THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING.
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, 2000
[ ] 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
<PAGE>
AEP Generating Company, Columbus Southern Power Company and Kentucky Power
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 October 31, 2000 was 321,993,409.
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 30, 2000
INDEX
Glossary of Terms i - iii
Forward-Looking Information iv
Page
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:
<S> <C>
Consolidated Financial Statements. . . . . . . . . . . . . A-1 - A-5
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . A-6 - A-8
AEP Generating Company:
Financial Statements . . . . . . . . . . . . . . . . . . . B-1 - B-4
Management's Narrative Analysis of Results of
Operations . . . . . . . . . . . . . . . . . . . . . B-5 - B-6
Appalachian Power Company and Subsidiaries:
Consolidated Financial Statements. . . . . . . . . . . . . C-1 - C-4
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . .C-5 - C-7
Central Power and Light Company and Subsidiaries:
Consolidated Financial Statements. . . . . . . . . . . . . D-1 - D-4
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . .D-5 - D-6
Columbus Southern Power Company and Subsidiaries:
Consolidated Financial Statements. . . . . . . . . . . . . E-1 - E-4
Management's Narrative Analysis of Results of
Operations . . . . . . . . . . . . . . . . . . . . . .E-5 - E-7
Indiana Michigan Power Company and Subsidiaries:
Consolidated Financial Statements. . . . . . . . . . . . . F-1 - F-4
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . .F-5 - F-7
Kentucky Power Company:
Financial Statements . . . . . . . . . . . . . . . . . . . G-1 - G-4
Management's Narrative Analysis of Results of
Operations . . . . . . . . . . . . . . . . . . . . . .G-5 - G-6
Ohio Power Company and Subsidiaries:
Consolidated Financial Statements. . . . . . . . . . . . . H-1 - H-4
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . .H-5 - H-6
Public Service Company of Oklahoma and Subsidiaries:
Financial Statements . . . . . . . . . . . . . . . . . . . I-1 - I-4
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . .I-5 - I-6
Southwestern Electric Power Company and Subsidiaries:
Consolidated Financial Statements. . . . . . . . . . . . . J-1 - J-4
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . .J-5 - J-7
<PAGE>
West Texas Utilities Company:
Financial Statements . . . . . . . . . . . . . . . . . . . K-1 - K-4
Management's Discussion and Analysis of Results of
Operations. . . . . . . . . . . . . . . . . . . . . .K-5 - K-7
Footnotes to Financial Statements. . . . . . . . . . . . . .L-1 - L-28
Item 2.Registrants' Combined Management Discussion and
Analysis of Financial Condition and Other Matters. . .M-1 - M-25
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-2
Item 5.Other Information . . . . . . . . . . . . . . . . . . . . . . O-2
Item 6.Exhibits and Reports on Form 8-K. . . . . . . . . . . . . . . O-2 - O-3
(a) Exhibits
Exhibit 12
Exhibit 27
(b) Reports on Form 8-K
SIGNATURE. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . P-1
</TABLE>
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.
<PAGE>
<TABLE>
<CAPTION>
GLOSSARY OF TERMS
When the following terms and abbreviations appear in the text of this
report, they have the meanings indicated below.
Term Meaning
<C> <S>
2004 True-up Proceeding............ A filing to be made after January 10,
2004 under the Texas Legislation to
finalize the amount of stranded
costs and the recovery of such
costs.
AEGCo.............................. AEP Generating Company, an electric utility subsidiary of AEP.
AEP ............................... American Electric Power Company, Inc.
AEP Consolidated................... AEP and its majority owned subsidiaries consolidated.
AEP Credit, Inc.................... AEP Credit, Inc., a subsidiary of AEP which factors accounts receivable and accrued utility
revenues for affiliated domestic electric utility companies.
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.
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.
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 electric utility subsidiary of AEP.
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, 2,100 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 Credit......................... CSW Credit, Inc., an AEP subsidiary which factors accounts receivable and accrued utility
revenues for affiliated domestic electric utility companies.
CSW International.................. CSW International, Inc., an AEP subsidiary which invests in energy projects and entities
outside the United States.
i
<PAGE>
D.C. Circuit Court................. The United States Court of Appeals for the District of Columbia Circuit.
DHMV............................... Dolet Hills Mining Venture.
DOE................................ United States Department of Energy.
ECOM............................... Excess Cost Over Market.
ENEC............................... Expanded net energy costs.
EITF............................... The Financial Accounting Standards Board's Emerging Issues Task Force.
ERCOT.............................. The Electric Reliability Council of Texas.
Federal EPA........................ United States Environmental Protection Agency.
FERC............................... Federal Energy Regulatory Commission.
FMB................................ First Mortgage Bond.
GAAP............................... Generally Accepted Accounting Principles.
I&M................................ Indiana Michigan Power Company, an AEP electric utility subsidiary.
IPC................................ Installment Purchase Contract.
IRS................................ Internal Revenue Service.
IURC............................... Indiana Utility Regulatory Commission.
ISO................................ Independent system operator.
Joint Stipulation.................. Joint Stipulation and Agreement for Settlement of APCo's WV rate proceeding.
KPCo............................... Kentucky Power Company, an AEP electric utility subsidiary.
KPSC............................... Kentucky Public Service Commission.
KWH................................ Kilowatthour.
Michigan Legislation............... The Customer Choice and Electricity Reliability Act, a Michigan law which provides for
customer choice of electricity supplier.
Midwest ISO........................ An independent operator of transmission assets in the Midwest.
MLR................................ Member load ratio, the method used to allocate AEP Power Pool transactions to its members.
Money Pool......................... AEP System's Money Pool.
MPSC............................... Michigan Public Service Commission.
MTN................................ Medium Term Notes.
MW................................. Megawatt.
MWH................................ Megawatt hour
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 7 of the states in which AEP 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.
PJM................................ Pennsylvania - New Jersey - Maryland regional transmission organization.
<PAGE>
ii
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.
RCRA............................... Resource Conservation and Recovery Act of 1976, as amended.
Rockport Plant..................... A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport,
Indiana owned by AEGCo and I&M.
SEC................................ Securities and Exchange Commission.
SFAS............................... Statement of Financial Accounting Standards issued by the Financial Accounting Standards
Board.
SFAS 71............................ Statement of Financial Accounting Standards No. 71, Accounting for the Effects of Certain
-------------------------------------
Types of Regulation.
-------------------
SFAS 101........................... Statement of Financial Accounting Standards No. 101, Accounting for the Discontinuance of
------------------------------------
Application of Statement 71.
---------------------------
SFAS 121........................... Statement of Financial Accounting Standards No. 121, Accounting for the Impairment of
--------------------------------
Long-Lived Assets and for Long-Lived Assets to be Disposed of.
--------------------------------------------------------------
SFAS 133........................... Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments
-------------------------------------
and Hedging Activities.
----------------------
SNF................................ Spent Nuclear Fuel.
SPP................................ Southwest Power Pool.
STP................................ South Texas Project Nuclear Generating Plant, owned 25.2% by Central Power and Light Company
an AEP electric utility subsidiary .
SWEPCo............................. Southwestern Electric Power Company, an AEP electric utility subsidiary.
Texas Appeals Court................ The Third District of Texas Court of Appeals.
Texas Legislation.................. Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNRCC.............................. The Texas Natural Resource Conservation Commission.
Travis District Court.............. State District Court of Travis County, Texas.
TVA ............................... Tennessee Valley Authority.
UN................................. Unsecured Note.
VaR................................ Value at Risk, a method to quantify risk exposure.
Virginia SCC....................... Virginia State Corporation Commission.
WV................................. West Virginia.
WVPSC.............................. Public Service Commission of West Virginia.
WPCo............................... Wheeling Power Company, an AEP electric distribution subsidiary.
WTU................................ West Texas Utilities Company, an AEP electric utility subsidiary.
Zimmer Plant....................... William H. Zimmer Generating Station, a 1,300 MW coal-fired unit owned 25.4% by Columbus
Southern Power Company, an AEP subsidiary.
</TABLE>
iii
<PAGE>
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:
C Electric load and customer growth. C Abnormal weather conditions. C
Available sources and costs of fuels. C Availability of generating
capacity.
C The speed and degree to which competition is introduced to our power
generation business. C The structure and timing of a competitive market and
its impact on energy prices or fixed rates. C The ability to recover
stranded costs in connection with possible/proposed deregulation of
generation. C New legislation and government regulations.
C The ability of AEP to successfully control its costs. C The success of
new business ventures. C International developments affecting AEP's foreign
investments. C The economic climate and growth in AEP's service territory.
C Unforeseen events affecting AEP's restart of Cook Plant Unit 1 which is
on an extended safety related shutdown. C Inflationary trends. C
Electricity and gas market prices.
C Interest rates C Other risks and unforeseen events.
iv
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- ------------------
2000 1999 2000 1999
---- ---- ---- ----
REVENUES:
<S> <C> <C> <C> <C>
Domestic Electric Utilities. . . . . . . $3,232 $2,927 $ 8,124 $7,567
Worldwide Electric and Gas Operations. . 689 605 2,010 1,846
------ ------ ------- ------
TOTAL REVENUES . . . . . . . . . 3,921 3,532 10,134 9,413
------ ------ ------- ------
EXPENSES:
Fuel and Purchased Power . . . . . . . . 1,237 1,072 3,043 2,643
Maintenance and Other Operation. . . . . 758 680 2,164 1,960
Merger Costs . . . . . . . . . . . . . . 20 - 181 -
Depreciation and Amortization. . . . . . 275 276 804 776
Taxes Other Than Income Taxes. . . . . . 173 157 507 504
Worldwide Electric and Gas Operations. . 578 541 1,797 1,635
------ ------ ------- ------
TOTAL EXPENSES . . . . . . . . . 3,041 2,726 8,496 7,518
------ ------ ------- ------
OPERATING INCOME . . . . . . . . . . . . . 880 806 1,638 1,895
OTHER INCOME, net. . . . . . . . . . . . . 16 12 30 33
------ ------ ------- ------
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES . . . . . . . 896 818 1,668 1,928
INTEREST AND PREFERRED DIVIDENDS . . . . . 274 249 796 738
------ ------ ------- ------
INCOME BEFORE INCOME TAXES . . . . . . . . 622 569 872 1,190
INCOME TAXES . . . . . . . . . . . . . . . 219 166 348 403
------ ------ ------- ------
INCOME BEFORE EXTRAORDINARY ITEMS. . . . . 403 403 524 787
EXTRAORDINARY ITEMS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(Note 2) . . . . . . . . . . . . . . . . (44) (8) (35) (8)
------ ------ ------- ------
NET INCOME . . . . . . . . . . . . . . . . $ 359 $ 395 $ 489 $ 779
====== ====== ======= ======
AVERAGE NUMBER OF SHARES OUTSTANDING . . . 322 321 322 320
=== === === ===
EARNINGS PER SHARE:
Before Extraordinary Items . . . . . . . $1.25 $1.26 $1.63 $2.46
Extraordinary Loss -
Discontinuance of Regulatory
Accounting for Generation. . . . . . . (.14) (.03) (0.11) (.03)
----- ----- ----- ----- -
After Extraordinary Items. . . . . . . . $1.11 $1.23 $1.52 $2.43
===== ===== ===== =====
CASH DIVIDENDS PAID PER SHARE. . . . . . . $0.60 $0.60 $1.80 $1.80
===== ===== ===== =====
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in millions)
ASSETS
CURRENT ASSETS:
<S> <C> <C>
Cash and Cash Equivalents. . . . . . . . . . . . . . . . $ 295 $ 659
Accounts Receivable (net). . . . . . . . . . . . . . . . 3,022 2,027
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 326 436
Materials and Supplies . . . . . . . . . . . . . . . . . 480 460
Accrued Utility Revenues . . . . . . . . . . . . . . . . 373 322
Energy Trading Contracts . . . . . . . . . . . . . . . . 3,660 1,001
Prepayments and Other. . . . . . . . . . . . . . . . . . 449 169
------- -------
TOTAL CURRENT ASSETS . . . . . . . . . . . . . . 8,605 5,074
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production . . . . . . . . . . . . . . . . . . . . . . 15,973 15,869
Transmission . . . . . . . . . . . . . . . . . . . . . 5,590 5,495
Distribution . . . . . . . . . . . . . . . . . . . . . 10,664 10,432
Other (including gas and coal mining assets
and nuclear fuel). . . . . . . . . . . . . . . . . . . 4,027 4,081
Construction Work in Progress. . . . . . . . . . . . . . 1,295 1,061
------- -------
Total Property, Plant and Equipment. . . . . . . 37,549 36,938
Accumulated Depreciation and Amortization. . . . . . . . 15,479 15,073
------- -------
NET PROPERTY, PLANT AND EQUIPMENT. . . . . . . . 22,070 21,865
------- -------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . 3,540 3,395
------- -------
INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS . . . . . 879 862
------- -------
GOODWILL (net of amortization) . . . . . . . . . . . . . . 1,378 1,531
------- -------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . 4,046 2,992
------- -------
TOTAL. . . . . . . . . . . . . . . . . . . . . $40,518 $35,719
======= =======
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
<S> <C> <C>
Accounts Payable . . . . . . . . . . . . . . . . . . . . $ 1,782 $ 1,280
Short-term Debt. . . . . . . . . . . . . . . . . . . . . 4,375 3,012
Long-term Debt Due Within One Year . . . . . . . . . . . 753 1,367
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 598 601
Interest Accrued . . . . . . . . . . . . . . . . . . . . 232 142
Obligations Under Capital Leases . . . . . . . . . . . . 128 91
Energy Trading Contracts . . . . . . . . . . . . . . . . 3,623 964
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 1,268 609
------- -------
TOTAL CURRENT LIABILITIES. . . . . . . . . . . . 12,759 8,066
------- -------
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . . 10,071 10,157
------- -------
CERTAIN SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE,
PREFERRED SECURITIES OF SUBSIDIARY TRUSTS HOLDING
SOLELY JUNIOR SUBORDINATED DEBENTURES OF SUCH
SUBSIDIARIES . . . . . . . . . . . . . . . . . . . . . . 334 335
------- -------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . 5,076 5,150
------- -------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . 537 580
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . . 206 213
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . . . 1,316 715
------- -------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . 1,641 1,648
------- -------
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . . . 161 182
------- -------
CONTINGENCIES (Note 12)
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
2000 1999
---- ----
Shares Authorized . . . .600,000,000 600,000,000
Shares Issued . . . . . .330,993,401 330,692,317
(8,999,992 shares held in treasury). . . . . . . . . . 2,151 2,149
Paid-in Capital. . . . . . . . . . . . . . . . . . . . . 2,915 2,898
Accumulated Other Comprehensive Income (Loss). . . . . . (155) (4)
Retained Earnings. . . . . . . . . . . . . . . . . . . . 3,506 3,630
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . . . 8,417 8,673
------- -------
TOTAL. . . . . . . . . . . . . . . . . . . . . $40,518 $35,719
======= =======
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
---------------------
2000 1999
---- ----
(in millions)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 489 $ 779
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . . . 976 976
Deferred Federal Income Taxes. . . . . . . . . . . . . . . . 40 99
Deferred Investment Tax Credits. . . . . . . . . . . . . . . (26) (26)
Amortization of Deferred Property Taxes. . . . . . . . . . . 138 138
Amortization (Deferral) of Cook Plant Restart Costs. . . . . 30 (90)
Deferred Costs Under Fuel Clause Mechanisms. . . . . . . . . (276) (133)
Extraordinary Loss - Discontinuance of SFAS 71 . . . . . . . 35 8
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . . (927) (452)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . . 88 (131)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . . (134) -
Prepayments and Other. . . . . . . . . . . . . . . . . . . . (280) (43)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . 445 23
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . (3) (46)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . . (15) (43)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . (52) 134
------- -------
Net Cash Flows From Operating Activities . . . . . . . . 528 1,193
------- -------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . . (1,204) (1,147)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (29) (26)
------- -------
Net Cash Flows Used For Investing Activities . . . . . . (1,233) (1,173)
------- -------
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . . . 12 93
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . 948 578
Change in Short-term Debt (net). . . . . . . . . . . . . . . . 1,406 541
Retirement of Cumulative Preferred Stock . . . . . . . . . . . (20) (5)
Retirement of Long-term Debt . . . . . . . . . . . . . . . . . (1,400) (618)
Other Financing Activities . . . . . . . . . . . . . . . . . . - 120
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . (612) (624)
------- -------
Net Cash Flows From Financing Activities . . . . . . . . 334 85
------- -------
Effect of Exchange Rate Change on Cash . . . . . . . . . . . . . 7 (2)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . . . (364) 103
Cash and Cash Equivalents at Beginning of Period . . . . . . . . 659 330
------- -------
Cash and Cash Equivalents at End of Period . . . . . . . . . . . $ 295 $ 433
======= =======
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $685 million and $633
million and for income taxes was $242 million and $172 million in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $79 million
and $67 million in 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY
(UNAUDITED)
Accumulated
Additional Other
Common Paid-in Retained Comprehensive
Stock Capital Earnings Income (Loss) Total
------- ----------- -------- ------------- -------
(in millions)
<S> <C> <C> <C> <C> <C>
JANUARY 1, 1999 $2,049 $2,903 $3,507 $ 7 $8,466
Conforming Change in
Accounting Policy - - (14) - (14)
Reclassification Adjustment 85 (85) - - -
------ ------ ------ ---- -------
Adjusted Balance at
Beginning of Period 2,134 2,818 3,493 7 8,452
Issuance of Common Stock 15 79 - - 94
Common Stock Dividends - - (624) - (624)
Other - - (1) - (1)
------
7,921
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes
Foreign Currency Translation
Adjustment - - - (30) (30)
Unrealized Gains
on Securities - - - 9 9
Net Income - - 779 - 779
------
Total Comprehensive Income 758
------ ------ ------ ---- ------
SEPTEMBER 30, 1999 $2,149 $2,897 $3,647 $(14) $8,679
====== ====== ====== ==== ======
JANUARY 1, 2000 $2,064 $2,983 $3,646 $ (4) $8,689
Conforming Change in
Accounting Policy - - (16) - (16)
Reclassification Adjustment 85 (85) - - -
------ ------ ------ ---- ----------
Adjusted Balance at
Beginning of Period 2,149 2,898 3,630 (4) 8,673
Issuance of Common Stock 2 10 - - 12
Common Stock Dividends - - (612) - (612)
Other - 7 (1) - 6
------
8,079
Comprehensive Income:
Other Comprehensive Income,
Net of Taxes
Foreign Currency Translation
Adjustment - - - (171) (171)
Reclassification Adjustment
For Loss Included in
Net Income - - - 20 20
Net Income - - 489 - 489
------
Total Comprehensive Income 338
------ ------ ------ ----- ------
SEPTEMBER 30, 2000 $2,151 $2,915 $3,506 $(155) $8,417
====== ====== ====== ===== ======
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Income before extraordinary items remained constant for the quarter and
decreased by $263 million or 33% for the year-to-date period due predominately
to the expensing of costs related to AEP's recently completed merger with CSW
and a write down to market of a CSW investment in a company based in Chile in
the second quarter and increased costs to restart the Cook Nuclear Plant.
Extraordinary losses were recorded in both periods as a result of discontinuing
SFAS 71 regulatory accounting in the Ohio jurisdiction in 2000 and Texas and
Arkansas jurisdictions in 1999.
Excluding extraordinary items, increased Cook Plant restart costs,
merger expenses and the write down of the Chilean investment, comparative income
before extraordinary items for the third quarter and nine months ended September
were favorable. This favorable result was predominately due to increases in
wholesale marketing sales and net revenues from trading.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Revenues:
Domestic Electric Utilities. . . . . . $305 10 $557 7
Worldwide Electric and Gas Operations. 84 14 164 9
Fuel and Purchased Power Expense . . . . 165 15 400 15
Maintenance and Other Operation
Expense . . . . . . . . . . . . . . . 78 11 204 10
Merger Costs . . . . . . . . . . . . . . 20 N.M. 181 N.M.
Worldwide Electric and Gas Operations
Expense . . . . . . . . . . . . . . . 37 7 162 10
Interest and Preferred Dividends . . . . 25 10 58 8
Income Taxes . . . . . . . . . . . . . . 53 32 (55) (14)
N.M. = Not Meaningful
Domestic revenues increased in the third quarter due to increased
fuel-related revenues, reflecting higher fuel and purchased power expenses,
discussed below, and increased wholesale sales to and forward net trades with
other utilities and marketers by the domestic electric utility business. These
domestic wholesale revenue increases were offset by a decline in industrial
retail sales which reflects the expiration of a long-term contract on December
31, 1999. The increase in wholesale sales resulted from growing the energy
marketing and trading operations, favorable wholesale market conditions and the
availability of additional generation due to the return to service of one of the
Cook Nuclear Units in June 2000 and improved generating unit outage management.
Revenues from worldwide electric and gas operations increased primarily
due to increased natural gas and gas liquid product prices. Volumes of natural
gas remained consistent with the prior year, however, prices have increased
significantly rebounding from a depressed gas market during 1999.
The increase in fuel and purchased power expense was primarily
attributable to a significant increase in the cost of natural gas used for
generation.
Maintenance and other operation expense increased for the quarter due to
increased usage of and prices for emission allowances, higher ERCOT transmission
charges and increases in employee related expenses. The increase in emission
allowance usage and prices resulted from the stricter air quality standards of
Phase II of the 1990 Clean Air Act Amendments which became effective January 1,
2000. The increase in transmission expenses resulted from higher prices for the
ERCOT transmission usage. Each year ERCOT establishes new rates to allocate the
cost of the Texas transmission system to Texas electric utilities. Accruals for
incentive compensation caused the increase in employee related expenses. The
increase in maintenance and other operation expense for the year-to-date period
was mainly due to increased expenditures to prepare the Cook Plant nuclear units
for restart following an extended NRC monitored outage. The increase results
from the effect of deferring restart costs in 1999 and an increase in the
restart expenditure level. The Cook Plant began an extended outage in September
1997 when both nuclear generating units were shut down because of questions
regarding the operability of certain safety systems. In 1999 a portion of
incremental restart expenses were deferred in accordance with IURC and MPSC
settlement agreements which resolved all jurisdictional rate-related issues
related to the Cook Plant's extended outage. Unit 2 returned to service in June
and achieved full power operation on July 5, 2000. Management expects, barring
any unforeseen events, that Unit 1 will be restarted in the first quarter of
2001.
With the consummation of the merger with CSW, certain merger costs were
expensed. The merger costs expensed included transaction and transition costs
not allocable to and recoverable from ratepayers under regulatory commission
approved settlement agreements to share net merger savings.
Worldwide electric and gas operations expense rose in the quarter due
mainly to a significant increase in prices for natural gas used to produce gas
liquid products. For the year-to-date period, the increase in worldwide electric
and gas operations expense was due to the increase in natural gas prices and a
second quarter write down to market value of an available-for-sale investment in
a Chilean-based electric company.
Interest and preferred dividends increased due to an increase in average
outstanding short-term debt balances and an increase in average short-term debt
interest rates reflecting increased short-term cash demands and short-term debt
market conditions.
The third quarter increase in income taxes results from increased
pre-tax income and the favorable effect of a 1999 foreign tax credit. The
decrease in income taxes in the year-to-date period is predominately due to a
decrease in pre-tax income.
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $55,658 $57,235 $169,452 $161,674
------- ------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 25,308 28,556 75,791 68,983
Rent - Rockport Plant Unit 2 . . . . . 17,071 17,071 51,212 51,212
Other Operation. . . . . . . . . . . . 1,840 2,447 6,894 7,909
Maintenance. . . . . . . . . . . . . . 2,042 1,457 7,723 8,208
Depreciation . . . . . . . . . . . . . 5,558 5,459 16,604 16,382
Taxes Other Than Federal Income Taxes. 1,164 1,398 3,414 3,890
Federal Income Tax Expense (Credit). . 466 (74) 1,464 807
------- ------- -------- --------
TOTAL OPERATING EXPENSES . . . 53,449 56,314 163,102 157,391
------- ------- -------- --------
OPERATING INCOME . . . . . . . . . . . . 2,209 921 6,350 4,283
NONOPERATING INCOME. . . . . . . . . . . 869 885 2,638 2,630
------- ------- -------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 3,078 1,806 8,988 6,913
INTEREST CHARGES . . . . . . . . . . . . 1,106 848 2,918 2,119
------- ------- -------- --------
NET INCOME . . . . . . . . . . . . . . . $ 1,972 $ 958 $ 6,070 $ 4,794
======= ======= ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $5,836 $4,460 $3,673 $2,770
NET INCOME . . . . . . . . . . . . . . . 1,972 958 6,070 4,794
CASH DIVIDENDS DECLARED. . . . . . . . . - 2,073 1,935 4,219
------ ------ ------ ------
BALANCE AT END OF PERIOD . . . . . . . . $7,808 $3,345 $7,808 $3,345
====== ====== ====== ======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $635,389 $629,286
General . . . . . . . . . . . . . . . . . . . . . . . . . 2,587 2,400
Construction Work in Progress . . . . . . . . . . . . . . 3,463 8,407
-------- --------
Total Electric Utility Plant. . . . . . . . . . . 641,439 640,093
Accumulated Depreciation. . . . . . . . . . . . . . . . . 310,815 295,065
-------- --------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 330,624 345,028
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 189 317
Accounts Receivable:
Affiliated Companies. . . . . . . . . . . . . . . . . . 38,442 22,464
Miscellaneous . . . . . . . . . . . . . . . . . . . . . 2,186 2,643
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 17,999 17,505
Materials and Supplies. . . . . . . . . . . . . . . . . . 4,203 3,966
Prepayments . . . . . . . . . . . . . . . . . . . . . . . - 150
-------- --------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 63,019 47,045
-------- --------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 5,564 5,744
-------- --------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 1,567 823
-------- --------
TOTAL . . . . . . . . . . . . . . . . . . . . . $400,774 $398,640
======== ========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
<S> <C> <C>
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares . . . . . . . $ 1,000 $ 1,000
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 24,369 29,235
Retained Earnings . . . . . . . . . . . . . . . . . . . . 7,808 3,673
-------- --------
TOTAL CAPITALIZATION AND
COMMON SHAREHOLDER'S EQUITY . . . . . . . . . . 33,177 33,908
-------- --------
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 421 592
-------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . 44,806 44,800
Short-term Debt - Notes Payable . . . . . . . . . . . . . - 24,700
Advances from Affiliates. . . . . . . . . . . . . . . . . 31,574 -
Accounts Payable:
General . . . . . . . . . . . . . . . . . . . . . . . . 6,576 7,539
Affiliated Companies. . . . . . . . . . . . . . . . . . 4,783 19,451
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 8,907 4,285
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 23,427 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 4,228 4,763
-------- --------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 124,301 110,501
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 123,581 127,759
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . . . 60,603 63,114
Amounts Due to Customers for Income Taxes . . . . . . . . 24,527 26,266
-------- --------
TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 85,130 89,380
-------- --------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 34,014 36,500
-------- --------
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 150 -
-------- --------
CONTINGENCIES (Note 12)
TOTAL . . . . . . . . . . . . . . . . . . . . . $400,774 $398,640
======== ========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 6,070 $ 4,794
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 16,604 16,382
Deferred Federal Income Taxes. . . . . . . . . . . . . . (4,225) (3,994)
Deferred Investment Tax Credits. . . . . . . . . . . . . (2,511) (2,516)
Amortization of Deferred Gain on Sale
and Leaseback - Rockport Plant Unit 2. . . . . . . . . (4,178) (4,178)
Deferred Property Taxes. . . . . . . . . . . . . . . . . (807) (827)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . . (15,521) 772
Fuel, Materials and Supplies . . . . . . . . . . . . . . (731) (7,886)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (15,631) 6,890
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 4,622 2,919
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 1,056 (2,549)
-------- --------
Net Cash Flows From Operating Activities . . . . . . 3,212 28,271
-------- --------
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (3,413) (5,671)
-------- --------
FINANCING ACTIVITIES:
Return of Capital to Parent Company. . . . . . . . . . . . (4,866) (6,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . (24,700) (10,625)
Change in Advances from Affiliates (net) . . . . . . . . . 31,574 -
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (1,935) (4,219)
-------- --------
Net Cash Flows From (Used For) Financing Activities. 73 (20,844)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (128) 1,756
Cash and Cash Equivalents at Beginning of Period . . . . . . 317 232
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 189 $ 1,988
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $2,671,000 and
$1,889,000 and for income taxes was $3,101,000 and $4,458,000 in 2000 and
1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Operating revenues are derived from the sale of Rockport Plant energy
and capacity to two affiliated companies and in 1999 one unaffiliated utility
pursuant to FERC approved long-term unit power agreements. The unit power
agreements provide for recovery of costs including a FERC approved rate of
return on common equity and a return on other capital net of temporary cash
investments.
