 95,978 95,08533,257 41,970 129,235 137,055
Taxes Other Than Federal Income Taxes 21,711 19,922 41,199 37,45640,735 19,717 81,934 57,173
Federal Income Taxes 28,715 35,827 47,319 40,23244,600 47,908 91,919 88,140
------ ------ ------ ------
TOTAL OPERATING EXPENSES 566,148 342,194 1,105,408 619,872
-------1,123,343 675,141 2,228,751 1,295,013
--------- ------- --------- ----------------
OPERATING INCOME 82,351 95,717 146,503 134,367112,598 120,653 259,101 255,020
NONOPERATING INCOME (LOSS) (1,541) 1,815 98 2,362
------3,540 818 3,638 3,180
----- ----- ----- -----
INCOME BEFORE INTEREST CHARGES 80,810 97,532 146,601 136,729116,138 121,471 262,739 258,200
INTEREST CHARGES 28,292 29,979 59,052 61,03732,436 31,497 91,488 92,534
------ ------ ------ ------
NET INCOME 52,518 67,553 87,549 75,69283,702 89,974 171,251 165,666
PREFERRED STOCK DIVIDEND REQUIREMENTS
61 61 121 12160 60 181 181
-- -- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 52,457 $67,49283,642 $ 87,428 $75,57189,914 $ 171,070 $165,485
======== ======== ========== ======= ======== =======
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $790,176 $727,973$805,619 $756,465 $792,219 $758,894
NET INCOME 52,518 67,553 87,549 75,69283,702 89,974 171,251 165,666
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 37,01437,015 39,000 74,028 78,000111,043 117,000
Preferred Stock 60 61 61 121 121181 182
-- -- --- ---
BALANCE AT END OF PERIOD $805,619 $756,465 $805,619 $756,465$852,246 $807,378 $852,246 $807,378
======== ======== ======== ========
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)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $3,163,111$3,165,533 $3,175,867
Transmission 604,057646,264 581,931
Distribution 1,250,2241,272,057 1,221,750
General 240,386244,803 237,764
Construction Work in Progress 195,948164,633 138,273
Nuclear Fuel 240,151245,745 236,859
------- -------
Total Electric Utility Plant 5,693,8775,739,035 5,592,444
Accumulated Depreciation and Amortization 2,361,7802,395,951 2,297,189
--------- ---------
NET ELECTRIC UTILITY PLANT 3,332,0973,343,084 3,295,255
--------- ---------
OTHER PROPERTY AND INVESTMENTS 46,22947,099 44,225
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 32,19986,270 66,231
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 5,7556,706 14,253
Accounts Receivable:
Customers 38,61674,642 67,787
Affiliated Companies 12,81813,295 31,272
Allowance for Uncollectible Accounts (1,638)(447) (1,675)
Fuel Inventory - at LIFO cost 39,51136,111 22,842
Materials and Supplies - at average cost 54,12755,700 53,108
Under-recovered Fuel Costs 93,34110,822 127,295
Energy Trading Contracts 112,483314,177 481,206
Prepayments and Other Current Assets 6,1514,357 3,014
----- -----
TOTAL CURRENT ASSETS 361,164515,363 799,102
------- -------
REGULATORY ASSETS 178,299234,038 202,440
------- -------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION 953,249 953,249
------- -------
NUCLEAR DECOMMISSIONING TRUST FUND 95,03291,859 93,592
------ ------
DEFERRED CHARGES 45,11521,367 18,402
------ ------
TOTAL ASSETS $5,043,384$5,292,329 $5,472,496
========== ==========
See Notes to Financial Statements beginning on page L-1.
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 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 $168,888$ 168,888
Paid-in Capital 405,000 405,000
Retained Earnings 805,619852,246 792,219
------- -------
Total Common Shareowner's Equity 1,379,5071,426,134 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 136,750136,250 148,500
Long-term Debt 942,863942,865 1,254,559
------- ---------
TOTAL CAPITALIZATION 2,465,0872,511,216 2,775,133
--------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 511,700 200,000
Advances from Affiliates 223,51257,722 269,712
Accounts Payable - General 115,732125,578 128,957
Accounts Payable - Affiliated Companies 26,65714,118 40,962
Taxes Accrued 128,983219,657 55,526
Interest Accrued 24,22123,339 26,217
Energy Trading Contracts 111,536314,346 489,888
Other 46,77846,712 40,630
------ ------
TOTAL CURRENT LIABILITIES 1,189,1191,313,172 1,251,892
--------- ---------
DEFERRED INCOME TAXES 1,221,2131,186,803 1,242,797
--------- ---------
DEFERRED INVESTMENT TAX CREDITS 125,496124,194 128,100
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 32,99987,095 65,740
------- ------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 9,47069,849 8,834
----------- -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,043,384$5,292,329 $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)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $87,549 $75,692$ 171,251 $ 165,666
Adjustments for Noncash Items:
Depreciation and Amortization 95,978 95,085129,235 137,055
Deferred Federal Income Taxes (17,699) (4,178)(50,506) 14,529
Deferred Investment Tax Credits (2,604) (2,603)(3,905) (3,905)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 47,588 8,3859,894 (30,689)
Fuel, Materials and Supplies (17,688) 4,575(15,861) 5,829
Fuel Recovery 33,954 (25,227)116,473 (89,733)
Accounts Payable (27,530) 24,785(30,223) 80,539
Taxes Accrued 73,457 (17,148)164,131 30,147
Transmission Coordination Agreement Settlement - 15,519
Deferred Property Taxes (21,563)(8,063) -
Other (net) (17,628) 10,002
------- ------4,257 3,396
----- -----
Net Cash Flows From Operating Activities 233,814 184,887486,683 328,353
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (109,638) (85,215)(158,191) (137,053)
Other (354) (4,067)-
---- -------------
Net Cash Flows Used For Investing Activities (109,992) (89,282)(158,545) (137,053)
-------- ---------------
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)
Reacquisition of Trust Preferred Securities (12,471) (1,440)
Change in Advances from Affiliates (net) (46,200) (68,379)(211,990) (123,836)
Special Deposit for Reacquisitions of Long-term Debt - 50,000
-
Dividends Paid on Common Stock (74,028) (78,000)(111,043) (117,000)
Dividends Paid on Cumulative Preferred Stock (121) (127)(181) (188)
---- ----
Net Cash Flows Used For Financing Activities (132,320) (97,093)(335,685) (193,051)
-------- ---------------
Net Decrease in Cash and Cash Equivalents (8,498) (1,488)(7,547) (1,751)
Cash and Cash Equivalents at Beginning of Period 14,253 7,995
------ -----
Cash and Cash Equivalents at End of Period $ 5,7556,706 $ 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 $11,307,0006,244
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $80,612,000 and
$81,211,000 and for income taxes was $11,939,000 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
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD 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 $25 million or 62% in the third quarter of 2001 due
to the effect of a prior period $25 million extraordinary loss. Income before
extraordinary item for the third quarter of 2001 was flat. Net income increased
$21 million or 20% and income before extraordinary item increased $22 million or
17% for the year-to-date period, due to the strength and growth of the wholesale
business during the first half of 2001.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $337 35 $1,010 40
Fuel Expense (8) (15) (8) (5)
Purchased Power Expense 343 52 960 55
Other Operation Expense - - 14 9
Maintenance Expense (4) (20) 2 4
Depreciation and Amortization 7 29 21 28
Taxes Other Than Federal Income Taxes 5 17 8 8
Nonoperating Income 6 N.M. 8 N.M.
Extraordinary Loss (25) N.M. 1 5
N.M. = Not Meaningful
The significant increase in revenues for the quarter is due to an 86%
increase in trading volume partially offset by lower wholesale electricity
prices. The significant year-to-date increase is due to a 41% increase in
wholesale trading volume and an increase in wholesale electricity prices due to
changes in market conditions. 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).
Fuel expense of the wholesale business decreased due to a decrease in
net generation partially offset by an increase in the average unit price of fuel
and the discontinuance of deferred fuel accounting effective January 1, 2001
because of deregulation. In 2000 fuel expense included charges for the
amortization of previously deferred fuel costs. The amortization was concurrent
with recovery through fuel clause revenues.
For the quarter the increase in the wholesale business' purchased power
expense is attributable to an increase in trading volume offset by a decrease in
wholesale electricity prices. For the year-to-date period the increase was
attributable to increases in trading volume and wholesale electricity prices
Other operation expense increased year-to-date due to increases in
uncollectible accounts, factored customer accounts receivable expenses, the
effect of gains in 2000 from the disposition of emission allowances, higher
power trading expenses and trading incentive compensation and energy delivery
severance accruals.
For the quarter, maintenance expenses decreased due to boiler overhauls
and maintenance of overhead energy delivery lines completed in the prior period.
The commencement of the 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.
The increase in taxes other than income taxes is due to a new state
excise tax which produces a larger tax than the gross receipts tax it replaced.
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 and swaps).
In the second quarter of 2001 we recorded an extraordinary loss of $26
million net of tax to write-off prepaid Ohio excise taxes stranded by Ohio
deregulation (see Note 2). The application of regulatory accounting for
generation was discontinued in September 2000 which resulted in an after tax
extraordinary loss of $25 million.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,297,704 $960,837 $3,532,372 $2,522,474
---------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 42,702 50,452 132,100 139,781
Purchased Power 1,003,135 660,438 2,720,906 1,760,551
Other Operation 58,398 57,940 167,456 153,561
Maintenance 15,254 18,991 53,763 51,915
Depreciation and Amortization 32,352 25,091 95,213 74,531
Taxes Other Than Federal Income Taxes 36,473 31,079 101,289 93,640
Federal Income Taxes 32,470 33,284 69,899 70,011
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,220,784 877,275 3,340,626 2,343,990
--------- ------- --------- ---------
OPERATING INCOME 76,920 83,562 191,746 178,484
NONOPERATING INCOME (LOSS) 5,269 (683) 11,753 3,498
----- ---- ------ -----
INCOME BEFORE INTEREST CHARGES 82,189 82,879 203,499 181,982
INTEREST CHARGES 16,871 17,337 53,092 53,634
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 65,318 65,542 150,407 128,348
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION - net of tax (Note 2) - (25,236) (26,407) (25,236)
------ ------- ------- -------
NET INCOME 65,318 40,306 124,000 103,112
PREFERRED STOCK DIVIDEND REQUIREMENTS
244 416 847 1,481
--- --- --- -----
EARNINGS APPLICABLE TO
COMMON STOCK $ 65,074 $ 39,890 $ 123,153 $ 101,631
========== ========== ========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $115,243 $261,024 $ 99,069 $246,584
NET INCOME 65,318 40,306 124,000 103,112
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 20,738 169,650 62,214 216,950
Cumulative Preferred Stock 175 263 700 1,138
Capital Stock Expense 255 250 762 441
--- --- --- ---
BALANCE AT END OF PERIOD $159,393 $131,167 $159,393 $131,167
======== ======== ======== ========
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)
September 30, 2001 December 31, 2000
------------------ -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,576,522 $1,564,254
Transmission 396,871 360,302
Distribution 1,142,740 1,096,365
General 146,720 156,534
Construction Work in Progress 78,922 89,339
------ ------
Total Electric Utility Plant 3,341,775 3,266,794
Accumulated Depreciation and Amortization 1,358,623 1,299,697
--------- ---------
NET ELECTRIC UTILITY PLANT 1,983,152 1,967,097
--------- ---------
OTHER PROPERTY AND INVESTMENTS 41,944 39,848
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 227,288 172,167
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 23,019 11,600
Accounts Receivable:
Customers 52,491 73,711
Affiliated Companies 77,952 49,591
Miscellaneous 14,920 18,807
Allowance for Uncollectible Accounts (659) (659)
Fuel - at average cost 22,137 13,126
Materials and Supplies - at average cost 38,063 38,097
Accrued Utility Revenues 4,509 9,638
Energy Trading Contracts 562,351 1,085,989
Prepayments and Other Current Assets 30,919 46,735
------ ------
TOTAL CURRENT ASSETS 825,702 1,346,635
------- ---------
REGULATORY ASSETS 266,273 291,553
------- -------
DEFERRED CHARGES 26,769 77,634
------ ------
TOTAL ASSETS $3,371,128 $3,894,934
========== ==========
See Notes to Financial Statements beginning on page L-1.
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 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 574,115 573,354
Retained Earnings 159,393 99,069
------- ------
Total Common Shareowner's Equity 774,534 713,449
Cumulative Preferred Stock - Subject to Mandatory Redemption 10,000 15,000
Long-term Debt 623,579 899,615
------- -------
TOTAL CAPITALIZATION 1,408,113 1,628,064
--------- ---------
OTHER NONCURRENT LIABILITIES 39,175 47,584
------ ------
CURRENT LIABILITIES:
Affiliated Long-term Debt Due Within One Year 200,000 -
Advances from Affiliates 140,154 88,732
Accounts Payable - General 85,911 89,846
Accounts Payable - Affiliated Companies 83,276 72,493
Taxes Accrued 134,068 162,904
Interest Accrued 15,845 13,369
Energy Trading Contracts 529,145 1,115,967
Other 45,437 60,701
------ ------
TOTAL CURRENT LIABILITIES 1,233,836 1,604,012
--------- ---------
DEFERRED INCOME TAXES 435,290 422,759
------- -------
DEFERRED INVESTMENT TAX CREDITS 38,726 41,234
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 20,006 12,861
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 195,982 138,420
------- -------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $3,371,128 $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)
Nine Months Ended September 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $124,000 $103,112
Adjustments for Noncash Items:
Depreciation and Amortization 78,739 74,945
Amortization of Transition Assets 17,455 -
Deferred Federal Income Taxes 23,527 7,945
Deferred Investment Tax Credits (2,508) (2,541)
Amortization of Deferred Property Taxes 53,168 50,130
Extraordinary Loss 26,407 25,236
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (3,254) 3,511
Fuel, Materials and Supplies (8,977) 407
Accrued Utility Revenues 5,129 40,080
Prepayments and Other Current Assets 15,816 (3,500)
Accounts Payable 6,848 87,706
Taxes Accrued (28,836) (35,879)
Interest Accrued 2,476 10,505
Energy Trading Contracts (net) (60,743) (8,619)
Other (net) (40,658) (1,757)
------- ------
Net Cash Flows From Operating Activities 208,589 351,281
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (110,631) (91,122)
Proceeds from Sale of Property 10,673 992
------ ---
Net Cash Flows Used For Investing Activities (99,958) (90,130)
-------- -------
FINANCING ACTIVITIES:
Proceeds from Issuance of Affiliated Long-term Debt 200,000 -
Change in Advances from Affiliates (net) 51,422 43,970
Change in Short-term Debt (net) - (45,500)
Retirement of Cumulative Preferred Stock (5,000) (10,000)
Retirement of Long-term Debt (280,632) (25,274)
Dividends Paid on Common Stock (62,214) (216,950)
Dividends Paid on Cumulative Preferred Stock (788) (1,312)
---- ------
Net Cash Flows Used For Financing Activities (97,212) (255,066)
------- --------
Net Increase in Cash and Cash Equivalents 11,419 6,085
Cash and Cash Equivalents at Beginning of Period 11,600 5,107
------ -----
Cash and Cash Equivalents at End of Period $ 23,019 $ 11,192
======== =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $49,126,000 and
$40,411,000 and for income taxes was $17,579,000 and $42,007,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $1,019,000
and $4,043,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2001 vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of generation,
regulated retail power sales and wholesale power 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 $10 million in the quarter and $145 million
in the year-to-date period primarily due to the return to service of
both of I&M's Cook Plant nuclear units in June and December 2000.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $342 32 $1,173 42
Fuel Expense 3 6 36 24
Purchased Power Expense 360 51 1,073 56
Other Operation Expense (17) (12) (94) (22)
Maintenance Expense (22) (40) (73) (44)
Depreciation and Amortization 2 6 7 6
Taxes Other Than Federal Income Taxes 2 14 9 18
Federal Income Taxes 3 37 72 N.M.
Nonoperating Income 2 147 8 168
Interest Charges 1 2 5 7
N.M. = Not Meaningful
Operating revenues for the third quarter increased due to
increased wholesale sales while average wholesale prices declined. The
significant increase in operating revenues in the year-to-date period
resulted from increased wholesale volumes and prices. I&M's share of
the AEP System's sales to and forward trades with other utility systems
and power marketers and sales to the AEP Power Pool rose in 2001. The
number of forward electricity contracts made in AEP System's
traditional marketing area (up to two transmission systems from the AEP
System's service territory) grew due to the expansion of our trading
operation and increased liquidity in the markets. Changes in wholesale
prices reflect market conditions. With the return to service of the
nuclear units in 2000, I&M's available generation increased resulting
in additional wholesale power sales 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
increases in wholesale prices and sales and trading volume in the
year-to-date period. During the third quarter, a decline in average
prices, reflecting market conditions, partly offset the volume increase.
Other operation and maintenance expenses decreased primarily
due to the cessation of expenses related to work for the 2000 restart of
the Cook Plant units.
The increase in depreciation and amortization charges reflects
increased generation and distribution plant investments and amortization
of deferred merger costs.
Taxes other than federal income taxes and federal income tax
expense attributable to operations increased primarily due to increases
in pre-tax operating income.
The increase in nonoperating income reflects an increase in net
gains from trading transactions outside the AEP System's traditional
marketing area and speculative financial transactions (options, futures
and swaps).
