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 JUNE 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
1-1443 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 April 30, 2000 was 194,103,349.
<PAGE>
<TABLE>
<CAPTION>
Page
Part I. FINANCIAL INFORMATION
<S> <C>
American Electric Power Company, Inc. and Subsidiary Companies:
Consolidated Statements of Income. . . . . . . . . . . . . . A-1
Consolidated Statements of Comprehensive Income . .. . . . . A-2
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-3 - A-4
Consolidated Statements of Cash Flows. . . . . . . . . . . . A-5
Consolidated Statements of Retained Earnings . . . . . . . . A-6
Notes to Consolidated Financial Statements . . . . . . . . . A-7 - A-26
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . A-27- A-45
AEP Generating Company:
Statements of Income and Statements of Retained Earnings . . B-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . B-2 - B-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . B-4
Notes to Financial Statements. . . . . . . . . . . . . . . . B-5 - B-6
Management's Narrative Analysis of Results of Operations . . B-7 - B-8
Appalachian Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . C-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . C-2 - C-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . C-4
Notes to Consolidated Financial Statements . . . . . . . . . C-5 - C-11
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . C-12- C-18
Central Power and Light Company:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . D-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . D-2 - D-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . D-4
Notes to Consolidated Financial Statements . . . . . . . . . D-5 - D-11
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . D-12- D-20
Columbus Southern Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . E-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . E-2 - E-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . E-4
Notes to Consolidated Financial Statements . . . . . . . . . E-5 - E-11
Management's Narrative Analysis of Results of Operations . . E-12- E-14
Indiana Michigan Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . F-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . F-2 - F-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . F-4
Notes to Consolidated Financial Statements . . . . . . . . . F-5 - F-10
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . F-11- F-18
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY,INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June 30, 2000
INDEX
Page
<S> <C>
Kentucky Power Company:
Statements of Income and Statements of Retained Earnings . . G-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . G-2 - G-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . G-4
Notes to Financial Statements. . . . . . . . . . . . . . . . G-5 - G-9
Management's Narrative Analysis of Results of Operations . . G-10- G-12
Ohio Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . H-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . H-2 - H-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . H-4
Notes to Consolidated Financial Statements . . . . . . . . . H-5 - H-11
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . H-12- H-20
Public Service Company of Oklahoma
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . .. . I-1
Consolidated Balance Sheets . . . . . . . . . . . . . . . . I-2 - I-3
Consolidated Statements of Cash Flows . . . . . . . . . . . I-4
Notes to Consolidated Financial Statements . . . . . . .. . I-5
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . I-6 - I-7
Southwestern Electric Power Company:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . J-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . J-2 - J-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . J-4
Notes to Consolidated Financial Statements . . . . . . . . . J-5 - J-9
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . J-10- J-12
West Texas Utilities Company:
Statements of Income and Statements of Retained Earnings . . K-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . K-2 - K-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . K-4
Notes to Financial Statements . . . . . . .. . . . . . . . . K-5 - K-7
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . K-8 - K-9
Part II. OTHER INFORMATION
Item 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
Item 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1-II-3
Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3-II-4
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-5
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.
</TABLE>
<PAGE>
FORWARD-LOOKING INFORMATION
This report made by American Electric Power Company, Inc. (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:
- Electric load and customer growth. - Abnormal weather conditions. -
Available sources and costs of fuels. - Availability of generating
capacity.
- The speed and degree to which competition is introduced to our power
generation business. - The structure and timing of a competitive market and
its impact on energy prices or fixed rates. - The ability to recover
stranded costs in connection with possible/proposed deregulation of
generation. - New legislation and government regulations.
- The ability of AEP to successfully control its costs. - The success of
new business ventures. - International developments affecting AEP's foreign
investments. - The economic climate and growth in AEP's service territory.
- Unforeseen events affecting AEP's restart of Cook Nuclear Plant Unit 1
which is on an extended safety related shutdown.
- Inflationary trends.
- Electricity and gas market prices.
- Interest rates - Other risks and unforeseen events.
<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 Six Months Ended
June 30, June 30,
---------------------- ---------------
2000 1999 2000 1999
---- ---- ---- ----
REVENUES:
<S> <C> <C> <C> <C>
Domestic Regulated Electric Utilities. . $2,582 $2,393 $4,892 $4,640
Worldwide Electric and Gas Operations. . 586 569 1,321 1,241
------ ------ ------ ------
TOTAL REVENUES . . . . . . . . . 3,168 2,962 6,213 5,881
------ ------ ------ ------
EXPENSES:
Fuel and Purchased Power . . . . . . . . 976 822 1,806 1,571
Maintenance and Other Operation. . . . . 716 672 1,405 1,280
Merger Costs . . . . . . . . . . . . . . 161 - 161 -
Depreciation and Amortization. . . . . . 257 251 529 500
Taxes Other Than Income Taxes. . . . . . 169 170 334 347
Worldwide Electric and Gas Operations. . 584 499 1,219 1,094
------ ------ ------ ------
TOTAL EXPENSES . . . . . . . . . 2,863 2,414 5,454 4,792
------ ------ ------ ------
OPERATING INCOME . . . . . . . . . . . . . 305 548 759 1,089
OTHER INCOME (LOSS), net. . . .. . . . . . (2) 9 14 21
------ ------ ------ ------
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES . . . . . . . 303 557 773 1,110
INTEREST AND PREFERRED DIVIDENDS . . . . . 269 246 522 489
------ ------ ------ ------
INCOME BEFORE INCOME TAXES . . . . . . . . 34 311 251 621
INCOME TAXES . . . . . . . . . . . . . . . 52 121 129 237
------ ------ ------ ------
INCOME (LOSS) BEFORE EXTRAORDINARY ITEM . (18) 190 122 384
EXTRAORDINARY GAIN - DISCONTINANCE OF
SFAS 71 ( INCLUSIVE OF TAX BENEFIT
OF $8 MILLION ) . . . . . . . . . . . . 9 - 9 -
------ ------ ------ ------
NET INCOME (LOSS). . . . . . . . . . . . . $ (9) $ 190 $ 131 $ 384
====== ====== ====== ======
AVERAGE NUMBER OF SHARES OUTSTANDING . . . 322 320 322 320
=== === === ===
EARNINGS PER SHARE
Income (Loss) Before Extraordinary Item $(0.06) $0.59 $ 0.38 $ 1.20
Extraordinary Gain - Discontinance of
SFAS 71 . . . . . . . . . . . . . . . 0.03 - 0.03 -
------ ------ ------ ------
Net Income (Loss) . . . . . . . . . . . $(0.03) $0.59 $0.41 $1.20
====== ====== ====== ======
CASH DIVIDENDS PAID PER SHARE. . . . . . . $0.60 $0.60 $1.20 $1.20
===== ===== ===== =====
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ---------------
2000 1999 2000 1999
---- ---- ---- ----
(in millions)
<S> <C> <C> <C> <C>
NET INCOME (LOSS). . . . . . . . . . . . . $ (9) $190 $ 131 $384
OTHER COMPREHENSIVE INCOME:
Foreign Currency Translation
Adjustments. . . . . . . . . . . . . . (80) 7 (115) (55)
Reclassification Adjustment for Loss
Included in Net Income . . . . . . . . 27 - 20 -
Unrealized Gains on Securities . . . . . - 3 - 8
Minimum Pension Liability. . . . . . . . (2) - (2) -
---- ---- ----- ----
COMPREHENSIVE INCOME (LOSS). . . . . . . . $(64) $200 $ 34 $337
==== ==== ===== ====
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
----------- --------
(in millions)
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . . . $ 312 $ 653
Accounts Receivable (net). . . . . . . . . . . . . . . . 2,502 2,027
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 359 436
Materials and Supplies . . . . . . . . . . . . . . . . . 464 460
Accrued Utility Revenues . . . . . . . . . . . . . . . . 430 322
Energy Trading Contracts . . . . . . . . . . . . . . . . 4,941 1,001
Prepayments. . . . . . . . . . . . . . . . . . . . . . . 208 175
------- -------
TOTAL CURRENT ASSETS . . . . . . . . . . . . . . 9,216 5,074
------- -------
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production . . . . . . . . . . . . . . . . . . . . . . 15,986 15,869
Transmission . . . . . . . . . . . . . . . . . . . . . 5,563 5,495
Distribution . . . . . . . . . . . . . . . . . . . . . 10,534 10,432
Other (including gas and coal mining assets
and nuclear fuel). . . . . . . . . . . . . . . . . . . 3,995 4,081
Construction Work in Progress. . . . . . . . . . . . . . 1,211 1,061
------- -------
Total Property, Plant and Equipment. . . . . . . 37,289 36,938
Accumulated Depreciation and Amortization. . . . . . . . 15,335 15,073
------- -------
NET PROPERTY, PLANT AND EQUIPMENT. . . . . . . . 21,954 21,865
------- -------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . 3,629 3,395
------- -------
INVESTMENTS IN POWER AND COMMUNICATIONS PROJECTS . . . . . 924 862
------- -------
GOODWILL (net of amortization) . . . . . . . . . . . . . . 1,422 1,531
------- -------
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . 3,254 2,992
------- -------
TOTAL. . . . . . . . . . . . . . . . . . . . . $40,399 $35,719
======= =======
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
------------ --------
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts Payable . . . . . . . . . . . . . . . . . . . . $ 1,591 $ 1,280
Short-term Debt. . . . . . . . . . . . . . . . . . . . . 4,116 3,012
Preferred Stock Due Within One Year. . . . . . . . . . . 18 -
Long-term Debt Due Within One Year . . . . . . . . . . . 711 1,367
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 396 601
Interest Accrued . . . . . . . . . . . . . . . . . . . . 178 142
Obligations Under Capital Leases . . . . . . . . . . . . 127 91
Energy Trading Contracts . . . . . . . . . . . . . . . . 4,857 964
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 681 609
------- -------
TOTAL CURRENT LIABILITIES. . . . . . . . . . . . 12,675 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 . . . . . . . . . . . . . . . . . . . . . . 335 335
------- -------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . 5,086 5,150
------- -------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . 553 580
------- -------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . . 208 213
------- -------
DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . . . 1,450 715
------- -------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . 1,604 1,648
------- -------
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . . . 163 182
------- -------
CONTINGENCIES (Note 9)
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. . . . . . . . . . . . . . . . . . . . . 2,862 2,898
Accumulated Other Comprehensive Income . . . . . . . . . (101) (4)
Retained Earnings. . . . . . . . . . . . . . . . . . . . 3,342 3,630
------- -------
TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . . . 8,254 8,673
------- -------
TOTAL. . . . . . . . . . . . . . . . . . . . . $40,399 $35,719
======= =======
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
----------------
2000 1999
---- ----
(in millions)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . .$ 131 $ 384
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . . . . 666 625
Deferred Federal Income Taxes. . . . . . . . . . . . . . . . . 19 41
Deferred Investment Tax Credits. . . . . . . . . . . . . . . . (17) (17)
Amortization of Deferred Property Taxes. . . . . . . . . . . . 79 80
Amortization (Deferral) of Cook Plant Restart Costs. . . . . . 20 (60)
Deferred Costs Under Fuel Clause Mechanisms. . . . . . . . . . (164) (58)
Extraorinary Gain - Discontinuance of SFAS No. 71 . . . . . . (9) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . . . (475) (53)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . . . 73 (160)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . . . (108) (10)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . . 311 (134)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . . (205) (74)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . . . (4) 38
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . . 58 (77)
------- -----
Net Cash Flows From Operating Activities . . . . . . . . . 375 525
------- -----
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . . . (808) (732)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (60) (37)
------- -----
Net Cash Flows Used For Investing Activities . . . . . . . (868) (769)
------- -----
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . . . . 12 64
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . . 751 323
Change in Short-term Debt (net). . . . . . . . . . . . . . . . . 1,104 718
Retirement of Long-term Debt . . . . . . . . . . . . . . . . . . (1,289) (400)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . . (419) (417)
------- -----
Net Cash Flows From Financing Activities . . . . . . . . . 159 288
------- -----
Effect of Exchange Rate Change on Cash . . . . . . . . . . . . . . (7) (4)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . . . . (341) 40
Cash and Cash Equivalents at Beginning of Period . . . . . . . . . 653 330
------- -----
Cash and Cash Equivalents at End of Period . . . . . . . . . . . .$ 312 $ 370
======= =====
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $471 million and $454
million and for income taxes was $206 million and $150 million in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $50 million
and $43 million in 2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ----------------
2000 1999 2000 1999
---- ---- ---- ----
(in millions)
<S> <C> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD . . . . . . $3,580 $3,495 $3,646 $3,507
CONFORMING CHANGE IN ACCOUNTING POLICY
(Note 2) . . . . . . . . . . . . . . . . (19) (16) (16) (14)
------ ------ ------ ------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. . 3,561 3,479 3,630 3,493
NET INCOME (LOSS). . . . . . . . . . . . . (9) 190 131 384
DEDUCTIONS:
Cash Dividends Declared - AEP. . . . . . 117 116 233 231
Cash Dividends Declared - CSW. . . . . . 93 93 186 186
------ ------ ------ ------
BALANCE AT END OF PERIOD . . . . . . . . . $3,342 $3,460 $3,342 $3,460
====== ====== ====== ======
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments
should be read in conjunction with the 1999 Annual Report as
incorporated in and filed with the Form 10-K. Certain prior-period
amounts have been reclassified to conform to current-period
presentation. In the opinion of management, the 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. MERGER OF AEP AND CSW
On June 15, 2000, AEP merged with Central and South West
Corporation (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.