Net income increased $1 million or 106% for the third quarter primarily
as a result of the effect of expenses incurred in the third quarter of 1999 that
were included in billings to wholesale customers in the fourth quarter of 1999,
partially offset by a return of capital that decreased the equity return. Also
contributing to the $1.3 million or 27% increase in net income for the
year-to-date period was the effect on billings to wholesale customers of the
placing in-service of plant additions. The transfer of construction work in
progress to in-service plant increases the billings because the AFUDC rate is
lower than the equity return billed.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . . . $(1.6) (3) $ 7.8 5
Fuel Expense . . . . . . . . . . (3.2) (11) 6.8 10
Other Operation Expense. . . . . (0.6) (25) (1.0) (13)
Maintenance Expense. . . . . . . 0.6 40 (0.5) (6)
Taxes Other Than Federal
Income Taxes . . . . . . . . . (0.2) (17) (0.5) (12)
Federal Income Taxes . . . . . . 0.5 N.M. 0.7 81
Interest Charges . . . . . . . . 0.3 30 0.8 38
N.M. = Not Meaningful
Operating revenues decreased for the quarter as a result of a decrease
in generation of 14% reflecting reduced availability of the Rockport Plant
units.
The increase in year-to-date operating revenues resulted primarily from
an increase in recoverable expenses as generation increased due to the
availability of the Rockport Plant. In 1999 planned maintenance outages reduced
the availability of the Rockport Plant units. Shorter outages in the first and
second quarters of 2000 allowed the Rockport Plant units to generate 22% more
electricity in the first six months of 2000 than in 1999.
Fuel expense decreased for the quarter and increased for the
year-to-date period resulting from a decrease and an increase, respectively, in
generation.
The effect of an unfavorable accrual adjustment for a FERC operating
assessment recorded in 1999 was the primary reason for the decrease in other
operation expense. Also contributing to the year-to-date decrease was a
reduction in pension expense due to favorable pension fund performance and an
insurance recovery for damaged rail cars.
The reduction in the number of outages and the shorter length of planned
outages accounted for the decrease in maintenance expense for the year-to-date
period. The increase in maintenance expense for the quarter was due to outages
for both units in the current period.
Taxes other than federal income taxes declined due to a decrease in
state income taxes attributable to the filing of a consolidated tax return with
an affiliate that had reduced taxable income.
Federal income taxes attributable to operations increased due to an
increase in pre-tax income.
The increase in interest charges was due to an increase in the average
outstanding short-term debt balances and an increase in average interest rates
on short-term and variable rate debt reflecting the Company's short-term cash
demands and market conditions for short-term interest rates.
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $475,092 $441,435 $1,360,687 $1,242,903
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 88,769 108,701 279,989 331,933
Purchased Power. . . . . . . . . . . . 128,489 93,041 327,463 204,680
Other Operation. . . . . . . . . . . . 72,297 59,090 194,504 182,001
Maintenance. . . . . . . . . . . . . . 29,369 26,240 86,683 93,112
Depreciation and Amortization. . . . . 42,798 37,700 120,035 111,475
Taxes Other Than Federal Income Taxes. 30,088 29,201 89,550 89,242
Federal Income Taxes . . . . . . . . . 17,532 21,153 60,259 49,445
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES . . . 409,342 375,126 1,158,483 1,061,888
-------- -------- ---------- ----------
OPERATING INCOME . . . . . . . . . . . . 65,750 66,309 202,204 181,015
NONOPERATING INCOME. . . . . . . . . . . 2,399 1,925 6,607 1,152
-------- -------- ---------- ----------
INCOME BEFORE INTEREST CHARGES . . . . . 68,149 68,234 208,811 182,167
INTEREST CHARGES . . . . . . . . . . . . 32,037 32,573 94,795 96,209
-------- -------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM . . . . 36,112 35,661 114,016 85,958
EXTRAORDINARY GAIN - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(INCLUSIVE OF TAX BENEFIT
OF $7,872,000). . . . . . . . . . . . . - - 8,938 -
-------- -------- ---------- ----------
NET INCOME . . . . . . . . . . . . . . . 36,112 35,661 122,954 85,958
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 750 667 2,015 2,015
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 35,362 $ 34,994 $ 120,939 $ 83,943
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $198,126 $167,714 $175,854 $179,461
NET INCOME . . . . . . . . . . . . . . . 36,112 35,661 122,954 85,958
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 31,653 30,348 94,959 91,044
Cumulative Preferred Stock . . . . . 375 558 1,425 1,690
Capital Stock Expense. . . . . . . . . 375 109 589 325
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $201,835 $172,360 $201,835 $172,360
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $2,042,497 $2,014,968
Transmission . . . . . . . . . . . . . . . . . . . . 1,173,720 1,151,377
Distribution . . . . . . . . . . . . . . . . . . . . 1,793,783 1,741,685
General. . . . . . . . . . . . . . . . . . . . . . . 248,938 247,798
Construction Work in Progress. . . . . . . . . . . . 100,553 107,123
---------- ----------
Total Electric Utility Plant . . . . . . . . 5,359,491 5,262,951
Accumulated Depreciation and Amortization. . . . . . 2,163,483 2,079,490
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,196,008 3,183,461
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 251,775 160,546
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 7,167 64,828
Advances to Affiliates . . . . . . . . . . . . . . . 8,626 -
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 192,113 109,525
Affiliated Companies . . . . . . . . . . . . . . . 42,175 37,827
Miscellaneous. . . . . . . . . . . . . . . . . . . 21,216 9,154
Allowance for Uncollectible Accounts . . . . . . . (2,181) (2,609)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 43,046 58,161
Materials and Supplies . . . . . . . . . . . . . . . 63,113 56,917
Accrued Utility Revenues . . . . . . . . . . . . . . 40,470 53,418
Energy Trading Contracts . . . . . . . . . . . . . . 420,386 143,777
Prepayments. . . . . . . . . . . . . . . . . . . . . 6,257 7,713
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 842,388 538,711
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 441,601 436,894
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 24,817 34,788
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $4,756,589 $4,354,400
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares. . . . . . . . . . $ 260,458 $ 260,458
Paid-in Capital. . . . . . . . . . . . . . . . . . . 715,066 714,259
Retained Earnings. . . . . . . . . . . . . . . . . . 201,835 175,854
---------- ----------
Total Common Shareholder's Equity. . . . . . 1,177,359 1,150,571
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 17,818 18,491
Subject to Mandatory Redemption. . . . . . . . . . 10,860 20,310
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,435,496 1,539,302
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,641,533 2,728,674
---------- ----------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 117,150 132,130
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 175,005 126,005
Short-term Debt. . . . . . . . . . . . . . . . . . . 100,025 123,480
Accounts Payable - General . . . . . . . . . . . . . 116,545 59,150
Accounts Payable - Affiliated Companies. . . . . . . 86,635 42,459
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 63,122 49,038
Customer Deposits. . . . . . . . . . . . . . . . . . 12,607 12,898
Interest Accrued . . . . . . . . . . . . . . . . . . 35,424 19,079
Energy Trading Contracts . . . . . . . . . . . . . . 411,887 140,279
Other. . . . . . . . . . . . . . . . . . . . . . . . 64,177 71,044
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 1,065,427 643,432
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 679,784 671,917
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 44,562 57,259
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 208,133 120,988
---------- ----------
CONTINGENCIES (Note 12)
TOTAL. . . . . . . . . . . . . . . . . . . $4,756,589 $4,354,400
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 122,954 $ 85,958
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 120,119 112,264
Deferred Federal Income Taxes. . . . . . . . . . . . . . 14,059 10,947
Deferred Investment Tax Credits. . . . . . . . . . . . . (3,446) (3,516)
Provision for Rate Refunds . . . . . . . . . . . . . . . (4,818) 5,139
Deferred Power Supply Costs (net). . . . . . . . . . . . (80,232) 27,715
Amortization of Deferred Property Taxes. . . . . . . . . 13,051 13,302
Extraordinary Gain - Discontinuance of SFAS No. 71 . . . (8,938) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (99,426) 21,766
Fuel, Materials and Supplies . . . . . . . . . . . . . . 8,919 (8,377)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 12,948 5,409
Accounts Payable . . . . . . . . . . . . . . . . . . . . 101,571 (27,582)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 14,084 (1,775)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 16,345 10,255
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . - (95,267)
Payment of Disputed Tax and Interest Related to COLI . . . - (4,124)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 42,216 (31,362)
--------- ---------
Net Cash Flows From Operating Activities . . . . . . 269,406 120,752
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (132,290) (134,645)
Proceeds from Sale of Property . . . . . . . . . . . . . . 160 274
--------- ---------
Net Cash Flows Used For Investing Activities . . . . (132,130) (134,371)
--------- ---------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . - 25,000
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 74,788 148,751
Change in Short-term Debt (net). . . . . . . . . . . . . . (23,455) 42,980
Change in Advances to Affiliates (net) . . . . . . . . . . (8,626) -
Retirement of Cumulative Preferred Stock . . . . . . . . . (9,905) (587)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (131,202) (86,687)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (94,959) (91,044)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,578) (1,699)
--------- ---------
Net Cash Flows From (Used For) Financing Activities. (194,937) 36,714
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (57,661) 23,095
Cash and Cash Equivalents at Beginning of Period . . . . . . 64,828 7,755
--------- ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 7,167 $ 30,850
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $75,938,000 and
$83,069,000 and for income taxes was $30,503,000 and $33,996,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $11,312,000
and $12,132,000 in 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Income before extraordinary items increased slightly for the quarter and
increased by $28 million or 33% for the year-to-date period largely due to
increased operating income. An extraordinary gain from the discontinuance of
SFAS 71 regulatory accounting of $9 million after tax was recorded in June 2000
(See Note 9 - Industry Restructuring).
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . . . $ 34 8 $118 9
Fuel Expense . . . . . . . . . . (20) (18) (52) (16)
Purchased Power Expense. . . . . 35 38 123 60
Other Operation Expense. . . . . 13 22 13 7
Maintenance Expense. . . . . . . 3 12 (6) (7)
Depreciation and Amortization. . 5 14 9 8
Federal Income Taxes . . . . . . (4) (17) 11 22
Extraordinary Gain . . . . . . . - - 9 N.M.
N.M. = Not Meaningful
The increase in operating revenues and purchased power expense resulted from the
Company's share of increased wholesale electricity transactions by the AEP Power
Pool. The Company as a member of the AEP Power Pool shares in the revenues and
costs of the AEP Power Pool's wholesale sales to and forward trades with other
utility systems and power marketers. The Company's share of the AEP Power Pool's
wholesale sales are recorded as operating revenues and purchased power expense.
Forward trading sales and purchases within the AEP System's traditional
marketing area (within two transmission systems of the AEP System) are recorded
on a net basis in operating revenues. Wholesale Power Pool sales increased as a
result of growing the AEP Power marketing and trading operation, favorable
wholesale market conditions and increased availability of AEP Power Pool
generation for wholesale sales. The increase in AEP Power Pool generation
availability was due to an affiliate's nuclear out of service unit going on line
in June 2000, a major industrial customer's decision not to continue purchasing
its power from an affiliate, and improved generating unit outage management.
Fuel expense decreased due to the combined effect of the discontinuance
of deferred accounting for over or under recovery of fuel cost effective January
1, 2000 as a result of the discontinuance of cost based rate making in WV and a
decrease in the average cost of fuel consumed.
The increase in other operation expense was due to increased marketing
and trading costs including increased accruals for incentive compensation and an
increase in transmission equalization payments. Under the AEP East Region
Transmission Agreement, the Company shares the costs associated with the
ownership of the extra-high voltage transmission system and certain facilities
at lower voltages based upon each company's MLR and investment. An increase in
the Company's MLR was the main reason for the increase in transmission
equalization charges.
The increase in maintenance expense in the third quarter is due to the
effect of performing generating plant boiler plant maintenance repairs to the
Amos Plant in 2000. The decrease in maintenance expense in the year-to-date
period is due to the effect of performing more extensive boiler plant
maintenance repairs during 1999 than in 2000 and the effect of recording two
years of storm damage amortization in 1999 pursuant to a Virginia SCC order.
Depreciation and amortization expense increased due to the amortization
beginning in July 2000 of a new transition regulatory asset established in June
2000 for the net generation-related regulatory assets related to the Company's
Virginia and West Virginia jurisdictions that were transferred to the
distribution portion of the business and are currently being recovered through
regulated rates (see Note 9 for further discussion of the effects of
restructuring). Additional investments in distribution plant also contributed to
the increase in depreciation and amortization expense.
The decrease in federal income taxes for the quarter was primarily due
to changes in certain book/tax timing differences accounted for on a
flow-through basis for rate-making and financial reporting purposes and a
decrease in pre-tax operating income. For the year-to-date period, federal
income taxes attributable to operations increased primarily due to an increase
in pre-tax operating income.
The extraordinary gain recorded in the second quarter of 2000 was the
result of the discontinuance of SFAS 71, for the generation portion of the
Company's business in Virginia and West Virginia. Based on management's belief
that all net regulatory assets related to the Virginia and West Virginia
generation business will be recovered, the Company's generation-related net
regulatory assets were transferred to the regulated distribution portion of the
business and are being amortized as they are recovered through rates. The
Company performed an accounting impairment analysis of its generation assets
under SFAS 121 and concluded there was no accounting impairment of generation
assets.
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $601,369 $495,653 $1,355,608 $1,161,714
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 181,827 138,020 412,065 312,333
Purchased Power. . . . . . . . . . . . 75,398 24,229 130,754 53,624
Other Operation. . . . . . . . . . . . 101,116 69,288 230,725 198,180
Maintenance. . . . . . . . . . . . . . 12,780 13,615 44,676 48,797
Depreciation and Amortization. . . . . 41,970 68,160 137,055 154,531
Taxes Other Than Federal Income Taxes. 19,717 14,899 57,173 61,194
Federal Income Taxes . . . . . . . . . 47,908 39,943 88,140 79,784
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES . . . 480,716 368,154 1,100,588 908,443
-------- -------- ---------- ----------
OPERATING INCOME . . . . . . . . . . . . 120,653 127,499 255,020 253,271
NONOPERATING INCOME. . . . . . . . . . . 818 2,080 3,180 4,227
-------- -------- ---------- ----------
INCOME BEFORE INTEREST CHARGES . . . . . 121,471 129,579 258,200 257,498
INTEREST CHARGES . . . . . . . . . . . . 31,497 25,590 92,534 85,463
-------- -------- ---------- ----------
NET INCOME . . . . . . . . . . . . . . . 89,974 103,989 165,666 172,035
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 60 1,979 181 5,527
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 89,914 $102,010 $ 165,485 $ 166,508
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD
AS PREVIOUSLY REPORTED . . . . . . . $756,465 $730,419 $764,225 $739,031
CONFORMING CHANGE IN ACCOUNTING POLICY - (5,535) (5,331) (4,644)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF
PERIOD . . . . . . . . . . . . . . . . 756,465 724,884 758,894 734,387
NET INCOME . . . . . . . . . . . . . . . 89,974 103,989 165,666 172,035
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . 39,000 37,000 117,000 111,000
Preferred Stock. . . . . . . . . 60 1,979 181 5,527
Other. . . . . . . . . . . . . . . . . 1 (2) 1 (1)
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $807,378 $789,896 $807,378 $789,896
======== ======== ======== ========
The Company is a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- -----------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $3,174,186 $3,152,319
Transmission. . . . . . . . . . . . . . . . . . . . . . . 582,395 566,629
Distribution. . . . . . . . . . . . . . . . . . . . . . . 1,205,873 1,157,091
General . . . . . . . . . . . . . . . . . . . . . . . . . 236,292 307,378
Construction Work in Progress . . . . . . . . . . . . . . 106,495 101,550
Nuclear Fuel. . . . . . . . . . . . . . . . . . . . . . . 229,094 226,927
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 5,534,335 5,511,894
Accumulated Depreciation. . . . . . . . . . . . . . . . . 2,277,409 2,263,925
---------- ----------
Net Electric Utility Plant. . . . . . . . . . . . 3,256,926 3,247,969
---------- ----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 58,377 41,433
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 6,244 7,995
Special Deposits for Reacquisition of Long-term Debt. . . - 50,000
Accounts Receivable:
General . . . . . . . . . . . . . . . . . . . . . . . . 61,370 49,228
Affiliated Companies. . . . . . . . . . . . . . . . . . 33,800 15,254
Materials and Supplies. . . . . . . . . . . . . . . . . . 56,469 58,196
Fuel Inventory. . . . . . . . . . . . . . . . . . . . . . 22,333 26,434
Under-recovered Fuel Costs. . . . . . . . . . . . . . . . 120,157 30,911
Energy Trading Contracts. . . . . . . . . . . . . . . . . 38,032 -
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 8,060 3,188
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 346,465 241,206
---------- ----------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 224,888 240,059
---------- ----------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION . . . . . . 953,249 953,249
---------- ----------
NUCLEAR DECOMMISSIONING TRUST . . . . . . . . . . . . . . . 94,180 86,122
---------- ----------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 26,981 37,812
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . $4,961,066 $4,847,850
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ----------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
Outstanding - 6,755,535 Shares. . . . . . . . . . . . . $ 168,888 $ 168,888
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 405,000 405,000
Retained Earnings . . . . . . . . . . . . . . . . . . . . 807,378 758,894
---------- ----------
TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . . 1,381,266 1,332,782
PREFERRED STOCK . . . . . . . . . . . . . . . . . . . . . . 5,967 5,967
CPL-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
SUBORDINATED DEBENTURES OF CPL . . . . . . . . . . . . . . 148,500 150,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . . 1,454,556 1,304,541
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 2,990,289 2,793,290
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . - 150,000
Advances from Affiliates. . . . . . . . . . . . . . . . . 198,322 322,158
Accounts Payable - General. . . . . . . . . . . . . . . . 187,356 88,702
Accounts Payable - Affiliated Companies . . . . . . . . . 17,229 35,344
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 71,268 41,121
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 26,046 14,723
Energy Trading Contracts. . . . . . . . . . . . . . . . . 39,809 -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 34,916 25,349
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 574,946 677,397
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 1,241,981 1,234,175
---------- ----------
DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . . 129,401 133,306
---------- ----------
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 24,449 9,682
---------- ----------
CONTINGENCIES (Note 12)
TOTAL . . . . . . . . . . . . . . . . . . . . . $4,961,066 $4,847,850
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $165,666 $ 172,035
Adjustments For Non-Cash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 137,055 169,023
Deferred Federal Income Taxes. . . . . . . . . . . . . . 14,529 (2,835)
Deferred Investment Tax Credits. . . . . . . . . . . . . (3,905) (3,905)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (30,689) (9,563)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 5,829 (1,166)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 80,539 (7,738)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 30,147 27,935
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (89,246) (31,811)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 18,428 (21,931)
-------- --------
Net Cash Flows From Operating Activities . . . . . . 328,353 290,044
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (137,053) (138,506)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . - 5,810
-------- ---------
Net Cash Flows Used For Investing Activities . . . . (137,053) (132,696)
-------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt . . . . . . . . . . . . . . . (151,440) (125,000)
Redemption of Preferred Stock. . . . . . . . . . . . . . . - (1)
Special Deposit for Reacquisition of Long-term Debt. . . . 50,000 -
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 149,413 -
Changes in Advances from Affiliates. . . . . . . . . . . . (123,836) 91,394
Dividends Paid on Common Stock . . . . . . . . . . . . . . (117,000) (111,000)
Dividends Paid on Preferred Stock. . . . . . . . . . . . . (188) (5,476)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (193,051) (150,083)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (1,751) 7,265
Cash and Cash Equivalents at Beginning of Period . . . . . . 7,995 5,195
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 6,244 $ 12,460
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $81,211,000 and
$75,012,000 and for income taxes was $48,141,000 and $50,798,000 in 2000 and
1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
CPL's net income for the third quarter was $14 million or 13% lower
than the comparable period in 1999 and year-to-date net income was $6 million or
4% lower largely as a result of increased operating expenses and interest
charges.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . . . $106 21 $194 17
Fuel Expense . . . . . . . . . . 44 32 100 32
Purchased Power Expense. . . . . 51 211 77 144
Other Operation Expense. . . . . 32 46 33 16
Depreciation Expense . . . . . . (26) (38) (17) (11)
Taxes Other Than Federal
Income Taxes . . . . . . . . . 5 32 (4) (7)
Federal Income Taxes . . . . . . 8 20 8 10
Interest Expense . . . . . . . . 6 23 7 8
Preferred Stock Dividends. . . . (2) (97) (5) (97)
The increase in operating revenues was the result of a rise in fuel
related revenue, reflecting higher fuel and purchased power expenses, and
increased wholesale sales to neighboring utilities and marketers resulting from
the introduction of AEP's power trading and marketing operation. The increased
fuel related revenue is generally offset by increases in fuel related expenses.
A rise in the average price per unit of fuel, resulting mainly from
higher spot market natural gas prices, accounted for the increase in fuel
expense.
The significant increase in purchased power expense resulted primarily
from an increase in the cost per KWH purchased. The increase was primarily due
to the rise in spot market natural gas prices, an increase in the quantity of
energy purchased to meet the rise in demand, and increased cogeneration
purchases.
<PAGE>
Other operation expenses increased in the third quarter primarily due
to an increase in transmission expenses that resulted from new prices for the
ERCOT transmission grid. Each year ERCOT establishes new rates to allocate the
costs of the Texas transmission system to Texas electric utilities. In addition
to higher transmission expenses, other operation expenses increased for the
first nine months due to higher administrative expenses resulting from increased
consulting expense for a sales tax audit, insurance expense, regulatory
restructing expenses, and an allocation of administrative costs from the AEP
power trading and marketing operation.
Depreciation and amortization expenses decreased due to a reduction in
excess earnings under the Texas Legislation. Under the legislation excess
earnings are expensed to the extent they reduce stranded cost.
The increase for the third quarter in taxes other than federal income
taxes was mainly attributable to a favorable accrual adjustment to ad valorem
tax expense recorded in 1999. The decline for the year-to-date period in taxes
other than federal income taxes can be attributed to a reduction in state
franchise taxes.
Federal income tax expense attributable to utility operations increased
as a result of a favorable accrual adjustment recorded in September 1999 in
conjunction with the filing of the 1998 tax return and the effect of tax
adjustments in 1999 for securitization of regulatory assets retroactive to
January 1, 1999.
The increase in interest expense for the quarter was due to an increase
in long-term debt outstanding. For the year-to-date period interest expense
increased due to increases in long-term and short-term debt outstanding.
Preferred stock dividends decreased as a result of the redemption of
preferred stock in the fourth quarter of 1999.
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $386,583 $368,946 $1,015,803 $949,432
-------- -------- ---------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 50,452 44,416 139,781 139,416
Purchased Power. . . . . . . . . . . . 86,184 90,272 253,880 204,718
Other Operation. . . . . . . . . . . . 57,940 46,829 153,561 139,312
Maintenance. . . . . . . . . . . . . . 18,991 16,693 51,915 49,013
Depreciation . . . . . . . . . . . . . 25,091 23,723 74,531 70,429
Taxes Other Than Federal Income Taxes. 31,079 31,558 93,640 92,687
Federal Income Taxes . . . . . . . . . 33,284 31,977 70,011 69,859
-------- -------- --------- --------
TOTAL OPERATING EXPENSES . . . 303,021 285,468 837,319 765,434
-------- -------- --------- --------
OPERATING INCOME . . . . . . . . . . . . 83,562 83,478 178,484 183,998
NONOPERATING INCOME (LOSS) . . . . . . . (683) (1,076) 3,498 (1,193)
-------- -------- --------- -------
INCOME BEFORE INTEREST CHARGES . . . . . 82,879 82,402 181,982 182,805
INTEREST CHARGES . . . . . . . . . . . . 17,337 18,683 53,634 57,109
-------- -------- --------- --------
INCOME BEFORE EXTRAORDINARY ITEM . . . . 65,542 63,719 128,348 125,696
EXTRAORDINARY LOSS:
DISCONTINUANCE OF REGULATORY
ACCOUNTING FOR GENERATION
(INCLUSIVE OF TAX BENEFIT
OF $14,148,000). . . . . . . . . . . . (25,236) - (25,236) -
-------- -------- --------- --------
NET INCOME . . . . . . . . . . . . . . . 40,306 63,719 103,112 125,696
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 416 533 1,481 1,598
-------- -------- --------- --------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 39,890 $ 63,186 $ 101,631 $124,098
======== ======== ========= ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $261,024 $203,354 $246,584 $186,441
NET INCOME . . . . . . . . . . . . . . . 40,306 63,719 103,112 125,696
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 169,650 21,999 216,950 65,997
Cumulative Preferred Stock . . . . . 263 437 1,138 1,312
Capital Stock Expense. . . . . . . . . 250 95 441 286
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $131,167 $244,542 $131,167 $244,542
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP. See Notes to Financial
Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- -------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $1,554,958 $1,544,858
Transmission . . . . . . . . . . . . . . . . . . . . 357,866 350,826
Distribution . . . . . . . . . . . . . . . . . . . . 1,085,802 1,032,550
General. . . . . . . . . . . . . . . . . . . . . . . 146,036 141,137
Construction Work in Progress. . . . . . . . . . . . 83,340 82,248
---------- ----------
Total Electric Utility Plant . . . . . . . . 3,228,002 3,151,619
Accumulated Depreciation . . . . . . . . . . . . . . 1,275,674 1,210,994
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,952,328 1,940,625
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 144,551 101,286
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 11,192 5,107
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 57,768 77,418
Affiliated Companies . . . . . . . . . . . . . . . 35,218 28,453
Miscellaneous. . . . . . . . . . . . . . . . . . . 15,875 8,887
Allowance for Uncollectible Accounts . . . . . . . (659) (3,045)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 17,958 21,484
Materials and Supplies . . . . . . . . . . . . . . . 44,815 41,696
Accrued Utility Revenues . . . . . . . . . . . . . . 8,037 48,117
Energy Trading Contracts . . . . . . . . . . . . . . 224,291 90,103
Prepayments and Other. . . . . . . . . . . . . . . . 41,469 37,969
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 455,964 356,189
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 298,235 339,103
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 25,455 72,787
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $2,876,533 $2,809,990
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares. . . . . . . . . . $ 41,026 $ 41,026
Paid-in Capital. . . . . . . . . . . . . . . . . . . 573,314 572,873
Retained Earnings. . . . . . . . . . . . . . . . . . 131,167 246,584
---------- ----------
Total Common Shareholder's Equity. . . . . . 745,507 860,483
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . . 15,000 25,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 899,486 924,545
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . 1,659,993 1,810,028
---------- ----------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 44,603 43,056
---------- ----------
CURRENT LIABILITIES:
Short-term Debt. . . . . . . . . . . . . . . . . . . - 45,500
Advances from Affiliates . . . . . . . . . . . . . . 43,970 -
Accounts Payable - General . . . . . . . . . . . . . 65,169 28,279
Accounts Payable - Affiliated Companies. . . . . . . 103,592 52,776
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 107,598 143,477
Interest Accrued . . . . . . . . . . . . . . . . . . 24,441 13,936
Energy Trading Contracts . . . . . . . . . . . . . . 219,757 87,911
Other. . . . . . . . . . . . . . . . . . . . . . . . 58,189 34,375
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 622,716 406,254
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 433,575 447,607
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 42,175 44,716
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 73,471 58,329
---------- ----------
CONTINGENCIES (Note 12)
TOTAL. . . . . . . . . . . . . . . . . . . $2,876,533 $2,809,990
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 103,112 $ 125,696
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . 74,945 70,727
Deferred Federal Income Taxes. . . . . . . . . . . . . . 7,945 7,854
Deferred Investment Tax Credits. . . . . . . . . . . . . (2,541) (2,605)
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . 890 3,765
Amortization of Deferred Property Taxes. . . . . . . . . 50,130 51,680
Extraordinary Loss - Discontinuance of SFAS No. 71 . . . 25,236 -
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 3,511 (5,666)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 407 (6,277)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 40,080 (5,076)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 87,706 4,894
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (35,879) (42,534)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 10,505 8,784
Other (net) . . . . . . . . . . . . . . . . . . . . . . . (14,766) (7,143)
--------- ---------
Net Cash Flows From Operating Activities . . . . . . 351,281 204,099
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (91,122) (75,933)
Proceeds from Sale of Property and Other . . . . . . . . . 992 495
--------- ---------
Net Cash Flows Used For Investing Activities . . . . (90,130) (75,438)
--------- ---------
FINANCING ACTIVITIES:
Change in Money Pool . . . . . . . . . . . . . . . . . . . 43,970 -
Change in Short-term Debt (net). . . . . . . . . . . . . . (45,500) (24,300)
Retirement of Cumulative Preferred Stock . . . . . . . . . (10,000) -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (25,274) (35,523)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (216,950) (65,997)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,312) (1,312)
--------- ---------
Net Cash Flows Used For Financing Activities . . . . (255,066) (127,132)
--------- ---------
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 6,085 1,529
Cash and Cash Equivalents at Beginning of Period . . . . . . 5,107 7,206
--------- ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 11,192 $ 8,735
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $40,411,000 and
$45,659,000 and for income taxes was $42,007,000 and $41,866,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $4,043,000
and $5,573,000 in 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Income before extraordinary items increased by $1.8 million or 3% for the
quarter and $2.7 million or 2% for the year-to-date period due primarily to
increased wholesale power marketing and trading activities. An extraordinary
loss related to the discontinuance of SFAS 71 regulatory accounting of $25
million after tax was recorded in September 2000 in connection with the approval
of a plan to transition the company's generation business from cost based rate
regulation to customer choice market pricing (See Note 9 - Industry
Restructuring).