Interest charges increased due to lower amounts of interest
being capitalized as part of plant construction costs.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,402,178 $1,060,654 $3,953,590 $2,780,510
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 59,535 56,338 183,999 148,042
Purchased Power 1,070,889 710,605 2,978,930 1,905,531
Other Operation 122,809 139,375 330,369 424,254
Maintenance 31,913 53,596 91,594 164,821
Depreciation and Amortization 41,172 38,951 122,735 115,661
Taxes Other Than Federal Income Taxes 19,574 17,156 60,222 51,152
Federal Income Tax Expense (Credit) 11,777 8,577 41,194 (31,157)
------ ----- ------ -------
TOTAL OPERATING EXPENSES 1,357,669 1,024,598 3,809,043 2,778,304
--------- --------- --------- ---------
OPERATING INCOME 44,509 36,056 144,547 2,206
NONOPERATING INCOME 3,320 1,344 12,176 4,546
----- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 47,829 37,400 156,723 6,752
INTEREST CHARGES 22,765 22,210 71,922 67,296
------ ------ ------ ------
NET INCOME (LOSS) 25,064 15,190 84,801 (60,544)
PREFERRED STOCK DIVIDENDREQUIREMENTS
1,155 1,156 3,466 3,469
----- ----- ----- -----
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK
$ 23,909 $ 14,034 $ 81,335 $ (64,013)
========== ======== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME (LOSS) $25,064 $15,190 $84,801 $(60,544)
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (878) - (3,700) -
---- ------ ------ ------
COMPREHENSIVE INCOME (LOSS) $24,186 $15,190 $81,101 $(60,544)
======= ======= ======= ========
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 September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $60,869 $60,930 $ 3,443 $166,389
NET INCOME (LOSS) 25,064 15,190 84,801 (60,544)
DEDUCTIONS:
Cash Dividends Declared:
Common Stock - - - 26,290
Cumulative Preferred Stock 1,121 - 3,365 3,368
Capital Stock Expense 34 34 101 101
-- -- --- ---
BALANCE AT END OF PERIOD $84,778 $76,086 $84,778 $ 76,086
======= ======= ======= ========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,751,287 $2,708,436
Transmission 953,699 945,709
Distribution 888,851 863,736
General (including nuclear fuel) 216,682 257,152
Construction Work in Progress 83,809 96,440
------ ------
Total Electric Utility Plant 4,894,328 4,871,473
Accumulated Depreciation and Amortization 2,402,447 2,280,521
--------- ---------
NET ELECTRIC UTILITY PLANT 2,491,881 2,590,952
--------- ---------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS
816,169 778,720
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 253,571 194,947
------- -------
OTHER PROPERTY AND INVESTMENTS 130,955 131,417
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 27,398 14,835
Accounts Receivable:
Customers 69,668 106,832
Affiliated Companies 47,711 48,706
Miscellaneous 30,717 27,491
Allowance for Uncollectible Accounts (734) (759)
Fuel - at average cost 27,926 16,532
Materials and Supplies - at average cost 89,493 84,471
Energy Trading Contracts 637,645 1,230,041
Prepayments 7,450 6,066
----- -----
TOTAL CURRENT ASSETS 937,274 1,534,215
------- ---------
REGULATORY ASSETS 466,752 552,140
------- -------
DEFERRED CHARGES 24,298 36,156
------ ------
TOTAL ASSETS $5,120,900 $5,818,547
========== ==========
See Notes to Financial Statements beginning on page L-1.
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 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 733,173 733,072
Accumulated Other Comprehensive Income (Loss) (3,700) -
Retained Earnings 84,778 3,443
------ -----
Total Common Shareowner's Equity 870,835 793,099
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,152,513 1,298,939
--------- ---------
TOTAL CAPITALIZATION 2,097,029 2,165,719
--------- ---------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 587,398 560,628
Other 96,523 108,600
------ -------
TOTAL OTHER NONCURRENT LIABILITIES 683,921 669,228
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 200,000 90,000
Advances from Affiliates 214,420 253,582
Accounts Payable:
General 87,769 119,472
Affiliated Companies 45,670 75,486
Taxes Accrued 116,196 68,416
Interest Accrued 24,001 21,639
Rent Accrued - Rockport Plant Unit 2 23,427 4,963
Obligations Under Capital Leases 9,796 100,848
Energy Trading Contracts 591,679 1,275,097
Other 79,827 92,107
------ ------
TOTAL CURRENT LIABILITIES 1,392,785 2,101,610
--------- ---------
DEFERRED INCOME TAXES 465,565 487,945
------- -------
DEFERRED INVESTMENT TAX CREDITS 108,169 113,773
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 78,519 81,299
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 214,683 156,736
------- -------
DEFERRED CREDITS 80,229 42,237
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $5,120,900 $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)
Nine Months Ended September 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $ 84,801 $ (60,544)
Adjustments for Noncash Items:
Depreciation and Amortization 124,993 122,345
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) (224) 4,830
Unrecovered Fuel and Purchased Power Costs 28,126 28,126
Amortization of Nuclear Outage Costs 30,000 30,000
Deferred Federal Income Taxes (6,517) (25,619)
Deferred Investment Tax Credits (5,604) (5,660)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 34,908 23,303
Fuel, Materials and Supplies (16,416) (6,304)
Accrued Utility Revenues - 44,428
Accounts Payable (61,519) 47,236
Taxes Accrued 47,780 (48,970)
Rent Accrued - Rockport Plant Unit 2 18,464 18,464
Net Change in Energy Trading Contracts (91,699) (4,039)
Regulatory Liability - Trading Gains 39,040 (10,143)
Other (net) 31,283 (29,211)
------ -------
Net Cash Flows From Operating Activities 257,416 128,242
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (65,312) (129,799)
Buyout of Nuclear Fuel Leases (92,616) -
Other 524 587
--- ---
Net Cash Flows Used For Investing Activities (157,404) (129,212)
-------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - 199,220
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) (39,162) 113,423
Dividends Paid on Common Stock - (26,290)
Dividends Paid on Cumulative Preferred Stock (3,365) (3,368)
------ ------
Net Cash Flows From (Used For) Financing Activities (87,449) 10,409
------- ------
Net Increase in Cash and Cash Equivalents 12,563 9,439
Cash and Cash Equivalents at Beginning of Period 14,835 3,863
------ -----
Cash and Cash Equivalents at End of Period $ 27,398 $ 13,302
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $67,657,000 and
$57,466,000 and for income taxes was $13,079,000 and $43,675,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $1,023,000
and $19,134,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2001 vs. THIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale, which consists of generation,
regulated retail power sales and wholesale power 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 $1.4 million or 21% for the quarter and $2.1
million or 12% year-to-date due to a decline in operating income. This decline
was primarily attributable to a slowing economy and reduced wholesale energy
margins. Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $126.5 35 $450.7 48
Fuel Expense (5.8) (25) (5.0) (9)
Purchased Power Expense 131.9 46 456.3 62
Other Operation Expense 1.3 9 8.0 22
Maintenance Expense (0.1) (2) (4.3) (21)
Depreciation and Amortization Expense 0.3 4 1.2 5
Taxes Other Than Federal Income Taxes 0.4 17 1.8 22
Federal Income Taxes (0.4) (11) (1.9) (23)
Nonoperating Income (0.6) (234) 1.5 176
Interest Charges (0.3) (4) (1.6) (7)
Increases in operating revenues are a result of increases in power
trading activity. Revenues from sales to and forward trades with other utility
systems and power marketers rose by 50% and 69% for the quarter and year-to-date
periods, respectively. The number of forward electricity contracts grew due to
the expansion of trading operations and increased liquidity in the markets. A
downward trend in wholesale prices reflected market conditions.
Fuel expense decreased as a result of credits from profits on trading
power. Under the Kentucky commission's fuel clause mechanism, a portion of the
profits on wholesale transactions are shared with the customers. This sharing is
recognized through credits to fuel expense thus reducing overall fuel expense.
Purchased power expense for the wholesale business increased due to
additional purchases to support the increased sales and trading volume.
Increases in other operation expense for the quarter were a result of
increased trading incentive compensation expense and charges related to
severance pay for distribution employees. Increases in year-to-date other
operation expense are primarily attributable to trader compensation expenses and
decreases in AEP transmission equalization credits. 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 the transmission
equalization credits. Other changes contributing to increases in other operation
expense include an increase in medical insurance rates, and increases in
accounts receivable factoring costs stemming from nine months activity in 2001
versus three months in 2000 when the program was implemented.
Lower maintenance expense is a result of significant planned maintenance
outages incurred at the Big Sandy Plant in year 2000 for which there is no
comparable activity in the current year.
Depreciation and amortization expense increased as a result of additions
to property, plant and equipment and the resultant increase in the depreciable
basis.
Federal income tax on operations decreased due to a decline in pre-tax
income.
The quarter to date decrease in nonoperating income was due to losses
resulting from power trading activity. The quarterly decrease is mitigated by
year-to-date net gains for trading activity and other non-regulated financial
market investments.
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 September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $485,820 $359,296 $1,384,108 $933,410
-------- -------- ---------- --------
OPERATING EXPENSES:
Fuel 17,581 23,366 52,955 58,039
Purchased Power 420,402 288,479 1,196,180 739,864
Other Operation 15,430 14,117 44,628 36,604
Maintenance 5,984 6,098 16,598 20,903
Depreciation and Amortization 8,163 7,828 24,270 23,107
Taxes Other Than Federal Income Taxes 2,802 2,387 9,638 7,880
Federal Income Taxes 2,871 3,231 6,284 8,210
----- ----- ----- -----
TOTAL OPERATING EXPENSES 473,233 345,506 1,350,553 894,607
------- ------- --------- -------
OPERATING INCOME 12,587 13,790 33,555 38,803
NONOPERATING INCOME (LOSS) (326) 243 2,392 868
---- --- ----- ---
INCOME BEFORE INTEREST CHARGES 12,261 14,033 35,947 39,671
INTEREST CHARGES 6,949 7,272 20,818 22,409
----- ----- ------ ------
NET INCOME $ 5,312 $ 6,761 $ 15,129 $ 17,262
======== ======== ======== ========
STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $5,312 $6,761 $15,129 $17,262
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (618) - (2,040) -
---- ------- ------ -------
COMPREHENSIVE INCOME $4,694 $6,761 $13,089 $17,262
====== ====== ======= =======
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 September 30, Nine Months Ended September 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $52,208 $62,431 $57,513 $67,110
NET INCOME 5,312 6,761 15,129 17,262
CASH DIVIDENDS DECLARED:
Common Stock 7,561 7,590 22,683 22,770
----- ----- ------ ------
BALANCE AT END OF PERIOD $49,959 $61,602 $49,959 $61,602
======= ======= ======= =======
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, 2001 December 31, 2000
------------------ -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 270,996 $ 271,107
Transmission 370,373 360,563
Distribution 398,792 387,499
General 65,021 67,476
Construction Work in Progress 15,059 16,419
------ ------
Total Electric Utility Plant 1,120,241 1,103,064
Accumulated Depreciation and Amortization 377,938 360,648
------- -------
NET ELECTRIC UTILITY PLANT 742,303 742,416
------- -------
OTHER PROPERTY AND INVESTMENTS 6,894 6,559
----- -----
LONG-TERM ENERGY TRADING CONTRACTS 92,242 76,657
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 7,909 2,270
Accounts Receivable:
Customers 21,684 34,555
Affiliated Companies 22,008 22,119
Miscellaneous 4,119 6,419
Allowance for Uncollectible Accounts (278) (282)
Fuel - at average cost 7,521 4,760
Materials and Supplies - at average cost 15,898 15,408
Accrued Utility Revenues 2,215 6,500
Energy Trading Contracts 226,116 483,537
Prepayments and Other 1,047 766
----- ---
TOTAL CURRENT ASSETS 308,239 576,052
------- -------
REGULATORY ASSETS 97,757 98,515
------ ------
DEFERRED CHARGES 9,816 11,817
----- ------
TOTAL ASSETS $1,257,251 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 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) (2,040) -
Retained Earnings 49,959 57,513
------ ------
Total Common Shareowner's Equity 257,119 266,713
Long-term Debt 246,041 270,880
Long-term Debt - Affiliated Company 75,000 -
------ -
TOTAL CAPITALIZATION 578,160 537,593
------- -------
OTHER NONCURRENT LIABILITIES 13,075 18,348
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 25,000 60,000
Advances from Affiliates 64,246 47,636
Accounts Payable:
General 31,438 32,043
Affiliated Companies 23,673 37,506
Customer Deposits 5,290 4,389
Taxes Accrued 7,402 11,885
Interest Accrued 6,873 5,610
Energy Trading Contracts 216,755 496,884
Other 17,514 14,517
------ ------
TOTAL CURRENT LIABILITIES 398,191 710,470
------- -------
DEFERRED INCOME TAXES 174,639 165,935
------- -------
DEFERRED INVESTMENT TAX CREDITS 10,767 11,656
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 78,802 61,632
------ ------
DEFERRED CREDITS 3,617 6,382
----- -----
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,257,251 $1,512,016
========== ==========
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended September 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 15,129 $ 17,262
Adjustments for Noncash Items:
Depreciation and Amortization 24,270 23,112
Deferred Federal Income Taxes 9,644 4,081
Deferred Investment Tax Credits (889) (894)
Amortization of Deferred Property Taxes 4,299 4,157
Deferred Fuel Costs (net) (2,708) 4,430
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 15,278 (8,128)
Fuel, Materials and Supplies (3,251) 5,718
Accrued Utility Revenues 4,285 13,737
Accounts Payable (14,438) 32,763
Taxes Accrued (4,483) (1,323)
Net Change in Energy Trading Contracts (21,123) (2,171)
Other (net) (2,889) (5,069)
------ ------
Net Cash Flows From Operating Activities 23,124 87,675
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (26,628) (23,765)
Proceeds from Sales of Property 216 -
--- -----
Net Cash Flow Used for Investing Activities (26,412) (23,765)
------- -------
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) 16,610 23,863
Dividends Paid (22,683) (22,770)
------- -------
Net Cash Flows From (Used For) Financing Activities 8,927 (63,572)
----- -------
Net Increase in Cash and Cash Equivalents 5,639 338
Cash and Cash Equivalents at Beginning of Period 2,270 674
----- ---
Cash and Cash Equivalents at End of Period $ 7,909 $ 1,012
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $18,899,000 and
$19,776,000 and for income taxes was $6,011,000 and $5,167,000 in 2001 and 2000,
respectively. Noncash acquisitions under capital leases were $817,000 and
$2,440,000 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
THIRD QUARTER 2001 vs. THIRD 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 $14$7 million or 41%12% for the third quarter of 2001
and $47 million or 29% for the year-to-date period. We recorded extraordinary
losses 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 secondthird 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%2000 for the year-to-date period. The increase in wholesale prices is due to changes
in market conditions during a periodeffects
of high volatility in prices.
Fuel expense of the wholesale business decreased in the second quarter
of 2001 due to a decrease in net generation partially offset by an increase in
price and the discontinuance of deferred fuel accounting because of deregulation
effective January 1, 2001.
The increase in purchased power expense was attributable to increases in
the wholesale business electric trading prices and volume.
Other operation expense increased due to increases in uncollectible
accounts, factored customer accounts receivable expenses, the effect of gains in
2000 from the disposition of emission allowances and higher power trading
expenses and trading incentive compensation.
Maintenance expenses increased due to planned outages at several of the
wholesale business' plants for boiler overhauls 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.
The extraordinary loss was recorded in June 2001 to recognize stranded
prepaid Ohio excise taxes (See Note 2).