The merger was accounted for as a pooling of interests.
Accordingly, the consolidated financial statements give retroactive
effect to the merger, with all periods presented as if AEP and CSW had
always been combined. 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 $19 million at March 31, 2000 and reduce net income by $2
million for the three months ended March 31, 2000 and by $3 million and
$1 million for the years ended December 31, 1999 and 1998, respectively.
Certain reclassifications have been made to conform the presentation of
AEP and CSW.
CSW's four wholly-owned domestic utility electric subsidiaries are: Central
Power and Light Company (CPL), Public Service Company of Oklahoma (PSO),
Southwestern Electric Power Company (SWEPCo) and West Texas Utilities Company
(WTU). CSW also has the following principal subsidiaries: CSW International
Inc., CSW Energy, Inc., Seeboard, CSW Credit, Inc., C3 Communications, Inc. and
CSW Energy Services, Inc.
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The following table sets forth summary data for the separate
companies and the combined amounts for the following periods:
Six Months Ended Twelve Months Ended
June 30, December 31,
----------------- ----------------
2000 1999 1999 1998
---- ---- ---- ----
(in millions)
Revenues:
AEP $3,494 $3,337 $ 6,916 $ 6,397
CSW 2,719 2,544 5,537 5,482
------ ------ ------- -------
AEP After Pooling $6,213 $5,881 $12,453 $11,879
====== ====== ======= =======
Net Income:
AEP $126 $239 $520 $536
CSW 8 148 455 440
Conforming
Adjustments (3) (3) (3) (1)
---- ---- ---- ----
AEP After Pooling $131 $384 $972 $975
==== ==== ==== ====
In connection with the merger, $161 million ($145 million
after-tax) of non-recoverable merger costs were expensed. Such costs
included transaction and transition costs not recoverable from
ratepayers. Also included in the merger costs were non-recoverable
accrued change in control payments. Merger transaction and transition
costs of $35 million recoverable from customers are deferred pursuant to
settlement agreements which, among other things, provide for the sharing
of net merger savings. 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 effective in the third quarter of 2000. If realized 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 megawatts (MW) of generating capacity is
required as a condition of regulatory approval of the merger by the
Federal Energy Regulatory Commission (FERC) and Public Utility
Commission of Texas (Texas Commission). Under the FERC-approved merger
settlement agreement the divestiture of 550 MW of generating capacity
comprised of 300 MW of capacity in the Southwest Power Pool (SPP) and
250 MW of capacity in the Electric Reliability Council of Texas (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 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 completion of the required SPP and ERCOT
divestitures. The Texas settlement calls for the divestiture of a total
of 1,604 MW of existing and proposed generating capacity within Texas
inclusive of 250 MW ordered by FERC. Divestiture can not proceed until
two years after the merger closes to satisfy the requirements to use
pooling-of-interests accounting treatment.
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.
3. COOK NUCLEAR PLANT SHUTDOWN
As discussed in Note 2 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Cook Nuclear Plant was shut
down in September 1997 due to questions regarding the operability of
certain safety systems that arose during a Nuclear Regulatory Commission
(NRC) architect engineer design inspection. The two-unit, 2,110 megawatt
plant is owned and operated by the Company-s subsidiary, Indiana
Michigan Power Company (I&M).
On July 5, 2000, Cook Nuclear Plant Unit 2, the first unit
scheduled to restart, reached 100% power completing its restart process.
On July 26, 2000, the Company announced that the restart of Cook
Nuclear Plant Unit 1 would cost an additional $145 million and was
scheduled to occur in the first quarter of 2001. Unforeseen issues or
difficulties encountered in preparing Unit 1 for restart could
potentially delay its return to service.
Expenditures to restart the Cook units had been estimated to
total approximately $574 million. The additional $145 million raises the
total estimate to $719 million. Through June 30, 2000, $534 million has
been spent. For the six months ended June 30, 2000, restart costs of
$181 million have been recorded in other operation and maintenance
expense, including amortization of $20 million of restart costs
previously deferred in accordance with settlement agreements in the
Indiana and Michigan retail jurisdictions. At June 30, 2000, deferred
restart costs of $140 million are included in regulatory assets.
The costs of the extended outage and restart efforts will 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 the restart cost deferrals is $40 million. Management
believes that Unit 1 of the Cook Plant 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.
4. FINANCING AND RELATED ACTIVITIES
During the first six months of 2000, subsidiaries issued $751
million of long-term notes at variable interest rates with due dates
ranging from 2001 to 2007. Also short-term debt borrowings increased by
$1.1 billion. The Company has in the past, and may in the future,
acquire outstanding debt and preferred stock securities in open market
transactions.
Retirements of debt were: first mortgage bonds totaling $398
million with interest rates ranging from 6.35% to 8.4% 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% and a
$625 million revolving credit agreement that matured and was refinanced
with short-term debt.
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, the Company raises funds through external borrowing. If there is a
net excess in cash, existing external borrowings are paid down, or, if
there are no external borrowings maturing, the excess funds are
invested.
CSW Credit, Inc., a subsidiary, factors electric customer accounts
receivable for affiliated operating companies and unaffiliated companies. CSW
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
June 30, 2000, CSW Credit, Inc. had a $2 billion revolving credit agreement
which had $1.2 billion of commercial paper outstanding.
5. RATE MATTERS
FERC
As discussed in Note 3 of the Notes to Financial Statements of the
1999 Annual Report, certain AEP System companies filed a settlement
agreement for FERC approval related to an open access transmission tariff.
The Company made a provision 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, AEP is 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 and CSW merger. Prior to
January 1, 2000, the rate was $2.04 kw/month. Unless the Company and the
market grow the volume of physical power transactions 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
As discussed in Note 3 of the Notes to Consolidated Financial
Statements of the 1999 Annual Report, the Company?s subsidiary
Appalachian Power Company (APCo) has been involved in a rate proceeding
regarding base and expanded net energy cost (ENEC) rates. On February 7,
2000, APCo and other parties to the proceeding filed a Joint Stipulation
and Agreement for Settlement (Joint Stipulation) with the Public Service
Commission of West Virginia (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 over or under recovery
effective January 1, 2000; the retention, as a regulatory liability, on
the books of the 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 West
Virginia (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.
Also under the Joint Stipulation APCo's share of any net savings
from the merger between the Company and Central and South West
Corporation prior to December 31, 2004 shall be retained by APCo. All
costs incurred in the merger that were allocated to APCo shall be fully
charged to expense as of December 31, 2004 and shall not be included in
any WV rate proceeding after that date. After December 31, 2004, any
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 6 for discussion of WV Restructuring Plan).
On June 2, 2000, the WVPSC issued an order approving the Joint
Stipulation.
CPL Fuel Factor Filings
In March 2000 the Texas Commission 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 Texas Commission, 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 early 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 will be made in September 2000. The
settlement requires the approval of the Texas Commission.
6. INDUSTRY RESTRUCTURING
Restructuring legislation has been enacted in five of the Company's
eleven retail jurisdictions that results in the transition from
cost-based regulation for generation to customer choice market pricing
for the supply of electricity. The enactment of restructuring
legislation and the ability to determine transition rates and wires
charges under restructuring legislation results in the discontinuance of
the application of Statement of Financial Accounting Standards (SFAS)
71, "Accounting for the Effects of Certain Types of Regulation." Prior
to restructuring, the electric utility subsidiaries 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 based on SFAS 101
"Accounting for the Discontinuance of Application of Statement 71".
Pursuant to those requirements and further guidance provided in the
Financial Accounting Standards Board's Emerging Issues Task Force (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 the
company's operations which continues to be 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,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of." A SFAS 121 accounting impairment analysis
involves estimating future non-discounted net cash flows arising from
the use of an asset. If the undiscounted net cash flows exceed the net
book value of the asset, then there is no impairment of the asset for
accounting purposes.
As legislative and regulatory proceedings evolve, the Company's
subsidiaries are applying the standards discussed above. Following is a
summary of restructuring legislation, the status of the transition plans
and the status of electric utility subsidiaries' accounting to comply
with the changes.
Virginia Restructuring
Under a 1999 Virginia restructuring law 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 State Corporation
Commission (Virginia SCC) that an effective competitive market exists by
January 1, 2004 but not later than January 1, 2005.
The Virginia restructuring law 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 law 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, the Company's
subsidiary operating in Virginia, does not intend to request new rates,
its current rates will become the capped rates.
West Virginia Restructuring Plan
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the WVPSC issued an order on
January 28, 2000 approving an electricity restructuring plan. On March
11, 2000, the West Virginia 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. The Company
provides electric service in West Virginia through APCo and a
distribution only subsidiary, Wheeling Power Company (WPCo).
The provisions of the restructuring plan provide for customer
choice to begin on January 1, 2001, or at a later date set by the WVPSC
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 by the
Company of a rate stabilization deferral balance of $81 million 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 are 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. The
Company's Joint Stipulation agreement, discussed in Note 5 above, which
was approved by the WVPSC on June 2, 2000 in connection with a base rate
filing, also provides additional mechanisms to recover the Company's
regulatory assets.
APCo Discontinues Application of SFAS 71
In June 2000 APCo discontinued the application of SFAS 71 for the
Virginia and West Virginia retail jurisdictional portions of its
generation business since generation is no longer considered to be
cost-based regulated in those jurisdictions and it was able to determine
its transition rates and wires charges. The discontinuance in the West
Virginia 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 it would not request capped rates different from
its current rates. The existence of effective restructuring legislation
in Virginia and the probability that the West Virginia 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.
APCo's discontinuance of SFAS 71 for generation resulted in an extraordinary
gain of $9 million because management believes that all net regulatory
assets related to the Virginia and West Virginia generation business will
be recovered. Under the provisions of EITF 97-4, APCo's generation-related
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. APCo performed an accounting impairment analysis of
generation assets under SFAS 121 and concluded there was no impairment of
generation assets.
Ohio Restructuring Law and Transition Plan Filing
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Ohio Electric Restructuring
Act of 1999 (the 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 Act also provides for a
five-year transition period to move from cost based rates to market
pricing for generation services. It authorizes the Public Utilities
Commission of Ohio (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 costs. Stranded costs are generation costs
that are not deemed to be recoverable in a competitive market.
On March 28, 2000, the PUCO staff issued its report on the
Company's transition plan filings for its subsidiaries, Ohio Power
Company (OPCo) and Columbus Southern Power Company (CSP). On May 8,
2000, a stipulation agreement between the Company, the PUCO staff, the
Ohio Consumers' Counsel and other concerned parties was filed with the
PUCO for approval. The key provisions of the stipulation agreement are:
o Recovery of generation-related regulatory assets over seven years
for OPCo and eight years for CSP 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 CSP residential customers that switch suppliers. There
is no shopping incentive for OPCo customers.
o The absorption of $40 million by CSP 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 The companies will make available a fund of up to $10 million to
reimburse customers who chose to purchase their power from another
company for certain transmission charges imposed by Pennsylvania-New
Jersey-Maryland transmission organization (PJM) and/or a midwest
independent system operator (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 will be
litigated separately.