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues. . . . . $18 5 $66 7
Fuel Expense. . . . . . . . 6 14 - -
Purchased Power Expense . . (4) (5) 49 24
Other Operation Expense . . 11 24 14 10
Maintenance Expense . . . . 2 14 3 6
Nonoperating Income . . . . - N.M. 5 N.M.
Interest Charges. . . . . . (1) (7) (3) (6)
Extraordinary Loss. . . . . (25) N.M. (25) N.M.
N.M. = Not Meaningful
The increases in operating revenues and purchased power expense are due
to a significant increase in AEP Power Pool transactions. The Company as a
member of the AEP Power Pool shares in the revenues and costs of the AEP Power
Pool's wholesale marketing sales to and forward trades with other utility
systems and power marketers. The Company's share of the AEP Power Pool's
wholesale sales are recorded as operating revenues and purchased power expense.
Forward trading sales and purchases within the AEP System traditional marketing
area (within two transmission systems of the AEP System) are recorded on a net
basis in operating revenues. As a result of a major industrial customer's
decision in January 2000 not to continue purchasing power from an affiliate,
additional power was available to the AEP Power Pool for sale on the wholesale
market accounting in part for the increase in the Company's wholesale Power Pool
revenues and for the increase in year-to-date purchased power expense. The
increase in AEP Power Pool wholesale sales also resulted from growing AEP's
power marketing and trading operation, favorable wholesale market conditions and
increased availability of generation. AEP generating unit availability was
increased due to the return to service of one of an affiliate's nuclear
generating units and improved generating unit outage management. The decline in
higher cost purchased power expense in the third quarter reflects a decrease in
purchases from unaffiliated entities as that power was supplied by the AEP Power
Pool. With the return to service in June 2000 of one of an affiliate's two
nuclear generating units that affiliate supplied more power to the AEP Power
Pool at a lower cost reducing the need to acquire higher cost power on the open
market.
Fuel expense increased in the third quarter due to an increase in
generation reflecting an increase in availability of certain Company generating
units and favorable demand for wholesale energy.
The increase in other operation expense was due to increased power
generation costs. The increase in generation costs is due to higher emission
allowance consumption, increased emission allowance cost, increased costs for
power trading reflecting the growth of the power marketing and trading operation
including incentive compensation.
Additional generating unit boiler repairs and maintenance of overhead
transmission and distribution lines accounted for the increase in maintenance
expense.
The increase in nonoperating income in the year-to-date period was due
to an increase in net gains from non-regulated AEP Power Pool power trading
transactions outside of the AEP System's traditional marketing area. The AEP
Power Pool enters into power trading transactions for the purchase and sale of
electricity and for options, futures and swaps. The Company's share of the AEP
Power Pool's gains and losses from forward electricity trading transactions
outside of the AEP System traditional marketing area and for speculative
financial transactions (options, futures, swaps) is included in nonoperating
income. The increase in nonoperating income is also attributable to the reversal
in the first quarter of 2000 of a remaining provision for potential liability
for clean-up of possible environmental contamination from underground storage
tanks at a Company facility after the state of Ohio reviewed the matter and
determined that no further corrective action would be required.
The decline in interest charges was due to a decrease in outstanding
long-term debt balances.
An extraordinary loss was recorded in the third quarter of 2000 when the
Company discontinued the application of SFAS 71 regulatory accounting for the
generation portion of its business due to the approval in September 2000 of a
stipulation agreement by the PUCO providing for a transition from cost based
rate regulation for the Company's generation business to customer choice market
pricing.
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $423,217 $411,248 $1,129,475 $1,081,914
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 56,338 51,908 148,042 135,831
Purchased Power. . . . . . . . . . . . 73,168 93,683 254,496 223,508
Other Operation. . . . . . . . . . . . 139,375 139,997 424,254 346,830
Maintenance. . . . . . . . . . . . . . 53,596 43,526 164,821 99,349
Depreciation and Amortization. . . . . 38,951 37,626 115,661 112,106
Taxes Other Than Federal Income Taxes. 17,156 12,356 51,152 48,641
Federal Income Tax Expense (Credit). . 8,577 6,067 (31,157) 23,760
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES . . . 387,161 385,163 1,127,269 990,025
-------- -------- ---------- ----------
OPERATING INCOME . . . . . . . . . . . . 36,056 26,085 2,206 91,889
NONOPERATING INCOME. . . . . . . . . . . 1,344 2,407 4,546 5,698
-------- -------- ---------- ----------
INCOME BEFORE INTEREST CHARGES . . . . . 37,400 28,492 6,752 97,587
INTEREST CHARGES . . . . . . . . . . . . 22,210 20,408 67,296 59,688
-------- -------- ---------- ----------
NET INCOME (LOSS). . . . . . . . . . . . 15,190 8,084 (60,544) 37,899
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,156 1,218 3,469 3,647
-------- -------- ---------- ----------
EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . $ 14,034 $ 6,866 $ (64,013) $ 34,252
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $ 60,930 $223,212 $166,389 $253,154
NET INCOME (LOSS). . . . . . . . . . . . 15,190 8,084 (60,544) 37,899
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . - 28,664 26,290 85,992
Cumulative Preferred Stock . . . . . - 1,182 3,368 3,546
Capital Stock Expense. . . . . . . . . 34 65 101 130
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $ 76,086 $201,385 $ 76,086 $201,385
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $2,594,609 $2,587,288
Transmission . . . . . . . . . . . . . . . . . . . . 942,564 928,758
Distribution . . . . . . . . . . . . . . . . . . . . 852,300 818,697
General (including nuclear fuel) . . . . . . . . . . 260,682 244,981
Construction Work in Progress. . . . . . . . . . . . 243,805 190,303
---------- ----------
Total Electric Utility Plant . . . . . . . . 4,893,960 4,770,027
Accumulated Depreciation and Amortization. . . . . . 2,290,841 2,194,397
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,603,119 2,575,630
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . 767,121 707,967
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 259,074 213,658
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 13,302 3,863
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 84,691 91,268
Affiliated Companies . . . . . . . . . . . . . . . 29,550 48,901
Miscellaneous. . . . . . . . . . . . . . . . . . . 20,156 18,644
Allowance for Uncollectible Accounts . . . . . . . (735) (1,848)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 28,666 27,597
Materials and Supplies . . . . . . . . . . . . . . . 89,384 84,149
Accrued Utility Revenues . . . . . . . . . . . . . . - 44,428
Energy Trading Contracts . . . . . . . . . . . . . . 253,975 97,946
Prepayments. . . . . . . . . . . . . . . . . . . . . 4,487 7,631
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 523,476 422,579
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 553,466 624,810
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 22,500 32,052
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $4,728,756 $4,576,696
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares . . . . . . . . . . $ 56,584 $ 56,584
Paid-in Capital. . . . . . . . . . . . . . . . . . . 733,039 732,739
Retained Earnings. . . . . . . . . . . . . . . . . . 76,086 166,389
---------- ----------
Total Common Shareholder's Equity. . . . . . 865,709 955,712
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 8,736 9,248
Subject to Mandatory Redemption. . . . . . . . . . 64,945 64,945
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,295,388 1,126,326
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,234,778 2,156,231
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 552,081 501,185
Other. . . . . . . . . . . . . . . . . . . . . . . . 186,420 242,522
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 738,501 743,707
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 190,000 198,000
Short-term Debt. . . . . . . . . . . . . . . . . . . - 224,262
Advances from Affiliates . . . . . . . . . . . . . . 113,423 -
Accounts Payable - General . . . . . . . . . . . . . 91,170 78,784
Accounts Payable - Affiliated Companies. . . . . . . 65,968 31,118
Taxes Accrued. . . . . . . . . . . . . . . . . . . . - 48,970
Interest Accrued . . . . . . . . . . . . . . . . . . 21,503 13,955
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 23,427 4,963
Obligations Under Capital Leases . . . . . . . . . . 44,219 11,072
Energy Trading Contracts . . . . . . . . . . . . . . 249,418 95,564
Other. . . . . . . . . . . . . . . . . . . . . . . . 77,708 86,721
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 876,836 793,409
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 582,145 622,157
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 115,967 121,627
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 82,225 85,005
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 98,304 54,560
---------- ----------
CONTINGENCIES (Note 12)
TOTAL. . . . . . . . . . . . . . . . . . . $4,728,756 $4,576,696
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . $ (60,544) $ 37,899
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 122,345 115,014
Amortization of Incremental Nuclear Refueling
Outage Expenses (net). . . . . . . . . . . . . . . . . 4,830 6,413
Unrecovered Fuel and Purchased Power Costs . . . . . . . 28,126 (82,213)
Amortization (Deferral) of Nuclear Outage Costs (net). . 30,000 (90,000)
Deferred Federal Income Taxes. . . . . . . . . . . . . . (25,619) 57,254
Deferred Investment Tax Credits. . . . . . . . . . . . . (5,660) (5,694)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 23,303 (1,132)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (6,304) (10,200)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 44,428 (5,768)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 47,236 (30,007)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (48,970) (4,651)
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (43,393) 31,631
--------- ---------
Net Cash Flows From Operating Activities . . . . . . 128,242 37,010
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (129,799) (97,044)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 587 1,904
--------- ---------
Net Cash Flows Used For Investing Activities . . . . (129,212) (95,140)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 199,220 148,379
Change in Advances from Affiliates (net) . . . . . . . . . 113,423 -
Retirement of Cumulative Preferred Stock . . . . . . . . . (314) (1,042)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (48,000) (74,500)
Change in Short-term Debt (net). . . . . . . . . . . . . . (224,262) 82,150
Dividends Paid on Common Stock . . . . . . . . . . . . . . (26,290) (85,992)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (3,368) (3,546)
--------- ---------
Net Cash Flows From Financing Activities . . . . . . 10,409 65,449
--------- ---------
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 9,439 7,319
Cash and Cash Equivalents at Beginning of Period . . . . . . 3,863 12,465
--------- ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 13,302 $ 19,784
========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $57,466,000
and $54,928,000 and for income taxes was $43,675,000 and $(29,106,000) in 2000
and 1999, respectively. Noncash acquisitions under capital leases were
$19,134,000 and $9,005,000 in 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Net income increased $7 million for the third quarter primarily
due to the return to service of one of the Company's two nuclear units.
The Company reported a $61 million loss for the year-to-date period
compared to net income of $38 million in 1999. Increased operating and
maintenance expenses to prepare the Company's Cook Plant for restart
following an extended outage is the primary reason for the year-to-date
earnings decline. An extended outage of the Cook Plant began in
September 1997 when both nuclear generating units were shut down because
of questions regarding the operability of certain safety systems. Unit 2
returned to service in June 2000 and achieved full power operation on
July 5, 2000. In accordance with settlement agreements in Indiana and
Michigan, which resolved all jurisdictional rate-related issues
applicable to the Cook Plant's extended outage, certain restart expenses
were deferred in 1999. The settlements in the Indiana and Michigan
jurisdictions were approved in March 1999 and December 1999,
respectively, retroactive to January 1, 1999. These deferrals are being
amortized on a straight-line basis through December 31, 2003.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
-------------- - ------------- -
Operating Revenues . . . . . $ 12 3 $ 48 4
Fuel Expense . . . . . . . . 4 9 12 9
Purchased Power Expense. . . (21) (22) 31 14
Other Operation Expense. . . (1) N.M. 77 22
Maintenance Expense. . . . . 10 23 65 66
Taxes Other Than Federal
Income Taxes . . . . . . . 5 39 3 5
Federal Income Taxes . . . . 3 41 (55) N.M.
Interest Charges . . . . . . 2 9 8 13
N.M. = Not Meaningful
The increase in operating revenues resulted from increased
wholesale sales to the AEP Power Pool and sales to and forward trades
with other utility systems and power marketers by the AEP Power Pool.
As a member of the AEP Power Pool, the Company shares in the revenues
and costs of the AEP Power Pool's wholesale sales and forward trades.
Forward trading sales and purchases by the AEP Power Pool within the
AEP System traditional marketing area (within two transmission systems
of the AEP System) are recorded on a net basis in operating revenues.
AEP Power Pool members are compensated for the out-of-pocket costs of
energy delivered to the AEP Power Pool and charged for energy received
from the AEP Power Pool. As a result of the Company's obligation to
purchase power from an affiliated company, the Company was required to
purchase additional energy and capacity in 2000 due to the expiration
of that affiliate's agreement to supply power to an unaffiliated
utility. Since this capacity was no longer committed under a long-term
contract I&M was able to use it to supply the AEP Power Pool and thus
received additional wholesale revenues from the AEP Power Pool. Also
with the return to service of Cook Plant Unit 2 in June 2000, the
Company's available generation increased. Consequently, the Company was
able to deliver additional power to the AEP Power Pool, contributing to
the AEP Power Pool's and the Company's share of increase in wholesale
sales and operating revenues. A decline in retail sales and the effect
of the settlement agreements in Indiana and Michigan led to a decrease
in operating revenues from retail customers partially offsetting the
wholesale increases.
Fuel expense increased primarily due to increased generation
reflecting the return to service of the Company's Cook Plant Unit 2
following an extended outage.
The decrease in purchased power expense for the third quarter
resulted mainly from reduced purchases of power from unaffiliated
entities and the AEP Power Pool reflecting a decreased need to purchase
energy with the return to service of one unit at the Cook Plant.
Purchased power expense increased in the year-to-date period primarily
due to the Company's obligation to purchase an affiliate's power when
its agreement to supply power to an unaffiliated utility expired at the
end of 1999.
Other operation expense increased in the year-to-date period
and maintenance expense increased in both periods primarily due to the
expenses related to work to restart the Cook Plant units and the effect
of deferring restart expenditures in 1999 under the terms of the
approved settlement agreement in Indiana.
Increased accruals for Indiana supplemental net income tax
expense reflecting an increase in taxable income is the primary reason
for higher taxes other than federal income taxes.
The increase in federal income tax expense attributable to
operations for the third quarter was primarily due to an increase in
pre-tax operating income offset in part by changes in certain book/tax
timing differences accounted for on a flow-through basis for rate-making
and financial reporting purposes. The year-to-date decrease in federal
income tax expense attributable to operations was primarily due to a
decrease in pre-tax operating income.
Interest charges increased as a result of additional long-term
and short-term borrowings mainly to fund the restart expenditures.
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $106,698 $94,939 $301,661 $271,911
-------- ------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 23,366 18,258 58,039 60,233
Purchased Power. . . . . . . . . . . . . 35,881 32,177 108,115 82,524
Other Operation. . . . . . . . . . . . . 14,117 10,607 36,604 34,726
Maintenance. . . . . . . . . . . . . . . 6,098 5,522 20,903 15,360
Depreciation and Amortization. . . . . . 7,828 7,356 23,107 21,833
Taxes Other Than Federal Income Taxes. . 2,387 2,967 7,880 8,183
Federal Income Taxes . . . . . . . . . . 3,231 3,808 8,210 9,215
-------- -------- -------- --------
TOTAL OPERATING EXPENSES. . . . . 92,908 80,695 262,858 232,074
-------- -------- -------- --------
OPERATING INCOME . . . . . . . . . . . . . 13,790 14,244 38,803 39,837
NONOPERATING INCOME (LOSS) . . . . . . . . 243 111 868 (44)
-------- -------- -------- --------
INCOME BEFORE INTEREST CHARGES . . . . . . 14,033 14,355 39,671 39,793
INTEREST CHARGES . . . . . . . . . . . . . 7,272 7,158 22,409 21,392
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . . $ 6,761 $ 7,197 $ 17,262 $ 18,401
======== ======== ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $62,431 $67,770 $67,110 $71,452
NET INCOME . . . . . . . . . . . . . . . . 6,761 7,197 17,262 18,401
CASH DIVIDENDS DECLARED. . . . . . . . . . 7,590 7,443 22,770 22,329
------- ------- ------- -------
BALANCE AT END OF PERIOD . . . . . . . . . $61,602 $67,524 $61,602 $67,524
======= ======= ======= =======
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- -----------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $ 270,725 $ 268,618
Transmission . . . . . . . . . . . . . . . . . . . . 358,312 355,442
Distribution . . . . . . . . . . . . . . . . . . . . 383,388 372,752
General. . . . . . . . . . . . . . . . . . . . . . . 66,591 67,608
Construction Work in Progress. . . . . . . . . . . . 14,540 14,628
---------- ----------
Total Electric Utility Plant . . . . . . . . 1,093,556 1,079,048
Accumulated Depreciation and Amortization. . . . . . 353,406 340,008
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 740,150 739,040
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 41,305 20,416
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 1,012 674
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 26,186 18,952
Affiliated Companies . . . . . . . . . . . . . . . 18,488 15,223
Miscellaneous. . . . . . . . . . . . . . . . . . . 5,613 8,343
Allowance for Uncollectible Accounts . . . . . . . (278) (637)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 5,426 10,441
Materials and Supplies . . . . . . . . . . . . . . . 17,410 18,113
Accrued Utility Revenues . . . . . . . . . . . . . . - 13,737
Energy Trading Contracts . . . . . . . . . . . . . . 99,865 33,919
Prepayments. . . . . . . . . . . . . . . . . . . . . 765 1,450
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 174,487 120,215
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 100,204 96,296
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 7,419 10,671
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $1,063,565 $ 986,638
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
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
Retained Earnings. . . . . . . . . . . . . . . . . . 61,602 67,110
---------- --------
Total Common Shareholder's Equity. . . . . . 270,802 276,310
Long-term Debt . . . . . . . . . . . . . . . . . . . 200,991 260,782
---------- --------
TOTAL CAPITALIZATION . . . . . . . . . . . . 471,793 537,092
---------- --------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 21,553 23,797
---------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 140,000 105,000
Short-term Debt. . . . . . . . . . . . . . . . . . . - 39,665
Advances from Affiliates . . . . . . . . . . . . . . 23,863 -
Accounts Payable - General . . . . . . . . . . . . . 24,391 9,923
Accounts Payable - Affiliated Companies. . . . . . . 38,038 19,743
Customer Deposits. . . . . . . . . . . . . . . . . . 4,186 4,143
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 8,537 9,860
Interest Accrued . . . . . . . . . . . . . . . . . . 7,335 4,843
Energy Trading Contracts . . . . . . . . . . . . . . 97,847 33,094
Other. . . . . . . . . . . . . . . . . . . . . . . . 10,910 12,020
---------- --------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 355,107 238,291
---------- --------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 168,972 165,007
---------- --------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 12,014 12,908
---------- --------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 34,126 9,543
---------- --------
CONTINGENCIES (Note 12)
TOTAL. . . . . . . . . . . . . . . . . . . $1,063,565 $986,638
========== ========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 17,262 $ 18,401
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 23,112 21,838
Deferred Federal Income Taxes. . . . . . . . . . . . . . 4,081 2,361
Deferred Investment Tax Credits. . . . . . . . . . . . . (894) (902)
Amortization of Deferred Property Taxes. . . . . . . . . 4,157 4,035
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (8,128) 4,669
Fuel, Materials and Supplies . . . . . . . . . . . . . . 5,718 (7,762)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 13,737 4,334
Accounts Payable . . . . . . . . . . . . . . . . . . . . 32,763 (2,612)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (1,323) (362)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (2,810) (1,705)
-------- --------
Net Cash Flows From Operating Activities . . . . . . 87,675 42,295
-------- --------
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (23,765) (28,144)
-------- --------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . - 10,000
Retirement of Long-term Debt . . . . . . . . . . . . . . . (25,000) (48,307)
Change in Short-term Debt (net). . . . . . . . . . . . . . (39,665) 45,615
Change in Advances from Affiliates (net) . . . . . . . . . 23,863 -
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (22,770) (22,329)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (63,572) (15,021)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 338 (870)
Cash and Cash Equivalents at Beginning of Period . . . . . . 674 1,935
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,012 $ 1,065
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $19,776,000 and
$19,420,000 and for income taxes was $5,167,000 and $7,271,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $2,440,000
and $1,889,000 in 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Although revenues rose 12% for the quarter and 11% for the year-to-date
period, net income declined by $0.4 million or 6% and $1.1 million or 6%,
respectively, as increases in operating expense and interest expense more than
offset the revenue increases. Income statement line items which changed
significantly were:
Increase(Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $11.8 12 $29.8 11
Fuel Expense . . . . . . . . 5.1 28 (2.2) (4)
Purchased Power Expense. . . 3.7 12 25.6 31
Other Operation Expense. . . 3.5 33 1.9 5
Maintenance Expense. . . . . 0.6 10 5.5 36
Depreciation Expense . . . . 0.5 6 1.3 6
Federal Income Tax . . . . . (0.6) (15) (1.0) (11)
Nonoperating Income. . . . . 0.1 119 0.9 N.M.
Interest Charges . . . . . . 0.1 2 1.0 5
N.M. = Not Meaningful
The increases in operating revenues and purchased power expense are due
to a significant increase in AEP Power Pool transactions and affili-ated power
purchases under a unit power agreement. The Company as a member of the AEP Power
Pool shares in the revenues and costs of the AEP Power Pool's wholesale sales to
and net forward trades with other utility systems and power marketers. The
Company's share of these AEP Power Pool sales are recorded as operating revenues
and purchases accounting for the increases in revenues and purchased power
expense. Forward trading sales and purchases which are transactions within the
AEP System traditional marketing area (within two transactions systems of the
AEP System) are recorded on a net basis in operating revenues. As a result of an
affiliated company's major industrial customer's decision not to continue its
purchased power agreement, additional power was available to the AEP Power Pool
for wholesale sales also contributing to the increase in the Company's revenue
and purchased power expense. Purchased power also increased due to the
availability of the Rockport Plant from which the Company, under a unit power
agreement, purchases 15% of the available power from Rockport. Rockport Plant
generated 7% more KWH in the nine months ended September 2000 than in the nine
months ended September 1999.
Fuel expense increased in the quarter due to amortization of deferred
fuel costs and decreased in the year-to-date period due to a decline in internal
generation. The Big Sandy Plant Unit 2 began a planned outage on March 11, 2000
for boiler inspections and repairs and returned to service late in April. Big
Sandy Unit 1 started a planned outage on April 21, 2000 and returned to service
the second week in May after completion of boiler inspection and repairs.
Other operation expense increased due to emission allowance charges
under Phase II of the 1990 Clean Air Act Amendments. Under Phase II, which
became effective January 1, 2000, the Company was required to use emission
allowances to comply with the new emissions standards. The average cost of those
allowances are charged to other operation expense as required. In the
year-to-date period an increase in transmission equalization credits received
under the AEP East Region Transmission Agreement partially offset the emission
allowance charges. The Company as a party to the AEP Transmission Agreement
shares the costs associated with the ownership of the extra-high voltage
transmission system and certain facilities at lower voltages based upon each
company's MLR and investment. An increase in MLR and increased investment in
transmission plant were the reasons for the increase in transmission
equalization credits.
The outages at Big Sandy Plant caused maintenance expense to increase in
the year-to-date period. Comparing 1999 to 2000, unit 1 of the Big Sandy Plant,
experienced 3.6 weeks of various outages compared to 1 week of outages in 1999.
Unit 2 experienced 6.8 weeks of outages in 2000 and 4.6 weeks in 1999.
An increase in transmission plant investment and improvements to
distribution facilities accounted for the increase in depreciation expense.
The decrease in operating Federal income tax expense was primarily due
to a decrease in pre-tax operating book income. Nonoperating income
increased due to the effect of the non-regulated electric trading
outside the AEP Power Pool's
traditional marketing area. The AEP Power Pool enters into transactions for the
purchase and sale of electricity options, futures and swaps, and for the forward
purchase and sale of electricity outside of the AEP System's traditional
marketing area. The Company's share of these non-regulated trading activities
are included in nonoperating income.
Interest charges increased due to higher long-term debt interest rates
and an increase in average short-term debt interest rates.
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $582,702 $544,451 $1,668,434 $1,561,259
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 188,727 173,857 581,289 532,075
Purchased Power. . . . . . . . . . . . 46,772 68,836 129,125 125,808
Other Operation. . . . . . . . . . . . 99,930 81,113 270,626 249,003
Maintenance. . . . . . . . . . . . . . 28,128 27,434 89,753 81,425
Depreciation and Amortization. . . . . 39,121 37,509 116,453 111,691
Taxes Other Than Federal Income Taxes. 40,579 42,941 125,366 128,746
Federal Income Taxes . . . . . . . . . 42,793 39,903 114,089 107,369
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES . . . 486,050 471,593 1,426,701 1,336,117
-------- -------- ---------- ----------
OPERATING INCOME . . . . . . . . . . . . 96,652 72,858 241,733 225,142
NONOPERATING INCOME. . . . . . . . . . . 2,564 4,856 6,714 6,364
-------- -------- ---------- ----------
INCOME BEFORE INTEREST CHARGES . . . . . 99,216 77,714 248,447 231,506
INTEREST CHARGES . . . . . . . . . . . . 22,155 21,481 66,937 62,587
-------- -------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM . . . . 77,061 56,233 181,510 168,919
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(INCLUSIVE OF TAX BENEFIT
OF $21,281,000) . . . . . . . . . . . . (18,876) - (18,876) -
-------- -------- ---------- ----------
NET INCOME . . . . . . . . . . . . . . . 58,185 56,233 162,634 168,919
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 315 364 951 1,098
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 57,870 $ 55,869 $ 161,683 $ 167,821
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $615,834 $584,045 $587,424 $587,500
NET INCOME . . . . . . . . . . . . . . . 58,185 56,233 162,634 168,919
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 158,704 57,704 234,110 173,110
Cumulative Preferred Stock . . . . . 314 366 947 1,101
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $515,001 $582,208 $515,001 $582,208
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . . . . $2,750,822 $2,713,421
Transmission . . . . . . . . . . . . . . . . . . . . . . . 868,878 857,420
Distribution . . . . . . . . . . . . . . . . . . . . . . . 1,029,512 999,679
General (including mining assets). . . . . . . . . . . . . 703,964 713,882
Construction Work in Progress. . . . . . . . . . . . . . . 127,739 116,515
---------- ----------
Total Electric Utility Plant . . . . . . . . . . . 5,480,915 5,400,917
Accumulated Depreciation and Amortization. . . . . . . . . 2,716,760 2,621,711
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . . . . 2,764,155 2,779,206
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . 322,979 253,668
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . . . . 34,980 157,138
Advances to Affiliates . . . . . . . . . . . . . . . . . . 149,616 -
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . . . . 118,026 246,310
Affiliated Companies . . . . . . . . . . . . . . . . . . 147,109 89,215
Miscellaneous. . . . . . . . . . . . . . . . . . . . . . 30,865 22,055
Allowance for Uncollectible Accounts . . . . . . . . . . (1,026) (2,223)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 66,357 129,022
Materials and Supplies . . . . . . . . . . . . . . . . . . 97,946 95,967
Accrued Utility Revenues . . . . . . . . . . . . . . . . . - 45,575
Energy Trading Contracts . . . . . . . . . . . . . . . . . 353,205 134,567
Prepayments and Other. . . . . . . . . . . . . . . . . . . 34,848 38,472
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . . . . 1,031,926 956,098
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . . 655,575 594,385
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . . 36,760 93,852
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,811,395 $4,677,209
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares. . . . . . . . . . . . $ 321,201 $ 321,201
Paid-in Capital. . . . . . . . . . . . . . . . . . . . . 462,483 462,376
Retained Earnings. . . . . . . . . . . . . . . . . . . . 515,001 587,424
---------- ----------
Total Common Shareholder's Equity. . . . . . . . 1,298,685 1,371,001
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . . . 16,648 16,937
Subject to Mandatory Redemption. . . . . . . . . . . . 8,850 8,850
Long-term Debt . . . . . . . . . . . . . . . . . . . . . 1,078,952 1,139,834
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . 2,403,135 2,536,622
---------- ----------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . 406,616 414,837
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . . . 120,476 11,677
Short-term Debt. . . . . . . . . . . . . . . . . . . . . - 194,918
Accounts Payable - General . . . . . . . . . . . . . . . 147,134 180,383
Accounts Payable - Affiliated Companies. . . . . . . . . 105,502 64,599
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 157,757 179,112
Interest Accrued . . . . . . . . . . . . . . . . . . . . 22,923 16,863
Obligations Under Capital Leases . . . . . . . . . . . . 34,433 34,284
Energy Trading Contracts . . . . . . . . . . . . . . . . 346,065 131,844
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 138,325 96,445
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . . . 1,072,615 910,125
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . 683,556 676,460
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . 26,160 35,838
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . 219,313 103,327
---------- ----------
CONTINGENCIES (Note 12)
TOTAL. . . . . . . . . . . . . . . . . . . . . $4,811,395 $4,677,209
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 162,634 $ 168,919
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . 145,125 146,388
Deferred Federal Income Taxes. . . . . . . . . . . . . . (2,058) 7,529
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . (33,259) (14,632)
Amortization of Deferred Property Taxes. . . . . . . . . 60,297 59,567
Extraordinary Loss - Discontinuance of SFAS 71 . . . . . 18,876 -
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 60,383 (109,658)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 60,686 (51,186)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 45,575 5,355
Accounts Payable . . . . . . . . . . . . . . . . . . . . 7,654 114,563
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (21,355) (73,130)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 44,160 54,355
--------- ---------
Net Cash Flows From Operating Activities . . . . . . 548,718 308,070
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (143,717) (126,524)
Proceeds from Sale of Property and Other . . . . . . . . . 4,404 2,003
--------- ---------
Net Cash Flows Used For Investing Activities . . . . (139,313) (124,521)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 74,748 222,308
Change in Short-term Debt (net). . . . . . . . . . . . . . (194,918) (25,400)
Change in Advances to Affiliates (net) . . . . . . . . . . (149,616) -
Retirement of Cumulative Preferred Stock . . . . . . . . . (182) (3,267)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (26,538) (155,866)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (234,110) (173,110)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (947) (1,101)
--------- ---------
Net Cash Flows Used For Financing Activities . . . . (531,563) (136,436)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (122,158) 47,113
Cash and Cash Equivalents at Beginning of Period . . . . . . 157,138 89,652
--------- ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 34,980 $ 136,765
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $59,963,000 and
$52,526,000 and for income taxes was $56,813,000 and $48,052,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $12,734,000
and $23,955,000 in 2000 and 1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Income before extraordinary items increased $21 million or 37% for the
quarter and $13 million or 7% for the year-to-date period due predominantly to
an increase in wholesale sales and net revenues from electric trading
transactions and, in the third quarter, a reduction in purchased power costs. An
extraordinary loss related to the discontinuance of SFAS 71 regulatory
accounting, of approximately $19 million after tax, was recorded in September
2000 in connection with the approval of a plan to transition the company's
generation business from cost based rate regulation to customer choice market
pricing (See Note 9 - Industry Restructuring).