COLUMBUS SOUTHERN 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 $1,109,095 $928,332 $2,234,668 $1,561,637
---------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel 42,368 48,581 89,398 89,329
Purchased Power 845,860 685,411 1,717,771 1,100,113
Other Operation 54,510 50,332 109,058 95,621
Maintenance 19,729 18,228 38,509 32,924
Depreciation and Amortization 31,379 24,896 62,861 49,440
Taxes Other Than Federal Income Taxes 32,909 31,084 64,816 62,561
Federal Income Taxes 19,446 19,002 37,429 36,727
------ ------ ------ ------
TOTAL OPERATING EXPENSES 1,046,201 877,534 2,119,842 1,466,715
--------- ------- --------- ---------
OPERATING INCOME 62,894 50,798 114,826 94,922
NONOPERATING INCOME (LOSS) 3,012 2,497 6,484 4,181
----- ----- ----- -----
INCOME BEFORE INTEREST CHARGES 65,906 53,295 121,310 99,103
INTEREST CHARGES 18,488 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 21,011 35,335 58,682 62,806
PREFERRED STOCK DIVIDEND REQUIREMENTS 301 532 603 1,065
--- --- --- -----
EARNINGS APPLICABLE TO COMMON STOCK $ 20,710 $ 34,803 $ 58,079 $ 61,741
============ ======== ============ ========
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 $115,486 $249,872 $ 99,069 $246,584
NET INCOME 21,011 35,335 58,682 62,806
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 20,738 23,650 41,476 47,300
Cumulative Preferred Stock 263 438 525 875
Capital Stock Expense 253 95 507 191
--- -- --- ---
BALANCE AT END OF PERIOD $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)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,569,118 $1,564,254
Transmission 392,383 360,302
Distribution 1,124,668 1,096,365
General 148,224 156,534
Construction Work in Progress 79,612 89,339
------ ------
Total Electric Utility Plant 3,314,005 3,266,794
Accumulated Depreciation and Amortization 1,337,358 1,299,697
--------- ---------
NET ELECTRIC UTILITY PLANT 1,976,647 1,967,097
--------- ---------
OTHER PROPERTY AND INVESTMENTS 43,283 39,848
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 333,816 172,167
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 10,030 11,600
Accounts Receivable:
Customers 78,089 73,711
Affiliated Companies 82,426 49,591
Miscellaneous 19,463 18,807
Allowance for Uncollectible Accounts (659) (659)
Fuel - at average cost 20,648 13,126
Materials and Supplies - at average cost 37,333 38,097
Accrued Utility Revenues - 9,638
Energy Trading Contracts 966,617 1,085,989
Prepayments and Other Current Assets 27,334 46,735
------ ------
TOTAL CURRENT ASSETS 1,241,281 1,346,635
--------- ---------
REGULATORY ASSETS 273,528 291,553
------- -------
DEFERRED CHARGES 36,923 77,634
------ ------
TOTAL ASSETS $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)
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)
Six Months Ended June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 58,682 $62,806
Adjustments for Noncash Items:
Depreciation and Amortization 52,392 49,709
Amortization of Regulatory Assets 11,294 -
Deferred Federal Income Taxes 18,384 6,783
Deferred Investment Tax Credits (1,671) (1,694)
Deferred Fuel Cost (net) - (1,835)
Amortization of Deferred Property Taxes 35,416 33,721
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (37,869) 83,720
Fuel, Materials and Supplies (6,758) 1,447
Accrued Utility Revenues 9,638 46,416
Prepayments and Other Current Assets 19,401 (11,899)
Accounts Payable 28,155 12,174
Taxes Accrued (45,627) (53,895)
Energy Trading Contracts (net) (51,347) (5,321)
Other (net) (9,981) 3,047
------ -----
Net Cash Flows From Operating Activities 80,109 225,179
------ -------
INVESTING ACTIVITIES:
Construction Expenditures (67,532) (59,372)
Proceeds from Sale of Property 1,284 463
----- ---
Net Cash Flows Used For Investing Activities (66,248) (58,909)
------- -------
FINANCING ACTIVITIES:
Change in Advances from Affiliates (net) 26,570 (61,504)
Change in Short-term Debt (net) - (45,500)
Retirement of Long-term Debt - (6,879)
Dividends Paid on Common Stock (41,476) (47,300)
Dividends Paid on Cumulative Preferred Stock (525) (875)
---- ----
Net Cash Flows Used For Financing Activities (15,431) (162,058)
------- --------
Net Increase (Decrease) in Cash and Cash Equivalents (1,570) 4,212
Cash and Cash Equivalents at Beginning of Period 11,600 5,107
------ -----
Cash and Cash Equivalents at End of Period $ 10,030 $ 9,319
========== =======
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.
INDIANA MICHIGAN 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 increased $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 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 $248 25 $832 48
Fuel Expense 17 38 33 36
Purchased Power Expense 191 26 713 60
Other Operation Expense (41) (27) (77) (27)
Maintenance Expense (24) (44) (52) (46)
Federal Income Taxes 34 N.M. 69 N.M.
N.M. = Not Meaningful
The significant increase in operating revenues resulted from
increased wholesale prices and volumes. I&M's share of the AEP System's
sales to and forward trades with other utility systems and power
marketers and sales to the AEP Power Pool rose in 2001. In 2001 both
price and volume in the trading operation increased. The number of
forward electricity contracts made 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. 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
increases 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 major increases in
pre-tax operating income.
INDIANA MICHIGAN 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 $1,259,874 $1,011,706 $2,551,412 $1,719,856
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 60,491 43,844 124,464 91,704
Purchased Power 936,454 745,656 1,908,041 1,194,926
Other Operation 110,197 151,328 207,560 284,879
Maintenance 31,506 55,841 59,681 111,225
Depreciation and Amortization 40,840 38,499 81,563 76,710
Taxes Other Than Federal Income Taxes 20,316 16,787 40,648 33,996
Federal Income Tax Expense (Credit) 12,730 (21,650) 29,417 (39,734)
------ ------- ------ -------
TOTAL OPERATING EXPENSES 1,212,534 1,030,305 2,451,374 1,753,706
--------- --------- --------- ---------
OPERATING INCOME (LOSS) 47,340 (18,599) 100,038 (33,850)
NONOPERATING INCOME 4,411 2,637 8,856 3,202
----- ----- ----- -----
INCOME (LOSS) BEFORE INTEREST CHARGES 51,751 (15,962) 108,894 (30,648)
INTEREST CHARGES 24,377 23,219 49,157 45,086
------ ------ ------ ------
NET INCOME (LOSS) 27,374 (39,181) 59,737 (75,734)
PREFERRED STOCK DIVIDEND REQUIREMENTS 1,156 1,153 2,311 2,313
----- ----- ----- -----
EARNINGS (LOSS) APPLICABLE TO COMMON
STOCK $ 26,218 $ (40,334) $ 57,426 $ (78,047)
============ ============ ============ =========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME (LOSS) $27,374 $(39,181) $59,737 $(75,734)
OTHER COMPREHENSIVE INCOME (LOSS)
Cash Flow Interest Rate Hedge (903) - (2,822) -
---- ------ ------ ------
COMPREHENSIVE INCOME (LOSS) $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 June 30, Six Months Ended June 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING 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)
June 30, 2001 December 31, 2000
------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,738,228 $2,708,436
Transmission 950,648 945,709
Distribution 878,487 863,736
General (including nuclear fuel) 231,786 257,152
Construction Work in Progress 98,130 96,440
------ ------
Total Electric Utility Plant 4,897,279 4,871,473
Accumulated Depreciation and Amortization 2,379,292 2,280,521
--------- ---------
NET ELECTRIC UTILITY PLANT 2,517,987 2,590,952
--------- ---------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL DISPOSAL TRUST FUNDS
801,760 778,720
------- -------
LONG-TERM ENERGY TRADING CONTRACTS 380,005 194,947
------- -------
OTHER PROPERTY AND INVESTMENTS 133,032 131,417
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 12,069 14,835
Accounts Receivable:
Customers 89,393 106,832
Affiliated Companies 47,644 48,706
Miscellaneous 35,595 27,491
Allowance for Uncollectible Accounts (734) (759)
Fuel - at average cost 26,906 16,532
Materials and Supplies - at average cost 87,955 84,471
Energy Trading Contracts 1,130,779 1,230,041
Prepayments 3,888 6,066
----- -----
TOTAL CURRENT ASSETS 1,433,495 1,534,215
--------- ---------
REGULATORY ASSETS 500,879 552,140
------- -------
DEFERRED CHARGES 30,071 36,156
------ ------
TOTAL ASSETS $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)
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 733,139 733,072
Accumulated Other Comprehensive Income (Loss) (2,822) -
Retained Earnings 60,869 3,443
------ -----
Total Common Shareowner's Equity 847,770 793,099
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption 8,736 8,736
Subject to Mandatory Redemption 64,945 64,945
Long-term Debt 1,349,874 1,298,939
--------- ---------
TOTAL CAPITALIZATION 2,271,325 2,165,719
--------- ---------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning 576,267 560,628
Other 101,000 108,600
------- -------
TOTAL OTHER NONCURRENT LIABILITIES 677,267 669,228
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 90,000
Advances from Affiliates 302,030 253,582
Accounts Payable:
General 99,800 119,472
Affiliated Companies 53,775 75,486
Taxes Accrued 99,671 68,416
Interest Accrued 22,919 21,639
Obligations Under Capital Leases 9,141 100,848
Energy Trading Contracts 1,092,357 1,275,097
Other 77,955 97,070
------ ------
TOTAL CURRENT LIABILITIES 1,757,648 2,101,610
--------- ---------
DEFERRED INCOME TAXES 472,626 487,945
------- -------
DEFERRED INVESTMENT TAX CREDITS 110,037 113,773
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK - ROCKPORT PLANT UNIT 2 79,445 81,299
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 345,216 156,736
------- -------
DEFERRED CREDITS 83,665 42,237
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $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)
Six Months Ended June 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income (Loss) $59,737 $ (75,734)
Adjustments for Noncash Items:
Depreciation and Amortization 83,090 81,423
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses (net) (771) 3,722
Unrecovered Fuel and Purchased Power Costs 18,751 18,751
Amortization of Nuclear Outage Costs 20,000 20,000
Deferred Federal Income Taxes (4,256) (12,038)
Deferred Investment Tax Credits (3,736) (3,773)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 10,372 61,510
Fuel, Materials and Supplies (13,858) (1,464)
Accrued Utility Revenues - 44,428
Accounts Payable (41,383) (14,093)
Taxes Accrued 31,255 (28,268)
Net Change in Energy Trading Contracts (80,056) (8,935)
Regulatory Liability - Trading Gains 38,159 3,284
Other (net) 12,261 (23,988)
------ -------
Net Cash Flows From Operating Activities 129,565 64,825
------- ------
INVESTING ACTIVITIES:
Construction Expenditures (41,321) (93,002)
Buyout of Nuclear Fuel Leases (92,616) -
Other 324 587
--- ---
Net Cash Flows Used For Investing Activities (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) 48,448 331,852
Dividends Paid on Common Stock (26,290)
-
Dividends Paid on Cumulative Preferred Stock (2,244) (2,249)
------ ------
Net Cash Flows From Financing Activities 1,282 30,737
----- ------
Net Increase (Decrease) in Cash and Cash Equivalents (2,766) 3,147
Cash and Cash Equivalents at Beginning of Period 14,835 3,863
------ -----
Cash and Cash Equivalents at End of Period $ 12,069 $ 7,010
======== =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $46,243,000 and
$39,686,000 and for income taxes was $11,073,000 and $(2,365,000) in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $1,020,000
and $15,423,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
KENTUCKY POWER COMPANY
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 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 significantly, net income increased slightly in
the quarter and declined by less than $1.0 million or 7% for the 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 $96 28 $324 56
Purchased Power Expense 98 35 324 72
Other Operation Expense 2 20 7 29
Maintenance Expense (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%
in33% for the second quarter of 2001 and $19$45 million or 18%25% in the year-to-date period
because ofperiod. A decline
in wholesale business performance and the implementation of customer choice.choice
account for the reduction in the quarter's earnings. 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. Although performance of our wholesale business is up
for the year-to-date period, the implementation of customer choice caused
earnings to decline year-to-date.
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
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $335 23 $1,178 30
Fuel Expense (22) (11) (34) (6)
Purchased Power Expense 364 38 1,209 50
Other Operation 4 4 18 7
Maintenance Expense 6 20 16 18
Depreciation and Amortization 20 51 61 52
Taxes Other Than Federal Income Taxes 10 24 12 10
Federal Income Taxes (20) (47) (44) (39)
Nonoperating Income 4 165 19 283
Interest Charges 3 13 3 5
Extraordinary Loss (19) N.M. 3 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 for the quarter is due to increasesa 63%
increase in electric
trading volume partially offset by lower wholesale electricity
prices. The significant year-to-date revenue increase is due to a 31% increase
in trading volume and an increase in wholesale electricity prices and volume of our wholesale business.due to changes
in market conditions. Expansion of the wholesale business' trading operation and
greater liquidity in the marketplace 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 19%
forFuel expense decreased during both periods due to decreased generation
and a lower average unit cost of fuel.
For the year-to-date period. The increase in wholesale prices reflects market
conditions during a period of high volatility in prices.
Thequarter the increase in purchased power expense was attributable
to the increase in the wholesale business' electric trading volume offset in
part by a decrease in wholesale electricity prices. For the year-to-date period
the increase is attributable to increase in trading volume and wholesale
electricity prices.
Other operation expense increased due to increases in uncollectible
accounts and factored customer accounts receivable expenses of both the
wholesale business and energy delivery business, the effect of gains in 2000
from the disposition of emission allowances, andincreased trading incentive
compensation of the wholesale business.
business and energy delivery severance accruals.
Maintenance expenses increased due to planned outages at several of the
wholesale business' plants for boiler overhauls at Kammer,
Mitchell, Muskingum and inspections.Sporn plants and boiler inspections at Amos and Cardinal
plants.
The commencement of amortization of transition regulatory assets in
connection with the transition to customer choice and market-based pricing of
electricity under Ohio deregulation accounted for the increase in depreciation
and amortization expense.
The increase in taxes other than federal income taxes is due to a new
State Excise Tax which produced a larger tax than the gross receipts tax it
replaced.
Federal income taxes attributable to operations decreased due to a
decrease in pre-tax operating income.
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 and swaps).
AnInterest expense increased due to increased long-term debt outstanding.
In the second quarter of 2001 we recorded an extraordinary loss was recorded in June 2001of $22
million net of tax to recognize strandedwrite-off prepaid Ohio excise taxes (Seestranded by Ohio
deregulation (see Note 2). The application of regulatory accounting for
generation was discontinued in September 2000 which resulted in an after tax
extraordinary loss of $19 million.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $1,627,177 $1,436,330 $3,326,842 $2,484,167$1,819,792 $1,484,663 $5,146,634 $3,968,830
---------- ---------- ---------- ----------
OPERATING EXPENSES:
Fuel 180,057 177,314 380,618 392,562167,155 188,727 547,773 581,289
Purchased Power 1,146,655 943,060 2,325,561 1,480,7881,312,668 948,733 3,638,229 2,429,521
Other Operation 96,623 86,244 185,029 170,696104,081 99,930 289,110 270,626
Maintenance 36,448 33,595 71,848 61,62533,786 28,128 105,634 89,753
Depreciation and Amortization 57,666 38,843 117,725 77,33259,267 39,121 176,992 116,453
Taxes Other Than Federal Income Taxes 46,193 41,055 87,054 84,78750,507 40,579 137,561 125,366
Federal Income Taxes 16,468 36,251 47,184 71,29622,660 42,793 69,844 114,089
------ ------ ------ -------------
TOTAL OPERATING EXPENSES 1,580,110 1,356,362 3,215,019 2,339,0861,750,124 1,388,011 4,965,143 3,727,097
--------- --------- --------- ---------
OPERATING INCOME 47,067 79,968 111,823 145,08169,668 96,652 181,491 241,733
NONOPERATING INCOME 7,809 1,250 18,917 4,1506,788 2,564 25,705 6,714
----- ----- ------ -----
INCOME BEFORE INTEREST CHARGES 54,876 81,218 130,740 149,23176,456 99,216 207,196 248,447
INTEREST CHARGES 22,782 22,985 45,249 44,78225,078 22,155 70,327 66,937
------ ------ ------ ------
INCOME BEFORE EXTRAORDINARY ITEM 32,094 58,233 85,491 104,44951,378 77,061 136,869 181,510
EXTRAORDINARY LOSS - EFFECTS OF
DEREGULATION (INCLUSIVE OF TAX BENEFIT
OF $11,585,000)- net of tax (See note 2) - (18,876) (21,515) - (21,515) -(18,876)
---- ------- ----- ------- ---------
NET INCOME 10,579 58,233 63,976 104,44951,378 58,185 115,354 162,634
PREFERRED STOCK DIVIDEND REQUIREMENTS
316314 315 630 636944 951
--- --- --- ---
EARNINGS APPLICABLE TO COMMON STOCK
$ 10,26351,064 $ 57,91857,870 $ 63,346 $103,813
=========== ======== ============ ========114,410 $ 161,683
========== ========== ========== ==========
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
NET INCOME $10,579 $58,233 $63,976 $104,449$51,378 $58,185 $115,354 $162,634
OTHER COMPREHENSIVE INCOME (LOSS)
Foreign Currency Exchange Rate Hedge (104)345 - (325)20 -
---- ------ ---- --------- ----- -- -----
COMPREHENSIVE INCOME $10,475 $58,233 $63,651 $104,449$51,723 $58,185 $115,374 $162,634
======= ======= =============== ========
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 JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $415,425 $595,620$389,945 $615,834 $398,086 $587,424
NET INCOME 10,579 58,233 63,976 104,44951,378 58,185 115,354 162,634
CASH DIVIDENDS DECLARED:
Common Stock 35,744 37,703 71,488 75,406158,704 107,232 234,110
Cumulative Preferred Stock 315 316 629 633314 944 947
--- --- --- ---
BALANCE AT END OF PERIOD $389,945 $615,834 $389,945 $615,834$405,264 $515,001 $405,264 $515,001
======== ======== ======== ========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $2,955,482$2,962,832 $2,764,155
Transmission 884,720886,986 870,033
Distribution 1,059,1741,068,738 1,040,940
General (including mining assets) 523,987assets at December 31, 2000 See Note 3) 241,683 707,417
Construction Work in Progress 83,461138,805 195,086
------------- -------
Total Electric Utility Plant 5,506,8245,299,044 5,577,631
Accumulated Depreciation and Amortization 2,670,8742,422,866 2,764,130
--------- ---------
NET ELECTRIC UTILITY PLANT 2,835,9502,876,178 2,813,501
--------- ---------
OTHER PROPERTY AND INVESTMENTS 114,81165,936 109,124
------------- -------
LONG-TERM ENERGY TRADING CONTRACTS 479,759309,122 256,455
------- -------
CURRENT ASSETS:
Cash and Cash Equivalents 28,94334,212 31,393
Advances to Affiliates - 92,486
Accounts Receivable:
Customers 174,891100,323 139,732
Affiliated Companies 141,778135,657 126,203
Miscellaneous 26,18825,846 39,046
Allowance for Uncollectible Accounts (1,026) (1,054)
Fuel - at average cost 100,40094,327 82,291
Materials and Supplies - at average cost 75,69266,406 96,053
Energy Trading Contracts 1,389,132769,154 1,617,660
Prepayments and Other 17,76624,344 33,146
------ ------
TOTAL CURRENT ASSETS 1,953,7641,249,243 2,256,956
--------- ---------
REGULATORY ASSETS 674,099659,631 714,710
------- -------
DEFERRED CHARGES 59,38438,914 101,690
------ -------
TOTAL ASSETS $6,117,767$5,199,024 $6,252,436
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 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 $321,201$ 321,201
Paid-in Capital 462,483 462,483
Accumulated Other Comprehensive Income (Loss) (325)20 -
Retained Earnings 389,945405,264 398,086
------- -------
Total Common Shareholder's Equity 1,173,3041,188,968 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 1,078,354981,380 1,077,987
--------- ---------Long-term Debt - Affiliated Company 300,000 -
------- ----
TOTAL CAPITALIZATION 2,277,1562,495,846 2,285,255
--------- ---------
OTHER NONCURRENT LIABILITIES 515,450136,600 542,017
------- -------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 117,506
Advances from Affiliates 252,323360,048 -
Accounts Payable - General 160,578160,717 179,691
Accounts Payable - Affiliated Companies 77,47770,661 121,360
Customer Deposits 7,3688,993 39,736
Taxes Accrued 184,07925,876 223,101
Interest Accrued 24,29930,054 20,458
Obligations Under Capital Leases 14,05714,180 32,716
Energy Trading Contracts 1,358,005719,697 1,662,315
Other 140,792121,306 151,934
------- -------
TOTAL CURRENT LIABILITIES 2,218,9781,511,532 2,548,817
--------- ---------
DEFERRED INCOME TAXES 609,885753,689 621,941
------- -------
DEFERRED INVESTMENT TAX CREDITS 23,64422,875 25,214
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 431,934266,545 206,187
------- -------
REGULATORY LIABILITIES AND DEFERRED CREDITS 40,72011,937 23,005
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $6,117,767$5,199,024 $6,252,436
========== ==========
See Notes to Financial Statements beginning on page L-1.