Hearings on the stipulation and the gross receipts tax issue were
held in June 2000. Approval of the stipulation agreement by the PUCO and
a decision on the gross receipt tax issue are pending.
Potential For Write Offs In The Ohio Jurisdiction
Management has concluded that as of June 30, 2000 the
requirements to apply SFAS 71 continue to be met in the Ohio
jurisdiction. The Company's accounting for the generation business will
continue to be in accordance with SFAS 71 in the Ohio jurisdiction and
will continue to be considered to be cost-based regulated for accounting
purposes until the amount of transition rates and stranded cost wires
charges are determined and known. OPCo and CSP will therefore, be unable
to discontinue SFAS 71 regulatory accounting until the stipulation
agreement is approved and/or the PUCO issues its restructuring order.
The law requires that the PUCO issue such an order no later than October
2000.
Upon the discontinuance of SFAS 71 the Company will have to write
off its Ohio jurisdictional generation-related regulatory assets to the
extent that they cannot be recovered under the frozen transition rates
and stranded costs distribution wires charges and record any asset
accounting impairments. An impairment loss would be recorded, under SFAS
No. 121, to the extent that the cost of generation assets cannot be
recovered through non-discounted generation-related revenues during the
transition period and future market prices.
The amount of regulatory assets recorded on the books at June 30,
2000 applicable to the Ohio retail jurisdictional generating business is
$757 million before related tax effects. Due to the planned closing of
the Company's affiliated mines, including the Meigs mine, projected
generation-related regulatory assets as of December 31, 2000 (the date
that recoverable generation-related regulatory assets are measured under
the Ohio law) allocable to the Ohio retail jurisdiction are estimated to
exceed $800 million, before income tax effects. Recovery of these
regulatory assets is being sought as a part of the Company's Ohio
transition plan filings and is provided for by the stipulation agreement
presently before the PUCO for approval. Based on transition rates and
wires charges currently in the stipulation agreement and management's
current projections of future market prices, management does not
anticipate that the Company will experience material tangible asset
accounting impairment or regulatory asset write-offs. Whether the
Company will experience material regulatory asset write-offs will depend
on whether the PUCO approves the Company's stipulation agreement which
provides for their recovery.
A determination of whether the Company will experience any asset
impairment loss regarding its Ohio retail jurisdictional generating
assets and any loss from a possible inability to recover Ohio
generation-related regulatory assets and other transition costs cannot
be made until such time as the transition rates and the wires charges
are determined through the regulatory process. In the event the Company
is unable to recover all or a portion of its generation-related
regulatory assets, stranded costs and other transition costs including
the duplicate gross receipt tax, it could have a material adverse effect
on results of operations, cash flows and possibly financial condition.
Texas and Arkansas Restructuring
In June 1999 restructuring legislation was signed into law in Texas
that will restructure the electric utility industry (Texas Legislation).
The Texas Legislation, 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 nitrogen oxide and sulfur dioxide emissions;
o provides 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 sets an earnings test for the three years of rate freeze (1999 through 2001);
o sets certain limits for ownership and control of generation capacity by
companies; and
o requires a filing after January 10, 2004 to finalize stranded costs
(2004 true-up proceeding) including final fuel recovery balances,
regulatory assets, certain environmental costs, accumulated excess
earnings and other issues.
<PAGE>
Delivery of electricity will continue to be the responsibility of
the local electric transmission and distribution utility company at
regulated prices. Each electric utility must submit a plan to unbundle
its business activities into a retail electric provider, a power
generation company and a transmission and distribution utility.
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry (Arkansas Legislation). Major
points of the Arkansas Legislation are:
o Retail competition begins January 1, 2002 but can be delayed until
as late as June 30, 2003 by the Arkansas Public Service
Commission (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.
SWEPCo filed a business unbundling plan in Arkansas on June 30,
2000.
CPL, SWEPCo and WTU filed their business separation (unbundling)
plans with the Texas Commission on January 10, 2000. The filings
described a financial and accounting functional separation but not a
legal or structural separation, described how operations will be
physically separated and the functions they will perform, described
competitive energy services, and provided a code of conduct. In March
2000, the Texas Commission ruled that the subsidiaries' plans were not
in compliance with the Texas Legislation and ordered revised plans be
submitted to separate the generation business from the wires business in
separate legal entities by January 1, 2002. In May 2000 a revised
separation plan was filed, which the Texas Commission approved on July
7, 2000 in an interim order.
Under the Texas Legislation, electric utilities are allowed,
with the approval of the Texas Commission, 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
Texas Commission 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 Texas Commission tentatively
approved a settlement, which will permit CPL to securitize approximately
$764 million of net regulatory assets. The Texas Commission'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 requested by CPL in its 1999 securitization request
has been included in a March 2000 filing with the Texas Commission,
requesting recovery of an additional $1.1 billion of stranded costs. The
March 2000 filing for $1.1 billion includes recovery of approximately
$800 million of South Texas Project (STP) nuclear plant costs included
in utility plant on the Balance Sheet and previously identified as
"Excess Cost Over Market" (ECOM) by the Texas Commission for regulatory
purposes. A final determination on recovery will occur as part of the
2004 true-up proceeding and the total amount recoverable can be
securitized.
On April 11, 2000, four parties appealed the Texas
Commission's securitization order to the Travis County District Court.
One of these appeals challenges the ability to recover securitization
charges under the Texas Constitution. CPL will not be able to issue the
securitization bonds until these appeals are resolved. As a result, the
securitization bonds are not likely to be issued until 2001.
The financial statements of CPL, SWEPCo and WTU have historically
reflected the effects of applying the requirements of SFAS 71. As a
result of the scheduled deregulation of generation in Texas and
Arkansas, the application of SFAS 71 for the generation portion of the
business in those states was discontinued in 1999. Under the provisions
of EITF 97-4, CPL's generation-related 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. Management believes that substantially all of CPL's
generation-related regulatory assets should be recovered as provided by
the Texas Legislation when an electric utility has a stranded cost. If
future events were to occur that made the recovery of regulatory assets
no longer probable, CPL would write-off the portion of such assets
deemed unrecoverable as a non-cash charge to earnings.
CPL's recovery of generation-related regulatory assets and stranded
costs are subject to a final determination by the Texas Commission in
2004. The Texas Legislation provides that all such finally determined
stranded costs will be recovered. Since SWEPCo and WTU are not expected
to have net stranded costs, all generation-related non-recoverable net
regulatory assets were written off in 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. An impairment analysis
involves estimating future net cash flows arising from the use of an
asset. If the undiscounted net cash flows exceed the net book value of
the asset, then there is no impairment of the asset to record for
accounting purposes. CPL, SWEPCo and WTU will test their generation
assets for impairment under SFAS 121 when circumstances change.
However, on a discounted basis the cash flows are less than CPL's
generating asset's net book value and together with its
generation-related regulatory assets create a recoverable stranded
cost under the Texas Legislation.
The Texas Legislation also 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 amounts back to customers or make capital expenditure to
improve transmission or distribution facilities or to improve air
quality.
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, plant assets will be
depreciated 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 by a charge to earnings.
Beginning January 1, 2002, fuel costs will not be subject to
Texas Commission fuel reconciliation proceedings. Consequently, CPL,
SWEPCo and WTU will file a final fuel reconciliation with the Texas
Commission 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 Company continues to analyze the impact of the electric utility
industry restructuring legislation on the Texas electric utility
companies. Although management believes that the Texas Legislation
provides for full recovery of the Company's stranded costs and that the
Company does not have a recordable accounting impairment a final
determination of whether the Company 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 the Company
is unable after the 2004 true-up proceeding to recover all or a portion
of its 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.
7. BUSINESS SEGMENTS
The Company's principal business segment is its cost-based rate
regulated Domestic Electric Utility business consisting of eleven
regulated utility operating companies providing residential, commercial,
industrial and wholesale electric services in eleven states. Also
included in this segment are the Company's electric power wholesale
marketing and trading activities 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 Domestic Electric Utility business includes both the retail
and wholesale domestic electricity supply businesses which are regulated
in Kentucky, Indiana, Michigan, Louisiana, Oklahoma and Tennessee and
are in the process of transitioning to market based pricing in Arkansas,
Ohio, Texas, West Virginia 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. The Domestic
Electric Utility business is reported as one business segment.
The income statement captions Worldwide Electric and Gas
Operations include two segments: Worldwide Energy Investments and other.
The Worldwide Energy Investments segment represents domestic and
international investments in energy-related gas and electric projects
and operations. It also includes the development and management of such
projects and operations. Such investment activities include electric
generation, supply and distribution, and natural gas pipeline, storage
and other natural gas services.
The other segment which is included in the income statement
captions Worldwide Electric and Gas includes non-regulated electric
trading activities outside of AEP's marketing area (beyond two
transmission system's from AEP's system) and gas trading activities,
telecommunication services, and the marketing of various energy related
products and services. Financial data for the three business segments
for the six months ending June 30, 2000 and 1999 is shown in the
following table:
<PAGE>
<TABLE>
<CAPTION>
Domestic Worldwide
Regulated Electric and
Electric Gas Reconciling AEP
Utilities* Operations Other Adjustments Consolidated
--------- ------------ ----- ----------- ------------
(in millions)
June 30, 2000
<S> <C> <C> <C> <C> <C>
Revenues from
external customers $ 4,892 $1,273 $ 48 $ - $ 6,213
Revenues from
transactions with other
operating segments - 147 67 (214) -
Segment net income (loss) 110 31 (10) - 131
Total assets 29,308 7,204 3,887 - 40,399
June 30, 1999
Revenues from
external customers 4,640 1,230 11 - 5,881
Revenues from
transactions with other
operating segments - 28 78 (106) -
Segment net income (loss) 342 45 (3) - 384
Total assets 27,100 7,173 1,446 - 35,719
* Includes the domestic generation retail and wholesale supply
businesses a significant portion of which is undergoing a transition
from regulated cost based rates to open access market pricing but which
have not yet been unbundled i.e., structurally separated from the
Company's vertically integrated electric utility business.
</TABLE>
8. SOUTH AMERICAN INVESTMENTS
At June 30, 2000, CSW International owned 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 Vale to purchase CSW International's
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 Vale is deemed unable to fulfill its responsibilities
under the put option. Vale has experienced cumulative losses of
approximately $22 million, net of tax, related to operations and the
devaluation of the Brazilian Real. 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 losses are recovered.
As of June 30, 2000, CSW International had invested $110 million
in 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 to market of $33 million
($21 million after tax) 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 June 30, 2000 was $59
million. The decline in foreign exchange rates has resulted in a
cumulative loss of $18 million ($11 million after tax) as of June 30,
2000 which is included in Other Comprehensive Income.
9. CONTINGENCIES
COLI Litigation
As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the deductibility of certain
interest deductions related to AEP?s corporate owned life insurance
(COLI) program for taxable years 1991 through 1996 is under review by
the Internal Revenue Service (IRS). Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions. A disallowance
of the COLI interest deductions through June 30, 2000 would reduce
earnings by approximately $318 million (including interest).
The Company 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 any additional above market rate
interest on the contested amount. The payments to the IRS are included
on the consolidated balance sheet in other assets pending the resolution
of this matter. The Company is seeking refund through litigation of all
amounts paid plus interest.
In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern District
of Ohio in 1998. 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. Notwithstanding the Tax Court?s
decision in Winn-Dixie, 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 will vigorously pursue 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
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 the Company 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 Nuclear Plant, the Company'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 the Company's
deteriorating financial condition, and ultimately on the Company's
operations, liquidity and stock price. Three other similar class action
complaints have been filed and it is anticipated that the court will
consolidate the various complaints. Management believes these
shareholder actions are without merit and intends to oppose them
vigorously.
CPL Municipal Franchise Fee Litigation
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 served 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 decline 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 CPL 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 the Company's results of
operations, cash flows or financial condition.