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $38 7 $107 7
Fuel Expense . . . . . . . . 15 9 49 9
Purchased Power Expense. . . (22) (32) 3 3
Other Operation Expense. . . 19 23 22 9
Maintenance Expense. . . . . 1 3 8 10
Federal Income Taxes . . . . 3 7 7 6
Extraordinary Loss . . . . . (19) N.M. (19) N.M.
N.M. = Not Meaningful
The increase in operating revenues resulted from increased wholesale
sales to the AEP Power Pool, the Company's share of increased Power Pool
wholesale sales to and net revenues from trading of electricity with other
utility systems and power marketers. The Company as a member of the AEP Power
Pool shares in the revenues and cost of the AEP Power Pool's whole-sale sales to
and forward trades with utility systems and power marketers. The Company's share
of Power Pool forward trades, both purchases and sales, within the AEP System's
traditional marketing area (within two transmission systems of the AEP System)
are recorded on a net basis in operating revenues. AEP Power Pool members are
compensated for the out of pocket costs of energy delivered to the AEP Power
Pool and charged for energy received from the AEP Power Pool. As a result of one
of the Company's major industrial customer's deciding not to continue its power
purchase agreement, the Company was able to deliver additional power to the AEP
Power Pool accounting for part of the increase in wholesale revenues. Wholesale
revenues also benefited from the growth in AEP's marketing and trading
operation, favorable wholesale market conditions and increased availability of
AEP Power Pool generation for wholesale sales. The increase in AEP Power Pool
generation availability was due to the return to service of one an affiliates
nuclear units in June 2000 and improved generating unit outage management.
Fuel expense increased due to increases in generation and the average
cost of fuel consumed reflecting shutdown costs included in the cost of coal
delivered from affiliated mining operations.
The decline in purchased power expense in the third quarter reflects a
decrease in high cost purchases by the Power Pool from unaffiliated entities.
With the return to service in June 2000 of one of an affiliate's two nuclear
units the affiliate was able to supply more power to the AEP Power Pool at lower
cost reducing the need to acquire power on the open market.
Other operation expense increased primarily due to increased power
generation costs. Increased emission allowance consumption and allowance prices
and increased costs of AEP's growing power marketing and trading operation,
including incentive compensation, accounted for the increase in generation
costs.
Additional generating plant boiler repairs accounted for the increase
in maintenance expense for the year-to-date period. The increase in federal
income taxes was primarily due to an increase in pre-tax operating income
offset in part in the quarter by changes in certain book/tax differences
accounted for on a flow-thru basis.
An extraordinary loss was recorded in the third quarter of 2000 when
the Company discontinued the application of SFAS 71 regulatory accounting for
the generation portion of its business due to the approval in September 2000 of
a stipulation agreement by the PUCO providing for a transition from cost based
rate regulation for the Company's generation business to customer choice market
pricing.
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $358,710 $258,656 $729,211 $588,385
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 155,103 82,076 302,497 208,873
Purchased Power. . . . . . . . . . . . 46,325 20,278 98,532 50,450
Other Operation. . . . . . . . . . . . 32,236 35,751 84,468 89,407
Maintenance. . . . . . . . . . . . . . 8,032 8,768 30,027 30,695
Depreciation and Amortization. . . . . 19,632 18,558 57,470 55,557
Taxes Other Than Federal Income Taxes. 12,660 9,439 28,718 28,676
Federal Income Taxes . . . . . . . . . 28,285 26,066 35,700 31,802
-------- -------- --------- --------
TOTAL OPERATING EXPENSES . . . 302,273 200,936 637,412 495,460
-------- -------- --------- --------
OPERATING INCOME . . . . . . . . . . . . 56,437 57,720 91,799 92,925
NONOPERATING INCOME. . . . . . . . . . . 7,211 1,430 7,927 920
-------- -------- --------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 63,648 59,150 99,726 93,845
INTEREST CHARGES . . . . . . . . . . . . 9,319 8,893 29,532 27,208
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 54,329 50,257 70,194 66,637
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 52 54 158 160
-------- -------- -------- ---------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 54,277 $ 50,203 $ 70,036 $ 66,477
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD
AS PREVIOUSLY REPORTED . . . . . . . . $120,995 $131,583 $142,018 $144,626
CONFORMING CHANGE IN ACCOUNTING POLICY . - (2,369) (2,782) (1,686)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. 120,995 129,214 139,236 142,940
NET INCOME . . . . . . . . . . . . . . . 54,329 50,257 70,194 66,637
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 17,000 15,000 51,000 45,000
Preferred Stock. . . . . . . . . . . 52 53 158 159
-------- -------- -------- ---------
BALANCE AT END OF PERIOD . . . . . . . . $158,272 $164,418 $158,272 $164,418
======== ======== ======== ========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $ 915,216 $ 916,889
Transmission. . . . . . . . . . . . . . . . . . . . . . . 395,594 392,029
Distribution. . . . . . . . . . . . . . . . . . . . . . . 926,195 897,516
General . . . . . . . . . . . . . . . . . . . . . . . . . 205,654 217,368
Construction Work in Progress . . . . . . . . . . . . . . 105,976 35,903
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 2,548,635 2,459,705
Accumulated Depreciation and Amortization . . . . . . . . 1,135,265 1,114,255
---------- ----------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 1,413,370 1,345,450
---------- -----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 78,190 46,205
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 5,644 3,173
Accounts Receivable:
Customers . . . . . . . . . . . . . . . . . . . . . . . 63,387 32,301
Affiliated Companies. . . . . . . . . . . . . . . . . . 6,130 2,283
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 24,815 24,143
Materials and Supplies. . . . . . . . . . . . . . . . . . 33,459 34,289
Under-recovered Fuel Costs. . . . . . . . . . . . . . . . 41,809 6,469
Energy Trading Contracts. . . . . . . . . . . . . . . . . 103,594 -
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 1,161 1,572
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 279,999 104,230
---------- ----------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 27,786 16,717
---------- ----------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 11,777 12,124
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,811,122 $1,524,726
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued 10,482,000 shares and
Outstanding Shares: 9,013,000 . . . . . . . . . . . . . $ 157,230 $ 157,230
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 180,000 180,000
Retained Earnings . . . . . . . . . . . . . . . . . . . . 158,272 139,236
---------- ----------
Total Common Shareholder's Equity . . . . . . . . 495,502 476,466
---------- ----------
Cumulative Preferred Stock Not Subject
To Mandatory Redemption . . . . . . . . . . . . . . . . 5,283 5,286
PSO-Obligated, Mandatorily Redeemable Preferred
Securities of Subsidiary Trust Holding Solely Junior
Subordinated Debentures of PSO. . . . . . . . . . . . . 75,000 75,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . 344,745 364,516
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 920,530 921,268
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . 30,000 20,000
Advances from Affiliates. . . . . . . . . . . . . . . . . 119,689 79,169
Accounts Payable - General. . . . . . . . . . . . . . . . 93,268 44,088
Accounts Payable - Affiliated Companies . . . . . . . . . 36,417 35,518
Customer Deposits . . . . . . . . . . . . . . . . . . . . 18,524 17,752
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 31,165 18,480
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 10,730 5,420
Energy Trading Contracts. . . . . . . . . . . . . . . . . 108,434 -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 12,758 8,058
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 460,985 228,485
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 306,260 281,916
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . 36,231 37,574
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS . . . . . . . . 87,116 55,483
---------- ----------
CONTINGENCIES (Note 12)
TOTAL . . . . . . . . . . . . . . . . . . . . . $1,811,122 $1,524,726
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 70,194 $ 66,637
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 57,470 56,290
Deferred Income Taxes. . . . . . . . . . . . . . . . . . 19,798 11,993
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,343) (1,343)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (34,933) (1,479)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 158 (1,610)
Equity and Other Investments . . . . . . . . . . . . . . (30,331) (5,802)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 50,079 (31,971)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 12,685 15,763
Other Deferred Credits . . . . . . . . . . . . . . . . . 22,627 10,761
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (35,340) (24,795)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 12,150 22,695
-------- ---------
Net Cash Flows From Operating Activities . . . . . . 143,214 117,139
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (120,105) (73,204)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . - (3,711)
-------- --------
Net Cash Flows Used For Investing Activities . . . . (120,105) (76,915)
-------- --------
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 33,257
Retirement of Long-term Debt . . . . . . . . . . . . . . . (10,000) (33,700)
Change in Advances from Affiliates (net) . . . . . . . . . 40,520 4,500
Dividends Paid on Common Stock . . . . . . . . . . . . . . (51,000) (45,000)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (158) (159)
-------- --------
Net Cash Flows From Financing Activities . . . . . . (20,638) (41,102)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 2,471 (878)
Cash and Cash Equivalents at Beginning of Period . . . . . . 3,173 4,670
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 5,644 $ 3,792
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $24,222,000 and
$23,454,000 and for income taxes was $13,925,395 and $16,614,000 in 2000 and
1999, respectively.
See Notes to Consolidated Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Net income increased $4.1 million or 8% for the third quarter and $3.6
million or 5% for the year-to-date due mainly to a gain from the sale of a
minority interest in Scientech, Inc. Scientech provides services, systems and
instruments, which describe, regulate, monitor and enhance the safety and
reliability of power plant operations and their environmental impact.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . . $100 39 $141 24
Fuel Expense . . . . . . . . . 73 89 94 45
Purchased Power Expense. . . . 26 128 48 95
Other Operation Expense. . . . (4) (10) (5) (6)
Taxes Other Than Federal
Income Taxes . . . . . . . . 3 34 N.M. N.M.
Federal Income Taxes . . . . . 2 9 4 12
Nonoperating Income. . . . . . 6 404 7 N.M.
Interest Charges . . . . . . . N.M. 5 2 9
N.M. = Not Meaningful
The increase in operating revenues was due to an increase in
fuel-related revenues, reflecting increased fuel and purchased power expenses
and increased wholesale sales to neighboring utilities and marketers. Fuel
revenue changes are generally offset by increases in fuel and purchased power
expenses due to the operation of a fuel clause mechanism in Oklahoma.
The increases in fuel and purchased power expenses were due primarily
to a rise in the average unit fuel cost and higher prices for economy energy
purchases reflecting an increase in natural gas prices.
Other operation expenses decreased due primarily to the effect of an
unfavorable reallocation adjustment recorded in 1999 as a result of FERC
approval of a transmission coordination agreement. The transmission coordination
agreement provides the means by which the AEP West electric operating companies
plan, operate and maintain their 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. In
1999 the AEP West electric operating companies filed a revised transmission
coordination agreement which includes changes that ensure a revenue and cost
allocation in proportion to each company's respective revenue requirement for
service it provides under a revised open access transmission tariff. In the
third quarter of 1999, PSO recorded the estimated impact of the reallocation of
open access transmission tariff revenues and costs retroactive to 1997 which
caused PSO to record additional other operation expense.
Taxes other than federal income taxes increased for the quarter due
primarily to an increase in state taxable income. Income tax expense
associated with utility operations increased as a result of an increase
in pre-tax book income. The increase in nonoperating income primarily
resulted from the gain on the sale of the Company's minority interest
in Scientech, Inc in 2000.
Interest charges increased reflecting additional short-term borrowings.
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $377,442 $312,035 $857,607 $751,987
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 172,763 124,737 375,888 292,698
Purchased Power. . . . . . . . . . . . 23,665 10,130 54,615 26,895
Other Operation. . . . . . . . . . . . 39,417 42,003 111,477 106,267
Maintenance. . . . . . . . . . . . . . 12,644 15,598 47,856 49,860
Depreciation and Amortization. . . . . 27,978 25,464 78,460 76,988
Taxes Other Than Federal Income Taxes. 17,518 10,859 41,634 44,195
Federal Income Taxes . . . . . . . . . 22,145 21,703 30,338 32,464
-------- -------- -------- --------
TOTAL OPERATING EXPENSES . . . 316,130 250,494 740,268 629,367
-------- -------- -------- --------
OPERATING INCOME . . . . . . . . . . . . 61,312 61,541 117,339 122,620
NONOPERATING INCOME (LOSS) . . . . . . . 1,008 (3,062) 1,453 (2,277)
-------- -------- -------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 62,320 58,479 118,792 120,343
INTEREST CHARGES . . . . . . . . . . . . 14,783 13,571 44,806 41,929
-------- -------- -------- --------
INCOME BEFORE EXTRAORDINARY ITEM . . . . 47,537 44,908 73,986 78,414
EXTRAORDINARY LOSS - DISCONTINUANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(NET OF TAXES OF $1,621,000) . . . . . - (3,011) - (3,011)
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 47,537 41,897 73,986 75,403
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 58 57 172 172
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK . . $ 47,479 $ 41,840 $ 73,814 $ 75,231
======== ======== ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD AS
PREVIOUSLY REPORTED. . . . . . . . . . $278,881 $280,760 $288,018 $300,592
Conforming Change in Accounting . . .
Policy. . . . . . . . . . . . . . . - (4,787) (4,472) (4,010)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. 278,881 275,973 283,546 296,582
NET INCOME . . . . . . . . . . . . . . . 47,537 41,897 73,986 75,403
DEDUCTIONS:
Cash Dividends Declared:
Common Stock. . . . . . . . . . . . . 15,500 27,000 46,500 81,000
Preferred Stock . . . . . . . . . . . 58 57 172 172
-------- -------- -------- ---------
BALANCE AT END OF PERIOD . . . . . . . . $310,860 $290,813 $310,860 $290,813
======== ======== ======== ========
The Company is a wholly owned subsidiary of AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $1,406,245 $1,402,062
Transmission. . . . . . . . . . . . . . . . . . . . . . . 517,133 484,327
Distribution. . . . . . . . . . . . . . . . . . . . . . . 989,224 958,318
General . . . . . . . . . . . . . . . . . . . . . . . . . 323,110 333,949
Construction Work in Progress . . . . . . . . . . . . . . 58,829 52,775
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 3,294,541 3,231,431
Accumulated Depreciation. . . . . . . . . . . . . . . . . 1,434,124 1,384,242
---------- ----------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 1,860,417 1,847,189
---------- -----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 73,708 37,080
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 3,512 3,043
Accounts Receivable . . . . . . . . . . . . . . . . . . . 62,804 45,511
Accounts Receivable - Affiliated Companies. . . . . . . . 6,275 6,053
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 59,812 60,844
Underrecovered Fuel . . . . . . . . . . . . . . . . . . . 34,089 -
Materials and Supplies. . . . . . . . . . . . . . . . . . 26,085 26,420
Energy Trading Contracts. . . . . . . . . . . . . . . . . 88,550 -
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 17,574 15,953
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 298,701 157,824
---------- ----------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 54,081 47,180
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . 20,333 16,942
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . $2,307,240 $2,106,215
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- -----------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
Outstanding - 7,536,640 Shares. . . . . . . . . . . . . $ 135,660 $ 135,660
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 245,000 245,000
Retained Earnings . . . . . . . . . . . . . . . . . . . . 310,860 283,546
---------- ----------
TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . . 691,520 664,206
Preferred Stock . . . . . . . . . . . . . . . . . . . . . . 4,704 4,706
SWEPCO-OBLIGATED, MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
SUBORDINATED DEBENTURES OF SWEPCO. . . . . . . . . . . . . 110,000 110,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . . 645,527 495,973
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . . . . . . 1,451,751 1,274,885
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . 595 45,595
Advances from Affiliates. . . . . . . . . . . . . . . . . 26,947 140,897
Accounts Payable - General. . . . . . . . . . . . . . . . 96,030 60,689
Accounts Payable - Affiliated Companies . . . . . . . . . 35,043 39,117
Customer Deposits . . . . . . . . . . . . . . . . . . . . 15,857 14,236
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 47,457 24,374
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 11,971 9,792
Energy Trading Contracts. . . . . . . . . . . . . . . . . 92,688 -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 23,934 21,878
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 350,522 356,578
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 392,803 376,504
---------- ----------
DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . . 54,288 57,649
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS . . . . . . . . 57,876 40,599
---------- ----------
CONTINGENCIES (Note 12)
TOTAL . . . . . . . . . . . . . . . . . . . . . $2,307,240 $2,106,215
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIAREIS
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 73,986 $ 75,403
Adjustments for NonCash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 83,060 81,122
Deferred Income Taxes. . . . . . . . . . . . . . . . . . 10,901 (16,204)
Deferred Investment Tax Credits . . . . . . . . . . . . (3,361) (3,423)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (17,515) (34,306)
Fuel, Material and Supplies. . . . . . . . . . . . . . . 1,367 (16,404)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 31,267 (5,546)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 23,083 35,411
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (36,977) (223)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (16,756) 37,020
-------- ---------
Net Cash Flows From Operating Activities . . . . . . 149,055 152,850
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (92,379) (73,127)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 232 (3,545)
-------- --------
Net Cash Flows Used For Investing Activities . . . . (92,147) (76,672)
-------- --------
FINANCING ACTIVITIES:
Redemption of Preferred Stock. . . . . . . . . . . . . . . (1) (1)
Proceeds from Issuance of Long-term Debt . . . . . . . . . 149,634 -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (45,450) (43,787)
Change in Advances from Affiliates (net) . . . . . . . . . (113,950) 47,370
Dividends Paid on Common Stock . . . . . . . . . . . . . . (46,500) (81,000)
Dividends Paid on Preferred Stock. . . . . . . . . . . . . (172) (172)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (56,439) (77,590)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 469 (1,412)
Cash and Cash Equivalents at Beginning of Period . . . . . . 3,043 4,444
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 3,512 $ 3,032
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $42,627,000 and
$40,056,000 and for income taxes was $16,040,000 and $32,812,000 in 2000 and
1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Net income increased $5.6 million, or 13%, for the quarter and was $1.4
million, or 2%, lower for the nine months ended September 30, 2000. The increase
for the quarter resulted primarily from increased nonoperating income and an
extraordinary loss due to the discontinuance of regulatory accounting for
generation in 1999. The decrease for the year-to-date period resulted primarily
from increased operating expenses and interest charges offset in part by the
effect of the extraordinary loss in 1999.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . . $65 21 $106 14
Fuel Expense . . . . . . . . . 48 39 83 28
Purchased Power Expense. . . . 14 134 28 103
Other Operation Expense. . . . (3) (6) 5 5
Maintenance Expense. . . . . . (3) (19) (2) (4)
Depreciation and Amortization. 3 10 1 2
Taxes Other Than Federal
Income Taxes . . . . . . . . 7 61 (3) (6)
Nonoperating Income. . . . . . 4 133 4 164
Interest Charges . . . . . . . 1 9 3 7
The increase in operating revenues resulted from higher fuel related
revenues due to increased fuel and purchased power expense, the post merger
implementation of AEP's power marketing and trading operations which increased
wholesale sales to neighboring utilities and power marketers, and an unfavorable
adjustment in 1999 as a result of FERC's approval of a transmission coordination
agreement. The transmission coordination agreement provides the means by which
the AEP West electric operating companies plan, operate and maintain their four
separate transmission systems as a single unit. The agreement also establishes
the method by which these companies allocate transmission revenues received
under open access transmission tariffs. In 1999 the AEP West electric operating
companies filed a revised transmission coordination agreement which includes
changes that ensure a revenue allocation in proportion to each company's
respective revenue requirement for service it provides under a revised open
access transmission tariff. In the third quarter of 1999, SWEPCo and the other
AEP West electric operating companies recorded the estimated impact of the
reallocation of open access transmission tariff revenues retroactive to 1997
which caused SWEPCo to record a reduction to revenues in the third quarter of
1999 thereby increasing comparative revenues.
Fuel expense increased due primarily to an increase in the average unit
cost of fuel as a result of higher spot market natural gas prices.
The increase in purchased power expenses was primarily caused by an
increase in the cost of economy energy purchases due to increased spot market
gas prices.
Other operation expense decreased for the quarter as a result of the
effect of an unfavorable adjustment recorded in 1999 for allocated transmission
services. Other operation expenses were up in the year-to-date period due
primarily to increased customer accounts expenses, increased insurance expenses,
and increased regulatory and consulting expenses for a sales tax audit which
more than offset the effect of the unfavorable transmission services adjustment
recorded in 1999.
A reduction in overhead line tree trimming work caused the decrease in
maintenance expense for the quarter. In the year-to-date period the decline in
maintenance expense reflects a decrease in generating station maintenance
activity.
Depreciation and amortization expense increased due to changes in
depreciation rates associated with rate-related settlements in Arkansas and
Louisiana in 1999.
The increase in taxes other than federal income taxes for the third
quarter was due to an increase in ad valorem taxes in 2000. The decrease in the
year-to-date taxes other than federal income taxes was a result of decreased
state taxable income.
<PAGE>
Nonoperating income increased due to a 1999 write off of Cajun Electric
Power Cooperative acquisition expenses. SWEPCo had deferred approximately $13
million in costs related to its attempt to acquire Cajun's non-nuclear assets.
Under a settlement agreement, SWEPCo received a $7.5 million reimbursement and
reflected an after tax loss in the third quarter of 1999 of $3.7 million.
The increase in interest charges can be attributed to the issuance of
additional long-term debt in 2000.
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $201,191 $164,104 $425,268 $352,938
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 57,728 41,478 133,515 93,821
Purchased Power. . . . . . . . . . . . 54,686 28,328 92,034 49,096
Other Operation. . . . . . . . . . . . 32,046 24,761 68,101 65,835
Maintenance. . . . . . . . . . . . . . 4,959 4,283 14,866 14,744
Depreciation and Amortization. . . . . 22,717 20,734 42,050 42,358
Taxes Other Than Federal Income Taxes. 7,096 6,464 18,712 21,049
Federal Income Taxes . . . . . . . . . 5,394 11,026 12,706 15,722
-------- -------- --------- --------
TOTAL OPERATING EXPENSES . . . 184,626 137,074 381,984 302,625
-------- -------- --------- --------
OPERATING INCOME . . . . . . . . . . . . 16,565 27,030 43,284 50,313
NONOPERATING INCOME (LOSS) . . . . . . . (202) 332 (3,441) 504
-------- -------- --------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 16,363 27,362 39,843 50,817
INTEREST CHARGES . . . . . . . . . . . . 5,693 5,949 17,270 18,356
-------- -------- -------- --------
INCOME BEFORE EXTRAORDINARY ITEM . . . . 10,670 21,413 22,573 32,461
EXTRAORDINARY LOSS - DISCONTINANCE OF
REGULATORY ACCOUNTING FOR GENERATION
(NET OF TAXES OF $2,941,000) . . . . . - (5,461) - (5,461)
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 10,670 15,952 22,573 27,000
PREFERRED STOCK DIVIDENDS REQUIREMENTS . 26 26 78 78
-------- -------- -------- ---------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 10,644 $ 15,926 $ 22,495 $ 26,922
======== ======== ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD
AS PREVIOUSLY REPORTED. . . .. . . . . $116,093 $114,772 $115,856 $117,189
CONFORMING CHANGE IN ACCOUNTING POLICY . - (2,836) (2,614) (2,249)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. 116,093 111,936 113,242 114,940
NET INCOME . . . . . . . . . . . . . . . 10,670 15,952 22,573 27,000
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 4,500 7,000 13,500 21,000
Preferred Stock. . . . . . . . . . . 26 26 78 78
-------- -------- -------- ---------
BALANCE AT END OF PERIOD . . . . . . . . $122,237 $120,862 $122,237 $120,862
======== ======== ======== =========
The common stock of the Company is wholly owned by AEP.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $ 422,972 $ 429,783
Transmission. . . . . . . . . . . . . . . . . . . . . . . 234,824 220,479
Distribution. . . . . . . . . . . . . . . . . . . . . . . 412,670 403,206
General . . . . . . . . . . . . . . . . . . . . . . . . . 110,543 113,945
Construction Work in Progress . . . . . . . . . . . . . . 28,242 15,131
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 1,209,251 1,182,544
Accumulated Depreciation and Amortization . . . . . . . . 506,207 495,847
---------- ----------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 703,044 686,697
---------- ----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 33,505 21,570
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 8,660 6,074
Accounts Receivable:
Customers . . . . . . . . . . . . . . . . . . . . . . . 40,833 45,742
Affiliated Companies. . . . . . . . . . . . . . . . . . 9,835 4,837
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 13,548 17,133
Materials and Supplies. . . . . . . . . . . . . . . . . . 11,145 14,029
Under-recovered Fuel Costs. . . . . . . . . . . . . . . . 48,303 14,652
Energy Trading Contracts. . . . . . . . . . . . . . . . . 27,456 -
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 1,075 619
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 160,855 103,086
---------- ----------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 14,071 16,687
---------- ----------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 5,146 20,108
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . $ 916,621 $ 848,148
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
September 30, December 31,
2000 1999
------------- ------------
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
Outstanding - 5,488,560 Shares. . . . . . . . . . . . . $ 137,214 $ 137,214
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 2,236 2,236
Retained Earnings . . . . . . . . . . . . . . . . . . . . 122,237 113,242
---------- ----------
Total Common Shareholder's Equity . . . . . . . . 261,687 252,692
Preferred Stock . . . . . . . . . . . . . . . . . . . . . 2,482 2,482
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . 263,792 263,686
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 527,961 518,860
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . - 40,000
Advances from Affiliates. . . . . . . . . . . . . . . . . 47,646 21,408
Accounts Payable - General. . . . . . . . . . . . . . . . 60,034 39,611
Accounts Payable - Affiliated Companies . . . . . . . . . 15,716 19,770
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 13,750 12,458
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 7,441 4,165
Energy Trading Contracts. . . . . . . . . . . . . . . . . 28,739 -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 13,339 13,906
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 186,665 151,318
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 152,951 148,992
---------- ----------
DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . . 24,369 25,323
---------- ----------
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 24,675 3,655
---------- ----------
CONTINGENCIES (Note 12)
TOTAL . . . . . . . . . . . . . . . . . . . . . $ 916,621 $ 848,148
========== ==========
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Nine Months Ended
September 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 22,573 $ 27,000
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 43,750 32,558
Deferred Income Taxes. . . . . . . . . . . . . . . . . . 5,586 7,911
Deferred Investment Tax Credits. . . . . . . . . . . . . (953) (956)
Extraordinary Loss - Discontinuance of SFAS 71 . . . . . - 5,461
Changes in Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . . (89) 759
Fuel, Materials and Supplies . . . . . . . . . . . . . . 6,469 (1,378)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 16,369 9,730
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 1,292 7,415
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (33,651) (9,052)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 12,518 350
-------- ---------
Net Cash Flows From Operating Activities . . . . . . 73,864 79,798
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (44,050) (35,444)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 112 (2,828)
-------- --------
Net Cash Flows Used For Investing Activities . . . . (43,938) (38,272)
-------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt . . . . . . . . . . . . . . . (40,000) -
Change in Advances from Affiliates (net) . . . . . . . . . 26,238 (4,573)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (13,500) (21,000)
Dividends Paid on Preferred Stock. . . . . . . . . . . . . (78) (78)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (27,340) (25,651)
-------- --------
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 2,586 15,875
Cash and Cash Equivalents at Beginning of Period . . . . . . 6,074 2,093
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 8,660 $ 17,968
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $13,994,000 and
$10,067,000 and for income taxes was $5,442,000 and $1,749,000 in 2000 and
1999, respectively.