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 63,976115,354 $ 104,449162,634
Adjustments for Noncash Items:
Depreciation 93,161 100,439134,105 145,125
Amortization of Transition Assets 36,70555,029 -
Deferred Federal Income Taxes 116 (6,387)182,166 (2,058)
Deferred Fuel Costs (net) - (8,844)(33,259)
Amortization of Deferred Property Taxes 40,596 39,94461,821 60,297
Extraordinary Loss - Discontinuance SFAS 71 21,515 18,876
Capital Lease Obligation- Noncurrent (15,104) (15,489)
Accumulated Provisions- Noncurrent (390,313) 7,268
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) (37,904) (88,341)43,127 60,383
Fuel, Materials and Supplies 2,252 47,68017,611 60,686
Accrued Utility Revenues 264 45,575
Prepayments and Other Current Assets 15,116 (6,219)8,538 3,624
Accounts Payable (62,996) 129,756(69,673) 7,654
Customer Deposits (32,368) (1,209)(30,743) (2,711)
Taxes Accrued (39,022) (44,129)(197,225) (21,355)
Interest Accrued 3,841 1,3349,596 6,060
Energy Trading Contract (net) (73,339) (8,546)(86,421) (7,067)
Other (net) (24,345) 10,864(26,038) 52,475
------- ------
Net Cash Flows From (Used For) Operating Activities (13,947) 316,366
-------(166,391) 548,718
-------- -------
INVESTING ACTIVITIES:
Construction Expenditures (151,314) (91,118)(242,898) (143,717)
Proceeds from Sale of Property and Other 7,62616,562 4,404
Investment in Coal Companies (32,115) -
------- ----- ------
Net Cash Flows Used For Investing Activities (143,688) (91,118)(258,451) (139,313)
-------- ---------------
FINANCING ACTIVITIES:
Issuance of Long-term Debt - Affiliated 300,000 -
Issuance of Long-term Debt - 74,748
Change in Advances to Affiliates (net) 344,809 (148,965)452,534 (149,616)
Change in Short-term Debt (net) - (194,918)
Retirement of Cumulative Preferred Stock - (160)(182)
Retirement of Long-term Debt (117,506) (11,752)(216,697) (26,538)
Dividends Paid on Common Stock (71,488) (75,406)(107,232) (234,110)
Dividends Paid on Cumulative Preferred Stock (630) (633)(944) (947)
---- ----
Net Cash Flows From (Used For) Financing Activities 155,185 (357,086)427,661 (531,563)
------- --------
Net DecreaseIncrease (Decrease) in Cash and Cash Equivalents (2,450) (131,838)2,819 (122,158)
Cash and Cash Equivalents at Beginning of Period 31,393 157,138
------ -------
Cash and Cash Equivalents at End of Period $ 28,94334,212 $ 25,300
=========== ========
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
$8,422,00034,980
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $59,492,000 and
$59,963,000 and for income taxes was $55,806,000 and $56,813,000 in 2001 and
2000, respectively. Noncash acquisitions under capital leases were $595,000 and
$12,734,000 in 2001 and 2000, respectively.
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of generation,
retail electricity sales, power marketing and trading of electricity; and energy
delivery which consists of transmission and distribution services. Since the
merger of AEP and CSW in June 2000, we participate in the AEP System's power
marketing and trading activities conducted on our behalf by
the AEP System.
Although revenues increased substantially, operating expenses increased
by a greater amount causing netactivities.
Net income to decrease by $2.8decreased $3.3 million or 19%6% in the secondthird quarter and $5.5$8.8
million or 35%12% in the first halfnine months of 2001.2001 due primarily from last year's
inclusion of a gain on the sale of a minority interest in Scientech, Inc. Income
statement line items which changed significantly were:
Increase (Decrease)
-------------------
SecondThird Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $189 90 $384 104$355 64 $739 80
Fuel Expense 70 92 110 75(1) (1) 109 36
Purchased Power Expense 118 373 264 505351 144 614 208
Other Operation Expense 61 2 17 21
17 32Maintenance 3 36 4 12
Federal Income Taxes (3) (40) (5) (61)(9) (7) (20)
Nonoperating Income (7) (97) (7) (89)
The significant increase in operating revenues was duefor the quarter resulted from
increased trading volumes of the wholesale business. In the year-to-date period,
the increase in revenues is primarily attributable to our participation in the AEP System'sAEP's
power marketing and trading activities subsequent to June
2000.operations. Revenues for the year-to-date period
also increased as a result of the
absence of aan adjustment in 2000 adjustment due tounder a FERC-approved
Transmission Coordination Agreement, which decreased revenues and other
operation expenses in 2000. The transmission coordination agreementTransmission 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 year-to-date 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
our participation in the AEP System's power marketing and trading activities.
OtherYear-to-date 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 due toin 2000 under the FERC-approved Transmission Coordination
Agreement mentioned above, along with increased incentive compensation for power
trading and transmission expenses.
Maintenance expense increased year-to-date due to scheduled power plant
maintenance and additional expenses related to a January ice storm. Maintenance
for the quarter increased due to scheduled power plant maintenance.
Federal income tax expense associated with utility operations decreased as a
result of a decline in pre-tax book income.
The decrease in nonoperating income primarily resulted from last
year's inclusion of a gain on the sale of a minority interest in Scientech, Inc.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $398,194 $209,172 $754,333 $370,501$910,428 $555,236 $1,664,761 $925,738
-------- -------- ------------------ --------
OPERATING EXPENSES:
Fuel 145,927 75,808 257,728 147,394154,177 155,103 411,905 302,497
Purchased Power 149,261 31,541 315,807 52,207593,577 242,852 909,384 295,059
Other Operation 34,332 28,476 68,889 52,23232,970 32,235 101,859 84,468
Maintenance 12,859 13,408 22,689 21,99510,886 8,032 33,575 30,027
Depreciation and Amortization 19,673 18,926 39,144 37,83820,313 19,632 59,458 57,470
Taxes Other Than Federal Income Taxes 9,550 8,819 16,923 16,05812,914 12,660 29,837 28,718
Federal Income Taxes 4,650 7,692 2,871 7,415
----- ----- ----- -----25,677 28,285 28,548 35,700
------ ------- ------ ------
TOTAL OPERATING EXPENSES 376,252 184,670 724,051 335,139850,514 498,799 1,574,566 833,939
------- ------- ---------------- -------
OPERATING INCOME 21,942 24,502 30,282 35,36259,914 56,437 90,195 91,799
NONOPERATING INCOME 92 494 695 716
--213 7,211 908 7,927
--- ----- --- --------
INCOME BEFORE INTEREST CHARGES 22,034 24,996 30,977 36,07860,127 63,648 91,103 99,726
INTEREST CHARGES 10,113 10,296 20,616 20,213
------ ------9,058 9,319 29,674 29,532
----- ----- ------ ------
NET INCOME 11,921 14,700 10,361 15,86551,069 54,329 61,429 70,194
PREFERRED STOCK DIVIDEND REQUIREMENTS
53 53 106 10652 159 158
-- -- --- ---
EARNINGS APPLICABLE TO COMMON STOCK $ 11,86851,016 $ 14,647 $10,25554,277 $ 15,75961,270 $ 70,036
======== ======== =============== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $123,015 $123,348$121,822 $120,995 $137,688 $139,236
NET INCOME 11,921 14,700 10,361 15,86551,069 54,329 61,429 70,194
CASH DIVIDENDS DECLARED:
Common Stock 13,060 17,000 26,120 34,00039,180 51,000
Preferred Stock 53 53 106 10652 159 158
-- -- --- ---
BALANCE AT END OF PERIOD $121,823 $120,995 $121,823 $120,995$159,778 $158,272 $159,778 $158,272
======== ======== ======== ========
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)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 914,958$1,037,025 $914,096
Transmission 415,083418,793 396,695
Distribution 960,152972,827 938,053
General 209,171204,981 206,731
Construction Work in Progress 157,45235,776 149,095
------------- -------
Total Electric Utility Plant 2,656,8162,669,402 2,604,670
Accumulated Depreciation and Amortization 1,167,8751,175,621 1,150,253
--------- ---------
NET ELECTRIC UTILITY PLANT 1,488,9411,493,781 1,454,417
--------- ---------
OTHER PROPERTY AND INVESTMENTS 39,74940,384 38,211
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 26,80172,313 52,629
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 10,9067,569 11,301
Accounts Receivable:
Customers 32,10522,964 59,957
Affiliated Companies 13,8175,912 3,453
Fuel - at LIFO costs 20,07815,320 28,113
Materials and Supplies - at average costs 31,58332,791 29,642
Under-recovered Fuel Costs 11,519- 43,267
Energy Trading Contracts 93,037259,930 382,380
Prepayments 2,8163,188 1,559
----- -----
TOTAL CURRENT ASSETS 215,861347,674 559,672
------- -------
REGULATORY ASSETS 23,10629,650 29,338
------ ------
DEFERRED CHARGES 22,11617,580 7,889
------ -----
TOTAL ASSETS $1,816,574$2,001,382 $2,142,156
========== ==========
See Notes to Financial Statements beginning on page L-1.
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 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 $157,230$ 157,230
Paid-in Capital 180,000 180,000
Retained Earnings 121,823159,778 137,688
------- -------
Total Common Shareholder's Equity 459,053497,008 474,918
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 450,975451,052 450,822
------- -------
TOTAL CAPITALIZATION 990,3111,028,343 1,006,023
---------------- ---------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year - 20,000
Advances from Affiliates 147,44758,426 81,120
Accounts Payable - General 60,94938,510 104,379
Accounts Payable - Affiliated Companies 55,10432,686 64,556
Customers Deposits 22,49719,137 19,294
Over-recovered Fuel Costs 24,708 -
Taxes Accrued 29,66572,522 1,659
Interest Accrued 7,38912,107 8,336
Energy Trading Contracts 92,367260,800 389,279
Other 12,61513,769 12,137
------ ------
TOTAL CURRENT LIABILITIES 428,033532,665 700,760
------- -------
DEFERRED INCOME TAXES 302,746288,614 312,060
------- -------
DEFERRED INVESTMENT TAX CREDITS 34,88834,440 35,783
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 32,34239,407 35,292
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 28,25477,913 52,238
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $1,816,574$2,001,382 $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)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 10,361 $15,86561,429 $ 70,194
Adjustments for Noncash Items:
Depreciation and Amortization 39,144 37,83859,458 57,470
Deferred Income Taxes (10,754) 18,715(25,491) 19,798
Deferred Investment Tax Credits (895) (896)(1,343) (1,343)
Amortization of Deferred Property Taxes (8,568) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 17,488 (2,608)34,534 (34,933)
Fuel, Materials and Supplies 6,094 1,9329,644 158
Other Deferred Credits 1,997 22,627
Accounts Payable (52,882) 48,788(97,739) 50,079
Taxes Accrued 28,006 (22,413)70,863 12,685
Other Property and Investments (1,178) 2,391
Transmission Coordination Agreement Settlement - (15,063)
Deferred Property Taxes (14,951) -(1,814) (30,331)
Fuel Recovery 31,748 (25,571)67,975 (35,340)
Other (net) (5,276) 796(4,090) 12,150
------ ---------
Net Cash Flows From Operating Activities 46,905 59,774
------ ------166,855 143,214
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (67,042) (80,997)(88,194) (120,105)
Other (359) (4,694)-
---- ------
Net Cash Flows Used For Investing Activities (67,401) (85,691)(88,553) (120,105)
------- ---------------
FINANCING ACTIVITIES:
Retirement of Long-term Debt (20,000) (10,000)
Retirement of Cumulative Preferred Stock - (1)
Change in Advances from Affiliates (net) 66,327 69,690(22,695) 40,520
Dividends Paid on Common Stock (26,120) (34,000)(39,180) (51,000)
Dividends Paid on Cumulative Preferred Stock (106) (108)(159) (158)
---- ----
Net Cash Flows From Financing Activities 20,101 25,581
------(82,034) (20,638)
------- ------
Net Increase in Cash and Cash Equivalents (395) (336)(3,732) 2,471
Cash and Cash Equivalents at Beginning of Period 11,301 3,173
------ -----
Cash and Cash Equivalents at End of Period $10,906 $2,837
======= ======$ 7,569 $ 5,644
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $19,011,000$24,351,000 and
$16,754,000$24,222,000 and for income taxes was $1,978,000$7,386,000 and $11,725,000$13,925,000 in 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of generation,
retail electricity sales, power marketing and trading of electricity; and energy
delivery which consists of transmission and distribution services. Since the
merger of AEP and CSW in June 2000, we participate in the AEP System's power
marketing and trading activities conducted on our behalf by
the AEP System.activities.
Net income increased $11.2$10 million, or 42%14%, for the first half of 2001year-to-date period
despite a small decrease in the quarter of $1 million, or 5%2%. The increase for the
first half of 2001year-to-date period resulted from the favorable impact of our participation in
AEP's 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 $162 60 $376 78
Fuel Expense 10 9 39 19
Purchased Power Expense 149 776 307 991
Other Operation Expense (3) (9) 1 2
Depreciation and Amortization 6 21 7 12
Taxes Other Than Federal Income Taxes 2 11 5 21
Federal Income Taxes - - 6 73
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $455 79 $835 79
Fuel Expense (38) (22) 1 -
Purchased Power Expense 483 219 789 314
Other Operation Expense 7 18 8 8
Maintenance 3 21 3 7
Depreciation and Amortization - N.M. 11 15
Taxes Other Than Federal Income Taxes 1 7 6 15
Federal Income Taxes - N.M. 6 19
N.M. = Not Meaningful
The significant increase in operating revenues and purchased power
expense for the quarter and first half of 2001 resulted from increased trading volumes of the wholesale
business duebusiness. In the year-to-date period, the increase in revenues and purchased
power expense is also attributable to the post merger favorable impact ofour participation in AEP's power marketing
and trading operations.
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 forof the wholesale business increaseddecreased for the quarter due
primarily to an
increasea decrease in the average unit cost of fuel as a result of higherlower
spot market natural gas prices.
Other operation expense decreased for the quarter dueDue to the reversalacquisition of a $4 million environmental reserve originally recordedDolet Hills mining operation in the fourth quarter
of 1999. The reserve was set up for expected remediation work at a site on which
a manufactured gas plant previously resided. In June 2001,
the 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.
Otherother operation expense increased for the quarter and year-to-date period as a resultperiods.
Although tree-trimming expenses increased in the third quarter of a
bad debt write-off, our share2001,
they were slightly lower for the year-to-date period. Repairs to overhead lines
because of power trading incentive compensation incurred
sincesevere ice storms in the June 2000 merger and increased transmission servicesfirst quarter of 2001 made maintenance
expense partially
offset byincrease for the reversal of the $4 million environmental reserve.year-to-date period.
Depreciation and amortization expensesexpense increased year-to-date due
primarily to an increase in excess earnings accruals under the Texas
restructuring legislation.legislation and the acquisition of Dolet Hills mining operation.