Federal EPA Complaint and Notice of Violation
As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company has been involved in
litigation regarding generating plant emissions. Notices of Violation
were issued and a complaint was filed by the U.S. Environmental
Protection Agency (Federal EPA) in the U.S. District Court that alleges
the Company 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 extend unit operating lives or
increase 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 Company under the
Clean Air Act. A lawsuit against power plants owned by the Company
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 Company 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 Company 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
As discussed in Note 7 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, Federal EPA had issued a final
rule (the NOx rule) that requires substantial reductions in nitrogen
oxide (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, had filed petitions
seeking a review of the final rule in the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court). In May 1999, the Appeals
Court indefinitely stayed the requirement that states develop revised
air quality programs to impose the NOx reductions but did not, however,
stay the final compliance date of May 1, 2003. In March 2000 the Appeals
Court issued a decision generally upholding the NOx rule. On April 20,
2000, certain AEP System companies and other petitioners filed for
rehearing of this decision including a rehearing by the entire Appeals
Court. On June 22, 2000, the Appeals Court denied the petition for
rehearing and lifted the stay related to the states' development of
revised air quality programs to impose the NOx reductions. The petition
for a rehearing before the entire Appeals Court was also denied. The AEP
System companies subject to the NOx rule plan to appeal to the U.S.
Supreme Court.
In a related matter, on April 19, 2000, the Texas Natural
Resource Conservation Commission (TNRCC) adopted rules requiring
significant reductions in NOx emissions from utility sources, including
SWEPCo and CPL. 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.
Preliminary estimates indicate that compliance with the NOx rule
upheld by the Appeals Court as well as compliance with the TNRCC rule
could result in required capital expenditures of approximately $1.8
billion for the Company. Since compliance costs cannot be estimated with
certainty, the actual cost to comply could be significantly different
than the Company's 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.
Other
The Company continues to be involved in certain other matters
discussed in the 1999 Annual Report.
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
---------------------------------------
RESULTS OF OPERATIONS
Net income declined by $199 million or 105% for the quarter and by $253
million or 66% for the year-to-date period due predominately to the expensing of
costs related to AEP's recently completed merger with Central and South West
Corporation (CSW), a write down to market of a CSW investment in a company based
in Chile and an increase in the costs charged to operations and maintenance
expense to restart the Company's shutdown Cook Nuclear Plant.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-To-Date
(in millions) % (in millions) %
Revenues:
Domestic Regulated Electric
Utilities. . . . . . . . . . . $189 8 $252 5
Worldwide Electric and
Gas Operations . . . . . . . . 17 3 80 6
Fuel and Purchased Power Expense. 154 19 235 15
Maintenance and Other Operation
Expense. . . . . . . . . . . . 44 7 125 10
Merger Costs. . . . . . . . . . . 161 N.M. 161 N.M.
Worldwide Electric and Gas
Operations Expense . . . . . . . 85 17 125 11
Interest and Preferred Dividends. 23 9 33 7
Income Taxes. . . . . . . . . . . (69) (57) (108) (46)
N.M. = Not Meaningful
Domestic revenues increased primarily due to increased wholesale sales
to neighboring utilities and marketers in the eastern markets of the domestic
regulated electric utility business. The increase in wholesale sales resulted
from growth in energy trading operations and the availability of additional
generation in the second quarter.
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
approximately 50% rebounding from a depressed gas market in the first half of
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 and an increase in net generation.
Maintenance and other operation expense increased largely as a result of
increased expenditures to prepare the Cook Plant nuclear units for restart
following an extended Nuclear Regulatory Commission (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 incremental restart expenses were deferred in accordance with Indiana and
Michigan regulatory commission settlement agreements which resolved all
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, 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. Change in control
payments were also charged to expense.
Worldwide electric and gas operations expenses rose in the quarter due
mainly to a significant increase in prices for natural gas used to produce gas
liquid products and a write down to market value of an available-for-sale
investment in a Chilean-based electric company. The write down to market was
recognized in June 2000 since the decline in market value was determined to be
other than temporary.
Interest charges increased due to an increase in average outstanding
short-term debt balances and an increase in average short-term debt interest
rates reflecting the Company's increased short-term cash demands and short-term
debt market conditions.
The decrease in income taxes is predominately due to a decrease in
pre-tax income.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
year-to-date period were $858 million.
During the first six months of 2000 the Company's subsidiaries issued
$751 million principal amount of long-term obligations at variable interest
rates and retired $1.3 billion principal amount of long-term debt with interest
rates ranging from 6.35% to 8.40% and increased short-term debt by $1.1 billion
from year-end balances. The Company has in the past, and may in the future,
acquire outstanding debt and preferred stock securities in open market
transactions. During the second quarter the Company 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, the Company raises funds through its
external borrowing. 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.
OTHER MATTERS
Cook Nuclear Plant Shutdown
As discussed in Management's Discussion and Analysis of Results of
Operations and Financial Condition (MDA) in the 1999 Annual Report, the Cook
Nuclear 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. The two-unit, 2,110 megawatt plant is owned and operated by
the Company's subsidiary, Indiana Michigan Power Company (I&M).
On July 5, 2000, Cook Nuclear Plant Unit 2, the first unit scheduled to
restart, reached 100% power completing its restart process.
On July 26, 2000, the Company announced that the restart of Cook Nuclear
Plant Unit 1 would cost an additional $145 million and was scheduled to occur in
the first quarter of 2001. Any issues or difficulties encountered in preparing
Unit 1 for restart could delay its return to service.
Expenditures to restart the Cook units had been estimated to total
approximately $574 million. The additional $145 million raises the total
estimate to $719 million. Through June 30, 2000, $534 million has been spent.
For the six months ended June 30, 2000, restart costs of $181 million have been
recorded in other operation and maintenance expense, including amortization of
$20 million of restart costs previously deferred in accordance with settlement
agreements in the Indiana and Michigan retail jurisdictions. At June 30, 2000,
deferred restart costs of $140 million are included in regulatory assets.
The costs of the extended outage and restart efforts will 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 jurisdiction settlement agreements will adversely
affect results of operations through 2003 when the amortization period ends. The
annual amortization of the restart cost deferrals is $40 million. Management
believes that Unit 1 of the Cook Plant 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 five retail jurisdictions
that results in the transition from cost-based regulation for generation to
customer choice market pricing for the supply of electricity. The enactment of
restructuring legislation and the ability to determine transition rates and
wires charges under restructuring legislation results in the discontinuance of
the application of Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation." Prior to
restructuring, the electric utility subsidiaries 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
based on SFAS 101 "Accounting for the Discontinuance of Application of Statement
71". Pursuant to those requirements and further guidance provided in the
Financial Accounting Standards Board's Emerging Issues Task Force (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 the company's operations which
continues to be 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, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of." A SFAS 121 accounting impairment
analysis involves estimating future net cash flows arising from the use of an
asset. If the undiscounted net cash flows exceed the net book value of the
asset, then there is no impairment of the asset for accounting purposes.
As legislative and regulatory proceedings evolve, the Company's subsidiaries
are applying the standards discussed above. Following is a summary of
restructuring legislation, the status of the transition and the status of
electric utility subsidiaries accounting to comply with the changes.
Virginia Restructuring
Under a 1999 Virginia restructuring law 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 State Corporation Commission (Virginia SCC)
that an effective competitive market exists by January 1, 2004 but not later
than January 1, 2005.
The Virginia restructuring law 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 law 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, the Company's
subsidiary operating in Virginia, does not intend to request new rates, its
current rates will become the capped rates.
West Virginia Restructuring Plan
As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the WVPSC issued an order on January 28, 2000
approving an electricity restructuring plan. On March 11, 2000, the West
Virginia 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. The Company provides electric service in West
Virginia through APCo and a distribution only subsidiary, Wheeling Power Company
(WPCo).
The provisions of the restructuring plan provide for customer choice to
begin on January 1, 2001, or at a later date set by the WVPSC 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 by the Company of a rate
stabilization deferral balance of $81 million 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
are discounted by 1% for four and a half years, beginning July 1, 2000, and then
increase 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. The Company's Joint Stipulation agreement, discussed in Note 5 above,
which was approved by the WVPSC on June 2, 2000 in connection with a base rate
filing, also provides additional mechanisms to recover the Company's regulatory
assets.
APCo Discontinues Application of SFAS 71
In June 2000 APCo discontinued the application of SFAS 71 for the
Virginia and West Virginia retail jurisdictional portions of its generation
business since generation is no longer considered to be cost-based regulated in
those jurisdictions. The discontinuance in the West Virginia jurisdiction
resulted from the 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 discontinued application of SFAS 71
for the generation portion of its Virginia retail jurisdiction after management
decided that it would not request capped rates different from its current rates.
The existence of effective restructuring legislation in Virginia and the
probability that the West Virginia legislation would become effective with the
passage of required tax legislation in 2001 supported management's decision to
discontinue SFAS 71 regulatory accounting. APCo's discontinuance of SFAS 71 for
generation resulted in an extraordinary gain of $9 million because
management believes that all net regulatory assets related to the Virginia and
West Virginia generation business will be recovered. Under the provisions of
EITF 97-4, APCo's generation-related 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. APCo performed an accounting
impairment analysis of generation assets under SFAS 121 and concluded there was
no impairment of generation assets.
Ohio Restructuring Law and Transition Plan Filings
A discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the 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 Act also provides for a five-year transition period to move from cost based
rates to market pricing for generation services. It authorizes the Public
Utilities Commission of Ohio (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
costs. Stranded costs are generation costs that are not deemed to be recoverable
in a competitive market.
On March 28, 2000, the PUCO staff issued its report on the Company's
transition plan filings for its subsidiaries, Ohio Power Company (OPCo) and
Columbus Southern Power Company (CSP). On May 8, 2000, a stipulation agreement
between the Company, the PUCO staff, the Ohio Consumers' Counsel and other
concerned parties was filed with the PUCO for approval. The key provisions of
the stipulation agreement are:
o Recovery of generation-related regulatory assets over seven years for OPCo
and eight years for CSP 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 CSP residential customers that switch suppliers. There is no
shopping incentive for OPCo customers.
o The absorption of $40 million by CSP 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 The companies will make available a fund of up to $10 million to reimburse
customers who chose to purchase their power from another company for
certain transmission charges imposed by Pennsylvania-New Jersey-Maryland
transmission organization (PJM) and/or a midwest independent system
operator (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 will be litigated
separately.
<PAGE>
Hearings on the stipulation and the gross receipts tax issue were held
in June 2000. Approval of the stipulation agreement by
the PUCO and a decision on the gross receipts tax issue are pending.
Potential For Write Offs In The Ohio Jurisdiction
Management has concluded that as of June 30, 2000 the requirements to
apply SFAS 71 continue to be met in the Ohio jurisdiction. The Company's
accounting for generation will continue to be in accordance with SFAS 71 in the
Ohio jurisdiction and will continue to be considered to be cost-based regulated
for accounting purposes until the amount of transition rates and stranded cost
wires charges are determined and known. OPCo and CSP will therefore, be unable
to discontinue SFAS 71 regulatory accounting until the stipulation agreement is
approved and/or the PUCO issues its restructuring order. The law requires that
the PUCO issue such an order no later than October 2000.
Upon the discontinuance of SFAS 71 the Company will have to write off
its Ohio jurisdictional generation-related regulatory assets to the extent that
they cannot be recovered under the frozen transition rates and stranded costs
distribution wires charges and record any asset accounting impairments. An
impairment loss would be recorded, under SFAS No. 121, to the extent that the
cost of generation assets cannot be recovered through non-discounted
generation-related revenues during the transition period and future market
prices.
The amount of regulatory assets recorded on the books at June 30, 2000
applicable to the Ohio retail jurisdictional generating business is $757 million
before related tax effects. Due to the planned closing of the Company's
affiliated mines, including the Meigs mine, projected generation-related
regulatory assets as of December 31, 2000 (the date that recoverable
generation-related regulatory assets are measured under the Ohio law) allocable
to the Ohio retail jurisdiction are estimated to exceed $800 million, before
income tax effects. Recovery of these regulatory assets is being sought as a
part of the Company's Ohio transition plan filings and is provided for by the
stipulation agreement presently before the PUCO for approval. Based on
transition rates and wires charges currently in the stipulation agreement and
management's current projections of future market prices, management does not
anticipate that the Company will experience a material tangible asset accounting
impairment or regulatory asset write-offs. Whether the Company will experience
material regulatory asset write-offs will depend on whether the PUCO approves
the Company's stipulation agreement which provides for their recovery.