See Notes to Financial Statements beginning on page L-1.
</TABLE>
<PAGE>
WEST TEXAS UTILITIES COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
-------------------------------------------------------------
THIRD QUARTER 2000 vs. THIRD QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
---------------------------------------
Income before extraordinary items decreased $11 million or 50%
for the quarter and $10 million or 30% for the year-to-date period
largely due to the effects of a 1999 FERC order related to a transmission
coordination agreement. The transmission coordination agreement provides
the means by which the AEP West electric operating companies plan,
operate and maintain their four separate transmission systems as a single
unit. The agreement also establishes the method by which these companies
allocate revenues received under open access transmission tariffs. In
1999 the AEP West electric operating companies filed a revised
transmission coordination agreement which includes changes that ensure a
revenue allocation in proportion to each company's respective revenue
requirement for service it provides under a revised open access
transmission tariff. In the third quarter of 1999, WTU and the other AEP
West electric operating companies recorded the estimated impact of the
reallocation of open access transmission tariff revenues retroactive to
1997 which caused WTU to record additional revenues and thereby
increasing net income in 1999.
An extraordinary loss related to the discontinuance of SFAS 71
regulatory accounting of $5.5 million after tax was recorded in September
1999.
<PAGE>
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues, . . . . . . . $ 37 23 $72 20
Fuel Expense. . . . . . . . . . . 16 39 40 42
Purchased Power Expense . . . . . 26 93 43 87
Other Operation Expense . . . . . 7 29 2 3
Depreciation and Amortization . . 2 10 - N.M.
Taxes Other Than Federal
Income Taxes. . . . . . . . . . 1 10 (2) (11)
Federal Income Taxes. . . . . . . (6) (51) (3) (19)
Nonoperating Income . . . . . . . (1) N.M. (4) N.M.
Interest Charges. . . . . . . . . - N.M. (1) (6)
Extraordinary Loss. . . . . . . . 5 N.M. 5 N.M.
N.M. = Not Meaningful
The increase in operating revenues was due to increased
fuel-related revenues, reflecting higher fuel and purchased power
expenses, and an increase in weather-related demand for electricity.
Under the operation of a fuel clause mechanism in Texas, revenues are
accrued to reflect fuel and purchased power cost increases. These
increases were partially offset by a reduction in non-MWH revenue. The
decline in non-MWH revenue was primarily due to the effect of the 1999
FERC transmission coordination agreement order.
The increase in fuel expense was due to a rise in the average
unit fuel cost resulting from an increase in the spot market price of
natural gas.
Purchased power expense increased due primarily to a 40%
increase in the cost per MWH purchased to replace generation at a power
plant which was out of service for more than half of the current quarter
as a result of a control room fire.
The increase in other operation expense was due primarily to
an increase in transmission expenses that resulted from new higher prices
for the ERCOT transmission grid. Each year ERCOT establishes new rates to
allocate the costs of the Texas transmission system to Texas electric
utilities.
Depreciation and amortization expense increased for the third
quarter due to the recordation of increased accruals for estimated excess
earnings under the Texas Legislation.
The decrease in taxes other than federal income taxes for the
year-to-date period was primarily due to lower ad valorem and state
franchise taxes.
Federal income taxes attributable to operations decreased due
primarily to a decrease in pre-tax net income. The decrease in
nonoperating income was due primarily to the termination of
merchandise sales and the cost of phasing out these sales.
Interest charges decreased as a result of a reduction in
long-term borrowings.
An extraordinary loss was recorded in the third quarter of
1999 when WTU discontinued the application of SFAS 71 regulatory
accounting for the generation portion of its business as a result of the
Texas Legislation providing for a transition from cost based rate
regulation for the Company's generation business to customer choice
market pricing.
<PAGE>
NOTES TO FINANCIAL STATEMENTS AND THE REGISTRANT TO WHICH THEY APPLY
Note 1. General AEP, AEGCo, APCo, CPL, CSPCo, I&M,
KPCo, OPCo, PSO, SWEPCo, WTU
Note 2. Extraordinary
Item AEP, APCo, CSP, OPCo, SWEPCo, WTU
Note 3. Merger AEP, CPL, I&M, KPCo, PSO, SWEPCo, WTU
Note 4. Cook
Plant Shutdown AEP, I&M
Note 5. Financing
Activities AEP, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
Note 6. Money Pool AEP, AEGCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo, WTU
Note 7. Factoring of
Receivables AEP, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo, WTU
Note 8. Rate Matters AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo,
SWEPCo, WTU
Note 9. Industry
Restructuring AEP, APCo, CPL, CSPCo, I&M, OPCo, PSO,
SWEPCo, WTU
Note 10. Business
Segments AEP
Note 11. South American
Investments AEP
Note 12. Contingencies AEP, AEGCo, APCo, CPL, CSPCo, I&M,
KPCo, OPCo, PSO, SWEPCo, WTU
<PAGE>
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 1999 audited financial statements. For AEP, AEGCo,
APCo, CSPCo, I&M, KPCo and OPCo the 1999 audited financial statements
are included in their 1999 Annual Reports, which are incorporated in and
filed with their Form 10-K. The 1999 audited financial statements for
CPL, PSO, SWEPCo and WTU are included in their Form 10-K. Certain
prior-period amounts have been reclassified to conform to current-period
presentation. In the opinion of management, these unaudited financial
statements reflect all adjustments (consisting of only normal recurring
accruals) which are necessary for a fair presentation of the results of
operations for interim periods.
2. EXTRAORDINARY ITEMS
Extraordinary items were recorded for the discontinuance of
regulatory accounting under SFAS 71 for the generation portion of the
business in the Ohio, Virginia, West Virginia, Texas and Arkansas
jurisdictions. See Note 9 "Industry Restructuring" for descriptions of
the restructuring plans and related accounting effects. The following
table shows the components of the extraordinary items reported on the
consolidated statement of income:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2000 1999 2000 1999
---- ---- ---- ----
(in millions)
Extraordinary Items -
Discontinuance of
Regulatory Accounting
for Generation:
Ohio Jurisdiction (Net of
Tax of $35 Million). . . . $(44) $ - $(44) $ -
Virginia and West Virginia
Jurisdictions (Inclusive
of Tax Benefit of $8
Million) . . . . . . . . . - - 9 -
Texas and Arkansas
Jurisdictions (Net of Tax
of $5 Million) . . . . . . - (8) - (8)
---- --- ---- ---
Extraordinary Items . . . $(44) $(8) $(35) $(8)
===== === ==== ===
3. MERGER OF AEP AND CSW
On June 15, 2000, AEP merged with CSW so that CSW became a
wholly-owned subsidiary of AEP. Under the terms of the merger agreement,
approximately 127.9 million shares of AEP Common Stock were issued in
exchange for all the outstanding shares of CSW Common Stock based upon
an exchange ratio of 0.6 share of AEP Common Stock for each share of CSW
common stock. Following the exchange, former shareholders of AEP owned
approximately 61.4 percent of the corporation, while former CSW
shareholders owned approximately 38.6 percent of the corporation.
CSW's four wholly-owned domestic electric utility subsidiaries are: CPL,
PSO, SWEPCo and WTU. CSW also has the following principal subsidiaries:
CSW International, CSW Energy, Seeboard, CSW Credit, C3 Communications,
Inc. and CSW Energy Services, Inc.
The merger was accounted for as a pooling of interests.
Accordingly, AEP's consolidated financial statements give retroactive
effect to the merger, with all periods presented as if AEP and CSW had
always been combined. Certain reclassifications have been made to
conform the historical financial statement presentation of AEP and CSW.
The following table sets forth revenues, extraordinary items and
net income previously reported by AEP and CSW and the combined amounts
shown in the accompanying financial statements:
Three Months Ended Nine Months Ended
September 30, 1999 September 30, 1999
------------------ ------------------
(in millions)
Revenues:
AEP $1,914 $5,251
CSW 1,618 4,162
------ ------
AEP After Pooling $3,532 $9,413
====== ======
Extraordinary Items:
AEP $ - $ -
CSW (8) (8)
--- ---
AEP After Pooling $(8) $(8)
=== ===
Net Income:
AEP $174 $413
CSW 222 370
Conforming Adjustment (1) (4)
---- ----
AEP After Pooling $395 $779
==== ====
The combined financial statements include an adjustment to
conform CSW's accounting for vacation pay accruals with AEP's
accounting. The effect of the conforming adjustment was to reduce net
assets by $16.4 million at December 31, 1999 and reduce net income by
$0.8 million and $3.8 million for the three months and nine months ended
September 1999, respectively.
<PAGE>
The following table shows the vacation accrual conforming
adjustment for CSW's registrant utility subsidiaries:
Net Income Reductions
Three Months Nine Months
Net Asset Ended Ended
Reduction At September 30, September 30,
December 31, 1999 1999 1999
----------------- ------------- -------------
(in millions) (in millions)
CPL $5.3 $0.2 $1.1
PSO 2.8 0.1 0.8
SWEPCo 4.5 0.2 1.0
WTU 2.6 0.1 0.7
In connection with the merger, $181 million ($169 million
after-tax) of non-recoverable merger costs were expensed through
September 30, 2000. Such costs included transaction and transition costs
not recoverable from ratepayers. Also included in the merger costs were
non-recoverable change in control payments. Merger transaction and
transition costs of $38 million recoverable from ratepayers were
deferred pursuant to settlement agreements. Deferred merger costs are
being amortized over five to eight year recovery periods depending on
the specific terms of the settlement agreements. Merger transition costs
are expected to continue to be incurred for several years after the
merger and will be expensed or deferred for amortization as appropriate.
The settlement agreements provide for a sharing of net merger savings
with certain regulated customers over periods of up to eight years
through rate reductions beginning in the third quarter of 2000.
In connection with the merger, the PUCT approved a settlement
agreement that provides for, among other things, sharing net merger
savings with Texas customers of CPL, SWEPCo and WTU over six years after
consummation of the merger through rate reduction riders.
The IURC and MPSC approved merger settlement agreements that,
among other things, provide for sharing net merger savings with I&M's
retail customers over eight years through reductions to customers'
bills. The terms of the Indiana settlement require reductions in
customers' bills of approximately $67 million over eight years. Under
the Michigan settlement, billing credits will be used to reduce
customers' bills by approximately $14 million over eight years for net
guaranteed merger savings.
The KPSC approved a settlement agreement that, among other
things, provides for sharing net merger savings with KPCo's customers
over eight years through reductions to customers' bills. The Kentucky
customers' share of the net merger savings is expected to be
approximately $28 million.
A merger settlement agreement for PSO was approved by the
Oklahoma Corporation Commission that, among other things, provides for
sharing approximately $28 million in guaranteed net merger savings over
five years with Oklahoma customers.
The Arkansas Public Service Commission approved an agreement
related to the merger which, among other things, provides for $6 million
of net merger savings to reduce SWEPCo customers rates over five years
in Arkansas.
SWEPCo's Louisiana customers will receive approximately $18
million of merger savings over eight years according to a merger
approval order issued by the Louisiana Public Service Commission.
If actual merger savings are significantly less than the merger
savings rate reductions required by the merger settlement agreements in
the eight-year period following consummation of the merger, future
results of operations, cash flows and possibly financial condition could
be adversely affected.
The divestiture of 1,904 MW of generating capacity was required
as a condition of regulatory approval of the merger by the FERC and
PUCT. Under the FERC-approved merger settlement agreement the
divestiture of 550 MW of generating capacity comprised of 300 MW of
capacity in SPP and 250 MW of capacity in ERCOT is required. The FERC is
requiring AEP and CSW to divest their entire ownership interest in and
operational control of the entire generating facilities that produce the
capacity to be divested. The FERC required divestiture of the identified
ERCOT capacity must be completed by March 15, 2001 and for the SPP
capacity by July 1, 2002. The FERC found that certain energy sales in
SPP and ERCOT would be a reasonable and effective interim mitigation
measure until the required SPP and ERCOT divestitures could be
completed. The Texas settlement calls for the divestiture of a total of
1,604 MW of generating capacity within Texas inclusive of 250 MW ordered
to be divested by FERC. The divestiture under the Texas settlement can
not proceed until two years after the merger closes to satisfy the
requirements to use pooling-of-interests accounting treatment. The FERC
divestiture is not limited by the pooling rules because it is regulatory
ordered.
The current annual dividend rate per share of AEP common stock is
$2.40. The dividends per share reported on the statements of income for
prior periods represent pro forma amounts and are based on AEP's
historical annual dividend rate of $2.40 per share. If the dividends per
share reported for prior periods were based on the sum of the historical
dividends declared by AEP and CSW, the annual dividend rate would be
$2.60 per combined share.
4. COOK PLANT SHUTDOWN
As discussed in the 1999 Annual Report, the Cook Plant was shut
down in September 1997 due to questions regarding the operability of
certain safety systems that arose during a NRC architect engineer design
inspection.
On July 5, 2000, Cook Plant Unit 2, the first unit scheduled to
restart, reached 100% power completing its restart process.
On July 26, 2000, I&M announced that the restart of Cook Plant
Unit 1 would cost an additional $145 million and was scheduled to occur
in the first quarter of 2001. However, unforeseen issues or difficulties
encountered in preparing Unit 1 for restart could potentially delay its
return to service.
Expenditures to restart the Cook Plant units had been estimated
to total approximately $574 million. The additional $145 million to
restart Unit 1 raises the total estimate to $719 million. Through
September 30, 2000, $592 million has been spent to restart the units.
For the nine months ended September 30, 2000, restart costs of $249
million were recorded in other operation and maintenance expense,
including amortization of $30 million of restart costs previously
deferred in accordance with settlement agreements in the Indiana and
Michigan retail regulatory jurisdictions. Also pursuant to the
settlement agreements, accrued fuel-related revenues of $28 million were
amortized in 2000. At September 30, 2000, deferred restart costs of $130
million remained in regulatory assets to be amortized through 2003. Also
deferred as a regulatory asset at September 30, 2000 are $122 million of
fuel-related revenues to be amortized through December 31, 2003 for both
jurisdictions.
The costs of the extended outage and restart efforts will
continue to have a material adverse effect on future results of
operations and on cash flows until the second unit is restarted. The
amortization of restart costs deferred under Indiana and Michigan retail
jurisdictional settlement agreements will adversely affect results of
operations through December 31, 2003 when the amortization period ends.
The annual amortization of restart cost deferrals is $40 million.
Management believes that the second Cook Plant unit, Unit 1, will also
be successfully returned to service. However, if for some unknown reason
it is not returned to service or its return is delayed significantly it
would have an even greater material adverse effect on future results of
operations, cash flows and financial condition.
5. FINANCING ACTIVITIES
During the first nine months of 2000, AEP subsidiaries issued
$951 million of long-term notes at variable interest rates with due
dates ranging from 2001 to 2007. Also short-term debt borrowings
increased by $1.4 billion. The AEP System companies have in the past,
and may in the future, acquire outstanding debt and preferred stock
securities in open market transactions.
The following table lists long-term notes issued during the first
nine months of 2000 by the subsidiaries that are registrants:
Issuance Interest Due
Company Amount Rate Date
------- -------- -------- ----
(in millions)
APCo $ 75 Floating June 27, 2001
CPL 150 Floating February 22, 2002
I&M 200 Floating September 3, 2002
OPCo 75 Floating May 16, 2001
SWEPCo 150 Floating March 1, 2002
Retirements of debt during 2000 were: first mortgage bonds
totaling $416 million and due dates ranging from 2000 to 2024, $268
million of long-term notes with variable interest rates as well as fixed
rates ranging from 6.43% to 6.57%, a $625 million revolving credit
agreement that matured and was refinanced with short-term debt and a $45
million revolving credit agreement that was redeemed early.
<PAGE>
The following table lists specific long-term debt retirements
during the first nine months of 2000 by subsidiaries that are
registrants:
Principal
Type Amount Interest Due
Company of Debt Retired Rate Date
------- ------- ----------- -------- ----
(in millions) (%)
APCo IPC $ 30 7.40 January 1, 2014
APCo FMB 48 6.35 March 1, 2000
APCo FMB 48 6.71 June 1, 2000
CPL FMB 100 6 April 1, 2000
CPL FMB 50 7.5 March 1, 2020
CSPCo FMB 19 7.25 October 1, 2002
I&M FMB 48 6.40 March 1, 2000
KPCo NP 25 6.57 April 1, 2000
OPCo MTN 13 6.24 December 4, 2008
PSO MTN 10 6.43 March 30, 2000
SWEPCo FMB 45 5.25 April 1, 2000
WTU FMB 40 7.5 April 1, 2000
CSPCo redeemed 100,000 shares of its 7% series of preferred stock
on August 1, 2000.
6. MONEY POOL
In June 2000 the AEP System established a Money Pool to
coordinate short-term borrowings for certain subsidiaries, primarily the
domestic electric utility operating companies. The operation of the
Money Pool is designed to match on a daily basis the available cash and
borrowing requirements of the participants, thereby minimizing the need
for short-term borrowings from external sources and increasing the
interest income for participants with available cash. Participants with
excess cash loan funds to the Money Pool reducing the amount of external
funds AEP needs to borrow to meet the short-term cash requirements of
other participants whose short-term cash requirements are met through
advances from the Money Pool. AEP borrows the funds on a daily basis,
when necessary, to meet the net cash requirements of the Money Pool
participants. A weighted average daily interest rate which is calculated
based on the outstanding short-term debt borrowings made by AEP is
applied to each Money Pool participant's daily outstanding investment or
debt position to determine interest income or interest expense. The
Money Pool participants include interest income in nonoperating income
and interest expense in interest charges. As a result of becoming Money
Pool participants, AEGCo, CSPCo, I&M, KPCo and OPCo retired their
short-term debt. CPL, PSO, SWEPCo and WTU participated in a CSW money
pool prior to the merger and subsequent to the merger participate in the
AEP Money Pool. At September 30, 2000, participating subsidiaries who
are net investors from the Money Pool report their investment in the
Money Pool as Advances to Affiliates and companies who are net borrowers
from the Money Pool report their debt position as Advances from
Affiliates on their balance sheets.
<PAGE>
7. FACTORING OF RECEIVABLES
AEP Credit, Inc. factors electric customer accounts receivable
for affiliated operating companies and unaffiliated companies. Prior
to September 1, 2000, AEP Credit, Inc. was known as CSW Credit. AEP
Credit, Inc. issues commercial paper on a stand alone basis and does
not participate in the Money Pool. In June 2000 the factoring of
customer accounts receivable for affiliated companies was expanded as
a result of the merger. At September 30, 2000, AEP Credit, Inc. had a
$2 billion revolving credit agreement which had $1.5 billion of
commercial paper outstanding.
Under the factoring arrangement most of the domestic electric
subsidiary companies sell without recourse certain of their customer
accounts receivable and accrued utility revenue balances to AEP Credit,
Inc. and are charged a fee based on AEP Credit, Inc.'s financing costs,
uncollectible accounts experience for each company's receivables and
administrative costs. The costs of factoring customer accounts
receivable is reported as an operating expense. At September 30, 2000,
the amount of factored accounts receivable and accrued utility revenues
for each registrant subsidiary was as follows:
Company (in millions)
-------
CPL $200
CSPCo 111
I&M 101
KPCo 24
OPCo 96
PSO 135
SWEPCo 111
WTU 60
8. RATE MATTERS
FERC Jurisdiction - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
As discussed in the 1999 Annual Report, APCo, CSPCo, I&M, KPCo, and
OPCo filed a settlement agreement for FERC approval related to an open
access transmission tariff. A provision was recorded in 1999 for an agreed
to refund including interest which was part of the settlement agreement.
On March 16, 2000, the FERC approved the settlement agreement filed
in December 1999 resolving the issues on rehearing of a July 30, 1999
order. Under terms of the settlement, APCo, CSPCo, I&M, KPCo, and OPCo are
required to make refunds retroactive to September 7, 1993 to certain
customers affected by the July 30, 1999 FERC order. The refunds were made
in two payments. Pursuant to FERC orders the first payment was made in
February 2000 and the second payment was made on August 1, 2000. In
addition, a new lower rate of $1.55 kw/month was made effective January 1,
2000, for all transmission service customers. Also as agreed, a new rate
of $1.42 kw/month took effect on June 16, 2000 upon consummation of the
AEP/CSW merger. Prior to January 1, 2000, the rate was $2.04 kw/month.
Unless the market volume of physical power transactions grows to increase
the utilization of the AEP System's transmission lines, the new open
access transmission rate will adversely impact future results of
operations and cash flows.
West Virginia Jurisdiction - Affecting AEP and APCo
As discussed in the 1999 Annual Report, APCo has been involved in a
WV rate proceeding regarding base and ENEC rates. On February 7, 2000,
APCo and other parties to the proceeding filed a Joint Stipulation with
the WVPSC for approval.
The Joint Stipulation's main provisions include no change in either
base or ENEC rates effective January 1, 2000 from those base and ENEC
rates in effect from November 1, 1996 until December 31, 1999 (these rates
provide for recovery of regulatory assets including any generation-related
regulatory assets through frozen transition rates and a wires charge of
0.5 mills per kwh); the suspension of annual ENEC recovery proceedings and
deferral accounting for any over or under recovery effective January 1,
2000; and the retention, as a regulatory liability, on the books of a net
cumulative deferred ENEC recovery balance of $66 million as established by
a WVPSC order on December 27, 1996. The Joint Stipulation provides that
when deregulation of generation occurs in WV, APCo will use this retained
regulatory liability to reduce generation-related regulatory assets and,
to the extent possible, any additional costs or obligations that
deregulation may impose. The elimination of ENEC recovery proceedings in
WV will subject AEP and APCo to the risk of fuel market price increases
and reductions in wholesale sales levels which could adversely affect
results of operations and cash flows.
Also under the Joint Stipulation APCo's share of any net savings
from the merger between AEP and CSW prior to December 31, 2004 shall be
retained by APCo. As a result, all costs incurred in the merger that
were allocated to APCo shall be fully charged to expense to partially
offset merger savings as of December 31, 2004 and shall not be included
in any WV rate proceeding after that date. After December 31, 2004,
current distribution savings related to the merger will be reflected in
rates in any future rate proceeding before the WVPSC to establish
distribution rates or to adjust rate caps during the transition to
market based rates. When deregulation of generation occurs in WV, the
net retained generation-related merger savings shall be used to recover
any generation-related regulatory assets that are not recovered under
the other provisions of the Joint Stipulation and the mechanisms
provided for in the deregulation legislation and, to the extent
possible, to recover any additional costs or obligations that
deregulation may impose on APCo. Regardless of whether the net
cumulative deferred ENEC recovery balance and the net merger savings are
sufficient to offset all of APCo's generation-related regulatory assets,
under the terms of the Joint Stipulation there will be no further
explicit adjustment to APCo's rates to provide for recovery of
generation-related regulatory assets beyond the above discussed specific
adjustments provided in the Joint Stipulation and the 0.5 mills per KWH
wires charge in the WV Restructuring Plan (see Note 9 for discussion of
WV Restructuring Plan). On June 2, 2000, the WVPSC issued an order
approving the Joint Stipulation.
<PAGE>
Texas Jurisdictional Fuel Factor Filings - Affecting AEP, CPL, SWEPCo
and WTU
AEP's Texas electric operating companies have been experiencing
natural gas fuel price increases which have resulted in under-recoveries
of fuel costs and the need to seek increases in fuel rates and
surcharges to recover past under-recoveries.
In March 2000 the PUCT approved a settlement related to CPL's
January 2000 fuel factor filing. The settlement provided for an increase
in fuel factor revenues of $43.3 million annually beginning in March
2000 and a prospective surcharge to provide $24.7 million for previously
under-recovered fuel cost beginning in April 2000.
In July 2000 CPL filed, with the PUCT, an application for
authority to implement an increase in fuel factors effective with the
September 2000 billing month. CPL also proposed to implement an interim
fuel surcharge to collect its under-recovered fuel costs, including
accumulated interest, over a 12-month period beginning in October 2000.
In August 2000, a settlement was reached between the various parties.
The settlement allows CPL to increase its fuel factor by $173.5 million
and provides for a surcharge of $21.3 million for previously
under-recovered fuel costs for the period from December 1, 1999 through
May 31, 2000 and a surcharge not to exceed $65.1 million for projected
under-recoveries for the period from June 2000 through August 2000. A
compliance filing detailing the actual under-recoveries for June 2000
through August 2000 was made in September 2000 and was approved by the
PUCT in November 2000. The actual under-recovery for the months of June,
July and August 2000 was $93.7 million. As a consequence of the
limitations in the Order, the remaining under-recovery amount of $28.6
million is being carried forward into subsequent fuel surcharge/refund
calculations.
In August 2000 WTU filed, with the PUCT, an application for
authority to implement an increase in fuel factors effective with the
October 2000 billing month. WTU also proposed to implement an interim
fuel surcharge to collect its under-recovered fuel costs, including
accumulated interest, over a 6-month period beginning in November 2000.
In October 2000, a settlement was reached between the various parties.
The settlement allows WTU to increase its fuel factors by $42.6 million
and provides for a surcharge of $19.6 million for previously
under-recovered fuel costs for the period from August 1, 1999 through
June 30, 2000. A final order from the Texas Commission to approve the
settlement is pending.
In November 2000 SWEPCo filed, with the PUCT, an application for
authority to implement an increase in fuel factor revenues of $11.9
million effective with the January 2001 billing month. SWEPCo also
proposed to implement a six-month interim fuel surcharge of $13.0
million for under-recoveries for the period from July 1999 through
September 2000 beginning with the January 2001 billing month.
Fuel Reconciliation Filing - SWEPCo
On June 30, 2000, SWEPCo filed with the PUCT an application to
reconcile fuel costs and to request authorization to carry the
unrecovered balance forward into the next reconciliation period. During
the reconciliation period of January 1, 1997 through December 31, 1999,
SWEPCo incurred $347 million of Texas jurisdiction eligible fuel and
fuel-related expenses, including $4 million of carrying costs on the
unamortized balance of a coal dispute settlement payment. Upon review
should the PUCT disallow fuel cost recoveries for the Texas
jurisdiction, it would result in a refund or credit surcharge which
would have an adverse effect on future results of operations and cash
flows. A final order is expected in the second quarter of 2001.
9. INDUSTRY RESTRUCTURING
Restructuring legislation has been enacted in seven of the eleven
state retail jurisdictions in which the AEP domestic electric utility
companies operate. The legislation provides for a transition from
cost-based regulation of bundled electric service to customer choice
market pricing for the supply of electricity. The enactment of
restructuring legislation and the ability to determine transition rates,
wires charges and any resultant extraordinary gain or loss under
restructuring legislation enabled AEP and certain subsidiaries to
discontinue regulatory accounting under the application of SFAS 71.
Prior to restructuring, the electric utility companies accounted for
their operations according to the cost-based regulatory accounting
principles of SFAS 71. Under the provisions of SFAS 71, regulatory
assets and regulatory liabilities are recorded to reflect the economic
effects of regulation and to match expenses with regulated revenues. The
discontinuance of the application of SFAS 71 is in accordance with the
provisions of SFAS 101. Pursuant to those provisions and further
guidance provided in EITF Issue 97-4, a company is required to write-off
regulatory assets and liabilities related to deregulated operations,
unless recovery of such amounts is provided through rates to be
collected in a portion of operations which continues to be rate
regulated. Additionally, a company experiencing a discontinuance of
cost-based rate regulation is required to determine if any plant assets
are impaired under SFAS 121. A SFAS 121 accounting impairment analysis
involves estimating cumulative future non-discounted net cash flows
arising from the use of assets. If the cumulative undiscounted net cash
flows exceed the net book value of the assets, then there is no
impairment of the assets for accounting purposes.