Taxes other than federal income taxes increased during the second quarter due
to increased state income taxes reflecting higher state taxable income. The increase for the first six months of 2001 isTaxes
other than federal income taxes increased year-to-date due to a favorable
adjustment of ad valorem taxes recorded in 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 JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $434,795 $272,409 $860,484 $484,565$1,028,742 $573,891 $1,889,226 $1,054,056
---------- -------- -------- -------- ------------------ ----------
OPERATING EXPENSES:
Fuel 124,151 113,773 242,397 203,125134,560 172,763 376,957 375,888
Purchased Power 168,671 19,252 337,528 30,950702,899 220,114 1,040,427 251,064
Other Operation 34,071 37,362 73,339 72,06046,631 39,417 119,970 111,477
Maintenance 20,431 20,906 35,667 35,21215,344 12,644 51,011 47,856
Depreciation and Amortization 33,328 27,525 61,458 54,88228,461 27,978 89,919 78,460
Taxes Other Than Federal Income Taxes 14,986 13,455 29,252 24,11618,754 17,518 48,006 41,634
Federal Income Taxes 6,508 6,840 14,208 8,193
----- -----21,899 22,145 36,107 30,338
------ ----------- ------ ------
TOTAL OPERATING EXPENSES 402,146 239,113 793,849 428,538968,548 512,579 1,762,397 936,717
------- ------- ---------------- -------
OPERATING INCOME 32,649 33,296 66,635 56,02760,194 61,312 126,829 117,339
NONOPERATING INCOME 30 678 277 445
--627 1,008 904 1,453
--- ----- --- --------
INCOME BEFORE INTEREST CHARGES 32,679 33,974 66,912 56,47260,821 62,320 127,733 118,792
INTEREST CHARGES 14,895 15,188 29,259 30,02314,464 14,783 43,723 44,806
------ ------ ------ ------
NET INCOME 17,784 18,786 37,653 26,44946,357 47,537 84,010 73,986
PREFERRED STOCK DIVIDEND REQUIREMENTS
57 58 57 115 114172 172
-- -- --- ---
EARNINGS APPLICABLE TO
COMMON STOCK $ 17,72646,300 $ 18,72947,479 $ 37,53883,838 $ 26,33573,814
========= =========== ================= ======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $295,248 $275,652$294,422 $278,881 $293,989 $283,546
NET INCOME 17,784 18,786 37,653 26,44946,357 47,537 84,010 73,986
CASH DIVIDENDS DECLARED:
Common Stock 18,55218,554 15,500 37,105 31,00055,659 46,500
Preferred Stock 57 58 57 115 114172 172
-- -- --- ---
BALANCE AT END OF PERIOD $294,422 $278,881 $294,422 $278,881$322,168 $310,860 $322,168 $310,860
======== ======== ======== ========
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)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $1,472,831$1,432,242 $1,414,527
Transmission 531,793537,835 519,317
Distribution 1,024,4421,033,083 1,001,237
General 327,976375,603 325,948
Construction Work in Progress 48,38150,650 57,995
------ ------
Total Electric Utility Plant 3,405,4233,429,413 3,319,024
Accumulated Depreciation and Amortization 1,500,0991,525,936 1,457,005
--------- ---------
NET ELECTRIC UTILITY PLANT 1,905,3241,903,477 1,862,019
--------- ---------
OTHER PROPERTY AND INVESTMENTS 41,44342,213 39,627
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 32,21286,306 63,028
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 1,9544,650 1,907
Accounts Receivable:
Customers 50,53270,192 41,399
Affiliated Companies -2,283 11,419
Fuel Inventory - at average cost 43,19436,648 40,024
Under-recovered Fuel 44,91619,445 35,469
Materials and Supplies - at average cost 30,00431,342 25,137
Energy Trading Contracts 112,529314,306 457,936
Prepayments 18,56219,729 16,780
------ ------
TOTAL CURRENT ASSETS 301,691498,595 630,071
------- -------
REGULATORY ASSETS 52,12353,156 57,082
------ ------
DEFERRED CHARGES 83,77478,567 10,707
------ ------
TOTAL ASSETS $2,416,567$2,662,314 $2,662,534
========== ==========
See Notes to Financial Statements beginning on page L-1.
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
JuneSeptember 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 $135,660$ 135,660
Paid-in Capital 245,000 245,000
Retained Earnings 294,422322,168 293,989
------- -------
Total Common Shareowner's Equity 675,082702,828 674,649
Preferred Stock 4,704 4,704
SWEPCO-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
SUBORDINATED DEBENTURES OFSWEPCO-Obligated, Mandatorily Redeemable Preferred Securities
Of Subsidiary Trust Holding Solely Junior Subordinated
Debentures Of SWEPCO 110,000 110,000
Long-term Debt 494,876494,855 645,368
------- -------
TOTAL CAPITALIZATION 1,284,6621,312,387 1,434,721
--------- ---------
OTHER NONCURRENT LIABILITIES 32,37733,810 11,290
------ ------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year 150,595 595
Advances from Affiliates 136,48378,931 16,823
Accounts Payable - General 63,89254,042 107,747
Accounts Payable - Affiliated Companies 34,65030,909 36,021
Customer Deposits 20,47115,698 16,433
Taxes Accrued 52,38274,877 11,224
Interest Accrued 13,46614,697 13,198
Energy Trading Contracts 111,582314,475 466,198
Other 20,48724,767 15,064
------ ------
TOTAL CURRENT LIABILITIES 604,008758,991 683,303
------- -------
DEFERRED INCOME TAXES 396,364399,717 399,204
------- -------
DEFERRED INVESTMENT TAX CREDITS 50,95549,846 53,167
------ ------
REGULATORY LIABILITIES AND DEFERRED CREDITS 15,18920,432 18,288
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 33,01287,131 62,561
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $2,416,567$2,662,314 $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)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 37,653 $26,44984,010 $ 73,986
Adjustments for Noncash Items:
Depreciation and Amortization 61,458 54,88289,919 78,460
Deferred Income Taxes (4,546) 9,960(2,534) 10,901
Deferred Investment Tax Credits (2,212) (2,241)(3,321) (3,361)
Deferred Property Taxes (17,703)(9,316) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 2,286 8,375(19,657) (17,515)
Fuel, Materials and Supplies (4,266) (5,890)943 1,367
Accounts Payable (45,226) 29,989(58,817) 31,267
Taxes Accrued 41,158 (8,474)63,653 23,083
Transmission Coordination Agreement Settlement - (24,406)
Fuel Recovery (9,447) (18,218)16,024 (36,977)
Other (5,553) 647(1,193) 12,250
------ ---------
Net Cash Flows From Operating Activities 53,602 71,073
------ ------159,711 149,055
------- -------
INVESTING ACTIVITIES:
Construction Expenditures (49,418) (61,879)(76,668) (92,147)
Purchase of Dolet Hills Mining Operations (85,716) -
Other (411) (4,338)
---- -------
----- -------
Net Cash Flows Used For Investing Activities (135,545) (66,217)(162,795) (92,147)
-------- -------
FINANCING ACTIVITIES:
Redemption of Preferred Stock - (1)
Issuance of Long-term Debt - 149,367149,634
Retirement of Long-term Debt (450) (45,451)(45,450)
Change in Advances from Affiliates (net) 119,660 (77,655)62,108 (113,950)
Dividends Paid on Common Stock (37,105) (31,000)(55,659) (46,500)
Dividends Paid on Cumulative Preferred Stock (115) (119)(172) (172)
---- ----
Net Cash Flows From (Used For) Financing Activities 81,990 (4,858)
------ ------5,827 (56,439)
----- -------
Net Increase (Decrease) in Cash and Cash Equivalents 47 (2)2,743 469
Cash and Cash Equivalents at Beginning of Period 1,907 3,043
----- -----
Cash and Cash Equivalents at End of Period $ 1,9544,650 $ 3,0413,512
========= =======
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========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $38,614,000 and
$42,627,000 and for income taxes was $5,524,000 and $16,040,000 in 2001 and
2000, respectively.
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECONDTHIRD QUARTER 2001 vs. SECONDTHIRD QUARTER 2000
AND
YEAR-TO-DATE 2001 vs. YEAR-TO-DATE 2000
We have two businesses: wholesale which consists of
generation, retail electricity sales, power marketing and trading of
electricity; and energy delivery which consists of transmission and
distribution services. Since the merger of AEP and CSW in June 2000, we
participate in power marketing and trading
activities conducted on our behalf by the AEP System.
Net income decreased $1.9 million or 24% for the quarter and
was $4.9 million, or 41%, lower for the six months ended June 30, 2001.
The decreases were primarily due to increased operating expenses
primarily higher transmission related expenses offset in part by 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 $62 47 $161 71
Fuel Expense - - 31 41
Purchased Power Expense 58 258 125 334
Other Operation Expense 10 61 15 42
Maintenance Expense 2 40 2 17
Federal Income Taxes (3) (56) (5) (69)
Nonoperating Income 3 82 4 127
The significant increase in operating revenues was primarily
due to the participation in the AEP System's power marketing and trading activities subsequentactivities.
Net income for the third quarter increased $3.4 million, or
32%, due to Juneincreases in operating and nonoperating income. Year-to-date
net income decreased $1.5 million, or 7%, as the result of a decrease in
operating income offset by an increase in nonoperating income.
Nonoperating income increased in both periods as the result of loss
provisions that were recorded in the second and third quarters of 2000
for the termination of merchandise sales and the cost of phasing out of
the merchandising sales programs. Income statement line item which
changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues $180 72 $344 73
Fuel Expense (16) (28) 15 11
Purchased Power Expense 204 198 329 235
Other Operation Expense (6) (20) 9 13
Maintenance Expense (1) (12) 1 8
Depreciation and Amortization (7) (29) (3) (6)
Taxes Other Than Federal Income Taxes 3 43 4 23
Federal Income Taxes 2 29 (3) (27)
Nonoperating Income 2 N.M. 6 N.M.
N.M. = Not Meaningful
The significant increase in revenues for the quarter resulted
from increased trading volumes of the wholesale business. In the
year-to-date period, the increase in revenues is primarily attributable
to our participation in AEP's power marketing and trading operations and
higher fuel related revenues due to increased fuel and purchased power
expense of the wholesale business.
WTU began sharing in AEP's marketing and trading transactions as a result
of the merger of AEP and CSW in June 2000.
Fuel expense decreased for the quarter and increased due primarily toin the
year-to-date period. The fluctuation in spot market natural gas prices
resulted in a decrease for the quarter and an increase in the
average unit cost of fuel as a result of higher spot market natural gas
prices.
Purchasedyear-to-date period.
The increase in purchased power expense's significant riseexpense was primarily
attributable to our participation in AEP's power marketing and trading
operation and the adverse impact of natural gas prices on wholesale
purchased power prices.
Other operation expense increase isdecreased for the quarter due
primarily to a 2000
reduction in energy delivery'sdecreased transmission expenses that resulted from
new prices for the Electric Reliability Council of Texas (ERCOT)
transmission grid.expenses. Other operation expense also
increased year-to-date due to a favorable adjustment made in January 2000
related to the FERC
approveda FERC-approved Transmission Coordination Agreement.
Maintenance expense increased due to a scheduledthe overhaul in 2001 of
the Oklaunion Power Plant of our wholesale business.
Depreciation and amortization expense decreased due to the
effect of recording additional accruals in the third quarter of 2000 for
estimated excess earnings as required by Texas Restructuring Legislation.
An increase in taxes other than federal income taxes resulted
from an increase in Texas franchise tax assessments and an increase in
the Texas PUCT benefit assessment tax, a new tax in the state of Texas.
Federal income taxes attributable to operations increased in
the quarter and decreased due primarily to a
decreaseyear-to-date, reflecting the fluctuations in
pre-tax income.income in those periods.
The increase in nonoperating income was due primarily to a loss
provision that was recorded in the second quarterand third quarters of 2000 for
the termination of merchandise sales and the cost of phasing out of the
merchandising sales program.programs.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
OPERATING REVENUES $192,839 $130,742 $387,845 $227,277$429,623 $249,330 $817,468 $473,407
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel 46,848 47,207 106,753 75,78741,667 57,728 148,420 133,515
Purchased Power 80,485 22,455 162,177 37,348306,931 102,825 469,108 140,173
Other Operation 25,355 15,751 51,111 36,05525,636 32,046 76,747 68,101
Maintenance 7,046 5,045 11,608 9,9074,379 4,959 15,987 14,866
Depreciation and Amortization 11,529 11,292 23,300 22,53316,149 22,717 39,449 42,050
Taxes Other Than Federal Income Taxes 6,775 6,653 12,813 11,61610,136 7,096 22,949 18,712
Federal Income Taxes 2,373 5,401 2,263 7,3126,980 5,394 9,243 12,706
----- ----- ----- -----------
TOTAL OPERATING EXPENSES 180,411 113,804 370,025 200,558411,878 232,765 781,903 430,123
------- ------- ------- -------
OPERATING INCOME 12,428 16,938 17,820 26,71917,745 16,565 35,565 43,284
NONOPERATING INCOME (LOSS) (553) (3,149) 878 (3,239)1,628 (202) 2,506 (3,441)
----- ---- ------ -------- ------
INCOME BEFORE INTEREST CHARGES 11,875 13,789 18,698 23,48019,373 16,363 38,071 39,843
INTEREST CHARGES 5,742 5,719 11,674 11,5775,306 5,693 16,980 17,270
----- ----- ------ ------
NET INCOME 6,133 8,070 7,024 11,90314,067 10,670 21,091 22,573
PREFERRED STOCK DIVIDEND REQUIREMENTS
26 26 52 5278 78
-- -- -- --
EARNINGS APPLICABLE TO COMMON STOCK
$ 6,10714,041 $ 8,04410,644 $ 6,972 $11,85121,013 $ 22,495
========= =============== ========= ===============
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended JuneSeptember 30, SixNine Months Ended JuneSeptember 30,
2001 2000 2001 2000
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD $116,247 $112,549$115,148 $116,093 $122,588 $113,242
NET INCOME 6,133 8,070 7,024 11,90314,067 10,670 21,091 22,573
DEDUCTIONS:
Cash Dividends Declared:
Common Stock 7,206 4,500 14,412 9,00021,618 13,500
Preferred Stock 26 26 52 5278 78
-- -- -- --
BALANCE AT END OF PERIOD $115,148 $116,093 $115,148 $116,093$121,983 $122,237 $121,983 $122,237
======== ======== ======== ========
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)
JuneSeptember 30, 2001 December 31, 2000
------------------------------- -----------------
(in thousands)
ASSETS
- ------
ELECTRIC UTILITY PLANT:
Production $ 437,880439,825 $ 431,793
Transmission 236,532249,976 235,303
Distribution 424,258428,473 416,587
General 112,139113,827 110,832
Construction Work in Progress 35,15621,106 34,824
------ ------
Total Electric Utility Plant 1,245,9651,253,207 1,229,339
Accumulated Depreciation and Amortization 531,411539,587 515,041
------- -------
NET ELECTRIC UTILITY PLANT 714,554713,620 714,298
------- -------
OTHER PROPERTY AND INVESTMENTS 24,10024,516 23,154
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 10,70528,683 20,944
------ ------
CURRENT ASSETS:
Cash and Cash Equivalents 6,328 6,941
3,982
Accounts Receivable:
Customers 19,11120,340 36,217
Affiliated Companies 8,2719,570 16,095
Allowance for Uncollectible Accounts (299)(163) (288)
Fuel Inventory - at average cost 14,8619,969 12,174
Materials and Supplies - at average cost 11,09911,314 10,510
UnderrecoveredUnder-recovered Fuel 59,12953,863 68,107
Energy Trading Contracts 37,398104,458 152,174
Prepayments and Other Current Assets 1,306 851
----- ---
811
TOTAL CURRENT ASSETS 154,363216,985 302,781
------- -------
REGULATORY ASSETS 19,07516,849 24,808
------ ------
DEFERRED CHARGES 10,1887,128 2,947
----------- -----
TOTAL ASSETS $ 932,985$1,007,781 $1,088,932
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
JuneSeptember 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 $137,214
Paid-in Capital 2,236 2,236
Retained Earnings 115,148121,983 122,588
------- -------
Total Common Shareowner's Equity 254,598261,433 262,038
Cumulative Preferred Stock Not Subject to Mandatory Redemption 2,482 2,482
Long-term Debt 255,905255,936 255,843
------- -------
TOTAL CAPITZALIZATION 512,985519,851 520,363
------- -------
CURRENT LIABILITIES:
Advances from Affiliates 71,95346,130 58,578
Accounts Payable - General 32,07321,356 45,562
Accounts Payable - Affiliated Companies 12,89614,992 42,212
Customer Deposits 3,221 2,659
4,614
Taxes Accrued 32,20646,009 18,901
Interest Accrued 4,319 3,717
3,119
Energy Trading Contracts 37,083104,489 154,919
Other 10,614 7,906
------ -----
8,895
TOTAL CURRENT LIABILITIES 202,839251,130 334,454
------- -------
DEFERRED INCOME TAXES 152,232148,872 157,038
------- -------
DEFERRED INVESTMENT TAX CREDITS 23,41623,099 24,052
------ ------
LONG-TERM ENERGY TRADING CONTRACTS 28,957 20,789
------ 10,972------
REGULATORY LIABILITIES AND DEFERRED CREDITS 30,54135,872 32,236
------ ------
CONTINGENCIES (Note 8)
TOTAL CAPITALIZATION AND LIABILITIES $ 932,985$1,007,781 $1,088,932
========== ==========
See Notes to Financial Statements beginning on page L-1.
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
SixNine Months Ended JuneSeptember 30,
2001 2000
---- ----
(in thousands)
OPERATING ACTIVITIES:
Net Income $ 7,024 $11,90321,091 $ 22,573
Adjustments for Noncash Items:
Depreciation and Amortization 23,300 22,95939,449 42,050
Deferred Income Taxes (4,738) (1,220)(8,060) 5,586
Deferred Investment Tax Credits (636) (636)(953) (953)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net) 24,941 8,64422,277 (89)
Fuel, Materials and Supplies (3,276) 5,6821,401 6,469
Accounts Payable (42,805) 11,627(51,426) 16,369
Taxes Accrued 13,305 (1,981)27,108 1,292
Transmission Coordination Agreement Settlement - 15,465
Deferred Property Taxes (6,200)(4,297) -
Fuel Recovery 8,978 (5,818)14,245 (34,310)
Other (net) (1,324) (894)
------1,634 (588)
----- ----
Net Cash Flows From Operating Activities 18,569 65,73162,469 73,864
------ ------
INVESTING ACTIVITIES:
Construction Expenditures (20,312) (32,470)(28,811) (43,938)
Other (127) (1,878)-
---- -------------
Net Cash Flows Used For Investing Activities (20,439) (34,348)(28,938) (43,938)
------- -------
FINANCING ACTIVITIES:
Retirement of Long-term Debt - (40,000)
Change in Advances from Affiliates (net) 13,375 19,048(12,448) 26,238
Dividends Paid on Common Stock (14,412) (9,000)(21,618) (13,500)
Dividends Paid on Cumulative Preferred Stock (52) (55)(78) (78)
--- ---
Net Cash Flows Used For Financing Activities (1,089) (30,007)
------(34,144) (27,340)
------- -------
Net Increase (Decrease) in Cash and Cash Equivalents (2,959) 1,376(613) 2,586
Cash and Cash Equivalents at Beginning of Period 6,941 6,074
----- -----
Cash and Cash Equivalents at End of Period $ 3,9826,328 $ 7,450
======= =======
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $10,139,000 and
$9,053,0008,660
======== ========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $11,761,000 and
$13,994,000 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.