A determination of whether the Company will experience any asset
impairment loss regarding its Ohio retail jurisdictional generating assets and
any loss from a possible inability to recover Ohio generation-related regulatory
assets and other transition costs cannot be made until such time as the
transition rates and the wires charges are determined through the regulatory
process. In the event the Company is unable to recover all or a portion of its
generation-related regulatory assets, stranded costs and other transition costs
including the duplicate gross receipts tax, it could have a material adverse
effect on results of operations, cash flows and possibly financial condition.
Texas and Arkansas Restructuring
In June 1999 restructuring legislation was signed into law in Texas that
will restructure the electric utility industry (Texas Legislation). The Texas
Legislation, 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 nitrogen oxide and sulfur dioxide emissions;
o provides 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 sets an earnings test for the three years of rate freeze (1999 through 2001);
o sets certain limits for ownership and control of generation capacity by
companies; and
o requires a filing after January 10, 2004 to finalize stranded costs
(2004 true-up proceeding) including final fuel recovery balances,
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 must submit a plan to unbundle its business activities into a
retail electric provider, a power generation company and a transmission and
distribution utility.
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry (Arkansas Legislation). Major points
of the Arkansas Legislation are: o Retail competition begins January 1, 2002 but
can be delayed until as late as June 30, 2003 by the Arkansas Public Service
Commission (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.
SWEPCo filed a business unbundling plan in Arkansas on June 30, 2000.
CPL, SWEPCo and WTU filed their business separation (unbundling) plans with
the Texas Commission on January 10, 2000. The filings described a financial and
accounting functional separation but not a legal or structural separation,
described how operations will be physically separated and the functions they
will perform, described competitive energy services, and provided a code of
conduct. In March 2000, the Texas Commission ruled that the subsidiaries' plans
were not in compliance with the Texas Legislation and ordered revised plans be
submitted to separate the generation business from the wires business in
separate legal entities by January 1, 2002. In May 2000 a revised separation
plan was filed, which the Texas Commission approved on July 7, 2000 in an
interim order.
Under the Texas Legislation, electric utilities are allowed, with the
approval of the Texas Commission, 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 Texas
Commission 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 Texas Commission tentatively approved a
settlement, which will permit CPL to securitize approximately $764 million of
net regulatory assets. The Texas Commission'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 requested
by CPL in its 1999 securitization request has been included in a March 2000
filing with the Texas Commission, requesting recovery of an additional $1.1
billion of stranded costs. The March 2000 filing for $1.1 billion includes
recovery of approximately $800 million of South Texas Project (STP) nuclear
plant costs included in utility plant on the Balance Sheet and previously
identified as "Excess Cost Over Market" (ECOM) by the Texas Commission for
regulatory purposes. A final determination on recovery will occur as part of the
2004 true-up proceeding and the total amount recoverable can be securitized.
On April 11, 2000, four parties appealed the Texas Commission's
securitization order to the Travis County District Court. One of these appeals
challenges the ability to recover securitization charges under the Texas
Constitution. CPL will not be able to issue the securitization bonds until these
appeals are resolved. As a result, the securitization bonds are not likely to be
issued until 2001.
The financial statements of CPL, SWEPCo and WTU have historically
reflected the effects of applying the requirements of SFAS 71. As a result of
the scheduled deregulation of generation in Texas and Arkansas, the application
of SFAS 71 for the generation portion of the business in those states was
discontinued in 1999. Under the provisions of EITF 97-4, CPL's
generation-related 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. Management believes that substantially
all of CPL's generation-related regulatory assets should be recovered as
provided by the Texas Legislation when an electric utility has a stranded cost.
If future events were to occur that made the recovery of regulatory assets no
longer probable, CPL would write-off the portion of such assets deemed
unrecoverable as a non-cash charge to earnings.
CPL's recovery of generation-related regulatory assets and stranded costs
are subject to a final determination by the Texas Commission in 2004. The Texas
Legislation provides that all such finally determined stranded costs will be
recovered. Since SWEPCo and WTU are not expected to have net stranded costs, all
generation-related non-recoverable net regulatory assets were written off in
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. An impairment analysis
involves estimating future net cash flows arising from the use of an asset. If
the undiscounted net cash flows exceed the net book value of the asset, then
there is no impairment of the asset to record for accounting purposes. CPL,
SWEPCo and WTU will test their generation assets for impairment under
SFAS 121 when circumstances change. However, on a discounted basis the
cash flows are less than CPL's generating asset's net book value and
together with its generation-related regulatory assets create a
recoverable stranded cost under the Texas Legislation.
The Texas Legislation also 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 amounts back to customers or make capital
expenditure to improve transmission or distribution facilities or to improve air
quality.
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, plant assets will be depreciated 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 by a charge to earnings.
Beginning January 1, 2002, fuel costs will not be subject to Texas
Commission fuel reconciliation proceedings. Consequently, CPL, SWEPCo and WTU
will file a final fuel reconciliation with the Texas Commission 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 Company continues to analyze the impact of the electric utility
industry restructuring legislation on the Texas electric utility companies.
Although management believes that the Texas Legislation provides for full
recovery of the Company's stranded costs and that the Company does not have a
recordable accounting impairment a final determination of whether the Company
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 the Company is unable after the 2004 true-up proceeding to recover all or
a portion of its 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.
COLI Litigation
As discussed in Note 6 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the deductibility of certain interest deductions
related to AEP?s corporate owned life insurance (COLI) program for taxable years
1991 through 1996 is under review by the Internal Revenue Service (IRS).
Adjustments have been or will be proposed by the IRS disallowing COLI interest
deductions. A disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $318 million (including interest).
The Company 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 any additional above market rate interest on the
contested amount. The payments to the IRS are included on the consolidated
balance sheet in other assets pending the resolution of this matter. The Company
is seeking refund through litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District of Ohio in
1998. 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. Notwithstanding the Tax Court's decision in Winn-Dixie, 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 will vigorously pursue 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
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 the Company 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 Nuclear Plant, the
Company'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 the Company's deteriorating
financial condition, and ultimately on the Company's operations, liquidity and
stock price. Three other similar class action complaints have been filed and it
is anticipated that the court will consolidate the various complaints.
Management believes these shareholder actions are without merit and intends to
oppose them vigorously.
CPL Municipal Franchise Fee Litigation
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 served 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 decline 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 CPL 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 the Company's results of operations, cash flows or
financial condition.
Federal EPA Complaint and Notice of Violation
As discussed in MDA in the 1999 Annual Report, the Company has been
involved in litigation regarding generating plant emissions. Notices of
Violation were issued and a complaint was filed by the U.S. Environmental
Protection Agency (Federal EPA) in the U.S. District Court that alleges the
Company 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 extend unit operating lives or increase 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 Company under the Clean Air
Act. A lawsuit against power plants owned by the Company 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 Company 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 Company 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
As discussed in MDA in the 1999 Annual Report, Federal EPA had issued a
final rule (the NOx rule) that requires substantial reductions in nitrogen oxide
(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, had filed petitions seeking a review of the final rule in
the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court).
In May 1999, the Appeals Court indefinitely stayed the requirement that states
develop revised air quality programs to impose the NOx reductions but did not,
however, stay the final compliance date of May 1, 2003. In March 2000 the
Appeals Court issued a decision generally upholding the NOx rule. On April 20,
2000, certain AEP System companies and other petitioners filed for rehearing of
this decision including a rehearing by the entire Appeals Court. On June 22,
2000, the Appeals Court denied the petition for rehearing and lifted the stay
related to the states' development of revised air quality programs to impose the
NOx reductions. The petition for a rehearing before the entire Appeals Court was
also denied. The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.
In a related matter, on April 19, 2000, the Texas Natural Resource
Conservation Commission adopted rules (TNRCC rule) requiring significant
reductions in NOx emissions from utility sources, including SWEPCo and CPL. The
TNRCC rule's compliance date is May 2003 for CPL and 2005 for SWEPCo. The TNRCC
rule is being challenged in state court by an unaffiliated utility.
Preliminary estimates indicate that compliance with the NOx rule upheld
by the Appeals Court as well as compliance with the TNRCC rule could result in
required capital expenditures of approximately $1.8 billion for the Company.
Since compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the Company's 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. Market Risks
The Company has certain market risks inherent in its business activities
from changes in electricity commodity prices, foreign currency exchange rates
and interest rates. Market risk represents the risk of loss that may impact the
Company due to adverse changes in commodity market prices, foreign currency
exchange rates and interest rates. The Company's exposure to market risk from
the trading of electricity and natural gas and related financial derivative
instruments was less than $28 million at June 30, 2000 and $14 million at
December 31, 1999 based on the use of a risk measurement model which calculates
Value at Risk (VaR). The VaR is based on the variance-covariance method using
historical prices to estimate volatilities and correlations and assuming a 95%
confidence level and a three-day holding period.
There have been no material changes to the Company's exposure to
fluctuations in foreign currency exchange rates related to foreign ventures and
investments since December 31, 1999.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $56,928 $51,612 $113,794 $104,439
------- ------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 26,048 20,169 50,483 40,427
Rent - Rockport Plant Unit 2 . . . . . 17,070 17,070 34,141 34,141
Other Operation. . . . . . . . . . . . 1,956 2,092 5,054 5,462
Maintenance. . . . . . . . . . . . . . 3,166 4,489 5,681 6,751
Depreciation . . . . . . . . . . . . . 5,541 5,483 11,046 10,923
Taxes Other Than Federal Income Taxes. 1,124 1,253 2,250 2,492
Federal Income Taxes . . . . . . . . . 277 54 998 881
------- ------- -------- --------
TOTAL OPERATING EXPENSES . . . 55,182 50,610 109,653 101,077
------- ------- -------- --------
OPERATING INCOME . . . . . . . . . . . . 1,746 1,002 4,141 3,362
NONOPERATING INCOME. . . . . . . . . . . 900 889 1,769 1,745
------- ------- -------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 2,646 1,891 5,910 5,107
INTEREST CHARGES . . . . . . . . . . . . 993 669 1,812 1,271
------- ------- -------- --------
NET INCOME . . . . . . . . . . . . . . . $ 1,653 $ 1,222 $ 4,098 $ 3,836
======= ======= ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $4,183 $4,311 $3,673 $2,770
NET INCOME . . . . . . . . . . . . . . . 1,653 1,222 4,098 3,836
CASH DIVIDENDS DECLARED. . . . . . . . . - 1,073 1,935 2,146
------ ------ ------ ------
BALANCE AT END OF PERIOD . . . . . . . . $5,836 $4,460 $5,836 $4,460
====== ====== ====== ======
The common stock of the Company is wholly owned by American Electric Power
Company, Inc.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $635,273 $629,286
General . . . . . . . . . . . . . . . . . . . . . . . . . 2,578 2,400
Construction Work in Progress . . . . . . . . . . . . . . 2,578 8,407
-------- --------
Total Electric Utility Plant. . . . . . . . . . . 640,429 640,093
Accumulated Depreciation. . . . . . . . . . . . . . . . . 304,278 295,065
-------- --------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 336,151 345,028
-------- --------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 41 317
Accounts Receivable:
Affiliated Companies. . . . . . . . . . . . . . . . . . 19,147 22,464
Miscellaneous . . . . . . . . . . . . . . . . . . . . . 2,617 2,643
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 18,785 17,505
Materials and Supplies. . . . . . . . . . . . . . . . . . 4,279 3,966
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 70 150
-------- --------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 44,939 47,045
-------- --------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 5,624 5,744
-------- --------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 2,416 823
-------- --------
TOTAL . . . . . . . . . . . . . . . . . . . . . $389,130 $398,640
======== ========
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
June 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 . . . . . . . . . . . . . . . . . . . . . 26,300 29,235
Retained Earnings . . . . . . . . . . . . . . . . . . . . 5,836 3,673
-------- --------
TOTAL CAPITALIZATION AND
COMMON SHAREHOLDER'S EQUITY . . . . . . . . . . 33,136 33,908
-------- --------
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 475 592
-------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . 44,804 44,800
Short-term Debt - Notes Payable . . . . . . . . . . . . . - 24,700
Advances from Affiliates. . . . . . . . . . . . . . . . . 37,870 -
Accounts Payable:
General . . . . . . . . . . . . . . . . . . . . . . . . 7,207 7,539
Affiliated Companies. . . . . . . . . . . . . . . . . . 4,221 19,451
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 6,818 4,285
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 4,963 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 3,075 4,763
-------- --------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 108,958 110,501
-------- --------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 124,974 127,759
-------- --------
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . . . 61,440 63,114
Amounts Due to Customers for Income Taxes . . . . . . . . 25,107 26,266
-------- --------
TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 86,547 89,380
-------- --------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 34,890 36,500
-------- --------
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 150 -
-------- -----
CONTINGENCIES (Note 3)
TOTAL . . . . . . . . . . . . . . . . . . . . . $389,130 $398,640
======== ========
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
2000 1999
---- ----
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 4,098 $ 3,836
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 11,046 10,923
Deferred Federal Income Taxes. . . . . . . . . . . . . . (2,769) (2,661)
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,674) (1,677)
Amortization of Deferred Gain on Sale
and Leaseback - Rockport Plant Unit 2. . . . . . . . . (2,785) (2,785)
Deferred Property Taxes. . . . . . . . . . . . . . . . . (1,648) (1,666)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . . 3,343 936
Fuel, Materials and Supplies . . . . . . . . . . . . . . (1,593) (15,480)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (15,562) 6,496
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2,533 4,477
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (1,270) (3,413)
-------- --------
Net Cash Flows Used For Operating Activities . . . . (6,281) (1,014)
-------- --------
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (2,295) (4,436)
-------- --------
FINANCING ACTIVITIES:
Return of Capital to Parent Company. . . . . . . . . . . . (2,935) (6,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . (24,700) 14,925
Change in Advances from Affiliates (net) . . . . . . . . . 37,870 -
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (1,935) (2,146)
-------- --------
Net Cash Flows From Financing Activities . . . . . . 8,300 6,779
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (276) 1,329
Cash and Cash Equivalents at Beginning of Period . . . . . . 317 232
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 41 $ 1,561
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $1,619,000 and
$1,070,000 and for income taxes was $3,129,000 and $1,268,000 in 2000 and
1999, respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 1999 Annual Report as incorporated in and filed with the
Form 10-K. In the opinion of management, the 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. MONEY POOL
On June 15, 2000, the Company became a participant in the American
Electric Power (AEP) System Money Pool (Money Pool). The Money Pool is a
mechanism structured to meet the short-term cash requirements of the
participants with AEP Company, Inc. acting as the primary borrower on behalf of
the Money Pool. The Company's affiliates that are U.S. domestic electric utility
operating companies are the primary participants in the Money Pool.