As legislative and regulatory proceedings evolve, the AEP electric
operating companies doing business in the seven states that have passed
restructuring legislation are applying the standards discussed above to
discontinue SFAS 71 regulatory accounting. The following is a summary of
restructuring legislation, the status of the transition plans and the
status of the electric utility companies' accounting to comply with the
changes in each of the AEP System's seven state regulatory jurisdictions
affected by restructuring legislation.
<PAGE>
Virginia Restructuring - Affecting AEP and APCo
Under 1999 Virginia restructuring legislation a transition to
choice of supplier for retail customers will commence on January 1, 2002
and be completed, subject to a finding by the Virginia SCC that an
effective competitive market exists by January 1, 2004 but not later
than January 1, 2005. The Virginia restructuring legislation provides an
opportunity for recovery of just and reasonable net stranded generation
costs. The mechanisms in the Virginia law for stranded cost recovery
are: a capping of incumbent utility transition rates until as late as
July 1, 2007, and the application of a wires charge upon customers who
may depart the incumbent utility in favor of an alternative supplier
prior to the termination of the rate cap. The legislation provides for
the establishment of capped rates prior to January 1, 2001 and
establishment of a wires charge by the fourth quarter of 2001. Since
APCo does not intend to request new rates, its current rates will become
the capped rates. In the third quarter of 2000, the Virginia SCC
directed APCo to file a cost of service study using 1999 as a test year.
In the opinion of counsel, Virginia's restructuring law does not permit
the Virginia SCC to change rates for the transition period.
WV Restructuring Plan - Affecting AEP and APCo
As discussed in the 1999 Annual Report, the WVPSC issued an order
on January 28, 2000 approving an electricity restructuring plan. On
March 11, 2000, the WV legislature approved the restructuring plan by
joint resolution. The joint resolution provides that the WVPSC cannot
implement the plan until the legislature makes necessary tax law changes
to preserve the revenues of the state and local governments. Electric
service in West Virginia is provided by APCo and WPCo.
The provisions of the restructuring plan provide for customer
choice to begin after all necessary rules are in place (the "starting
date"); deregulation of generation assets occurring on the starting
date; functional separation of the generation, transmission and
distribution businesses on the starting date and their legal corporate
or structural separation no later than January 1, 2005; a transition
period of up to 13 years, during which the incumbent utility must
provide default service for customers who do not change suppliers unless
an alternative default supplier is selected through a WVPSC-sponsored
bidding process; capped and fixed rates for the 13-year transition
period as discussed below; deregulation of metering and billing; a 0.5
mills per KWH wires charge applicable to all retail customers for the
period January 1, 2001 through December 31, 2010 intended to provide for
recovery of any stranded cost including net regulatory assets;
establishment of a rate stabilization deferred liability balance of $81
million ($76 million by APCo and $5 million by WPCo) by the end of year
ten of the transition period to be used as determined by the WVPSC to
offset market prices paid for electricity in the eleventh, twelfth, and
thirteenth year of the transition period by residential and small
commercial customers that do not choose an alternative supplier.
Default rates for residential and small commercial customers are
capped for four years after the starting date and then increase as
specified in the plan for the next six years. In years eleven, twelve
and thirteen of the transition period, the power supply rate shall equal
the market price of comparable power. Default rates for industrial and
large commercial customers will be discounted by 1% for four and a half
years, beginning July 1, 2000, and then increased at pre-defined levels
for the next three years. After seven years the power supply rate for
industrial and large commercial customers will be market based. APCo's
Joint Stipulation agreement, discussed in Note 8 above, which was
approved by the WVPSC on June 2, 2000 in connection with a base rate
filing, also provides additional mechanisms to recover regulatory
assets.
APCo Discontinues Application of SFAS 71
In June 2000 APCo discontinued the application of SFAS 71 for its
Virginia and WV retail jurisdictional portions of its generation
business since generation is no longer considered to be cost-based
regulated in those jurisdictions and management was able to determine
APCo's transition rates and wires charges. The discontinuance in the WV
jurisdiction was possible as a result of a June 2, 2000 approval of the
Joint Stipulation which established rates, wires charges and regulatory
asset recovery procedures during the transition period to market rates.
APCo was also able to discontinue application of SFAS 71 for the
generation portion of its Virginia retail jurisdiction after management
decided that APCo would not request capped rates different from its
current rates. The existence of effective restructuring legislation in
Virginia and the probability that the WV legislation would become
effective with the passage of required tax legislation in 2001 supported
management's decision to discontinue SFAS 71 regulatory accounting for
APCo's electricity generation and supply business.
APCo's discontinuance of SFAS 71 for generation resulted in an
extraordinary gain, in the second quarter of 2000, of $9 million.
Management believes that it is probable that all net regulatory assets
related to the Virginia and WV generation business will be recovered.
Therefore, under the provisions of EITF 97-4, APCo's generation-related
net regulatory assets were transferred to the distribution portion of
the business and are being amortized as they are recovered through
charges to regulated distribution customers. APCo performed an
accounting impairment analysis on its generating assets under SFAS 121
and concluded that there was no impairment of generation assets.
Ohio Restructuring Law - Affecting AEP, CSPCo and OPCo
As discussed in the 1999 Annual Report, the Ohio Act provides
for, among other things, customer choice of electricity supplier, a
residential rate reduction of 5% for the generation portion of rates and
a freezing of generation rates including fuel rates beginning on January
1, 2001. The Ohio Act also provides for a five-year transition period to
move from cost-based rates to market pricing for generation services. It
authorizes the PUCO to address certain major transition issues including
unbundling of rates and the recovery of transition costs which include
regulatory assets, generating asset impairments and other stranded
costs, employee severance and retraining costs, consumer education costs
and other restructuring and transition costs. Stranded costs are
generation costs that are not deemed to be recoverable in a competitive
market.
On September 28, 2000, the PUCO approved, with minor
modifications, a stipulation agreement between CSPCo, OPCo, the PUCO
staff, the Ohio Consumers' Counsel and other concerned parties. The key
provisions of the stipulation agreement are:
o Recovery of generation-related regulatory assets over seven years
for OPCo and eight years for CSPCo through frozen transition rates
for the first five years of the recovery period and a wires charge
for the remaining years.
o A shopping incentive (a price credit) of 2.5 mills per KWH for the
first 25% of CSPCo residential customers that switch suppliers.
There is no shopping incentive for OPCo customers.
o The absorption of $40 million by CSPCo and OPCo ($20 million per
company) of consumer education, implementation and transition plan
filing costs with deferral of the remaining costs, plus a carrying
charge, as a regulatory asset for recovery in future distribution
rates.
o CSPCo and OPCo will make available a fund of up to $10 million to
reimburse customers who choose to purchase their power from another
company for certain transmission charges imposed by PJM and/or a
Midwest ISO on generation originating in the Midwest ISO or PJM
areas.
o The statutory 5% reduction in the generation component of
residential tariffs will remain in effect for the entire 5 year
transition period.
o The companies' request for a $90 million gross receipts tax rider to
recover duplicate gross receipts tax would be considered separately
by the PUCO.
The gross receipts tax issue was considered by the PUCO in
hearings held in June 2000. In the September 28, 2000 order approving
the stipulation agreement, the PUCO determined that there was no
duplicate tax overlap period and denied the request for a gross receipts
tax rider. Under the Ohio Act the gross receipts tax will be replaced
with a KWH based excise tax. The last year for which electric utilities
will pay the excise tax based on gross receipts is the tax year ending
April 30, 2002. As of May 1, 2001 electric distribution companies will
be subject to an excise tax based on KWH sold to Ohio customers. The
gross receipts tax is paid at the beginning of the tax year, deferred by
CSPCo and OPCo as a prepaid expense and amortized to expense during the
tax year pursuant to the tax law whereby the payment of the tax results
in the privilege to conduct business in the year following the payment
of the tax. The change in the tax law to impose an excise tax based on
KWH sold to Ohio customers commencing before the expiration of the gross
receipts tax privilege period will result in a 12 month period when
CSPCo and OPCo are recording as an expense both the gross receipts tax
and the excise tax. CSPCo and OPCo filed for rehearing of the gross
receipts tax issue. Unless this issue is resolved in the companies'
favor, it will have an adverse effect on results of operations and
financial position from May 1, 2001 to April 30, 2002.
Beginning January 1, 2001, fuel costs will not be subject to PUCO
fuel recovery proceedings. Deferred fuel costs at December 31, 2000
which represent under or over recoveries will be one of the items
included in the PUCO's final determination of net regulatory assets to
be collected during the transition period. The elimination of fuel
clause recoveries in 2001 in Ohio will subject AEP, CSPCo and OPCo to
the risk of fuel market price increases and could adversely affect
future results of operations and cash flows beginning in 2001.
CSPCo and OPCo Discontinue the Application of SFAS 71
for the Ohio Jurisdiction
In September 2000 CSPCo and OPCo discontinued the application of
SFAS 71 for their Ohio retail jurisdictional generation business since
generation is no longer cost-based regulated in that jurisdiction and
management was able to determine their transition rates and wires
charges. The discontinuance in the Ohio jurisdiction was possible as a
result of the PUCO's September 28, 2000 approval of the stipulation
agreement which established rates, wires charges and net regulatory
asset recovery procedures during the transition to market rates.
CSPCo's and OPCo's discontinuance of SFAS 71 for generation
resulted in after tax extraordinary losses in the third quarter of 2000
of $25 million and $19 million, respectively, due to certain
unrecoverable generation-related regulatory assets and transition
expenses. Management believes that substantially all net regulatory
assets related to the Ohio generation business will be recovered. Under
the provisions of EITF 97-4, CSPCo's and OPCo's generation-related
recoverable net regulatory assets were transferred to the transmission
and distribution portion of the business and will be amortized as they
are recovered through charges to customers. CSPCo and OPCo performed an
accounting impairment analysis on their generating assets under SFAS 121
and concluded there was no impairment of generation assets.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry. Its major provisions are:
o retail competition begins January 1, 2002 but can be delayed until as late as
June 30, 2003 by the Arkansas Commission; o transmission facilities must be
operated by an ISO if owned by a company which also owns generation assets; o
rates will be frozen for one to three years; o market power issues will be
addressed by the Arkansas Commission; and o a progress report to the Arkansas
General Assembly on the development of competition in electric markets and its
impact
on retail customers is required by January 2001.
In an Arkansas Commission proceeding to investigate the
progress toward competition and what recommendations should be made to
the General Assembly, a delay of the start date for competition from
January 1, 2002 to October 1, 2003 or as late as October 1, 2005 was
discussed. Such delay would require amendments to the existing
legislation, which could be requested in the Arkansas Commission's
progress report to the General Assembly. The timing of the ultimate
deregulation of SWEPCo's generation business in Arkansas is unclear
pending the findings of the Arkansas Commission and the response to
those findings by the Arkansas General Assembly.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
In June 1999 the Texas Legislation was signed into law which, among
other things:
o gives Texas customers of investor-owned utilities the opportunity to
choose their electric provider beginning January 1,2002;
o provides for the recovery of regulatory assets and of other stranded
costs through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o provides for a rate freeze until January 1, 2002 followed by a 6%
rate reduction for residential and small commercial customers, an
additional rate reduction for low-income customers and a number of
customer protections;
o provides for an earnings test for each of the three years of the rate
freeze period (1999 through 2001);
o provides for certain limits for ownership and control of generation
capacity by companies;
o provides for elimination of the fuel clause reconciliation process;and
o provides for a 2004 true-up proceeding for stranded costs including
final fuel recovery balances, net regulatory assets,certain
environmental costs, accumulated excess earnings and other issues.
Delivery of electricity will continue to be the responsibility
of the local electric transmission and distribution utility company at
regulated prices. Each electric utility was required to submit a plan to
structurally unbundle its business activities into a retail electric
provider, a power generation company, a transmission utility and a
distribution utility. In May 2000 CPL, SWEPCo and WTU filed revised
structural separation plans which the PUCT approved on July 7, 2000 in
an interim order.
Under the Texas Legislation, electric utilities are allowed,
with the approval of the PUCT, to recover stranded costs including
generation-related regulatory assets that may not be recoverable in a
future competitive market. The approved costs can be refinanced through
securitization, which is a financing structure designed to provide state
sponsored lower financing costs than are available through conventional
public utility financings. The securitized amounts plus interest are
then recovered through a non-bypassable wires charge.
In 1999 CPL filed an application with the PUCT to securitize
approximately $1.27 billion of its retail generation-related regulatory
assets and approximately $47 million in other qualified restructuring
costs. On February 10, 2000, the PUCT tentatively approved a settlement,
which will permit CPL to securitize approximately $764 million of net
regulatory assets. The PUCT's order authorized issuance of up to $797
million of securitization bonds including the $764 million for recovery
of net regulatory assets and $33 million for other qualified refinancing
costs. The $764 million for recovery of net regulatory assets reflects
the recovery of $949 million of regulatory assets offset by $185 million
of customer benefits associated with accumulated deferred income taxes.
CPL had previously proposed in its filing to flow these benefits back to
customers over the 14-year term of the securitization bonds. The
remaining regulatory assets originally included by CPL in its 1999
securitization request were included in a March 2000 filing with the
PUCT, requesting recovery of an additional $1.1 billion of stranded
costs. The March 2000 filing of $1.1 billion included recovery of
approximately $800 million of STP costs included in utility plant on the
balance sheet of CPL and in property, plant and equipment-electric on
the balance sheet of AEP Consolidated. The STP costs had previously been
identified as ECOM by the PUCT for regulatory purposes. The March 2000
filing will determine the initial amount of stranded costs to be
recovered beginning January 1, 2002. The PUCT required CPL to submit a
revised filing using an administrative model developed by the PUCT Staff
which reduced the amount of the initial stranded costs estimates to $361
million. Management does not agree with the critical inputs to this
model. A final determination of stranded costs and their recovery will
occur as part of the 2004 true-up proceeding. The total amount
recoverable can be securitized.
On April 11, 2000, four parties appealed the PUCT's
securitization order to the Travis County District Court. One of these
appeals challenges CPL's ability to recover securitization charges under
the Texas Constitution. CPL will not be able to issue the securitization
bonds until these appeals are resolved.
The Texas Legislation provides that each year during the 1999
through 2001 rate freeze period, electric utilities are subject to an
earnings test. For electric utilities with stranded costs, such as CPL,
any earnings in excess of the most recently approved cost of capital in
its last rate case must be applied to reduce stranded costs. Utilities
without stranded costs, such as SWEPCo and WTU, must either flow such
excess earnings amounts back to customers or make capital expenditures
to improve transmission or distribution facilities or to improve air
quality. The Texas Legislation requires PUCT approval of the earnings
test calculation.
Regarding the 1999 earnings test, CPL, SWEPCo and WTU filed
reports showing excess earnings of $21 million, $1 million and zero,
respectively. The PUCT Staff issued its report on the excess earnings
calculations filed by CPL, SWEPCo and WTU and calculated the excess
earnings amounts to be $41 million, $3 million and $11 million for CPL,
SWEPCo and WTU, respectively. Management has recorded an estimated
provision for 1999 excess earnings and does not expect that the final
resolution of 1999 excess earnings will have a material effect on future
results of operations. CPL and WTU also recorded an estimated provision
for excess 2000 earnings of $9 million per company in the third quarter
of 2000.
A Texas settlement agreement in connection with the AEP and
CSW merger permits CPL to apply for regulatory purposes up to $20
million of STP ECOM plant assets a year in 2000 and 2001 to reduce
excess earnings, if any. For book purposes, STP ECOM plant assets will
be depreciated in accordance with GAAP, on a systematic and rational
basis unless impaired. To the extent excess earnings exceed $20 million
in 2000 or 2001 CPL will establish a regulatory liability or reduce
regulatory assets by a charge to earnings.
Beginning January 1, 2002, fuel costs will not be subject to
PUCT fuel reconciliation proceedings. Consequently, CPL, SWEPCo and WTU
will file a final fuel reconciliation with the PUCT which reconciles
their fuel costs through the period ending December 31, 2001. These
final fuel balances will be included in each company's 2004 true-up
proceeding. The elimination of the fuel clause recoveries in 2002 in
Texas will subject AEP, CPL, SWEPCo and WTU to the risk of fuel market
price increases and could adversely affect future results of operations
beginning in 2002.
Discontinuance of the Application of SFAS 71 for Arkansas and Texas
The financial statements of CPL, SWEPCo and WTU have
historically reflected the economic effects of regulation by applying
the requirements of SFAS 71. As a result of the scheduled deregulation
of generation in Arkansas and Texas, the application of SFAS 71 for the
generation portion of the business in those states was discontinued in
the third quarter of 1999. Under the provisions of EITF 97-4, CPL's
generation-related net regulatory assets were transferred to the
distribution portion of the business and will be amortized as they are
recovered through charges to customers. Management believes that
substantially all of CPL's generation-related regulatory assets should
be recovered under the Texas Legislation. CPL's recovery of
generation-related regulatory assets and stranded costs are subject to a
final determination by the PUCT in 2004. If future events were to make
the recovery of generation-related regulatory assets no longer probable,
CPL would write-off the portion of such regulatory assets deemed
unrecoverable as a non-cash extraordinary charge to earnings.
The Texas Legislation provides that all finally determined
stranded costs will be recovered. Since SWEPCo and WTU are not expected
to have net stranded costs, all generation-related net regulatory assets
were written off as non-recoverable in the third quarter of 1999 when
they discontinued application of SFAS 71 regulatory accounting. An
impairment analysis for generation assets under SFAS 121 was completed
for CPL, SWEPCo and WTU which concluded there was no accounting
impairment of generation assets when the application of SFAS 71 was
discontinued. CPL, SWEPCo and WTU will test their generation assets for
impairment under SFAS 121 when circumstances change. Management believes
that on a discounted basis CPL's cash flows will probably be less than
its generating assets' net book value and together with its
generation-related regulatory assets should create a recoverable
stranded cost for regulatory purposes under the Texas Legislation.
Therefore, management continues to carry on CPL's balance sheet at
September 30, 2000, $953 million of regulatory assets already approved
for securitization and $194 million of net regulatory assets pending
approval for securitization. A final determination of whether they will
be securitized will be made as part of the 2004 true-up proceeding.
CPL, SWEPCo, and WTU continue to analyze the impact of the electric
utility industry restructuring legislation on their Texas electric
operations. Although management believes that the Texas Legislation
provides for full recovery of stranded costs and that the companies do
not have a recordable accounting impairment, a final determination of
whether CPL will experience an accounting loss or whether SWEPCo and WTU
will experience any additional accounting loss from an inability to
recover generation-related regulatory assets and other restructuring
related costs in Texas and Arkansas cannot be made until such time as
the litigation and the regulatory process are complete following the
2004 true-up proceeding. In the event CPL, SWEPCo, and WTU are unable
after the 2004 true-up proceeding to recover all or a portion of their
generation-related regulatory assets, 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
On June 5, 2000, the Michigan Legislation became law. Its major
provisions, which were effective immediately, applied only to electric
utilities with one million or more retail customers. I&M has less than
one million customers in Michigan. Consequently, I&M was not immediately
required to comply with the Michigan Legislation.
The following is the stated purpose of the Michigan Legislation:
o Allow all retail customers a choice of electric suppliers;
o Encourage MPSC to foster competition;
o Provide protection to customers who remain with their incumbent
supplier;
o Diversify ownership of electric generation;
o Ensure the availability of safe, reliable electric power at
reasonable rates; and
o Improve economic development opportunities.
The Michigan Legislation gives the MPSC broad power to issue
orders to implement retail customer choice of electric supplier no later
than January 1, 2002 including recovery of regulatory assets and
stranded costs. On October 2, 2000, I&M filed a restructuring
implementation plan as required by a MPSC order. The plan identifies
I&M's proposal to file with the MPSC on June 5, 2001 its unbundled
rates, open access tariffs, terms of service and supporting schedules.
Described in the plan are I&M's intentions and preparation for
competition related to supplier transactions, customer transactions,
rate unbundling, education programs, and regional transmission
organization. I&M proposes a methodology to determine stranded and
implementation costs and requests the continuation of a wires charge for
nuclear decommissioning costs. Approval of the restructuring
implementation plan is pending before the MPSC.
Management has concluded that as of September 30, 2000 the
requirements to apply SFAS 71 continue to be met since I&M's rates for
generation in Michigan will continue to be cost-based regulated until
the MPSC approves rates and wires charges in 2001. The establishment of
rates and wires charges under a MPSC approved transition plan will
enable management to determine the ability to recover stranded costs
including regulatory assets and other implementation costs, a
requirement to discontinue the application of SFAS 71.
Upon the discontinuance of SFAS 71, I&M will, if necessary,
have to write off its Michigan jurisdictional generation-related
regulatory assets to the extent that they cannot be recovered under the
transition rates and wires charges and record any asset accounting
impairments in accordance with SFAS 121.
The amount of regulatory assets recorded on the books at
September 30, 2000 applicable to I&M's Michigan retail jurisdictional
generation business is approximately $45 million before related tax
effects. Based on management's current projections of rates, wires
charges and future market prices, management does not anticipate that
I&M will experience any material tangible asset accounting impairment or
regulatory asset write-offs. Ultimately, however, whether I&M will
experience material regulatory asset write-offs will depend on whether
the MPSC approves their recovery in future orders.
A determination of whether I&M will experience any asset
impair-ment loss regarding its Michigan retail jurisdictional generating
assets and any loss from a possible inability to recover Michigan
generation-related regulatory assets and other transition costs cannot
be made until such time as the rates and the wires charges are
determined through the regulatory process. In the event I&M is unable to
recover all or a portion of its generation-related regulatory assets,
stranded costs and other implementation costs, it could have a material
adverse effect on results of operations, cash flows and possibly
financial condition.
Oklahoma Restructuring - Affecting AEP and PSO
In 1997, the Oklahoma Legislature passed restructuring
legislation providing for retail access by July 1, 2002. That
legislation called for a number of studies to be completed on a variety
of restructuring issues, including independent system operator,
technical, financial, transition and consumer issues. During 1998 and
1999 several of the studies were completed.
The information from the studies was expected to be used in
the development of additional industry restructuring legislation during
the 2000 legislative session.
Several additional electric industry restructuring bills were
filed in the 2000 Oklahoma Legislative session. The proposed bills
generally supplemented the industry restructuring legislation
previously enacted in Oklahoma which lacked specific procedures for a
transition to market based competitive prices. The industry
restructuring legislation previously passed did not delegate the
establishment of transition procedures to the Oklahoma Corporation
Commission. The 2000 Oklahoma legislative session adjourned in May
without passing further restructuring legislation and will not
reconvene until 2001.
Management has concluded that as of September 30, 2000 the
requirements to apply SFAS 71 continue to be met since PSO's rates for
generation in Oklahoma will continue to be cost-based regulated until
the Oklahoma Legislature approves further restructuring legislation and
transition rates and wires charges are established under an approved
transition plan. Until management is able to determine the ability to
recover stranded costs which includes regulatory assets and other
implementation costs, PSO cannot discontinue application of SFAS 71
accounting under GAAP.
Upon the discontinuance of SFAS 71, PSO will, if necessary,
have to write off its Oklahoma jurisdictional generation-related
regulatory assets to the extent that they cannot be recovered under the
transition rates and wires charges, when determined, and record any
asset accounting impairments in accordance with SFAS 121.
A determination of whether PSO will experience any asset
impairment loss regarding its Oklahoma retail jurisdictional generating
assets and any loss from a possible inability to recover Oklahoma
generation-related regulatory assets and other transition costs cannot
be made until such time as the rates and the wires charges are
determined through the legislative or regulatory process. In the event
PSO is unable to recover all or a portion of its generation-related
regulatory assets and implementation costs, Oklahoma restructuring could
have a material adverse effect on results of operations and cash flows.
10. BUSINESS SEGMENTS
-----------------
AEP's principal business segment is its cost-based rate regulated
Domestic Electric Utility business consisting of eleven regulated
utility operating companies providing bundled, generation, distribution
and transmission electric services in eleven states. Also included in
this segment are AEP's electric power wholesale marketing and trading
activities conducted within two transmission systems of the AEP System
that are conducted as part of regulated operations and subject to cost
of service rate regulation.
The AEP consolidated income statement caption "Revenues-Domestic
Electric Utilities" includes both the retail and wholesale domestic
electricity supply businesses which are cost-based rate regulated in
Kentucky, Indiana, Michigan, Louisiana, Oklahoma and Tennessee and are
in the process of transitioning to market based pricing in Arkansas,
Ohio, Texas, WV and Virginia. Since the domestic electric utility
companies have not yet structurally separated their retail and wholesale
electricity supply business from their regulated distribution service
business, separate financial data is not available and the Domestic
Electric Utilities business will continue to be reported as one business
segment which is the only reportable segment for the domestic electric
operating subsidiaries.
The AEP consolidated income statement caption "Revenues-Worldwide
Electric and Gas Operations" includes three segments: Foreign Energy
Delivery, Worldwide Energy investments and other. The Foreign Energy
Delivery segment includes investments in overseas electric distribution
and supply companies (Seeboard and Yorkshire in the U.K. and CitiPower
in Australia). The Worldwide Energy Investments segment represents
domestic and international investments in energy-related gas and
electric projects including the development and management of those
projects. Such investment activities include electric generation, and
natural gas pipeline, storage and other natural gas services.
The other segment which is included in AEP consolidated income
statement as part of Worldwide Electric and Gas Operations includes
non-regulated electric trading activities outside of AEP marketing area
(beyond two transmission systems from the AEP System) gas trading
activities, telecommunication services, and the marketing of various
energy related products and services.
<TABLE>
<CAPTION>
Financial data for what has been AEP's four business segments for
the nine months ending September 30, 2000 and 1999 is shown in the
following table:
<S> <C> <C> <C> <C> <C> <C>
Domestic Foreign Worldwide
Electric Energy Energy Reconciling AEP
Utilities* Delivery Investments Other Adjustments Consolidated
September 30, 2000 (in millions)
Revenues from
external customers $ 8,124 $1,429 $ 620 $ (39) $ - $10,134
transactions with other
operating segments - 80 269 (349) -
Segment net income (loss) 430 114 (18) (37) - 489
Total assets 28,182 4,288 2,739 5,309 - 40,518
September 30, 1999
Revenues from
external customers 7,567 1,447 407 (8) - 9,413
transactions with other
operating segments - 45 146 (191) -
Segment net income (loss) 713 88 10 (32) - 779
Total assets 25,754 4,716 2,532 1,914 - 34,916
* Includes the domestic generation retail and wholesale supply
businesses a significant portion of which is undergoing a transition
from regulated cost based bundled rates to open access market pricing
but which have not yet been unbundled i.e., structurally separated from
the distribution and transmission portions of the vertically integrated
electric utility business.
</TABLE>
In October 2000, management announced its intent to structurally
separate its operations into two business segments, a non-regulated
business and a regulated business. Separation of its non-regulated
generation business from its regulated bundled generation distribution
and transmission businesses will not be complete until the electric
operating subsidiaries have completed their structural separation and
made the necessary changes to their accounting software, books and
records.
11. SOUTH AMERICAN INVESTMENTS
--------------------------
CSW International owns a 44% equity interest in Vale, a
Brazilian electric operating company which it had purchased for a total
of $149 million. The investment is covered by a put option, which, if
exercised, requires CSW International's partners in Vale to purchase CSW
International's Vale shares at a minimum price equal to the U.S. dollar
equivalent of CSW International's purchase price. As a result,
management has concluded that CSW International's investment carrying
amount will not be reduced below the put option value unless it is
deemed to be a permanent impairment and CSW International's partners in
Vale are deemed unable to fulfill their responsibilities under the put
option. Vale has experienced losses from operations and CSW
International's investment has been affected by the devaluation of the
Brazilian Real. CSW International's cumulative equity share of these
operating and foreign currency translation losses through September 30,
2000 are approximately $28 million, net of tax, and $32 million, net of
tax, respectively. Pursuant to the put option arrangement, these losses
are not reflected in the carrying value of the Vale investment.
Conversely, CSW International will not recognize any future earnings
from Vale until the operating losses are recovered.
As of September 30, 2000, CSW International had invested $110
million in the stock of a Chilean electric company. The investment is
classified as securities available for sale and as such changes in
market value that are deemed to be temporary and foreign exchange rate
changes are reflected in other comprehensive income. In the second
quarter of 2000 management determined that the decline in market value
of the shares was other than temporary. As a result a write down of $33
million ($21 million after tax) to market was recorded in June 2000 and
is included in worldwide electric and gas expenses. Based on the quarter
end foreign exchange rate, the value of the investment at September 30,
2000 was $53 million. The decline in foreign exchange rates has resulted
in a cumulative loss of $19 million ($12 million after tax) as of
September 30, 2000 which is included in other comprehensive income.