NOTES TO FINANCIAL STATEMENTS
JUNESEPTEMBER 30, 2001
(UNAUDITED)
The notes to financial statements are a combined presentation for AEP and its
subsidiary registrants as follows:
1. General AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, WTU
2. Extraordinary Items
and Cumulative Effect
of Accounting Change 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 Activities
and Related
ActivitiesMinority Interest 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
prior year amounts were reclassified from revenues to purchased power
expense to present the prior period on a comparable basis:
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
Three Months Ended Nine Months Ended
September 30, 2000 September 30, 2000
Company (in thousands)
-------
AEP $7,692,103 $15,756,630
APCo 1,063,249 2,660,105
CPL 194,425 194,425
CSPCo 574,254 1,506,671
I&M 637,437 1,651,035
KPCo 252,596 631,748
OPCo 901,960 2,300,395
PSO 196,527 196,527
SWEPCo 196,449 196,449
WTU 48,139 48,139
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. EXTRAORDINARY ITEMS AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE
OPCo and CSPCo Recognize Extraordinary 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 the Gross Receipts Tax -
GRT) net of allowable Ohio coal credits during the quarter ended June
30, 2001. This loss resulted from regulatory decisions in connection
with Ohio deregulation which stranded the recovery of the GRT. 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 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.
Cumulative Effect of Accounting Change - Affecting AEP
Guidance for certain fuel supply contracts with volume
optionality and electricity capacity contracts issued by the FASB's
Derivative Implementation Group (DIG) regarding the implementation of
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities"
became effective in the third quarter of 2001. The guidance concluded
that fuel supply contracts with volumetric optionality cannot qualify
for a normal purchase or sale exclusion from mark-to-market accounting
and provided guidance for determining when electricity capacity
contracts can qualify as a normal purchase or sale.
Predominantly all of AEP's contracts for coal, gas and
electricity, which are recorded on a settlement basis, do not meet the
criteria of a financial derivative instrument, qualify as a normal
purchase or sale, and are thereby exempt from the DIG guidance described
above. Beginning July 1, 2001, the effective date of the DIG guidance,
certain of AEP's fuel supply contracts with volumetric optionality that
qualify as financial derivative instruments are marked to market with
any gain or loss recognized in the income statement. The effect of
initially adopting the DIG guidance at July 1, 2001, a favorable
earnings mark-to-market effect of $18 million, net of tax, is reported
as a cumulative effect of an accounting change on the income statement.
3. ACQUISITIONS AND SALES OF ASSETS
Sale of Generating Assets - Affecting AEP
As discussed in Note 3 of the 2000 Annual Report, the divestiture
of 1,904 MW of generating capacity was required by the FERC and the PUCT
as part of the approval of the merger. In March 2001 AEP completed the
sale of Frontera, one of the generating plants required to be divested
under the settlement agreements approved by the FERC. The sale proceeds
were $265 million and resulted in an after tax gain of $46 million.
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 adjustrecorded the assets acquired and liabilities assumed based upon
their estimated fair values. The allocation of the purchase price for changes in its
preliminary evaluations and assumptionsmay be
adjusted based on reviewupon completion of additional
information.the appraisal process. 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 jointly
owned lignite reserves in Louisiana. To settle litigation, which is
discussed in Note 8, SWEPCo paid $86 million to purchase the mining
assets and rights of the 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 minimal impact on results of operations.
Sale of Generating Assets - Affecting AEP
In July 2001 AEP, through a wholly owned subsidiary, sold its 50%
interest in a 120-megawatt generating plant located in Mexico. The sale
resulted in a third quarter after tax gain of approximately $11 million.
Sale of Affiliated Coal Mines - Affecting AEP and OPCo
In July 2001 AEP and OPCo sold coal mines in Ohio and West
Virginia and agreed to purchase approximately 34 million tons of coal
from the purchaser of the mines through 2008. The sale is expected to
havehad a nominal
impact on results of operations.
Acquisition of Coal Assets - Affecting AEP
In October 2001 AEP acquired substantially all the assets of
Quaker Coal Company as part of a bankruptcy proceeding settlement. AEP
paid $101 million to Quaker's creditors and assumed additional
liabilities of approximately $45 million. The acquisition includes
property, coal reserves, mining operations and cash flows.royalty interests in
Colorado, Kentucky, Ohio, Pennsylvania and West Virginia. AEP will
continue to operate the mines and facilities which employ over 800
individuals. The purchase method of accounting was used to record the
acquisition. AEP recorded the assets acquired and liabilities assumed
based upon their estimated fair values. The allocation of the purchase
price may be adjusted based upon completion of an appraisal process. 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 Barge Line - Affecting AEP
On November 1, 2001, AEP, through a wholly owned subsidiary,
acquired MEMCO Barge Line. The $270 million acquisition adds 1200 hopper
barges and 30 towboats to AEP's existing barging fleet. MEMCO's 450
employees will continue to operate the barge line. The purchase method
of accounting was used to record the acquisition. AEP recorded the
assets acquired and liabilities assumed based upon their estimated fair
values. The allocation of the purchase price may be adjusted based upon
completion of an appraisal process. 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.
4. RATE MATTERS
Texas Fuel Costs - Affecting AEP, CPL, SWEPCo and WTU
As discussed in Note 5 of the 2000 Annual Report, AEP's Texas
electric operating companies experienced natural gas fuel price increases
which resulted in under-recoveries of fuel costs.
Fuel recovery for Texas utilities is a multi-step procedure. When
fuel costs change, utilities file with the PUCT for authority to adjust
fuel factors. If a utility's prior fuel factors result in an over- or
under-recovery of fuel, the utility will also request a surcharge factor
to refund or collect that amount. While fuel factors are intended to
recover all fuel-related costs, final settlement of these accounts are
subject to reconciliation and approval by the PUCT.
Fuel reconciliation proceedings determine whether fuel costs
incurred and collected during the reconciliation period were reasonable
and necessary. All fuel costs incurred since the prior reconciliation date
are subject to PUCT review and approval. If material amounts are
determined to be unreasonable and ordered to be refunded to customers,
results of operations and cash flows would be negatively impacted.
FuelAccording to Texas Restructuring Legislation, fuel cost in the Texas
jurisdiction after 2001 will no longer be subject to PUCT review and
reconciliation. During 2002 CPL SWEPCo, and
WTU will file a final fuel reconciliation with
the PUCT to reconcile theirits fuel costs through the period ending December
31, 2001. The unrecoveredultimate recovery of deferred fuel balances at December 31,
2001 will be included in each
company'sdecided as part of CPL's 2004 true-up proceeding. If the
final under-recovered fuel balances or any amounts incurred but not yet
reconciled are disallowed, it would have a negative impact on results of
operations.
In October 2001 the PUCT delayed the start of customer choice in the
SPP area of Texas. Portions of SWEPCo's and WTU's service territories are
in the SPP. The effect of the delay on fuel recovery is being reviewed by
the PUCT and management. The PUCT has not announced how the delay will be
applied to WTU whose customers are in SPP and ERCOT.
The following table lists the status of Texas jurisdictional
reconciliation,
status, total fuel cost subject to reconciliation, under-recovered
fuel balances and the remaining fuel surcharge for the companies:by company:
Fuel cost subject to Under-recovered
Reconciliation reconciliation at fuel balances at Remaining authorized
Company completed through JuneSeptember 30, 2001 JuneSeptember 30, 2001 fuel surcharge
------- ----------------- ------------- ------------------------------- ------------------ --------------
CPL June 30, 1998 $1.4$1.6 billion $93$11 million $25 millionNONE
SWEPCo December 31, 1999 240283 million 2918 million 13$6 million
WTU June 30, 1997 581641 million 5751 million 63 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 expectsIn October 2001 the PUCT
to deferdeferred consideration of WTU's fuel 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.
FERC Transmission Rates - Affecting AEP, CPL, PSO, SWEPCo and WTU
In November 2001 FERC issued an order requiring CPL, PSO, SWEPCo and
WTU to submit revised open access transmission tariffs, and calculate and
issue refunds for overcharges from January 1, 1997. The order resulted
from a remand by an appeals court of a tariff compliance filing order
issued in November 1998 that had been appealed by certain customers. The
companies are evaluating the order and its impact on results of operations
and cash flows.
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 fromthat the Staff of the PUCT and the Office of Public
Utility Counsel (OPC). disagreed with the reports as filed. The Staff and
OPC took exception to certain adjustments made by the companies, andcompanies. 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 showsPUCT issued a final order in September 2001 and the amountscompanies
recorded adjustments to match estimated provisions with final amounts.
The companies requested a rehearing on the proper determination of
excess earnings calculated by
each company,which the PUCT Staff anddenied. In October 2001 the OPC:
2000 Excess Earnings
Ascompanies filed
As calculated As calculated
by company by PUCT Staff byin district court seeking judicial review of 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 amountPUCT's determination of
excess earnings finally approved
byearnings. A decision from the PUCT willcourt is not have a materially adverse effect on their results of
operations or cash flows. A PUCT decision is due in late August 2001.expected until 2002.
5. INDUSTRY RESTRUCTURING
----------------------
As discussed in the 2000 Annual Report, restructuring legislation
has been enacted in seven of AEP's eleven state retail electric
jurisdictions. The legislation provides for a transition from cost-based
regulation of bundled electric service to customer choice and market
pricing for the generation of electricity.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001, customer choice of electricity supplier
began under the Ohio Act. The PUCO approved alternative suppliers (many of
whom remain inactive) to compete for CSPCo's and OPCo's customers.
Virtually all customers continue to be served by CSPCo and OPCo.
In accordance with the Ohio Act, CSPCo and OPCo implemented rate
reductions of 5% for the generation portion of residential rates effective
January 1, 2001. The generation portion of retail rates, including fuel,
will remain frozen until December 31, 2005 or the PUCO determines that a
competitive market exists.
On January 16, 2001, Shell Energy Services Company filed a Notice of
Appeal with the Ohio Supreme Court challenging PUCO's approval of our
transition settlement agreement including recovery of regulatory assets.
Shell withdrew as an alternative retail supplier for Ohio. The PUCO's
motion to dismiss Shell's appeal is pending before the Ohio Supreme Court.
Management is unable to predict the outcome of this litigation. The
resolution of this matter could negatively impact future results of
operations and cash flows.
Virginia Restructuring - Affecting AEP and APCo
In accordance with its restructuring law, the Virginia jurisdiction
will begin a transition to choice of electricity supplier for retail
customers on January 1, 2002. The Virginia restructuring law requires
filings to be made that outline the functional separation of generation
from transmission and distribution and a rate unbundling plan. APCo filed
its separation plan and rate unbundling plan with the Virginia SCC.
Hearings are scheduled forwere held in October 2001. Settlement agreements that resolved
most issues except the assignment of the generation - related regulatory
assets among functionally separated generation and delivery organizations
are pending before the Virginia SCC. Presently, capped rates are
sufficient to recover generation-relatedgeneration - related regulatory assets. Management
is unable to predict if the outcome of the hearings will result in the
ability to recover generation-related regulatory assets.hearings.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 Arkansas enacted legislation to restructure its electric
utility industry. In February 2001 the Arkansas General Assembly passed
legislation that was signed into law by the Governor to delay
restructuring. The legislation extended the date for the start of retail
electric 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
Texas Restructuring Legislation gives customers 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 including the final
fuel recovery, net regulatory asset recovery, 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 is
still subject to challenge. In March 2000 CPL submitted a $1.1 billion
estimate of stranded costs. After hearinghearings on the submission, the PUCT
issued in February 2001 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 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 beginning
January 1, 2002 in order to return estimated excess earnings for 1999,
2000 and 2001. The Texas Restructuring Legislation intended that excess
earnings reduce stranded costs. Final stranded cost amounts and the
treatment of excess earnings will be determined in the 2004 true-up
proceeding. Currently the PUCT estimates that CPL will have no stranded
costs and has ordered the rate reduction to return excess earnings.
Management believes that CPL will have stranded costs in 2004, and that
the current treatment of excess earnings will be amended at that time.
Since CPL expensed excess earnings amounts in 1999, 2000 and 2001. Consequently,2001, the
April order has no additional effect on reported net income. The amount to
be refunded is recorded as a regulatory liability.
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 requestedCourt
dismissed the plaintiffs' request for 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 parts of 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 achieveIn October 2001 the PUCT ordered a final
PUCT determination by November 1, 2001.delay in the start of retail
competition in the SPP area of Texas and continued the pilot project in
the SPP area. Management is evaluating the ramifications of a potentialthis 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 up to $20 million of previously identified STP
ECOM plant assets a year in 2000 and 2001 to reduce any excess earnings.
STP ECOM plant assets will be depreciated in accordance with GAAP, on a
systematic and rational 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.
In the event CPL, SWEPCo, and WTU are unable after the 2004 true-up
proceeding to recover their generation-related regulatory assets,
unrecovered fuel balances, stranded costs and other restructuring related
costs, it could result in an extraordinary loss which 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. On October 11, 2001, the MPSC
action
onissued an "Order Approving Settlement Agreement" which generally approved
I&M's June 5, 2001 filing except for agreed upon modifications. In
accordance with the filing is expectedsettlement agreement, I&M agreed that recovery of
implementation costs and regulatory assets would be determined in 2001 with competition commencingfuture
proceedings. The settlement agreement did not modify the procedure for
review of decommissioning cost recoveries. Customer choice commences 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 andor other
implementation costs in future proceedings, it could result in an
extraordinary loss that 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's three principal business segments and their respective
activities are:
o Wholesale
o Generation of electricity for sale to retail and wholesale customers.customers
o TradingMarketing and trading of electricity and gas worldwide.worldwide,
o OtherGas pipeline and storage services and other energy supply related
businesses.
o Energy Delivery
o Domestic electric transmission.transmission,
o Domestic electric distribution.
o Other Investments
o Foreign electricity generation investments.investments,
o Foreign electric distribution and supply.supply investments,
o Telecommunication services.
Amounts reported below for the three business segments include
certain estimates and allocations where necessary.
Energy Other Reconciling
Wholesale Delivery Investments Adjustments Consolidated
June 30, 2001 (in millions)
Nine months ended September 30, 2001 (in millions) Revenues from:
External customers $22,877$36,219 $ 1,637 $1,8812,599 $5,041 $ 2,298 $28,6933,219 $47,078
Transactions with other operating segments 1,067 10 30 (1,107)1,771 14 789 (2,574) -
Segment EBIT 845 483 142 (71) 1,3991,387 810 201 (121) 2,277
Total assets 29,566 14,379 7,539 (1,257) 50,227
Juneat September 30, 2001 32,632 13,321 8,008 (1,142) 52,819
Nine months ended September 30, 2000 Revenues from:
External customers 11,731 1,508 1,078 (63) 14,25421,908 2,428 1,550 (24) 25,862
Transactions with other operating segments 7341,214 1 50 (785)503 (1,718) -
Segment EBIT 302 513 155 (197) 773779 872 261 (244) 1,668
Total assets 21,033 12,370 7,709 (713) 40,399at September 30, 2000 23,574 11,918 5,306 (105) 40,693
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.