The operation of the Money Pool is designed to match on a daily basis
the available cash and borrowing requirements of the participants. Participants
with excess cash loan funds to the Money Pool reducing the amount of external
funds AEP Company, Inc. needs to borrow and other participants meet their
short-term cash requirements with advances from the Money Pool. AEP Company,
Inc. borrows the funds needed on a daily basis 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
Company, Inc. is applied to each Money Pool participant's daily outstanding
investment or debt position to determine interest income or interest expense.
Interest income is included in nonoperating income, and interest expense is
included in interest charges. As a result of becoming a Money Pool participant,
the Company retired its short-term debt and reports its borrowing from the Money
Pool as Advances from Affiliates on the Balance Sheets.
3. CONTINGENCIES
NOx Reductions
As discussed in Note 3 of the Notes of Financial Statements of the 1999
Annual Report, the United States Environmental Protection Agency had issued a
final rule (the NOx rule) that requires substantial reductions in nitrogen oxide
(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, had filed petitions seeking a review of the final rule in
the U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court).
In May 1999, the Appeals Court indefinitely stayed the requirement that states
develop revised air quality programs to impose the NOx reductions but did not,
however, stay the final compliance date of May 1, 2003. In March 2000 the
Appeals Court issued a decision generally upholding the NOx rule. On April 20,
2000, certain AEP System companies and other petitioners filed for rehearing of
this decision including a rehearing by the entire Appeals Court. On June 22,
2000, the Appeals Court denied the petition for rehearing and lifted the stay
related to the states' development of revised air quality programs to impose the
NOx reductions. The petition for a rehearing before the entire Appeals Court was
also denied. The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.
Preliminary estimates indicate that compliance with the NOx rule upheld
by the Appeals Court could result in required capital expenditures of
approximately $125 million for the Company. Since compliance costs cannot be
estimated with certainty, the actual cost to comply could be significantly
different than the Company's preliminary estimate depending upon the compliance
alternatives selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates and/or reflected in the
future market price of electricity if generation is deregulated, they will have
an adverse effect on future results of operations, cash flows and possibly
financial condition.
<PAGE>
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2000 vs. SECOND 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 Federal Energy Regulatory Commission (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 $0.4 million or 35% for the second quarter
primarily as a result of the effect of a reduction in the April 1999 billings to
reflect an adjustment to actual for estimated power production expenses included
in March 1999 billings. The 1999 adjustment to actual expenses reduced revenues
and net income for the second quarter of 1999. Also contributing to the $0.3
million or 7% increase in net income for the year-to-date period was the effect
of expenses incurred in 1999 that were included in billing in the fourth quarter
of 1999.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $ 5.3 10 $ 9.4 9
Fuel Expense . . . . . . . . 5.9 29 10.1 25
Other Operation Expense. . . (0.1) (6) (0.4) (7)
Maintenance Expense. . . . . (1.3) (29) (1.1) (16)
Taxes Other Than Federal
Income Taxes . . . . . . . (0.1) (10) (0.2) (10)
Federal Income Taxes . . . . 0.2 N.M. 0.1 13
Net Interest Charges . . . . 0.3 48 0.5 43
N.M. = Not Meaningful
The increase in 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 units to generate 22% more electricity in the first
six months of 2000 than in 1999.
Fuel expense increased due to the increase in generation reflecting the
increased availability of the Rockport Plant units. The reduction in the
number of outages and the shorter length of planned outages accounted
for the decrease in maintenance
expense for the second quarter and year-to-date 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 Six Months Ended
June 30, June 30,
--------------------- ----------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $430,000 $373,766 $ 885,595 $ 801,468
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 92,663 99,659 191,220 223,232
Purchased Power. . . . . . . . . . . . 106,410 61,048 198,974 111,639
Other Operation. . . . . . . . . . . . 61,566 60,162 122,207 122,911
Maintenance. . . . . . . . . . . . . . 28,989 38,361 57,314 66,872
Depreciation and Amortization. . . . . 38,899 37,224 77,237 73,775
Taxes Other Than Federal Income Taxes. 28,817 30,066 59,462 60,041
Federal Income Taxes . . . . . . . . . 14,448 4,147 42,727 28,292
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES . . . 371,792 330,667 749,141 686,762
-------- -------- ---------- ----------
OPERATING INCOME . . . . . . . . . . . . 58,208 43,099 136,454 114,706
NONOPERATING INCOME (LOSS) . . . . . . . 3,427 315 4,208 (773)
-------- -------- ---------- ----------
INCOME BEFORE INTEREST CHARGES . . . . . 61,635 43,414 140,662 113,933
INTEREST CHARGES . . . . . . . . . . . . 31,395 32,378 62,758 63,636
-------- -------- ---------- ----------
INCOME BEFORE EXTRAORDINARY ITEM . . . . 30,240 11,036 77,904 50,297
EXTRAORDINARY GAIN - DISCONTINUANCE OF
SFAS NO. 71 (INCLUSIVE OF TAX BENEFIT
OF $7,872,000). . . . . . . . . . . . . 8,938 - 8,938 -
-------- -------- ---------- -------
NET INCOME . . . . . . . . . . . . . . . 39,178 11,036 86,842 50,297
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 632 673 1,265 1,348
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 38,546 $ 10,363 $ 85,577 $ 48,949
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ----------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $191,232 $187,699 $175,854 $179,461
NET INCOME . . . . . . . . . . . . . . . 39,178 11,036 86,842 50,297
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 31,653 30,348 63,306 60,696
Cumulative Preferred Stock . . . . . 525 565 1,050 1,132
Capital Stock Expense. . . . . . . . . 106 108 214 216
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $198,126 $167,714 $198,126 $167,714
======== ======== ======== ========
The common stock of the Company is wholly owned by American Electric Power
Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $2,040,224 $2,014,968
Transmission . . . . . . . . . . . . . . . . . . . . 1,164,462 1,151,377
Distribution . . . . . . . . . . . . . . . . . . . . 1,778,715 1,741,685
General. . . . . . . . . . . . . . . . . . . . . . . 247,847 247,798
Construction Work in Progress. . . . . . . . . . . . 84,986 107,123
---------- ----------
Total Electric Utility Plant . . . . . . . . 5,316,234 5,262,951
Accumulated Depreciation and Amortization. . . . . . 2,128,020 2,079,490
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,188,214 3,183,461
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 299,777 160,546
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 2,023 64,828
Advances to Affiliates . . . . . . . . . . . . . . . 12,857 -
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 135,110 109,525
Affiliated Companies . . . . . . . . . . . . . . . 47,252 37,827
Miscellaneous. . . . . . . . . . . . . . . . . . . 10,728 9,154
Allowance for Uncollectible Accounts . . . . . . . (2,205) (2,609)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 49,356 58,161
Materials and Supplies . . . . . . . . . . . . . . . 57,134 56,917
Accrued Utility Revenues . . . . . . . . . . . . . . 40,389 53,418
Energy Trading Contracts . . . . . . . . . . . . . . 986,681 143,777
Prepayments. . . . . . . . . . . . . . . . . . . . . 7,554 7,713
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 1,346,879 538,711
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 448,905 436,894
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 29,973 34,788
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $5,313,748 $4,354,400
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
<S> <C> <C>
Outstanding - 13,499,500 Shares. . . . . . . . . . $ 260,458 $ 260,458
Paid-in Capital. . . . . . . . . . . . . . . . . . . 717,464 714,259
Retained Earnings. . . . . . . . . . . . . . . . . . 198,126 175,854
---------- ----------
Total Common Shareholder's Equity. . . . . . 1,176,048 1,150,571
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 18,188 18,491
Subject to Mandatory Redemption. . . . . . . . . . 11,860 20,310
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,435,207 1,539,302
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,641,303 2,728,674
---------- ----------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 122,295 132,130
---------- ----------
CURRENT LIABILITIES:
Preferred Stock Due Within One Year. . . . . . . . . 8,450 -
Long-term Debt Due Within One Year . . . . . . . . . 175,005 126,005
Short-term Debt. . . . . . . . . . . . . . . . . . . 145,675 123,480
Accounts Payable - General . . . . . . . . . . . . . 40,039 59,150
Accounts Payable - Affiliated Companies. . . . . . . 89,137 42,459
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 48,274 49,038
Customer Deposits. . . . . . . . . . . . . . . . . . 12,769 12,898
Interest Accrued . . . . . . . . . . . . . . . . . . 18,176 19,079
Energy Trading Contracts . . . . . . . . . . . . . . 973,727 140,279
Other. . . . . . . . . . . . . . . . . . . . . . . . 63,408 71,044
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 1,574,660 643,432
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 685,551 671,917
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 45,676 57,259
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 244,263 120,988
---------- ----------
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $5,313,748 $4,354,400
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
----------------
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . $ 86,842 $ 50,297
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . . 77,293 74,302
Deferred Federal Income Taxes. . . . . . . . . . . . . . . 15,054 13,895
Deferred Investment Tax Credits. . . . . . . . . . . . . . (2,332) (2,344)
Deferred Power Supply Costs (net). . . . . . . . . . . . . (11,938) 23,208
Extraordinary Gain - Discontinuance of SFAS No. 71 . . . . (8,938) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . (36,988) 18,981
Fuel, Materials and Supplies . . . . . . . . . . . . . . . 8,588 (17,635)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . 13,029 7,266
Accounts Payable . . . . . . . . . . . . . . . . . . . . . 27,567 (25,164)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . (3,321) (73,030)
Unrealized Gain on Trading Assets and Liabilities. . . . . . (19,438) (6,047)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . (15,855) (3,081)
--------- ---------
Net Cash Flows From Operating Activities . . . . . . . 129,563 60,648
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . (80,870) (86,808)
Proceeds from Sale of Property . . . . . . . . . . . . . . . 148 200
--------- ---------
Net Cash Flows Used For Investing Activities . . . . . (80,722) (86,608)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . 74,787 148,751
Change in Short-term Debt (net). . . . . . . . . . . . . . . 22,195 38,750
Change in Advances to Affiliates (net) . . . . . . . . . . . (12,857) -
Retirement of Cumulative Preferred Stock . . . . . . . . . . (210) (149)
Retirement of Long-term Debt . . . . . . . . . . . . . . . . (131,202) (77,236)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . (63,306) (60,696)
Dividends Paid on Cumulative Preferred Stock . . . . . . . . (1,053) (1,134)
--------- ---------
Net Cash Flows From (Used For) Financing Activities. . (111,646) 48,286
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . . (62,805) 22,326
Cash and Cash Equivalents at Beginning of Period . . . . . . . 64,828 7,755
--------- ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . . $ 2,023 $ 30,081
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $61,828,000 and
$61,693,000 and for income taxes was $21,198,000 and $18,062,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $7,451,000
and $8,845,000 in 2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements
should be read in conjunction with the 1999 Annual Report as
incorporated in and filed with the Form 10-K. Certain prior-period
amounts have been reclassified to conform to current-period
presentation. In the opinion of management, the 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. FINANCING ACTIVITIES
--------------------
In May 2000 the Company issued $75 million of floating rate
senior unsecured notes due 2001. During the first six months of 2000,
the Company reacquired the following first mortgage bonds for $101
million.