12. CONTINGENCIES
COLI Litigation - Affecting AEP, APCo, CSPCo, I&M, KPCo and OPCo
As discussed in the 1999 Annual Report, the deductibility of
certain interest deductions related to COLI for taxable years 1991
through 1996 is under review by the IRS. Adjustments have been or will
be proposed by the IRS disallowing COLI interest deductions. A
disallowance of the COLI interest deductions through September 30, 2000
would reduce AEP Consolidated earnings by approximately $319 million
(including interest). Potential earnings reductions for affected
registrant subsidiaries are as follows:
(in millions)
APCo $ 79
CSPCo 43
I&M 66
KPCo 8
OPCo 118
AEP and its subsidiaries made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991 through
1998 to avoid the potential assessment by the IRS of above market rate
interest on the contested amount. The payments to the IRS are included
on the AEP Consolidated balance sheet in other assets and on the
subsidiaries' balance sheets in other property and investments pending
the resolution of this matter. The companies are seeking refunds of all
amounts paid plus interest through litigation.
In order to resolve this issue, AEP and its subsidiaries filed
suit in 1998 against the United States in the U.S. District Court for
the Southern District of Ohio. The trial began on October 30, 2000. In
1999 a U.S. Tax Court judge decided in the Winn-Dixie Stores v.
Commissioner case that a corporate taxpayer's COLI interest deduction
should be disallowed. In October 2000, a judge for the U.S. District
Court for Delaware reached a similar decision in Internal Revenue
Service vs. C.M. Holdings, Inc. Notwithstanding the Tax Court's and U.S.
District Court's decisions, management has made no provision for any
possible adverse earnings impact from this matter because it believes,
and has been advised by outside counsel, that it has a meritorious
position and is vigorously pursuing its lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations, cash flows and possibly
financial condition.
Shareholders' Litigation - Affecting AEP
On June 23, 2000, a complaint was filed in the U.S. District
Court for the Eastern District of New York seeking unspecified
compensatory damages against AEP and four former or present officers.
The individual plaintiff also seeks certification as the representative
of a class consisting of all persons and entities who purchased or
otherwise acquired AEP common stock between July 25, 1997, and June 25,
1999. The complaint alleges that the defendants knowingly violated
federal securities laws by disseminating materially false and misleading
statements concerning, among other things, the undisclosed materially
impaired condition of the Cook Plant, AEP's inability to properly
monitor, manage, repair, supervise and report on operations at the Cook
Plant and the materially adverse conditions these problems were having,
and would continue to have, on AEP's deteriorating financial condition,
and ultimately on AEP's operations, liquidity and stock price. Four
other similar class action complaints have been filed and the court has
consolidated the five cases. The plaintiffs are required to file a
consolidated complaint pursuant to this court order. The defendants'
motion to transfer this case to the U.S. District Court for the Southern
District of Ohio was granted on November 3, 2000. Management believes
these shareholder actions are without merit and intends to oppose them
vigorously.
Municipal Franchise Fee Litigation - Affecting AEP and CPL
CPL has been involved in litigation regarding municipal franchise
fees in Texas as a result of a class action suit filed by the City of
San Juan, Texas in 1996. The City of San Juan claims CPL underpaid
municipal franchise fees and seeks damage of up to $300 million plus
attorney's fees. CPL filed a counterclaim for overpayment of franchise
fees.
During 1997, 1998 and 1999 the litigation moved procedurally
through the Texas Court System and was sent to mediation without
resolution.
In 1999 a class notice was mailed to each of the cities served by
CPL. Over 90 of the 128 cities declined to participate in the lawsuit.
However, CPL has pledged that if any final, non-appealable court
decision in the litigation awards a judgement against CPL for a
franchise underpayment, CPL will extend the principles of that decision,
with regard to the franchise underpayment, to the cities that declined
to participate in the litigation. In December 1999, the court ruled that
the class of plaintiffs would consist of approximately 30 cities. A
trial date for June 2001 has been set.
Although management believes that it has substantial defenses to
the cities' claims and intends to defend itself against the cities'
claims and pursue its counterclaims vigorously, management cannot
predict the outcome of this litigation or its impact on results of
operations, cash flows or financial condition.
Texas Base Rate Litigation - Affecting AEP and CPL
In November 1995 CPL filed with the PUCT a request to increase
its retail base rates by $71 million. In October 1997 the PUCT issued a
final order which lowered CPL's annual retail base rates by $19 million
from the rate level which existed prior to May 1996. The PUCT also
included a "glide path" rate methodology in the final order pursuant to
which annual rates were reduced by $13 million beginning May 1, 1998 and
an additional reduction of $13 million on May 1, 1999.
CPL appealed the final order to the Travis District Court. The
primary issues being appealed include: the classification of $800
million of invested capital in STP as ECOM and assigning it a lower
return on equity than other generation property; the use of the "glide
path" rate reduction methodology; and an $18 million disallowance of
billings from an affiliate, CSW Services. CPL has a 25.2% ownership
interest in STP. As part of the appeal, CPL sought a temporary
injunction to prohibit the PUCT from implementing the "glide path" rate
reduction methodology. The temporary injunction was denied and the
"glide path" rate reduction was implemented. In February 1999 the Travis
District Court affirmed the PUCT order in regard to the three major
items discussed above.
CPL appealed the Travis District Court's findings to the Texas
Appeals Court which in July 2000, issued its opinion upholding the
Travis District Court except for the disallowance of affiliated service
company billings. Under Texas law, specific findings regarding
affiliate transactions must be made by PUCT. In regards to the
affiliate expense issue, the findings were not complete in the opinion
of the Texas Appeals Court who remanded the issue back to PUCT.
CPL has sought a rehearing of the Texas Appeals Court's
opinion. The Texas Appeals Court has requested briefs related to CPL's
rehearing request from interested parties. Management is unable to
predict the final resolution of its appeal. If the appeal is
unsuccessful it will continue to adversely affect results of operations
and cash flows.
As part of the AEP/CSW merger approval process in Texas, a
stipulation agreement was approved which resulted in the withdrawal of
the appeal related to the "glide path" rate methodology. CPL will
continue its appeal of the ECOM classification for STP property and the
disallowed affiliated billings.
Lignite Mining Agreement Litigation - Affecting SWEPCo
SWEPCo and CLECO are each a 50% owner of Dolet Hills Power
Station Unit 1 and jointly own lignite reserves in the Dolet Hills area
of northwestern Louisiana. In 1982, SWEPCo and CLECO entered into a
lignite mining agreement with DHMV, a partnership for the mining and
delivery of lignite from a portion of these reserves.
In April 1997, SWEPCo and CLECO sued DHMV and its partners in
U.S. District Court for the Western District of Louisiana seeking to
enforce various obligations of DHMV under the lignite mining agreement,
including provisions relating to the quality of delivered lignite,
pricing, and mine reclamation practices. In June 1997, DHMV filed an
answer denying the allegations in the suit and filed a counterclaim
asserting various contract-related claims against SWEPCo and CLECO.
SWEPCo and CLECO have denied the allegations contained in the
counterclaims. In January 1999, SWEPCo and CLECO amended the claims
against DHMV to include a request that the lignite mining agreement be
terminated.
In April 2000, the parties agreed to settle the litigation. As
part of the settlement, DHMV's interest in the mining operations and
related debt and other obligations will be purchased by SWEPCo and
CLECO. The closing date for the settlement is December 31, 2000. The
litigation has been stayed until January 2001 to give the parties time
to consummate the settlement agreement.
Management believes that the resolution of this matter will not
have a material effect on results of operations, cash flows or
financial condition.
Federal EPA Complaint and Notice of Violation - Affecting AEP, APCo,
CSPCo, I&M, KPCo and OPCo
As discussed in the 1999 Annual Report, the AEP System has been
involved in litigation regarding generating plant emissions. Notices of
Violation were issued and a complaint was filed by Federal EPA in the
U.S. District Court that alleges the AEP System and eleven unaffiliated
utilities made modifications to generating units at certain of their
coal-fired generating plants over the course of the past 25 years that
extended unit operating lives or increased unit generating capacity
without a preconstruction permit in violation of the Clean Air Act. The
complaint was amended in March 2000 to add allegations for certain
generating units previously named in the complaint and to include
additional AEP System generating units previously named only in the
Notices of Violation in the complaint. 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.
A number of northeastern and eastern states were granted leave to
intervene in the Federal EPA's action against the AEP System under the
Clean Air Act. A lawsuit against power plants owned by the AEP System
alleging similar violations to those in the Federal EPA complaint and
Notices of Violation was filed by a number of special interest groups
and has been consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per
day per violation at each generating unit ($25,000 per day prior to
January 30, 1997). Civil penalties, if ultimately imposed by the court,
and the cost of any required new pollution control equipment, if the
court accepts Federal EPA's contentions, could be substantial.
On May 10, 2000, the AEP System filed motions to dismiss all or
portions of the complaints. Briefing on these motions was completed on
August 2, 2000. Management believes its maintenance, repair and
replacement activities were in conformity with the Clean Air Act and
intends to vigorously pursue its defense of this matter.
In the event the AEP System does not prevail, any capital and
operating costs of additional pollution control equipment that may be
required as well as any penalties imposed would adversely affect future
results of operations, cash flows and possibly financial condition
unless such costs can be recovered through regulated rates, and where
states are deregulating generation, unbundled transition period
generation rates, stranded cost wires charges and future market prices
for electricity.
NOx Reductions - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo, OPCo
and SWEPCo
As discussed in the 1999 Annual Report, Federal EPA issued a NOx
rule that requires substantial reductions in NOx emissions in 22 eastern
states, including certain states in which the AEP System's generating
plants are located. A number of utilities, including certain AEP System
companies, filed petitions seeking a review of the final rule in the
D.C. Circuit Court. In March 2000, the D.C. Circuit Court issued a
decision generally upholding the NOx rule. The D.C. Circuit Court issued
an order in August 2000 which extends the final compliance date to May
31, 2004. In September 2000 following denial by the D.C. Circuit Court
of a request for rehearing, the industry petitioners, including the AEP
System companies, petitioned the U.S. Supreme Court for review.
In a related matter, on April 19, 2000, TNRCC adopted rules
requiring significant reductions in NOx emissions from utility sources,
including CPL and SWEPCo. The rule's compliance date is May 2003 for CPL
and 2005 for SWEPCo. The rule is being challenged in state court by an
unaffiliated utility.
In June 2000 OPCo announced that it was beginning a $175 million
installation of selective catalytic reduction technology (expected to be
operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW
Gavin Plant.
Preliminary estimates indicate that compliance with the NOx rule
upheld by the D.C. Circuit Court as well as compliance with the TNRCC
rule could result in required capital expenditures of approximately $1.6
billion for AEP Consolidated. Estimated compliance costs by registrant
subsidiary company are as follows:
(in millions)
AEGCo $125
APCo 365
CPL 57
CSPCo 136
I&M 202
KPCo 106
OPCo 624
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the
actual cost to comply could be significantly different than the
preliminary estimates depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless any capital and
operating costs of additional pollution control equipment are recovered
from customers through regulated rates and/or future market prices for
electricity where generation is deregulated, they will have an adverse
effect on future results of operations, cash flows and possibly
financial condition.
Other
AEP, AEGCo, APCo, CSPCo, I&M, KPCo and OPCo continue to be
involved in certain other matters discussed in their 1999 Annual Report.
CPL, PSO, SWEPCo and WTU continue to be involved in certain other
matters discussed in their 1999 Form 10-K.
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION, CONTINGENCIES AND OTHER MATTERS
The following is a combined presentation of management's discussion and
analysis of financial condition, contingencies and other matters for AEP and
certain of its subsidiary registrants. Management's discussion and analysis of
results of operations for AEP and each of its subsidiary registrants for the
third quarter and nine months ended September 30 is presented with their
financial statements earlier in this document.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
year-to-date period were $1.3 billion for AEP Consolidated. The following table
shows the additions by certain AEP subsidiary registrants.
Company Amount
------- ------
(in millions)
APCo $144
CPL 137
I&M 149
OPCo 155
PSO 120
SWEPCo 92
WTU 44
During the first nine months of 2000 AEP Consolidated issued $951
million of long-term obligations at variable interest rates, retired $1.4
billion of long-term debt with interest rates ranging from 5.25% to 8.4% and
increased short-term debt by $1.4 billion from 1999 year-end balances. The
following table shows the debt issuances and retirements by certain AEP
subsidiary registrants:
Security Interest Due
Company Type Rate Date Amount
------- -------- -------- ---- ------
(%) (in millions)
Issuances:
APCo UN Variable 2001 $ 75
CPL UN Variable 2002 150
I&M UN Variable 2002 200
OPCo UN Variable 2001 75
SWEPCo UN Variable 2002 150
Retirements:
APCo IPC 7.40 2014 30
APCo FMB 6.35 2000 48
APCo FMB 6.71 2000 48
CPL FMB 7-1/2 2020 50
CPL FMB 6 2000 100
I&M FMB 6.40 2000 48
OPCo MTN 6.24 2008 13
PSO MTN 6.43 2000 10
SWEPCo FMB 5.25 2000 45
WTU FMB 7-1/2 2000 40
The AEP System companies have in the past, and may in the future,
acquire outstanding debt and preferred stock securities in open market
transactions.
During the second quarter the AEP System established a Money Pool to
coordinate short-term borrowings for certain of its subsidiaries, primarily the
U.S. domestic electric utility operating companies. The operation of the Money
Pool is designed to match on a daily basis the available cash and borrowing
requirements of the participants, thereby minimizing the need for borrowings
from external sources. The daily cash positions of the participants are netted
and if there is a deficiency in cash, AEP raises funds through external
borrowing to meet the Money Pool's needs. If there is a net excess in cash,
external borrowings are paid down, or, if there are no external borrowings
maturing, the excess funds are invested.
AEP Credit, Inc. factors electric customer accounts receivable for
affiliated operating companies and unaffiliated companies. AEP Credit, Inc.
issues commercial paper on a stand alone basis and does not participate in
the Money Pool. In June 2000 the factoring of customer accounts receivable
for affiliated companies was expanded as a result of the merger with CSW to
include I&M and OPCo. AEP Credit, Inc. was formerly known as CSW Credit.
The shutdown of the Cook Plant and the related costs to restart its
units contributed to the reduction in I&M's retained earnings to $76 million at
September 30, 2000. Unless approval is received from the SEC under the PUHCA and
the FERC under the Federal Power Act, I&M can only pay dividends out of retained
earnings on its outstanding common stock held by its parent, AEP, and on its
publicly held outstanding preferred stock. In the event I&M has insufficient
retained earnings to make preferred dividend payments, management intends to
seek SEC and FERC approval to make preferred dividend payments out of its $733
million of capital surplus. Failure to obtain such approvals would restrict for
some period of time the ability of I&M to make preferred and common dividend
payments. Mortgage indentures, charter provisions and orders of regulatory
authorities place various restrictions on the use of retained earnings for the
payment of cash dividends on I&M's common stock. As of September 30, 2000, $5.9
million of I&M's retained earnings were so restricted.
OTHER MATTERS
Cook Plant Shutdown - AEP, I&M
As discussed in the 1999 Annual Report, the Cook Plant was shut down in
September 1997 due to questions regarding the operability of certain safety
systems that arose during a NRC architect engineer design inspection.
On July 5, 2000, Cook Plant Unit 2, the first unit scheduled to restart,
reached 100% power completing its restart process. On July 26, 2000, I&M
announced that the restart of Cook Plant Unit 1 would cost an additional
$145 million and is
scheduled to occur in the first quarter of 2001. However, unforeseen issues or
difficulties encountered in preparing Unit 1 for restart could potentially delay
its return to service.
Expenditures to restart the Cook Plant units had been estimated to total
approximately $574 million. The additional $145 million to restart Unit 1 raises
the total estimate to $719 million. Through September 30, 2000, $592 million has
been spent to restart the units. For the nine months ended September 30, 2000,
restart costs of $249 million were recorded in other operation and maintenance
expense, including amortization of $30 million of restart costs previously
deferred in accordance with settlement agreements in the Indiana and Michigan
retail regulatory jurisdictions. Also pursuant to the settlement agreements,
accrued fuel-related revenues of $28 million were amortized in 2000. At
September 30, 2000, deferred restart costs of $130 million remained in
regulatory assets to be amortized through 2003. Also deferred as a regulatory
asset at September 30, 2000 are $122 million of fuel-related revenues to be
amortized through December 31, 2003 for both jurisdictions.
The cost of the extended outage and restart efforts will continue to
have a material adverse effect on future results of operations and on cash flows
until the second unit is restarted. The amortization of restart costs deferred
under Indiana and Michigan retail jurisdictional settlement agreements will
adversely affect results of operations through December 31, 2003 when the
amortization period ends. The annual amortization of restart cost deferrals is
$40 million. Management believes that the second Cook Plant unit, Unit 1, will
also be successfully returned to service. However, if for some unknown reason it
is not returned to service or its return is delayed significantly it would have
an even greater material adverse effect on future results of operations, cash
flows and financial condition.
Restructuring Legislation
Restructuring legislation has been enacted in seven of the eleven state
retail jurisdictions in which the AEP domestic electric utility companies
operate. The legislation provided for a transition from cost-based regulation of
bundled electric service to customer choice market pricing for the supply of
electricity. The enactment of restructuring legislation and the ability to
determine transition rates, wires charges and any resultant extraordinary gain
or loss under restructuring legislation enabled AEP and certain subsidiaries to
discontinue regulatory accounting under the application of SFAS 71. Prior to
restructuring, the electric utility companies accounted for their operations
according to the cost-based regulatory accounting principles of SFAS 71. Under
the provisions of SFAS 71, regulatory assets and regulatory liabilities are
recorded to reflect the economic effects of regulation and to match expenses
with regulated revenues. The discontinuance of the application of SFAS 71 is in
accordance with the provisions of SFAS 101. Pursuant to those provisions and
further guidance provided in EITF Issue 97-4, a company is required to write-off
regulatory assets and liabilities related to deregulated operations, unless
recovery of such amounts is provided through rates to be collected in a portion
of operations which continues to be rate regulated. Additionally, a company
experiencing a dis-continuance of cost-based rate regulation is required to
determine if any plant assets are impaired under SFAS 121. A SFAS 121 accounting
impairment analysis involves estimating cumulative future non-discounted net
cash flows arising from the use of assets. If the cumulative undiscounted net
cash flows exceed the net book value of the assets, then there is no impairment
of the assets for accounting purposes.
As legislative and regulatory proceedings evolve, the AEP electric
operating companies doing business in the seven states that have passed
restructuring legislation are applying the standards discussed above to
discontinue SFAS 71 regulatory accounting. The following is a summary of
restructuring legislation, the status of the transition plans and the status of
the electric utility companies' accounting to comply with the changes in each of
the AEP System's seven state regulatory jurisdictions affected by restructuring
legislation.
Virginia Restructuring - Affecting AEP and APCo
Under 1999 Virginia restructuring legislation a transition to choice of
supplier for retail customers will commence on January 1, 2002 and be completed,
subject to a finding by the Virginia SCC that an effective competitive market
exists by January 1, 2004 but not later than January 1, 2005. The Virginia
restructuring legislation provides an opportunity for recovery of just and
reasonable net stranded generation costs. The mechanisms in the Virginia law for
stranded cost recovery are: a capping of incumbent utility transition rates
until as late as July 1, 2007, and the application of a wires charge upon
customers who may depart the incumbent utility in favor of an alternative
supplier prior to the termination of the rate cap. The legislation provides for
the establish-ment of capped rates prior to January 1, 2001 and establishment of
a wires charge by the fourth quarter of 2001. Since APCo does not intend to
request new rates, its current rates will become the capped rates. In the third
quarter of 2000, the Virginia SCC directed APCo to file a cost of service study
using 1999 as a test year. In the opinion of counsel, Virginia's restructuring
law does not permit the Virginia SCC to change rates for the transition period.
WV Restructuring Plan - Affecting AEP and APCo
As discussed in the 1999 Annual Report, the WVPSC issued an order on
January 28, 2000 approving an electricity restructuring plan. On March 11, 2000,
the WV legislature approved the restructuring plan by joint resolution. The
joint resolution provides that the WVPSC cannot implement the plan until the
legislature makes necessary tax law changes to preserve the revenues of the
state and local governments. Electric service in West Virginia is provided by
APCo and WPCo.
The provisions of the restructuring plan provide for customer choice to
begin after all necessary rules are in place (the "starting date"); deregulation
of generation assets occurring on the starting date; functional separation of
the generation, transmission and distribution businesses on the starting date
and their legal corporate or structural separation no later than January 1,
2005; a transition period of up to 13 years, during which the incumbent utility
must provide default service for customers who do not change suppliers unless an
alternative default supplier is selected through a WVPSC-sponsored bidding
process; capped and fixed rates for the 13-year transition period as discussed
below; deregulation of metering and billing; a 0.5 mills per KWH wires charge
applicable to all retail customers for the period January 1, 2001 through
December 31, 2010 intended to provide for recovery of any stranded cost
including net regulatory assets; establishment of a rate stabilization deferral
balance of $81 million ($76 million by APCo and $5 million by WPCo) by the end
of year ten of the transition period to be used as determined by the WVPSC to
offset market prices paid for electricity in the eleventh, twelfth, and
thirteenth year of the transition period by residential and small commercial
customers that do not choose an alternative supplier.
Default rates for residential and small commercial customers are capped
for four years after the starting date and then increase as specified in the
plan for the next six years. In years eleven, twelve and thirteen of the
transition period, the power supply rate shall equal the market price of
comparable power. Default rates for industrial and large commercial customers
will be discounted by 1% for four and a half years, beginning July 1, 2000, and
then increased at pre-defined levels for the next three years. After seven years
the power supply rate for industrial and large commercial customers will be
market based. APCo's Joint Stipulation agreement, discussed in Note 8, which was
approved by the WVPSC on June 2, 2000 in connection with a base rate filing,
also provides additional mechanisms to recover regulatory assets.
<PAGE>
The elimination of ENEC recovery proceedings in WV will subject AEP and
APCo to the risk of fuel market price increases and reductions in wholesale
sales levels which could adversely affect results of operations and cash flows.
Management will work aggressively to mitigate this risk by seeking to hedge such
risk where appropriate and possible.
APCo Discontinues Application of SFAS 71
In June 2000 APCo discontinued the application of SFAS 71 for its
Virginia and WV retail jurisdictional portions of its generation business since
generation is no longer considered to be cost-based regulated in those
jurisdictions and management was able to determine APCo's transition rates and
wires charges. The discontinuance in the WV jurisdiction was possible as a
result of a June 2, 2000 approval of the Joint Stipulation which established
rates, wires charges and regulatory asset recovery procedures during the
transition period to market rates. APCo was also able to discontinue application
of SFAS 71 for the generation portion of its Virginia retail jurisdiction after
management decided that APCo would not request capped rates different from its
current rates. The existence of effective restructuring legislation in Virginia
and the probability that the WV legislation would become effective with the
passage of required tax legislation in 2001 supported management's decision to
discontinue SFAS 71 regulatory accounting for APCo's electricity generation and
supply business.
APCo's discontinuance of SFAS 71 for generation resulted in an
extraordinary gain, in the second quarter of 2000, of $9 million. Management
believes that it is probable that all net regulatory assets related to the
Virginia and WV generation business will be recovered. Therefore, under the
provisions of EITF 97-4, APCo's generation-related net regulatory assets were
transferred to the distribution portion of the business and are being amortized
as they are recovered through charges to regulated distribution customers. APCo
performed an accounting impairment analysis on its generating assets under SFAS
121 and concluded that there was no impairment of generation assets.
<PAGE>
Ohio Restructuring Law - Affecting AEP, CSPCo and OPCo
As discussed in the 1999 Annual Report, the Ohio Act provides for, among
other things, customer choice of electricity supplier, a residential rate
reduction of 5% for the generation portion of rates and a freezing of generation
rates including fuel rates beginning on January 1, 2001. The Ohio Act also
provides for a five-year transition period to move from cost-based rates to
market pricing for generation services. It authorizes the PUCO to address
certain major transition issues including unbundling of rates and the recovery
of transition costs which include regulatory assets, generating asset
impairments and other stranded costs, employee severance and retraining costs,
consumer education costs and other restructuring and transition costs. Stranded
costs are generation costs that are not deemed to be recoverable in a
competitive market.
On September 28, 2000, the PUCO approved, with minor modifications, a
stipulation agreement between CSPCo, OPCo, the PUCO staff, the Ohio Consumers'
Counsel and other concerned parties. The key provisions of the stipulation
agreement are:
o Recovery of generation-related regulatory assets over seven years
for OPCo and eight years for CSPCo through frozen transition rates
for the first five years of the recovery period and a wires charge
for the remaining years.
o A shopping incentive (a price credit) of 2.5 mills per KWH for the
first 25% of CSPCo residential customers that switch suppliers.
There is no shopping incentive for OPCo customers.
o The absorption of $40 million by CSPCo and OPCo ($20 million per
company) of consumer education, implementation and transition plan
filing costs with deferral of the remaining costs, plus a carrying
charge, as a regulatory asset for recovery in future distribution
rates.
o CSPCo and OPCo will make available a fund of up to $10 million to
reimburse customers who choose to purchase their power from another
company for certain transmission charges imposed by PJM and/or a
Midwest ISO on generation originating in the Midwest ISO or PJM
areas.
o The statutory 5% reduction in the generation component of
residential tariffs will remain in effect for the entire 5 year
transition period.
o The companies' request for a $90 million gross receipts tax rider to
recover duplicate gross receipts tax would be considered separately
by the PUCO.
The gross receipts tax issue was considered by the PUCO in hearings held
in June 2000. In the September 28, 2000 order approving the stipulation
agreement, the PUCO determined that there was no duplicate tax overlap period
and denied the request for a gross receipts tax rider. Under the Ohio Act the
gross receipts tax will be replaced with a KWH based excise tax. The last year
for which electric utilities will pay the excise tax based on gross receipts is
the tax year ending April 30, 2002. As of May 1, 2001 electric distribution
companies will be subject to an excise tax based on KWH sold to Ohio customers.
The gross receipts tax is paid at the beginning of the tax year, deferred by
CSPCo and OPCo as a prepaid expense and amortized to expense during the tax year
pursuant to the tax law whereby the payment of the tax results in the privilege
to conduct business in the year following the payment of the tax. The change in
the tax law to impose an excise tax based on KWH sold to Ohio customers
commencing before the expiration of the gross receipts tax privilege period will
result in a 12 month period when CSPCo and OPCo are recording as an expense both
the gross receipts tax and the excise tax. CSPCo and OPCo filed for rehearing of
the gross receipts tax issue. Unless this issue is resolved in the companies'
favor, it will have an adverse effect on results of operations and financial
position from May 1, 2001 to April 30, 2002.
Beginning January 1, 2001, fuel costs will not be subject to PUCO fuel
recovery proceedings. Deferred fuel costs at December 31, 2000 which represent
under or over recoveries will be one of the items included in the PUCO's final
determination of net regulatory assets to be collected during the transition
period. The elimination of fuel clause recoveries in 2001 in Ohio will subject
AEP, CSPCo and OPCo to the risk of fuel market price increases and could
adversely affect future results of operations and cash flows beginning in 2001.
Management will work aggressively to mitigate this risk by seeking to hedge such
risk where appropriate and possible.
CSPCo and OPCo Discontinue the Application of SFAS 71 for the Ohio Jurisdiction
In September 2000 CSPCo and OPCo discontinued the application of SFAS 71
for their Ohio retail jurisdictional generation business since generation is no
longer cost-based regulated in that jurisdiction and management was able to
determine their transition rates and wires charges. The discontinuance in the
Ohio jurisdiction was possible as a result of the PUCO's September 28, 2000
approval of the stipulation agreement which established rates, wires charges and
net regulatory asset recovery procedures during the transition to market rates.
CSPCo's and OPCo's discontinuance of SFAS 71 for generation resulted in
after tax extraordinary losses in the third quarter of 2000 of $25 million and
$19 million, respectively, due to certain unrecoverable generation related
regulatory assets and transition expenses. Management believes that
substantially all net regulatory assets related to the Ohio generation business
will be recovered. Under the provisions of EITF 97-4, CSPCo's and OPCo's
generation-related recoverable net regulatory assets were transferred to the
transmission and distribution portion of the business and will be amortized as
they are recovered through charges to customers. CSPCo and OPCo performed an
accounting impairment analysis on their generating assets under SFAS 121 and
concluded there was no impairment of generation assets.
Arkansas Restructuring - Affecting AEP and SWEPCo
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry. Its major provisions are:
o retail competition begins January 1, 2002 but can be delayed until as late as
June 30, 2003 by the Arkansas Commission; o transmission facilities must be
operated by an ISO if owned by a company which also owns generation assets; o
rates will be frozen for one to three years; o market power issues will be
addressed by the Arkansas Commission; and o a progress report to the Arkansas
General Assembly on the development of competition in electric markets and its
impact
on retail customers is required by January 2001.