Wholesale Segment JuneNine Months Ended September 30, 2001 JuneNine Months Ended
September 30, 2001 September 30, 2000 September 30, 2000
------------------ ------------------ ------------------
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
--------- ---- --------- ----
(in thousands) (in thousands)
Wholesale Segment
APCo $3,523,410 $107,415 $3,666,392 $2,198,766$5,385,003 $135,288 $3,066,057 $3,595,000 $ 74,080 $2,970,385119,458 $2,658,933
CPL 1,008,450 133,445 2,935,249 535,881 100,597 2,789,4322,103,562 245,947 3,080,135 1,169,787 216,115 2,887,340
CSPCo 2,016,002 119,544 2,499,506 1,370,892 100,274 2,107,0873,173,388 197,304 2,157,522 2,222,019 186,255 1,840,981
I&M 2,394,505 86,108 3,994,291 1,569,142 (123,565) 3,517,8333,712,009 121,130 3,528,300 2,548,819 (124,079) 3,258,113
KPCo 831,124 4,162 772,669 509,991 2,425 605,1321,282,741 4,516 638,684 841,129 10,171 540,291
OPCo 3,061,833 125,565 3,927,606 2,255,604 147,781 3,657,3734,741,282 198,107 3,337,773 3,622,605 248,336 3,088,916
PSO 644,622 12,124 859,240 267,225 14,203 747,5761,455,850 51,063 946,654 729,999 59,411 856,661
SWEPCo 696,457 32,036 1,184,118 324,673 3,608 1,048,9721,626,283 73,034 1,304,534 782,780 33,247 1,130,548
WTU 306,515 1,336 400,251 149,959 241 360,295
682,956 12,410 432,338 332,458 8,548 393,230
Energy Delivery Segment
June 30, 2001 June 30, 2000
Revenues Revenues
From From
External Segment External Segment
Customers EBIT Total Assets Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $300,021 $115,711 $2,892,449 $283,686 $113,629 $2,343,363$455,587 $165,744 $2,418,839 $425,792 $155,580 $2,097,656
CPL 243,461 65,612 2,108,135 218,358 75,334 2,003,407384,290 120,376 2,212,194 380,246 129,952 2,073,726
CSPCo 218,666 44,065 1,405,972 190,745 36,605 1,185,236358,984 81,452 1,213,606 300,455 69,692 1,035,552
I&M 156,907 61,410 1,802,938 150,714 55,592 1,587,875241,581 91,305 1,592,600 231,691 103,294 1,470,643
KPCo 67,164 27,246 748,333 64,123 30,337 586,072101,367 42,748 618,567 92,281 40,484 523,274
OPCo 265,009 58,512 2,190,161 228,563 67,336 2,039,469405,352 78,516 1,861,251 346,225 109,428 1,722,479
PSO 109,711 23,187 957,334 103,276 28,855 832,922208,911 75,360 1,054,728 195,739 80,581 954,461
SWEPCo 164,027 51,909 1,232,449 159,892 60,994 1,091,788262,943 97,149 1,357,780 271,276 118,874 1,176,692
WTU 81,330 21,041 532,734 77,318 28,508 479,553
134,512 38,174 575,443 137,949 41,765 523,391
Registrant Subsidiaries
Company Total
June 30, 2001 June 30, 2000
Revenues Revenues
From From
External External
Customers EBIT Total Assets Customers EBIT Total Assets
(in thousands) (in thousands)
APCo $3,823,431 $223,126 $6,558,841 $2,482,452 $187,709 $5,313,748$5,840,590 $301,032 $5,484,896 $4,020,792 $275,038 $4,756,589
CPL 1,251,911 199,057 5,043,384 754,452 175,931 4,792,8392,487,852 366,323 5,292,329 1,550,033 346,067 4,961,066
CSPCo 2,234,668 163,609 3,905,478 1,561,637 136,879 3,292,3233,532,372 278,756 3,371,128 2,522,474 255,947 2,876,533
I&M 2,551,412 147,518 5,797,229 1,719,856 (67,973) 5,105,7083,953,590 212,435 5,120,900 2,780,510 (20,785) 4,728,756
KPCo 898,288 31,408 1,521,002 574,114 32,762 1,191,2041,384,108 47,264 1,257,251 933,410 50,655 1,063,565
OPCo 3,326,842 184,077 6,117,767 2,484,167 215,117 5,696,8425,146,634 276,623 5,199,024 3,968,830 357,764 4,811,395
PSO 754,333 35,311 1,816,574 370,501 43,058 1,580,4981,664,761 126,423 2,001,382 925,738 139,992 1,811,122
SWEPCo 860,484 83,945 2,416,567 484,565 64,602 2,140,7601,889,226 170,183 2,662,314 1,054,056 152,121 2,307,240
WTU 387,845 22,377 932,985 227,277 28,749 839,848817,468 50,584 1,007,781 470,407 50,313 916,621
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 unbundledstructurally separated into non-regulated wholesale and
regulated energy delivery businesses. The remaining utility
subsidiaries are expectedwill to be grouped with AEP's regulated business.
Management is currently in the process of obtaining the necessary
regulatory approvals to supportimplement this new business structure.
7. FINANCING ACTIVITIES AND RELATED ACTIVITIES
Long-term debt and other securities issuances and retirements
during the first sixMINORITY INTEREST
Long-term debt and other securities issuances and retirements
during the first nine months of 2001 were:
Type Principal Interest
Company of Debt Amount Rate Due Date
------- ------- --------- -------- --------
Issuances (in millions) (%)
---------
AEP Senior Unsecured Notes $ 250 5.505.50(a) 2003
AEP Senior Unsecured Notes 1,000 6.1256.125(a) 2006
OtherAPCo Senior Unsecured Notes 125 (b) 2003
Non-Registrant
AEP Subs. Various 152 4.00-6.00171 Various 2001-2004
------
Total AEP System $1,402$1,546
======
Retirements
APCo First Mortgage Bonds $100$ 100 6-3/8 2001
APCo Senior Unsecured Notes 75 4.00-6.00 2001
CPL Trust Preferred Securities 112 8.00 2037
CSP First Mortgage Bonds 42 7.25 2002
CSP First Mortgage Bonds 14 7.15 2002
CSP First Mortgage Bonds 32 6.80 2003
CSP First Mortgage Bonds 15 6.60 2003
CSP First Mortgage Bonds 15 6.10 2003
CSP First Mortgage Bonds 24 6.55 2004
CSP First Mortgage Bonds 24 6.75 2004
CSP First Mortgage Bonds 33 8.70 2022
CSP First Mortgage Bonds 23 8.40 2022
CSP First Mortgage Bonds 20 7.45 2024
CSP First Mortgage Bonds 21 7.60 2024
CSP Junior Debentures 2 8-3/8 2025
CSP Senior Unsecured Notes 12 6.85 2005
I&M First Mortgage Bonds 40 7.63 2001
I&M First Mortgage Bonds 5 7.35 2023
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
OPCo First Mortgage Bonds 13 6.00 2003
OPCo First Mortgage Bonds 30 6.15 2003
OPCo First Mortgage Bonds 45 8.80 2022
OPCo First Mortgage Bonds 10 7.75 2023
PSO First Mortgage Bonds 6 5.91 2001
PSO First Mortgage Bonds 5 6.02 2001
PSO First Mortgage Bonds 9 6.02 2001
OtherNon-Registrant
AEP Subs. Various 43 4.00-6.00230 Various 2001
----------
Total AEP System $457
====$1,035
======
In addition to the transactions reported in the table above, the
following table lists intercompany issuances of debt and retirements
of debt due to AEP Co., Inc.
Interest
Company Type of Debt Principal Amount Rate Due Date
------- ------------ ---------------- ---- --------
Issuances (in millions) (%)
---------
KPCo NoteCSP Notes Payable $ 200 (c) 2002
KPCo Notes Payable 60 6.501 2006
KPCo NoteNotes Payable 15 4.336 2003
OPCo Notes Payable 240 6.501 2006
OPCo Notes Payable 60 4.336 2003
Non-Registrant
AEP Subsidiaries NoteNotes Payable 644575 4.336-6.501 2001-2006
----------
Total AEP System $719$1,150
======
Retirements
-----------
Non-Registrant
AEP Subsidiaries Notes Payable $50 4.336-6.501 2001-2006
===
(a) In May 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 senior notes (due May 2006) is
6.125%. 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. If the Series B notes are not called for remarketing, they
will be redeemed.
(b) A floating interest rate is determined quarterly. The rate on
September 30, 2001 was 3.29%.
(c) A floating interest rate is determined quarterly. The rate on
September 30, 2001 was 3.265%.
Other Financing Activities
On May 24, 2001, AEP 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 an alternative means of funding 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 financings are
funding this facility.
Minority Interest in Subsidiaries
AEP's minority interests at September 30, 2001 and 2000 include the
following:
2001 2000
---- ----
(in millions)
Funding Subsidiary $750 $ -
Nanyang General Light Electric Co. 20 17
Other 3 3
---- ---
$773 $20
====
===
In August 2001 AEP formed a funding subsidiary as a limited
liability company and sold a non-controlling, preferred interest in
such limited liability company to a third party for $750 million. The
preferred interest receives a preferred return equal to an adjusted
floating reference rate. The $750 million received replaces interim
funding used to acquire Houston Pipe Line Company in June 2001(see Note
3). The preferred interest is supported by pipeline assets and $325
million of a preferred stock interest in an AEP affiliate which is
convertible, under certain circumstances, into $325 million of AEP
common stock. AEP could elect not to have the transaction supported by
the preferred stock of its affiliate if the preferred interest were
reduced by $225 million. The results of operations, cash flows and
financial position of the limited liability company are consolidated
with AEP. The non-controlling preferred interest in the limited
liability company is included on AEP's consolidated balance sheet line
"Minority Interest in Subsidiaries."
8. CONTINGENCIES
Litigation
Shareholders' Litigation - Affecting AEP
In 2000 five complaints were filed against AEP seeking
unspecified compensatory damages for alleged violations of federal
securities laws. A court order consolidated the cases. However, the
court has not determined if the plaintiffs represent a class consisting
of all persons and entities who acquired AEP common stock between July
25, 1997 and June 25, 1999. On March 5, 2001, AEP filed a motion to
dismiss the cases. All parties presented oral arguments on AEP's motion
to dismiss on June 7, 2001. Management believes these shareholder
complaints are without merit and intends to continue to oppose them. The
outcome of this litigation or its impact on results of operations, cash
flows or financial 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 damagedamages of up to $300 million plus
attorney's fees. CPL filed a counterclaim for overpayment of franchise
fees.
The litigation moved procedurally through the Texas Court System
and was sent to mediation without resolution. CPL notified the other
cities it serves of the pending class action suit. If aCPL has pledged to
extend any final decision which determines an underpayment of franchise
fees CPL has pledged to extend that final
decision to cities who declined to participate in the suit. The court ruled
that the class of plaintiffs would consist of approximately 30 cities
and set a trial datedate.
During the third quarter of 2001 the cities who declined to
participate in the class action lawsuit reached an agreement with CPL to
settle their claims. The agreement with approximately 95 cities requires
CPL to pay a total of $8 million and releases CPL from any further
liability. CPL recorded the liability in August 2001.
In October 2001 CPL settled with the city of San Juan and the
remaining class action cities for October 2001.approximately $3 million. Management
believes that it has substantial defenses against the cities' claimscourt will approve the settlements and plans to pursue its counterclaims. However,
management cannot predict the outcome of this litigation or its impact
on results of operations, cash flows or financial condition.payments will be
made before year-end.
Texas Base Rate Litigation - Affecting AEP and CPL
As discussed in the 2000 Annual Report, CPL ishas been involved in
litigation concerning a 1997 PUCT base rate order.
A request for review
is pending before the Texas Supreme Court.
The primary issues are:were:
o Classification of $800 million of invested capital at STP as
excess cost over market (ECOM) earning a lower return than
other generating property; and
o AnDisallowance of $18 million disallowance of affiliated service billings.
In October 2001 the Texas Supreme Court denied our request to
review this case. At this time, management is reviewing its options
which includes seeking a rehearing. Management is unable to predict the
final resolution of this litigation or its impact on results of
operations andor cash flows.
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 2000 Annual Report,
SWEPCo has been involved in litigation concerning the mining of lignite
from jointly owned lignite reserves. SWEPCo and CLECO are joint 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 2000 the parties agreed to settle the litigation. As part of the
settlement, SWEPCo purchased DHMV's interest in the mining assets and
mining rights for $86 million and assumed the related obligations for
mine reclamation (See Note 3). The settlement agreement gives CLECO the
option to acquire up to a 50% interest in the mining assets.
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. The Clean Air Act
authorizes civil penalties of up to $27,500 per day per violation at
each generating unit ($25,000 per day prior to January 30, 1997).
In March 2001 the District Court ruled claims for civil penalties
based on activities that occurred more than five years before the filing
date of the complaints cannot be imposed. There is no time limit on
claims for injunctive relief.
In February 2001 the plaintiffs requestedfiled a motion requesting a
determination that four projects undertaken on units at Sporn, Cardinal
and Clinch River plants do not constitute "routine maintenance, repair
and replacement" as used in the Clean Air Act. The AEP System companies' request to allow
time for additional discovery before responding toCourt denied the
plaintiffs' action was granted.motion as premature. 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.
In December 2000 Cinergy Corp., an unaffiliated utility, which
operates certain plants jointly owned with CSPCo, reached a tentative
agreement to settle litigation regarding generating plant emissions
under the Clean Air Act. Negotiations are continuing in an attempt to
reach final settlement terms. Cinergy's settlement could impact the
operation of Zimmer Plant and W.C. Beckjord Generating Station Unit 6
(owned 25.4% and 12.5%, respectively, by CSPCo). Until a final
settlement is reached, CSPCo will be unable to determine the
settlement's impact on its jointly owned facilities and its future
earningsresults of operations 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) requiring substantial
reductions in NOx emissions in a number of eastern states, including
states in which the AEP System's generating plants are located. The NOx
Rule washas been upheld by the D.C. Circuit Court. The U.S. Supreme Court denied
a petition requesting its review of the lower court decision.on appeal. The compliance date for the NOx Rule is
May 31, 2004.
The NOx Rule requiredrequires states to submit plans to comply with its
mandates.provisions. Federal EPA ruled that eleven states, including states in
which AEGCo's, APCo's, CSPCo's, I&M's, KPCo's and OPCo's generating
units are located, failed to submit approvable compliance plans. This ruling means
that thoseThose
states could face stringent sanctions including limits on construction
of new sources of air emissions, loss of federal highway funding and
possible Federal EPA takeover of state air quality management programs.
AEP and other utilities requested that 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 the Clean
Air Act. The rule imposes emissions reduction requirements comparable to
the NOx Rule beginning May 1, 2003, for most of AEP's coal-fired
generating units. After review, the D.C. Circuit Court upheld the
Section 126 Rule.
The D.C. Circuit Court instructed Federal EPA to justify methods
used to allocate allowances and project growth for both the NOx Rule and
the Section 126 Rule to justify methods used to allocate
allowances and project growth.Rule. AEP and other utilities requested that the D.C.
Circuit Court vacate the Section 126 Rule or suspend its May 2003
compliance date. They also askedOn August 24, 2001, the D.C. Circuit Court to retain
jurisdictionissued an
order tolling the compliance schedule until Federal EPA complied withresponds to the
Court's instructions.
remand.
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 compliance date is May 2003
for CPL and May 2005 for SWEPCo.
In May 2001 selective catalytic reduction (SCR) technology to
reduce NOx emissions on OPCo's Gavin 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 began 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, the Texas Natural Resource Conservation Commission
rule and the Section 126 Rule could result in required capital
expenditures totaling approximately $1.6 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, 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.
REGISTRANTS' COMBINED MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS
This is our combined presentation of management's discussion and
analysis of financial condition, contingencies and other matters related to AEP
and our subsidiary registrants. Management's discussion and analysis of results
of operations for the three and sixnine month periods ended JuneSeptember 30, 2001 is
presented with each registrants' financial statements elsewhere in this
document.
FINANCIAL CONDITION
Financing Activity
On May 10,Cash from operations and short-term borrowings provide working capital
and meet other short-term cash needs. We generally use short-term borrowings to
fund property acquisitions and construction until long-term funding mechanisms
are arranged. Sources of long-term funding include issuance of common stock,
minority interest or long-term debt and sale-leaseback or leasing agreements. We
operate a money pool and sell accounts receivables to provide liquidity for the
domestic electric subsidiaries. Short-term borrowings are supported by a
bank-sponsored note purchase agreement and two revolving credit agreements. At
September 30, 2001, approximately $1.4 billion was available for short-term
borrowings. To facilitate corporate separation, AEP issued $1.25 billion of
global notes in May 2001 (with intermediate maturities). The proceeds may be
loaned to certain subsidiaries, primarily in Ohio and Texas, to allow them to
reacquire debt consistingwith covenants that limit asset transfer or sale. Corporate
separation will require the transfer of $1assets between legal entities.
During the first nine months of 2001 cash from operations of $1.2
billion, the proceeds of seniorthe $1.25 billion global notes issuance and $250 millionproceeds
from the sale of putable callable notes. The interest
rate on the senior notes (due May 2006) is 6.125%. Additionally, AEP entered
into an interest rate swapa UK distribution company and two generating plants provided
cash to purchase HPL until permanent funding was arranged, fund construction,
retire debt and pay dividends. Major construction expenditures included amounts
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 purchasewind generation plant and remarketing,emission control technology on several
coal-fired generating units (see discussion in which case the maturity would
extend until May 2013. If the Series B notes are not called for remarketing,
they will be redeemed.
On May 24, 2001, AEP 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. InNote 8). During the third quarter
of 2001, HPL's permanent financing was completed by an issuance of a minority
interest which provided $735 million net of expenses. HPL's permanent financing
will increase funds available for other corporate purposes.
During the fourth quarter, Quaker Coal Co. and MEMCO Barge Line, Inc.
were acquired using short-term borrowings and available cash. In October 2001,
we planannounced our intent to replace this short-term
borrowing with long-term financing through a limited liability company.acquire two coal-fired generating plants in the UK.
The limited liability company expectstransaction is expected 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 positionbe completed by the end of the limited liability companyyear. Long-term
financing for these three acquisitions will be consolidated with AEParranged and treatedannounced 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
fleetcompleted. Long-term funding arrangements are often complex 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.can not be
completed immediately.
Total consolidated plant and property additions including capital leases
for the year-to-date period were $865 million.$1.3 billion. The following table shows the
additions by certain subsidiary registrants:
Company Amount
------- ------
(in millions)
APCo $108$188
CPL 110159
I&M 4166
OPCo 151244
SWEPCo 9677
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
forelectric operating companies
in Ohio and Texas operating companies, which includes CSPCo,(CSPCo, OPCo, CPL and WTU,WTU) to unregulated generation
companies. The filed plan also proposes amendments of the power pooling
agreements that affectsfor 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 atmay be
required to retire various debt securities of CSPCo, OPCo, CPL and WTU using
various methods including:
o call provisions forWTU.