Principal
Amount
% Rate Due Date Reacquired
------ -------- ----------
(in thousands)
6.35 March 1, 2000 $48,000
6.71 June 1, 2000 48,000
7.125 May 1, 2024 5,000
In January 2000 the Company redeemed $30 million of
pollution control revenue bonds early with a due date of 2014. The
Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
3. RATE MATTERS
As discussed in Note 4 of the Notes to Consolidated Financial
Statements of the 1999 Annual Report, the AEP System companies filed a
settlement agreement with the Federal Energy Regulatory Commission
(FERC) for their approval to establish an open access transmission
tariff. The Company made a provision in 1999 for a refund including
interest for amounts paid in excess of the agreed to rate.
On March 16, 2000, the FERC approved the settlement agreement
filed in December 1999 resolving the issues on rehearing raised in a
July 30, 1999 order. Under terms of the settlement, AEP is required to
make refunds retroactive to September 7, 1993 to certain customers
affected by the July 30, 1999 FERC order. Pursuant to FERC orders the
refunds were made in two payments. 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 and a rate of $1.42
kw/month was established and took effect on June 16, 2000 in connection
with the consummation of the AEP and Central and South West Corporation
merger. Prior to January 1, 2000, the rate was $2.04 kw/month. Unless
the Company and the market grow the volume of physical power
transactions 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
As discussed in Note 4 of the Notes to Consolidated Financial
Statements of the 1999 Annual Report, the Company has been involved in
a rate proceeding regarding base and expanded net energy cost (ENEC)
rates. On February 7, 2000, the Company and other parties to the
proceeding filed a Joint Stipulation and Agreement for Settlement
(Joint Stipulation) with the Public Service Commission of West Virginia
(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 provided for in the WV
Restructuring Plan, see Note 4); the suspension of annual ENEC recovery
proceedings and deferral accounting for over or under recovery
effective January 1, 2000; and the retention, as a regulatory
liability, on the books of the net cumulative deferred ENEC recovery
balance of $66 million. The Joint Stipulation provides that when
deregulation of generation occurs in West Virginia (WV), the Company
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.
Also under the Joint Stipulation the Company's share of any net
savings from the merger between the Company and Central and South West
Corporation prior to December 31, 2004 shall be retained by the
Company. All costs incurred in the merger that were allocated to the
Company shall be fully charged to expense as of December 31, 2004 and
shall not be included in any WV rate proceeding after that date. After
December 31, 2004, any 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 in the deregulation legislation and, to the
extent possible, to recover any additional costs or obligations that
deregulation may impose. Regardless of whether the net cumulative
deferred ENEC recovery balance and the net merger savings are
sufficient to offset all of the Company's generation-related regulatory
assets, under the terms of the Joint Stipulation there will be no
further explicit adjustment to the Company'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 kilowatthour (kwh) wires charge provided in the WV
Restructuring Plan (see Note 4 for discussion of WV Restructuring
Plan). On June 2, 2000, the WVPSC issued an order approving the Joint
Stipulation.
<PAGE>
4. INDUSTRY RESTRUCTURING
----------------------
Restructuring legislation has been enacted in both of the
Company's retail jurisdictions that results in the transition from
cost-based regulation for generation to customer choice market pricing
for the supply of electricity. The enactment of restructuring
legislation and the ability to determine transition rates and wires
charges under restructuring legislation resulted in the discontinuance
of the application of Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of Regulation."
Prior to restructuring, the Company accounted for its 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 based on SFAS 101 "Accounting for the
Discontinuance of Application of Statement 71". Pursuant to those
requirements and further guidance provided in the Financial Accounting
Standards Board's Emerging Issues Task Force (EITF) Issue 97-4, a
company is required to write-off regulatory assets and liabilities
related to its deregulated operations, unless recovery of such amounts
is provided through rates to be collected in a portion of the company's
operations which continues to be cost-based 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, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to be Disposed of." A SFAS 121
accounting impairment analysis involves estimating future
non-discounted net cash flows arising from the use of an asset. If the
undiscounted net cash flows exceed the net book value of the asset,
then there is no impairment of the asset for accounting purposes.
As legislative and regulatory proceedings evolve, the Company
is applying the standards discussed above. Following is a summary of
restructuring legislation, the status of the transition and the status
of the Company's accounting to comply with the changes.
Virginia Restructuring
Under a 1999 Virginia restructuring law 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 State Corporation
Commission (Virginia SCC) that an effective competitive market exists
by January 1, 2004 but not later than January 1, 2005.
The Virginia restructuring law provides an opportunity for
recovery of just and reasonable net stranded generation-related 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 law 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
the Company does not intend to request new rates, its current rates
will become the capped rates.
West Virginia Restructuring Plan
As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the WVPSC issued an order on
January 28, 2000 approving an electricity restructuring plan. On March
11, 2000, the West Virginia 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.
The provisions of the restructuring plan provide for customer
choice to begin on January 1, 2001, or at a later date set by the WVPSC
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 costs including net regulatory assets; and establishment by
the Company of a rate stabilization deferral balance of $76 million 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 are 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. The Company's Joint Stipulation agreement, discussed in
Note 3 above, which was approved by the WVPSC on June 2, 2000 in
connection with a base rate filing, also provides additional mechanisms
to recover the Company's regulatory assets.
Application of SFAS 71 Discontinued
In June 2000 the Company discontinued the application of SFAS 71
for the Virginia and West Virginia retail jurisdictional portions of
its generation business since generation is no longer considered to be
cost-based regulated in those jurisdictions and the Company was able to
determine its transition rates and wires charges. The discontinuance in
the West Virginia 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 (See discussion in Note 3). The Company was also
able to discontinue application of SFAS 71 for the generation portion
of its Virginia retail jurisdiction after management decided that it
would not request capped rates different from its current rates. The
existence of effective restructuring legislation in Virginia and the
probability that the West Virginia legislation would become effective
with the passage of the required tax legislation in 2001 supported
management's decision to discontinue SFAS 71 regulatory accounting.
The discontinuance of SFAS 71 for generation resulted in an
extraordinary gain of $9 million because management believes that all
net regulatory assets related to the Virginia and West Virginia
generating business will be recovered. Under the provisions of EITF
97-4, the Company's generation-related 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. An accounting impairment analysis of generation assets under
SFAS 121 was performed which concluded there was no impairment of
generation assets.
5. CONTINGENCIES
Litigation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the deductibility of certain
interest deductions related to AEP's corporate owned life insurance
(COLI) program for taxable years 1991 through 1996 is under review by
the Internal Revenue Service (IRS). Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions. A
disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $79 million (including
interest).
The Company 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 any additional above market rate
interest on the contested amount. The payments to the IRS are included
on the consolidated balance sheet in other property and investments
pending the resolution of this matter. The Company is seeking refund
through litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District of
Ohio in 1998. 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. Notwithstanding the Tax Court's
decision in Winn-Dixie, 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 will vigorously pursue 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.
Federal EPA Complaint and Notice of Violation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company has been involved in
litigation regarding generating plant emissions. Notices of Violation
were issued and a complaint was filed by the U.S. Environmental
Protection Agency (Federal EPA) in the U.S. District Court that alleges
the Company, certain affiliates 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 extend unit
operating lives or increase 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 Company under the
Clean Air Act. A lawsuit against power plants owned by the Company
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 Company 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 Company 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, stranded cost wires
charges and future market prices for energy.
<PAGE>
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, Federal EPA had issued a final
rule (the NOx rule) that requires substantial reductions in nitrogen
oxide (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, had filed petitions
seeking a review of the final rule in the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court). In May 1999, the Appeals
Court indefinitely stayed the requirement that states develop revised
air quality programs to impose the NOx reductions but did not, however,
stay the final compliance date of May 1, 2003. In March 2000 the
Appeals Court issued a decision generally upholding the NOx rule. On
April 20, 2000, certain AEP System companies and other petitioners
filed for rehearing of this decision including a rehearing by the
entire Appeals Court. On June 22, 2000, the Appeals Court denied the
petition for rehearing and lifted the stay related to the states'
development of revised air quality programs to impose the NOx
reductions. The petition for a rehearing before the entire Appeals
Court was also denied. The AEP System companies subject to the NOx rule
plan to appeal to the U.S. Supreme Court.
Preliminary estimates indicate that compliance with NOx rule upheld by
the Appeals Court could result in required capital expenditures of
approximately $365 million for the Company. Since compliance costs
cannot be estimated with certainty, the actual costs to comply could be
significantly different than the Company's preliminary estimate
depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from
customers through regulated rates, wires charges or future market price
of electricity, they will have a material adverse effect on future
results of operations, cash flows and possibly financial condition.
Other
The Company continues to be involved in certain other matters discussed
in its 1999 Annual Report.
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
---------------------------------------
RESULTS OF OPERATIONS
Net income increased $28 million or 255% for the quarter and $36 million
or 73% for the year-to-date period due to increased operating income, an
increase in nonoperating income from electricity trading gains outside the
Company's traditional marketing area and an extraordinary gain from the
discontinuance of regulatory accounting.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $56 15 $ 84 10
Fuel Expense . . . . . . . . (7) (7) (32) (14)
Purchased Power Expense. . . 45 74 87 78
Maintenance Expense. . . . . (9) (24) (10) (14)
Federal Income Taxes . . . . 10 248 14 51
Nonoperating Income. . . . . 3 N.M. 5 N.M.
Extraordinary Gain . . . . . 9 N.M. 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
American Electric Power System Power Pool (AEP Power Pool). The Company as a
member of the AEP Power Pool shares in the revenues and cost of the AEP Power
Pool's wholesale sales and forward trades to neighboring utility systems and
power marketers. As a result of an affiliate's major industrial customer's
decision not to continue a purchase power agreement, additional power was
delivered to the AEP Power Pool. The Company's share of these AEP Power Pool
marketing and trading transactions within the AEP System's traditional marketing
area (within two transmission systems of AEP System) are recorded as operating
revenues and purchases. Forward trading sales and purchases are recorded on a
net basis in operating revenues.
<PAGE>
Fuel expense decreased due to discontinuance of deferred accounting for
over or under recovery of fuel cost effective January 1, 2000 as a result of a
Joint Stipulation and Agreement for Settlement approved by the Public Service
Commission of West Virginia (WVPSC).
The decrease in maintenance expense is due to the effect of boiler plant
maintenance repairs to the Amos Plant during 1999. Federal income taxes
attributable to operations increased primarily due to an increase in
pre-tax operating income. Nonoperating income increased due to an
increase in net gains from the non-regulated electric trading outside
the AEP Power
Pool's traditional marketing area. The AEP Power Pool enters into financial
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
and financial trading activities are included in nonoperating income.