In an Arkansas Commission proceeding to investigate the progress toward
competition and what recommendations should be made to the General Assembly, a
delay of the start date for competition from January 1, 2002 to October 1, 2003
or as late as October 1, 2005 was discussed. Such delay would require amendments
to the existing legislation, which could be requested in the Arkansas
Commission's progress report to the General Assembly. The timing of the ultimate
deregulation of SWEPCo's generation business in Arkansas is unclear pending the
findings of the Arkansas Commission and the response to those findings by the
Arkansas General Assembly.
Texas Restructuring - Affecting AEP, CPL, SWEPCo and WTU
In June 1999 the Texas Legislation was signed into law which, among
other things:
o gives Texas customers of investor-owned utilities the opportunity to
choose their electric provider beginning January 1, 2002;
o provides for the recovery of regulatory assets and of other stranded
costs through securitization and non-bypassable wires charges;
o requires reductions in NOx and sulfur dioxide emissions;
o provides for a rate freeze until January 1, 2002 followed by a 6%
rate reduction for residential and small commercial customers, an
additional rate reduction for low-income customers and a number of
customer protections;
o provides for an earnings test for each of the three years of the rate
freeze period (1999 through 2001);
o provides for certain limits for ownership and control of generation
capacity by companies;
o provides for elimination of the fuel clause reconciliation process; and
o provides for a 2004 true-up proceeding for stranded costs including
final fuel recovery balances, net regulatory assets, certain
environmental costs, accumulated excess earnings and other issues.
Delivery of electricity will continue to be the responsibility of the
local electric transmission and distribution utility company at regulated
prices. Each electric utility was required to submit a plan to structurally
unbundle its business activities into a retail electric provider, a power
generation company, a transmission utility and a distribution utility. In May
2000 CPL, SWEPCo and WTU filed revised structural separation plans which the
PUCT approved on July 7, 2000 in an interim order.
Under the Texas Legislation, electric utilities are allowed, with the
approval of the PUCT, to recover stranded costs including generation-related
regulatory assets that may not be recoverable in a future competitive market.
The approved costs can be refinanced through securitization, which is a
financing structure designed to provide state sponsored lower financing costs
than are available through conventional public utility financings. The
securitized amounts plus interest are then recovered through a non-bypassable
wires charge.
In 1999 CPL filed an application with the PUCT to securitize
approximately $1.27 billion of its retail generation-related regulatory assets
and approximately $47 million in other qualified restructuring costs. On
February 10, 2000, the PUCT tentatively approved a settlement, which will permit
CPL to securitize approximately $764 million of net regulatory assets. The
PUCT's order authorized issuance of up to $797 million of securitization bonds
including the $764 million for recovery of net regulatory assets and $33 million
for other qualified refinancing costs. The $764 million for recovery of net
regulatory assets reflects the recovery of $949 million of regulatory assets
offset by $185 million of customer benefits associated with accumulated deferred
income taxes. CPL had previously proposed in its filing to flow these benefits
back to customers over the 14-year term of the securitization bonds. The
remaining regulatory assets originally included by CPL in its 1999
securitization request were included in a March 2000 filing with the PUCT,
requesting recovery of an additional $1.1 billion of stranded costs. The March
2000 filing of $1.1 billion included recovery of approximately $800 million of
STP costs included in utility plant on the balance sheet of CPL and in property,
plant and equipment-electric on the balance sheet of AEP Consolidated. The STP
costs had previously been identified as ECOM by the PUCT for regulatory
purposes. The March 2000 filing will determine the initial amount of stranded
costs to be recovered beginning January 1, 2002. The PUCT required CPL to submit
a revised filing using an administrative model developed by the PUCT Staff which
reduced the amount of the initial stranded costs estimates to $361 million.
Management does not agree with the critical inputs to this model. A final
determination of stranded costs and their recovery will occur as part of the
2004 true-up proceeding. The total amount recoverable can be securitized.
On April 11, 2000, four parties appealed the PUCT's securitization
order to the Travis County District Court. One of these appeals challenges CPL's
ability to recover securitization charges under the Texas Constitution. CPL will
not be able to issue the securitization bonds until these appeals are resolved.
The Texas Legislation provides that each year during the 1999 through
2001 rate freeze period, electric utilities are subject to an earnings test. For
electric utilities with stranded costs, such as CPL, any earnings in excess of
the most recently approved cost of capital in its last rate case must be applied
to reduce stranded costs. Utilities without stranded costs, such as SWEPCo and
WTU, must either flow such excess earnings amounts back to customers or make
capital expenditures to improve transmission or distribution facilities or to
improve air quality. The Texas Legislation requires PUCT approval of the
earnings test calculation.
Regarding the 1999 earnings test, CPL, SWEPCo and WTU filed reports
showing excess earnings of $21 million, $1 million and zero, respectively. The
PUCT Staff issued its report on the excess earnings calculations filed by CPL,
SWEPCo and WTU and calculated the excess earnings amounts to be $41 million, $3
million and $11 million for CPL, SWEPCo and WTU, respectively. Management has
recorded an estimated provision for the 1999 excess earnings and does not expect
that the final resolution of 1999 excess earnings will have a material effect on
future results of operations. CPL and WTU also recorded an estimated provision
for excess 2000 earnings of $9 million per company in the third quarter of 2000.
A Texas settlement agreement in connection with the AEP and CSW merger
permits CPL to apply for regulatory purposes up to $20 million of STP ECOM plant
assets a year in 2000 and 2001 to reduce excess earnings, if any. For book
purposes, STP ECOM plant assets will be depreciated in accordance with GAAP, on
a systematic and rational basis unless impaired. To the extent excess earnings
exceed $20 million in 2000 or 2001 CPL will establish a regulatory liability or
reduce regulatory assets by a charge to earnings.
Beginning January 1, 2002, fuel costs will not be subject to PUCT fuel
reconciliation proceedings. Consequently, CPL, SWEPCo and WTU will file a final
fuel reconciliation with the PUCT which reconciles their fuel costs through the
period ending December 31, 2001. These final fuel balances will be included in
each company's 2004 true-up proceeding. The elimination of the fuel clause
recoveries in 2002 in Texas will subject AEP, CPL, SWEPCo and WTU to the risk of
fuel market price increases and could adversely affect future results of
operations beginning in 2002. Management will work to aggressively manage this
risk by seeking to hedge such risk where appropriate and possible.
Discontinuance of the Application of SFAS 71 for Arkansas and Texas
The financial statements of CPL, SWEPCo and WTU have historically
reflected the economic effects of regulation by applying the requirements of
SFAS 71. As a result of the scheduled deregulation of generation in Arkansas and
Texas, the application of SFAS 71 for the generation portion of the business in
those states was discontinued in the third quarter of 1999. Under the provisions
of EITF 97-4, CPL's generation-related net regulatory assets were transferred to
the distribution portion of the business and will be amortized as they are
recovered through charges to customers. Management believes that substantially
all of CPL's generation-related regulatory assets should be recovered under the
Texas Legislation. CPL's recovery of generation-related regulatory assets and
stranded costs are subject to a final determination by the PUCT in 2004. If
future events were to make the recovery of generation-related regulatory assets
no longer probable, CPL would write-off the portion of such regulatory assets
deemed unrecoverable as a non-cash extraordinary charge to earnings.
The Texas Legislation provides that all finally determined stranded
costs will be recovered. Since SWEPCo and WTU are not expected to have net
stranded costs, all generation-related net regulatory assets were written off as
non-recoverable in the third quarter of 1999 when they discontinued application
of SFAS 71 regulatory accounting. An impairment analysis for generation assets
under SFAS 121 was completed for CPL, SWEPCo and WTU which concluded there was
no accounting impairment of generation assets when the application of SFAS 71
was discontinued. CPL, SWEPCo and WTU will test their generation assets for
impairment under SFAS 121 when circumstances change. Management believes that on
a discounted basis CPL's cash flows will probably be less than its generating
assets' net book value and together with its generation-related regulatory
assets should create a recoverable stranded cost for regulatory purposes under
the Texas Legislation. Therefore, management continues to carry on CPL's balance
sheet at September 30, 2000, $953 million of regulatory assets already approved
for securitization and $194 million of net regulatory assets pending approval
for securitization. A final determination of whether they will be securitized
will be made as part of the 2004 true-up proceeding.
CPL, SWEPCo, and WTU continue to analyze the impact of the electric
utility industry restructuring legislation on their Texas electric operations.
Although management believes that the Texas Legislation provides for full
recovery of stranded costs and that the companies do not have a recordable
accounting impairment, a final determination of whether CPL, SWEPCo, and WTU
will experience any accounting loss from an inability to recover
generation-related regulatory assets and other restructuring related costs in
Texas and Arkansas cannot be made until such time as the litigation and the
regulatory process are complete following the 2004 true-up proceeding. In the
event CPL, SWEPCo, and WTU are unable after the 2004 true-up proceeding to
recover all or a portion of their generation-related regulatory assets, 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
On June 5, 2000, the Michigan Legislation became law. Its major
provisions, which were effective immediately, applied only to electric utilities
with one million or more retail customers. I&M has less than one million
customers in Michigan. Consequently, I&M was not immediately required to comply
with the Michigan Legislation.
The following is the stated purpose of the Michigan Legislation: o Allow
all retail customers a choice of electric suppliers; o Encourage MPSC to foster
competition; o Provide protection to customers who remain with their incumbent
supplier;
o Diversify ownership of electric generation;
o Ensure the availability of safe, reliable electric power at
reasonable rates; and
o Improve economic development opportunities.
The Michigan Legislation gives the MPSC broad power to issue orders to
implement retail customer choice of electric supplier no later than January 1,
2002 including recovery of regulatory assets and stranded costs. On October 2,
2000, I&M filed a restructuring implementation plan as required by a MPSC order.
The plan identifies I&M's proposal to file with the MPSC on June 5, 2001 its
unbundled rates, open access tariffs, terms of service and supporting schedules.
Described in the plan are I&M's intentions and preparation for competition
related to supplier transactions, customer transactions, rate unbundling,
education programs, and regional transmission organization. I&M proposes a
methodology to determine stranded and implementation costs and requests the
continuation of a wires charge for nuclear decommissioning costs. Approval of
the restructuring implementation plan is pending before the MPSC.
Management has concluded that as of September 30, 2000 the requirements
to apply SFAS 71 continue to be met since I&M's rates for generation in Michigan
will continue to be cost-based regulated until the MPSC approves rates and wires
charges in 2001. The establishment of rates and wires charges under a MPSC
approved transition plan will enable management to determine the ability to
recover stranded costs including regulatory assets and other implementation
costs, a requirement to discontinue the application of SFAS 71.
Upon the discontinuance of SFAS 71, I&M will, if necessary, have to
write off its Michigan jurisdictional generation-related regulatory assets to
the extent that they cannot be recovered under the transition rates and wires
charges and record any asset accounting impairments in accordance with SFAS 121.
The amount of regulatory assets recorded on the books at September 30,
2000 applicable to the I&M's Michigan retail jurisdictional generation business
is approximately $45 million before related tax effects. Based on management's
current projections of rates, wires charges and future market prices, management
does not anticipate that I&M will experience any material tangible asset
accounting impairment or regulatory asset write-offs. Ultimately, however,
whether I&M will experience material regulatory asset write-offs will depend on
whether the MPSC approves their recovery in future orders.
A determination of whether I&M will experience any asset impairment
loss regarding its Michigan retail jurisdictional generating assets and any loss
from a possible inability to recover Michigan generation-related regulatory
assets and other transition costs cannot be made until such time as the rates
and the wires charges are determined through the regulatory process. In the
event I&M is unable to recover all or a portion of its generation-related
regulatory assets, stranded costs and other implementation costs, it could have
a material adverse effect on results of operations, cash flows and possibly
financial condition.
<PAGE>
Oklahoma Restructuring - Affecting AEP and PSO
In 1997, the Oklahoma Legislature passed restructuring legislation
providing for retail access by July 1, 2002. That legislation called for a
number of studies to be completed on a variety of restructuring issues,
including independent system operator, technical, financial, transition and
consumer issues. During 1998 and 1999 several of the studies were completed.
The information from the studies was expected to be used in the
development of additional industry restructuring legislation during the 2000
legislative session.
Several additional electric industry restructuring bills were filed in
the 2000 Oklahoma Legislative session. The proposed bills generally supplemented
the industry restructuring legislation previously enacted in Oklahoma which
lacked specific procedures for a transition to market based competitive prices.
The industry restructuring legislation previously passed did not delegate the
establishment of transition procedures to the Oklahoma Corporation Commission.
The 2000 Oklahoma legislative session adjourned in May without passing further
restructuring legislation and will not reconvene until 2001.
Management has concluded that as of September 30, 2000 the requirements
to apply SFAS 71 continue to be met since PSO's rates for generation in Oklahoma
will continue to be cost-based regulated until the Oklahoma Legislature approves
further restructuring legislation and transition rates and wires charges are
established under an approved transition plan. Until management is able to
determine the ability to recover stranded costs which includes regulatory assets
and other implementation costs, PSO cannot discontinue application of SFAS 71
accounting under GAAP.
Upon the discontinuance of SFAS 71, PSO will, if necessary, have to
write off its Oklahoma jurisdictional generation-related regulatory assets to
the extent that they cannot be recovered under the transition rates and wires
charges, when determined, and record any asset accounting impairments in
accordance with SFAS 121.
A determination of whether PSO will experience any asset impairment
loss regarding its Oklahoma retail jurisdictional generating assets and any loss
from a possible inability to recover Oklahoma generation-related regulatory
assets and other transition costs cannot be made until such time as the rates
and the wires charges are determined through the legislative or regulatory
process. In the event PSO is unable to recover all or a portion of its
generation-related regulatory assets and implementation costs, Oklahoma
restructuring could have a material adverse effect on results of operations and
cash flows.
COLI Litigation - Affecting AEP, APCo, I&M and OPCo
As discussed in the 1999 Annual Report, the deductibility of certain
interest deductions related to COLI for taxable years 1991 through 1996 is under
review by the IRS. Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions. A disallowance of the COLI interest
deductions through September 30, 2000 would reduce AEP Consolidated earnings by
approximately $319 million (including interest). Potential earnings reductions
for certain affected registrant subsidiaries are as follows:
Company Amount
------- ------
(in millions)
APCo $ 79
I&M 66
OPCo 118
AEP and its subsidiaries made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991 through 1998 to
avoid the potential assessment by the IRS of above market rate interest on the
contested amount. The payments to the IRS are included on the AEP Consolidated
balance sheet in other assets and on the subsidiaries' balance sheets in other
property and investments pending the resolution of this matter. The companies
are seeking refunds of all amounts paid plus interest through litigation.
In order to resolve this issue, AEP and its subsidiaries filed suit in
1998 against the United States in the U.S. District Court for the Southern
District of Ohio. The trail began on October 30, 2000. In 1999 a U.S. Tax Court
judge decided in the Winn-Dixie Stores v. Commissioner case that a corporate
taxpayer's COLI interest deduction should be disallowed. In October 2000, a
judge for the U.S. District Court for Delaware reached a similar decision in
Internal Revenue Service vs. C.M. Holdings, Inc. Notwithstanding the Tax Court's
and U.S. District Court's decisions, management has made no provision for any
possible adverse earnings impact from this matter because it believes, and has
been advised by outside counsel, that it has a meritorious position and is
vigorously pursuing its lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of operations,
cash flows and possibly financial condition.
Shareholders' Litigation - Affecting AEP
On June 23, 2000, a complaint was filed in the U.S. District Court for
the Eastern District of New York seeking unspecified compensatory damages
against AEP and four former or present officers. The individual plaintiff also
seeks certification as the representative of a class consisting of all persons
and entities who purchased or otherwise acquired AEP common stock between July
25, 1997, and June 25, 1999. The complaint alleges that the defendants knowingly
violated federal securities laws by disseminating materially false and
misleading statements concerning, among other things, the undisclosed materially
impaired condition of the Cook Plant, AEP's inability to properly monitor,
manage, repair, supervise and report on operations at the Cook Plant and the
materially adverse conditions these problems were having, and would continue to
have, on AEP's deteriorating financial condition, and ultimately on AEP's
operations, liquidity and stock price. Four other similar class action
complaints have been filed and the court has consolidated the five cases. The
plaintiffs are required to file a consolidated complaint pursuant to this court
order. The defendants' motion to transfer this case to the U.S. District Court
for the Southern District of Ohio was granted on November 3, 2000. Management
believes these shareholder actions are without merit and intends to oppose them
vigorously.
<PAGE>
Municipal Franchise Fee Litigation - Affecting AEP and CPL
CPL has been involved in litigation regarding municipal franchise fees
in Texas as a result of a class action suit filed by the City of San Juan, Texas
in 1996. The City of San Juan claims CPL underpaid municipal franchise fees and
seeks damage of up to $300 million plus attorney's fees. CPL filed a
counterclaim for overpayment of franchise fees.
During 1997, 1998 and 1999 the litigation moved procedurally through the
Texas Court System and was sent to mediation without resolution.
In 1999 a class notice was mailed to each of the cities served by CPL.
Over 90 of the 128 cities declined to participate in the lawsuit. However, CPL
has pledged that if any final, non-appealable court decision in the litigation
awards a judgement against CPL for a franchise underpayment, CPL will extend the
principles of that decision, with regard to the franchise underpayment, to the
cities that declined to participate in the litigation. In December 1999, the
court ruled that the class of plaintiffs would consist of approximately 30
cities. A trial date for June 2001 has been set.
Although management believes that it has substantial defenses to the
cities' claims and intends to defend itself against the cities' claims and
pursue its counterclaims vigorously, management cannot predict the outcome of
this litigation or its impact on results of operations, cash flows or financial
condition.
Federal EPA Complaint and Notice of Violation -
Affecting AEP, APCo, I&M, and OPCo
As discussed in the 1999 Annual Report, the AEP System has been involved
in litigation regarding generating plant emissions. Notices of Violation were
issued and a complaint was filed by Federal EPA in the U.S. District Court that
alleges the AEP System and eleven unaffiliated utilities made modifications to
generating units at certain of their coal-fired generating plants over the
course of the past 25 years that extended unit operating lives or increased unit
generating capacity without a preconstruction permit in violation of the Clean
Air Act. The complaint was amended in March 2000 to add allegations for certain
generating units previously named in the complaint and to include additional AEP
System generating units previously named only in the Notices of Violation in the
complaint. 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.
A number of northeastern and eastern states were granted leave to
intervene in the Federal EPA's action against the AEP System under the Clean Air
Act. A lawsuit against power plants owned by the AEP System alleging similar
violations to those in the Federal EPA complaint and Notices of Violation was
filed by a number of special interest groups and has been consolidated with the
Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per day
per violation at each generating unit ($25,000 per day prior to January 30,
1997). Civil penalties, if ultimately imposed by the court, and the cost of any
required new pollution control equipment, if the court accepts Federal EPA's
contentions, could be substantial.
On May 10, 2000, the AEP System filed motions to dismiss all or portions
of the complaints. Briefing on these motions was completed on August 2, 2000.
Management believes its maintenance, repair and replacement activities were in
conformity with the Clean Air Act and intends to vigorously pursue its defense
of this matter.
In the event the AEP System does not prevail, any capital and operating
costs of additional pollution control equipment that may be required as well as
any penalties imposed would adversely affect future results of operations, cash
flows and possibly financial condition unless such costs can be recovered
through regulated rates, and where states are deregulating generation, unbundled
transition period generation rates, stranded cost wires charges and future
market prices for electricity.
NOx Reductions - Affecting AEP, APCo, CPL, I&M, OPCo and SWEPCo
As discussed in the 1999 Annual Report, Federal EPA issued a NOx rule
that requires substantial reductions in NOx emissions in 22 eastern states,
including certain states in which the AEP System's generating plants are
located. A number of utilities, including certain AEP System companies, filed
petitions seeking a review of the final rule in the D.C. Circuit Court. In March
2000, the D.C. Circuit Court issued a decision generally upholding the NOx rule.
The D.C. Circuit Court issued an order in August 2000 which extends the final
compliance date to May 31, 2004. In September 2000 following denial by the D.C.
Circuit Court of a request for rehearing, the industry petitioners, including
the AEP System companies, petitioned the U.S. Supreme Court for review.
In a related matter, on April 19, 2000, TNRCC adopted rules requiring
significant reductions in NOx emissions from utility sources, including CPL and
SWEPCo. The rule's compliance date is May 2003 for CPL and 2005 for SWEPCo. The
rule is being challenged in state court by an unaffiliated utility.
In June 2000 OPCo announced that it was beginning a $175 million
installation of selective catalytic reduction technology (expected to be
operational in 2001) to reduce NOx emissions on its two-unit 2,600 MW Gavin
Plant.
Preliminary estimates indicate that compliance with the NOx rule upheld
by the D.C. Circuit Court as well as compliance with the TNRCC rule could result
in required capital expenditures of approximately $1.6 billion for AEP
Consolidated.
The following table shows the estimated compliance cost for certain of
AEP's subsidiary registrants.
Company Amount
------- ------
(in millions)
APCo $365
CPL 57
I&M 202
OPCo 624
SWEPCo 28
Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the preliminary estimate
depending upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless the depreciation of such costs are recovered from customers
through regulated rates and/or future market prices for electricity where
generation is deregulated, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
New Accounting Standards - Affecting AEP, AEGCo, APCo, CPL, CSPCo, I&M, KPCo,
OPCo, PSO, SWEPCo and WTU
SFAS 133, Accounting for Derivative Instruments and Hedging Activities,
as amended by SFAS 137 and SFAS 138, will be effective for the AEP System
beginning January 1, 2001. SFAS 133 requires that entities recognize all
derivatives as either assets or liabilities and measure them at fair value.
Changes in the fair value of derivative assets and liabilities must be
recognized currently in net income or other comprehensive income except for
certain hedges that are deemed to be effective. Derivatives that are highly
effective in hedging underlying transactions can lessen the impact on net
income.
It appears at this time that the adoption of SFAS 133, as amended, for
AEP's non-commodity derivatives is expected to result in an immaterial effect on
net income and on other comprehensive income based on the fair values of
existing non-commodity derivatives at September 30, 2000. However, the actual
effect on future net income and other comprehensive income of SFAS 133 will
depend upon the number and amount of derivatives that will exist at future
balances sheet dates and the market values of those derivative at those dates.
AEP's energy commodity trading contracts are generally currently
marked-to-market under the Financial Accounting Standards Board's EITF 98-10
with changes reflected in net income and on the balance sheet. There-fore,
implementation of SFAS 133 is not expected to significantly affect the
accounting for energy commodity trading contracts. However, currently, there are
outstanding issues under consideration by the Financial Accounting Standards
Board's Derivative Implementation Group that may affect the accounting treatment
of certain energy contracts which could result in certain contracts being
marked-to-market that are not presently being marked-to-market. As a result we
cannot determine the effect of implementation that SFAS 133 will have on the AEP
System's energy contracts.
The SEC has issued Staff Accounting Bulletin 101 "Revenue Recognition"
which provided guidance on the timing and methods of recognizing revenues that
SEC registrants must adopt in the fourth quarter of 2000. The adoption of this
Staff Accounting Bulletin is not expected to have a material effect on the
financial statements of the AEP System companies since the AEP System already
follows the principles outlined in this Staff Accounting Bulletin.
<PAGE>
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Market Risks
AEP and its subsidiaries have certain market risks inherent in their
business activities from changes in fuel and energy commodity prices, foreign
currency exchange rates and interest rates. Market risk represents the risk of
loss that may impact operations due to adverse changes in commodity market
prices, foreign currency exchange rates and interest rates.
Commodity Price Risk - Affecting AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO,
SWEPCo and WTU
The average exposure to market risk for AEP consolidated from the
trading of electricity and natural gas and related financial derivative
instruments was less than $20 million at September 30, 2000 and $14 million at
December 31, 1999 based on the use of a risk measurement model which calculates
VaR. The VaR is based on the variance-covariance method using historical prices
to estimate volatilities and correlations and assuming a 95% confidence level
and a three-day holding period. Based on the VaR model, the exposure to market
risk from the trading of electricity and related financial derivative
instruments of the AEP subsidiary registrants was as follows:
September 30, December 31,
Company 2000 1999
------- ------------ --------------
(in millions)
APCo $3 $4
CPL 1 -
CSPCo 2 3
I&M 2 3
KPCo 1 1
OPCo 3 4
PSO 3 -
SWEPCo 2 -
WTU 1 -
CPL, PSO, SWEPCo and WTU did not engage in trading activities prior to
the merger. Therefore, the market risk from trading activities was zero at
December 31, 1999 for CPL, PSO, SWEPCo and WTU.
<PAGE>
Foreign Currency Exchange Rates - Affecting AEP
AEP is exposed to foreign currency exchange rate risk from investments
in foreign ventures. Cross currency swaps are being used to manage adverse
changes in the floating exchange rate between the U.S. dollar and British pounds
for AEP's subsidiary Seeboard. At September 30, 2000, there were two cross
currency swap contracts. The table presented below represents third party
valuations of their fair value:
Contract Maturity Date Maturity Value Market Value
-------- ------------- -------------- ------------
(in millions)
Cross currency swaps 8/1/01 $200 $ 7.0
Cross currency swaps 8/1/06 200 $(7.5)
Based on these valuations, AEP's position in these swaps represented an
unrealized loss of $1 million at September 30, 2000. This unrealized loss is
offset by unrealized gains related to the underlying liability being hedged,
which are included in long-term debt on AEP's consolidated balance sheet at a
carrying value of approximately $400 million. Management expects to hold these
contracts to maturity.
Interest Rates - Affecting AEP, APCo, CPL, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo
and WTU
The exposure to changes in interest rates from short-term and long-term
borrowings at September 30, 2000 is not materially different than at December
31, 1999.
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.
American Electric Power Company, Inc. ("AEP") and Ohio Power Company ("OPCo")
On August 31, 2000, the U.S. Environmental Protection Agency ("Federal
EPA") Region 5, issued a Notice of Violation ("NOV") to OPCo's Gavin Plant in
connection with stack limit emissions. Among other alleged violations, the NOV
alleges violation of the Federal EPA-approved Ohio air pollution nuisance rule.
AEP has submitted a request for a conference to discuss the NOV with Region 5
officials.
Item 4. Submission of Matters to a Vote of Security Holders.
---------------------------------------------------
Central Power and Light Company ("CPL")
The annual meeting of shareholders was held on July 17, 2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 6,755,535 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 Joseph H. Vipperman
Armando A. Pena
No other business was transacted at the meeting.
Public Service Company of Oklahoma ("PSO")
The annual meeting of shareholders was held on July 17, 2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 9,013,000 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 Joseph H. Vipperman
Armando A. Pena
No other business was transacted at the meeting.
Southwestern Electric Power Company ("SWEPCo")
The annual meeting of shareholders was held on July 17, 2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 7,536,640 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 Joseph H. Vipperman
Armando A. Pena
No other business was transacted at the meeting.
West Texas Utilities Company ("WTU")
The annual meeting of shareholders was held on July 17, 2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 5,488,560 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 Joseph H. Vipperman
Armando A. Pena
No other business was transacted at the meeting.
Item 5. Other Information.
AEP and Appalachian Power Company ("APCo")
Reference is made to pages 18 and 19 of the Annual Report on Form 10-K
for the year ended December 31, 1999 ("1999 10-K") for a discussion of APCo's
proposed transmission facilities. On October 2, 2000, the Hearing Examiner
issued his report to the Virginia State Corporation Commission recommending
approval of a 90-mile 765,000-volt line to connect the Wyoming and Jacksons
Ferry substations. On October 27, 2000, APCo filed with the Public Service
Commission of West Virginia a request to amend its May 1998 order to accommodate
this potential change in the Virginia portion of the project.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
APCo, CPL, Columbus Southern Power Company ("CSPCo"),
Indiana Michigan Power Company ("I&M"), Kentucky Power Company
("KEPCo"), OPCo, PSO, SWEPCo and WTU
Exhibit 12 - Computation of Consolidated Ratio of Earnings to Fixed Charges.
AEP, AEP Generating Company, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO,
SWEPCo and WTU
Exhibit 27 - Financial Data Schedule.
(b) Reports on Form 8-K or 8-K/A:
Companies Reporting Date of Report Items Reported
CPL, PSO, SWEPCo and WTU July 5, 2000 Item 4. Changes in Registrant's
Certifying Accountant
Item 7. Financial Statements and
Exhibits
AEP June 15, 2000 Item 7. Financial Statements and
Exhibits
AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo
No reports on Form 8-K were filed during the quarter ended September 30,
2000.
<PAGE>
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/:Leonard V. Assante
Armando A. Pena Leonard V. Assante
Treasurer Deputy Controller
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/:Leonard V. Assante
Armando A. Pena Leonard V. Assante
Vice President and Deputy Controller
Treasurer
Date: November 10, 2000