In September 2001 CSPCo reacquired $263 million first mortgage bonds
that have an optional redemption
oand OPCo reacquired $97.5 million of first mortgage bonds in open market
purchases
o exchange offers
o tender offers
o defeasance
To date, wetransactions. CSPCo and OPCo used funds borrowed from AEP to reacquire the
bonds. First mortgage bond retirements will lower the amount of debt funded
under mortgage indenture covenants. The lower mortgage debt should facilitate
transfer of assets from one subsidiary to another.
RTO Formation
As discussed in Note 3 of the 2000 Annual Report, FERC Order No. 2000
and many of the settlement agreements with the state regulatory commissions to
approve the AEP-CSW Merger required the transfer of control of our transmission
system to an RTO. Certain AEP subsidiaries are participating in the formation of
the Alliance RTO, other subsidiaries are member of ERCOT or the SPP.
Subsidiaries who are members of the SPP are evaluating their options for RTO
membership following the SPP's announcement of its intention to merge with the
MISO.
In 2001 the Alliance companies and MISO entered into a settlement
addressing transmission pricing and other "seams" issues between the two RTOs.
The FERC also has expressed its opinion that four large RTO regions serving the
continental US will better support competition and reliability of electric
service. FERC is re-evaluating the functions that should be exercised by RTOs,
as expressed in Order No. 2000, and has formed federal/state panels to examine
the issue. It has extended the December 15, 2001 deadline set forth in Order No.
2000 for RTOs to become operational, and has stated that it will substitute a
new timeline. Certain state regulatory commissions have not made decisions relatingtaken exception to securities other than
first mortgage bonds.the
FERC's actions. Louisiana's commission ordered utilities it regulates, including
SWEPCo, to file to show the advantage of large RTOs to their customers.
Management is unable to predict the outcome of these activities and
proceedings or their impact on the timing and operation of RTOs or our results
of operations and cash flows.
OTHER MATTERS
Industry Restructuring
As discussed in Note 5 and our 2000 Annual Report, seven of our eleven
state retail jurisdictions enacted restructuring legislation. The legislation
provides for a transition from cost-based regulation of bundled electric service
to unbundled generation and energy delivery functions with customer choice and
market pricing for the generationsupply of electricity.
Ohio Restructuring - Affecting AEP, CSPCo and OPCo
Effective January 1, 2001, customer choice of electricity supplier
began under the Ohio Act. The PUCO approved alternative suppliers (many of whom
remain inactive) to compete for CSPCo's and OPCo's customers. CSPCo and OPCo
continue to serve virtually all customers.
In accordance with the Ohio Act, CSPCo and OPCo implemented rate
reductions of 5% for the generation portion of residential rates effective
January 1, 2001. Retail rates, including fuel, will remain frozen until December
31, 2005 or the PUCO determines that a competitive market exists.
On January 16, 2001, Shell Energy Services CompanyAn alternative supplier (who has since withdrawn from Ohio competition)
filed a Notice of Appeal with the Ohio Supreme Court challenging PUCO's approval
of our transition settlement agreement including recovery of regulatory assets.
A PUCO motion to dismiss this appeal is pending before the Ohio Supreme Court.
Management is unable to predict the outcome of this litigation. The resolution
of this matter could negatively impact our future results of operations and cash
flows. Virginia Restructuring - Affecting AEP and APCo
In accordance with its restructuring law, the Virginia jurisdiction
will begin a transition to choice of electricity supplier for retail customers
on January 1, 2002. The Virginia restructuring law requires filings to be made
that outline the functional separation of generation from transmission and
distribution and a rate unbundling plan. APCo filed its separation plan and rate
unbundling plan with the Virginia SCC. Hearings are scheduled forwere held in October 2001.
Settlement agreements that resolved most issues except the assignment of the
generation - related regulatory assets among functionally separated generation
and delivery organizations are pending before the Virginia SCC. Presently,
capped rates are sufficient to recover generation-relatedgeneration - related regulatory assets.
We are unable to predict if the outcome of the hearings will result in
the ability to recover generation-related regulatory assets.hearings.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 Arkansas enacted legislation to restructure its electric
utility industry. In February 2001 the Arkansas General Assembly passed
legislation that was signed into law by the Governor to delay restructuring. The
legislationwhich extended the date for the start of
retail electric competition to October 1, 2003 and provided the Arkansas
Commission with the authority to delay that date for up to two additional years.years
became law.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
Texas Restructuring Legislation gives customers 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 including the final fuel recovery, net regulatory asset
recovery, excess earnings offsets and other issues.
As discussed in our 2000 Annual Report, the method used to determine
initial stranded costs to be recovered beginning on January 1, 2002 is still
subject to challenge. In March 2000 CPL submitted a $1.1 billion estimate of
stranded costs. After hearinghearings on the submission, the PUCT issued in February
2001 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. We disagree with the ruling
and have requested a rehearing.
In April 2001 the PUCT issued an order requiring CPL to reduce futureits
distribution rates by $54.8 million over a five-year periodfor five-years beginning in January 2002 in
order to return estimated excess earnings for 1999, 2000 and 2001. The Texas
Restructuring Legislation intended that excess earnings reduce stranded costs.
Final stranded cost amounts and the treatment of excess earnings will be
determined in the 2004 true-up proceeding. Currently the PUCT estimates that CPL
will have no stranded costs and has ordered the rate reduction to return excess
earnings. We believe that CPL will have stranded costs in 2004, and that the
current treatment of excess earnings will be amended at that time. Since CPL
expensed excess earnings amounts in 1999, 2000 and 2001. Consequently,2001, the April order hashad no
additional effect on reported net income. The amount to be refunded is recorded
as a regulatory liability.
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 requestedCourt dismissed the plaintiffs'
request for 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,in the near
term.
In October 2001, the StaffPUCT delayed the start of the PUCT filed a Petition seeking a
determination of whether electric operationsretail competition in
the SPP are ready for
competition. This Petition affects SWEPCo and partarea 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.(see Note 5). We are evaluating the ramifications of a potentialthis
delay in the January 1, 2002 start date of competition for SWEPCo'sour SWEPCo and WTU'sWTU
Texas operations in the SPP.
A Texas settlement agreement in connection with our merger with CSW
permits CPL to apply up to $20 million of previously identified STP ECOM plant
assets a year in 2000 and 2001 to reduce any excess earnings. STP ECOM plant
assets will be depreciated in accordance with GAAP, on a systematic and rational
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.
In the event CPL, SWEPCo, and WTU are unable, after the 2004 true-up
proceeding, to recover 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, theThe Michigan Legislation gave the MPSC broad powers to implement
customer choice. In compliance with MPSC
orders, on June 5, 2001, I&MWe filed its proposed unbundled rates, open access tariffs and
terms of service.service in June 2001. In October 2001 the MPSC action on theapproved a settlement
agreement related to our filing is expected in 2001 with
competition commencingto implement customer choice on January 1, 2002.
We agreed that recovery of implementation costs and regulatory assets would be
determined in future proceedings and recovery of nuclear decommissioning costs
would continue to be reviewed separately.
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 andor other implementation costs in future proceedings,
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. Underindefinitely from its previously approved legislation,
thescheduled start
date for Oklahoma customer choice had beenof July 1, 2002.
Litigation
- ----------
Shareholders' Litigation - Affecting AEP
In 2000 five complaints were filed against us seeking unspecified
compensatory damages for alleged violations of federal securities laws (see Note
8). We believe these shareholder complaints are without merit and intend to
continue to oppose them. The outcome of this litigation or its impact on our
results of operations, cash flows or financial condition cannot be predicted.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
We have been involved inIn August and October 2001 CPL reached agreement to settle ongoing
litigation regardingrelated to municipal franchise fees with 125 cities in Texas as a result of a class action suit filedits service
territory. The agreements require CPL to pay approximately $11 million. The
agreements are subject to approval by the City of San Juan, Texas
in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and
seeks damage of upcourt which management expects to
$300 million plus attorney's fees. CPL filed a
counterclaim for overpayment of franchise fees.
The litigation moved procedurally through the Texas Court System and was
sent to mediation without resolution. CPL 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 who
declined to participate in the suit. The court ruled that the class of
plaintiffs would consist of approximately 30 cities and set a trial date for
October 2001.
We believe that we have substantial defenses against the cities' claims
and plan to pursue our counterclaims. However, we cannot predict the outcome of
this litigation or its impact on our results of operations, cash flows or
financial condition.occur before year-end.
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 2000 Annual Report, SWEPCo has been
involved in litigation concerning the mining of
lignite from reserves jointly owned lignite reserves. SWEPCo and CLECO are joint 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 2000 the parties agreed to settle the litigation.CLECO. As part of the settlement,
SWEPCo purchased DHMV'sthe mine operator's interest in the mining assets and mining rights
for $86 million and assumed the related obligations for mine reclamation (See(see
Note 3). The settlement agreement gives CLECO the option to acquire up to a 50%
interest in the mining assets.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo, I&M,
and OPCo
As discussed in our 2000 Annual Report and Note 8, Federal EPA, and a number
of states and certain special interest groups alleged that AEP, APCo, CSPCo,
I&M, and OPCo modified certain generating units over a 20 year period 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. We
believe our maintenance, repair and replacement activities were in conformity
with the Clean Air Act and intend to vigorously pursue our defense.
The Clean Air Act authorizes civil penalties of up to $27,500 per day
per violation at each generating unit ($25,000 per day prior to January 30,
1997). In March 2001 the District Court ruled claims for civil penalties based
on activities that occurred more than five years before the filing date of the
complaints, cannot be imposed. There is no time limit on claims for injunctive
relief.
In February 2001 the plaintiffs requested 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. Our request to allow time for additional discovery before responding to
the plaintiffs' action was granted. We believe our maintenance, repair and
replacement activities were in conformity with the Clean Air Act and intend to
vigorously pursue our defense.
If we do not prevail, any capital and operating costs of additional
pollution control equipment that may be required as well as any penalties
imposed would adversely affect future results of operations, cash flows and
possibly financial condition.
In December 2000 Cinergy Corp., anAn unaffiliated utility which operates certain plants jointly owned by
CSPCo, reached a tentative agreement to settle litigation regarding generating
plant emissions under the Clean Air Act. Negotiations are continuing in an attempt to reachand a final settlement terms.
Cinergy's
settlement could impact the operation of Zimmer Plant and W.C. Beckjord
Generating Station Unit 6 (owned 25.4% and 12.5%, respectively, by CSPCo). Until
a final settlement is reached, CSPCo will be unable to determine the
settlement's impact on its jointly owned facilities and its future earningsresults of
operations and cash flows.
NOx Reductions - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo
Federal EPA issued a rule (the NOx Rule) and granted petitions filed by
certain northeastern states (the Section 126 Rule) requiring substantial
reductions in NOx emissions in a number of eastern states, including certain
states in which the AEP System's generating plants are located. The NOx Rule was
upheld by the D.C. Circuit Court. The U.S. Supreme Court denied a petition
requesting its review of the lower court decision.located (see Note 8). The
compliance date for the NOx Rule is May 31, 2004.
The NOx Rule required states to submit plans to comply with its
mandates.
Federal EPA ruled that eleven states, including states in which APCo's,
I&M's and OPCo's generating units are located, failed to submit compliance plans.approvable plans
to comply with the NOx Rule. This ruling means that those states could face
stringent sanctions including limits on construction of new sources of air
emissions, loss of federal highway funding and possible Federal EPA takeover of
state air quality management programs. AEP and other utilities requestedA request for the D.C. Circuit Courtto review
this ruling.
Federal EPA also adopted a revised rule (the Section 126 Rule) granting
petitions filed by certain northeastern states under the Clean Air Act. The rule
imposes emissions reduction requirements comparable to the NOx Rule beginning
May 1, 2003, for most of our coal-fired generating units. After review, the D.C.
Circuit Court upheld the Section 126 Rule.ruling is pending.
The D.C. Circuit Court instructed Federal EPA to justify methods used to
allocate allowances and project growth for both the NOx Rule and the Section 126
RuleRule. In response to justify methods used to allocate allowances and project
growth. AEP and other utilities requested the D.C. Circuit Court vacate the
Section 126 Rule or suspend its May 2003 compliance date. They also askedrequest for the D.C. Circuit Court
to retain jurisdictionsuspend the May 2003 compliance date of the Section 126 Rule, the D.C.
Circuit Court issued an order tolling the compliance schedule until Federal EPA
complied withresponds to the Court's instructions.remand.
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 compliance date is May 2003 for CPL
and May 2005 for SWEPCo.
In May 2001 selective catalytic reduction (SCR) technology to reduce NOx
emissions on OPCo's Gavin 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 began 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,
the Texas Natural Resource Conservation Commission rule and the Section 126 Rule
could result in required capital expenditures totaling approximately $1.6
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, they will have an adverse effect
on future results of operations, cash flows and possibly financial condition.
New Accounting Standards
FASB's Derivative Implementation Group (DIG) Guidance for SFAS 133
"Accounting for Derivative Instruments and Hedging 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 normal
purchase or sale and provided guidance for determining when electricity
contracts can qualify as a normal purchase or sale.
Predominantly all of AEP's contracts for coal, gas and electricity 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 are 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 recently issued SFAS 141, "Business Combinations" and SFAS 142,
"Goodwill And Other Intangible Assets." SFAS 141 requires that the purchase
method of accounting be used to account for all business combinations entered
into after June 30, 2001. SFAS 142 requires that goodwill and other intangible
assets with indefinite lives be tested for impairment upon SFAS 142
implementation and annually thereafter. Amortization of goodwill and not be
subjected to amortization. The provisionsother
intangible assets with indefinite lives will cease with our implementation of
SFAS 142 will apply to us beginning January 1, 2002. The amortization of goodwill reduced our net
income by $23$35 million for the sixnine months ended JuneSeptember 30, 2001. We have not
quantifieddetermined the impact of adopting the other provision of these standards.
SFAS 143, "Accounting for Asset Retirement Obligations," will become
effective for us beginning January 1, 2003. SFAS 143 establishes accounting and
reporting for obligations associated with the retirement of tangible long-lived
assets and the related asset retirement costs. We are currently evaluating the
provisions of these standards.the standard and determining its impact on results of operations,
financial condition and cash flows.
In August 2001 the FASB issued SFAS 144, "Accounting for the Impairment
or Disposal of Long-lived Assets" which sets forth the accounting to recognize
and measure an impairment loss. This standard replaces the previous standard,
SFAS 121, "Accounting for the Long-lived Assets and for Long-lived Assets to be
Disposed Of." SFAS 144 will apply to us in January 2002. We do not expect the
implementation of SFAS 144 to materially affect results of operations or cash
flows.
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. AEP's internationally based electric distribution utilities
hedge market risk through forward commodity contracts.
Interest Rate Risk
Fair value and cash flow hedge contracts mitigate changes in interest
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
conditions.
We trade electricity and gas contracts with numerous counter parties.
Since our energy trading contracts are based on changes in market prices of the
related commodities, our exposures can change. We believe that our credit and
market exposures with any one counter party is not material.
QUANTITATIVE MARKET RISK
We employ policies and procedures to identify, assess and manage market
risk exposure. One procedure is the risk measurement model Value at Risk (VaR).
VaR is used daily to measure and monitor trading risk. VaR operates on the
variance - covariance method using historical prices to estimate volatility and
correlation and assumes a 95% confidence level and a one-day holding period.
The following table represents the high, average and low VaRs for AEP's
electric and gas trading activities and electric trading for its registrant
subsidiaries. VaR for AEP and Registrant Subsidiaries:
SixNine Months Ended Year Ending
JuneSeptember 30, December 31,
2001 2000
---- ----
High Average Low High Average Low
(in millions) (in millions)
AEP $25$28 $14 $6$5 $32 $10 $1
APCo 6 2 1 1 6 2 -
CPL 1 -1 - 4 1 -
CSPCo 31 1 - 3 1 -
I&M 41 1 - 4 1 -
KPCo 1 1- - - 1 - -
OPCo 5 2 1 - 5 2 -
PSO 1 -1 - 3 1 -
SWEPCo 1 -1 - 4 1 -
WTU - - - 1 - -
Near term changes in commodity prices are not expected to materially
affect our results of operations, cash flows and financial conditions.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
AEP
On May 15, 2001, the Louisiana Department of Environmental Quality
issued a Compliance Order and Notice 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 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 Intent to prepare a
Supplemental Draft Environmental Impact Statement (SDEIS). The Forest Service
has scheduled three public meetings in August 2001 in the Virginia area to be
crossed by the route to Jacksons Ferry. The Forest Service expects to file the
SDEIS with Federal EPA for public review by April 2002. Following public
comment, the Forest Service expects to file the final EIS with Federal EPA in
October 2002 and then issue a Record of Decision.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo and WTU
Exhibit 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 JuneSeptember 30,
2001.
Signature
Pursuant to the requirements of the Securities Exchange Act of 1934,
each registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signatures for each undersigned
company shall be deemed to relate only to matters having reference to such
company and any subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto
--------------------------- -----------------------------------
Armando A. Pena Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer
AEP GENERATING COMPANY
APPALACHIAN POWER COMPANY
CENTRAL POWER AND LIGHT COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
PUBLIC SERVICE COMPANY OF OKLAHOMA
SOUTHWESTERN ELECTRIC POWER COMPANY
WEST TEXAS UTILITIES COMPANY
By: /s/Armando A. Pena By: /s/Joseph M. Buonaiuto
--------------------------- ---------------------------------------------------------- -----------------------------------------
Armando A. Pena Joseph M. Buonaiuto
Treasurer Controller and Chief Accounting Officer
Date: August 10,November 12, 2001