The extraordinary gain in the second quarter was a result of the
discontinuance of Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation," for the generation
portion of the Company's business in Virginia and West Virginia as a result of
restructuring legislation in both states. 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 transmission and distribution portion of the
business and will be amortized as they are recovered through charges to
customers. The Company performed an accounting impairment analysis of generation
assets under SFAS 121 "Accounting for the Impairment of Long-lived Assets and
for Long-lived Assets to Be Disposed Of" and concluded there was no accounting
impairment of generation assets.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
first six months of 2000 were $88 million. Short-term debt increased by $22
million since December 1999. The Company has in the past, and may in the future,
acquire outstanding debt and preferred stock securities in open market
transactions.
<PAGE>
In January 2000 the Company redeemed $30 million of 7.40 pollution
control bonds due 2014 at 102%. In March 2000 the Company redeemed at maturity
$48 million of 6.35% first mortgage bonds. In June 2000 the Company issued $75
million of senior unsecured medium term notes with a variable interest rate due
in 2001. Also in June 2000 the Company redeemed at maturity $48 million of 6.71%
first mortgage bonds.
OTHER MATTERS
Litigation
As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the deductibility of certain interest deductions
related to AEP?s corporate owned life insurance (COLI) program for taxable years
1991 through 1996 is under review by the Internal Revenue Service (IRS).
Adjustments have been or will be proposed by the IRS disallowing COLI interest
deductions. A disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $79 million (including interest).
The Company 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 any additional above market rate interest on the
contested amount. The payments to the IRS are included on the consolidated
balance sheet in other property and investments pending the resolution of this
matter. The Company is seeking refund through litigation of all amounts paid
plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District of Ohio in
1998. 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. Notwithstanding the Tax Court?s decision in Winn-Dixie, 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 will vigorously pursue 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.
<PAGE>
Application of SFAS 71 Discontinued
In June 2000 the Company discontinued the application of SFAS 71 for the
Virginia and West Virginia retail jurisdictional portions of its generation
business since generation is no longer considered to be cost-based regulated in
those jurisdictions and the Company was able to determine its transition rates
and wires charges. The discontinuance in the West Virginia 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 (See discussion in Note 3). The Company
was also able to discontinue application of SFAS 71 for the generation portion
of its Virginia retail jurisdiction after management decided that it would not
request capped rates different from its current rates. The existence of
effective restructuring legislation in Virginia and the probability that the
West Virginia legislation would become effective with the passage of the
required tax legislation in 2001 supported management's decision to discontinue
SFAS 71 regulatory accounting.
The discontinuance of SFAS 71 for generation resulted in an
extraordinary gain of $9 million because management believes that all net
regulatory assets related to the Virginia and West Virginia generating business
will be recovered. Under the provisions of Financial Accounting Standards
Board's Emerging Issues Task Force (EITF) Issue 97-4, the Company's
generation-related 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. An accounting impairment analysis of
generation assets under SFAS 121 was performed which concluded there was no
impairment of generation assets.
Federal EPA Complaint and Notice of Violation
As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the Company has been involved in litigation regarding
generating plant emissions. Notices of Violation were issued and a complaint was
filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S.
District Court that alleges the Company, certain affiliates 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
extend unit operating lives or increase 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 Company under the Clean Air
Act. A lawsuit against power plants owned by the Company 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 Company 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 Company 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, stranded cost wires charges and future market prices
for energy. NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, Federal EPA had issued a final rule (the NOx rule)
that requires substantial reductions in nitrogen oxide (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, had filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals Court). In May
1999, the Appeals Court indefinitely stayed the requirement that states develop
revised air quality programs to impose the NOx reductions but did not, however,
stay the final compliance date of May 1, 2003. In March 2000 the Appeals Court
issued a decision generally upholding the NOx rule. On April 20, 2000, certain
AEP System companies and other petitioners filed for rehearing of this decision
including a rehearing by the entire Appeals Court. On June 22, 2000, the Appeals
Court denied the petition for rehearing and lifted the stay related to the
states' development of revised air quality programs to impose the NOx
reductions. The petition for a rehearing before the entire Appeals Court was
also denied. The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.
Preliminary estimates indicate that compliance with NOx rule upheld by
the Appeals Court could result in required capital expenditures of approximately
$365 million for the Company. Since compliance costs cannot be estimated with
certainty, the actual costs to comply could be significantly different than the
Company's preliminary estimate depending upon the compliance alternatives
selected to achieve reductions in NOx emissions. Unless such costs are recovered
from customers through regulated rates, wires charges or future market price of
electricity, they will have a material adverse effect on future results of
operations, cash flows and possibly financial condition.
Market Risks
The Company has certain market risks inherent in its business activities
from changes in electricity commodity prices and interest rates. Market risk
represents the risk of loss that may impact the Company due to adverse changes
in commodity market prices and interest rates. The Company's exposure to market
risk from the trading of electricity and related financial derivative
instruments, which are allocated to the Company through the American Electric
Power System Power Pool, were less than $8 million at June 30, 2000 and $4
million at December 31, 1999 based on the use of a risk measurement model which
calculates Value at Risk (VaR). The VaR is based on the variance - covariance
method using historical prices to estimate volatilities and correlations and
assuming a 95% confidence level and a three-day holding period.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $437,911 $383,783 $754,239 $666,060
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 140,841 106,397 230,238 174,312
Purchased Power. . . . . . . . . . . . 34,936 16,247 55,356 29,394
Other Operation. . . . . . . . . . . . 54,307 66,255 129,609 128,894
Maintenance. . . . . . . . . . . . . . 15,474 19,956 31,896 35,183
Depreciation and Amortization. . . . . 40,887 43,257 95,085 86,370
Taxes Other Than Federal Income Taxes. 19,922 22,971 37,456 46,296
Federal Income Taxes . . . . . . . . . 35,827 29,021 40,232 39,841
-------- -------- --------- --------
TOTAL OPERATING EXPENSES . . . 342,194 304,104 619,872 540,290
-------- -------- --------- --------
OPERATING INCOME . . . . . . . . . . . . 95,717 79,679 134,367 125,770
NONOPERATING INCOME. . . . . . . . . . . 1,815 1,199 2,362 2,147
-------- -------- --------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 97,532 80,878 136,729 127,917
INTEREST CHARGES . . . . . . . . . . . . 29,979 29,854 61,037 59,873
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 67,553 51,024 75,692 68,044
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 61 1,735 121 3,547
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 67,492 $ 49,289 $ 75,571 $ 64,497
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD
AS PREVIOUSLY REPORTED . . . . . . . $733,957 $717,767 $764,225 $739,031
CONFORMING CHANGE IN ACCOUNTING POLICY (5,984) (5,172) (5,331) (4,644)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF
PERIOD . . . . . . . . . . . . . . . . 727,973 712,595 758,894 734,387
NET INCOME . . . . . . . . . . . . . . . 67,553 51,024 75,692 68,044
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . 39,000 37,000 78,000 74,000
Preferred Stock. . . . . . . . . 61 1,735 121 3,547
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $756,465 $724,884 $756,465 $724,884
======== ======== ======== ========
The Company is a wholly owned subsidiary of American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $3,201,217 $3,152,319
Transmission. . . . . . . . . . . . . . . . . . . . . . . 577,345 566,629
Distribution. . . . . . . . . . . . . . . . . . . . . . . 1,190,819 1,157,091
General . . . . . . . . . . . . . . . . . . . . . . . . . 235,535 307,378
Construction Work in Progress . . . . . . . . . . . . . . 80,163 101,550
Nuclear Fuel. . . . . . . . . . . . . . . . . . . . . . . 228,013 226,927
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 5,513,092 5,511,894
Accumulated Depreciation. . . . . . . . . . . . . . . . . 2,266,917 2,263,925
---------- ----------
Net Electric Utility Plant. . . . . . . . . . . . 3,246,175 3,247,969
---------- ----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 42,765 41,433
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 4,342 5,830
Special Deposits for Reacquisition of Long-term Debt. . . - 50,000
Accounts Receivable:
General . . . . . . . . . . . . . . . . . . . . . . . . 42,182 49,228
Affiliate . . . . . . . . . . . . . . . . . . . . . . . 13,915 15,254
Materials and Supplies. . . . . . . . . . . . . . . . . . 56,469 58,196
Fuel Inventory. . . . . . . . . . . . . . . . . . . . . . 23,587 26,434
Under-recovered Fuel Costs. . . . . . . . . . . . . . . . 54,579 30,911
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 6,839 5,353
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 201,913 241,206
---------- ----------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 230,707 240,059
---------- ----------
REGULATORY ASSETS DESIGNATED FOR SECURITIZATION . . . . . . 953,249 953,219
---------- ----------
NUCLEAR DECOMMISSIONING TRUST . . . . . . . . . . . . . . . 91,045 86,122
---------- ----------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 26,985 37,812
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . $4,792,839 $4,847,850
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 12,000,000 Shares
<S> <C> <C>
Outstanding - 6,755,535 Shares. . . . . . . . . . . . . $ 168,888 $ 168,888
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 405,000 405,000
Retained Earnings . . . . . . . . . . . . . . . . . . . . 756,465 758,894
---------- ----------
TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . . 1,330,353 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 . . . . . . . . . . . . . . 150,000 150,000
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . . 1,454,554 1,304,541
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 2,940,874 2,793,290
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . - 150,000
Advances from Affiliates. . . . . . . . . . . . . . . . . 253,779 322,158
Accounts Payable - General. . . . . . . . . . . . . . . . 112,793 88,702
Accounts Payable - Affiliated Companies . . . . . . . . . 36,038 35,344
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 23,973 41,121
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 27,631 14,723
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 33,048 25,349
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 487,262 677,397
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 1,224,470 1,234,175
---------- ----------
DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . . 130,703 133,306
---------- ----------
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 9,530 9,682
---------- ----------
CONTINGENCIES (Note 6)
TOTAL . . . . . . . . . . . . . . . . . . . . . $4,792,839 $4,847,850
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 75,692 $ 68,044
Adjustments For Non-Cash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 101,723 95,659
Deferred Federal Income Taxes. . . . . . . . . . . . . . (9,255) (12,134)
Deferred Investment Tax Credits. . . . . . . . . . . . . (2,603) (2,602)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 8,385 (8,754)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 4,575 (714)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 24,785 (7,966)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (17,148) 14,603
Interest Accrued . . . . . . . . . . . . . . . . . . . . 12,908 (389)
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (23,668) 2,780
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 9,493 (1,072)
-------- --------
Net Cash Flows From Operating Activities . . . . . . 184,887 147,455
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (85,215) (80,142)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (4,067) (581)
-------- --------
Net Cash Flows Used For Investing Activities . . . . (89,282) (80,723)
-------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt . . . . . . . . . . . . . . . (100,000) (125,000)
Reacquisition of Long-term Debt. . . . . . . . . . . . . . (50,000) -
Special Deposit for Reacquisition of Long-term Debt. . . . 50,000 -
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 149,413 -
Changes in Advances from Affiliates. . . . . . . . . . . . (68,379) 140,337
Dividends Paid on Common Stock . . . . . . . . . . . . . . (78,000) (74,000)
Dividends Paid on Preferred Stock. . . . . . . . . . . . . (127) (3,923)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (97,093) (62,586)
-------- --------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (1,488) 4,146
Cash and Cash Equivalents at Beginning of Period . . . . . . 5,830 5,195
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 4,342 $ 9,341
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $46,981,000 and
$51,241,000 and for income taxes was $48,141,000 and $29,987,000 in 2000 and
1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements should be
read in conjunction with the Company's 1999 Form 10-K. Certain prior-period
amounts have been reclassified to conform to current-period presentation. In the
opinion of management, the 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. MERGER
In June 2000 the merger of American Electric Power Company, Inc. (AEP)
and Central and South West Corporation (CSW), the parent company of Central
Power and Light Company, was completed. As part of the change in control, an
adjustment to conform the Company's accounting for vacation pay accruals with
AEP's accounting policy was necessary.
The effect of the conforming change in accounting was to reduce net
assets by $5.3 million at December 31, 1999 and reduce net income by $0.7
million for the three months ended March 31, 2000 and by $0.4 million and $0.9
million for the three months and six months ended June 30, 1999, respectively.
In connection with the merger, the Texas Commission approved a
settlement agreement that provides for, among other things, sharing net merger
savings with customers over six years after consummation of the merger through
rate reduction riders. In the event that actual net merger savings are less than
the rate reduction riders, results of operations and cash flows will be
adversely affected.
3. TEXAS RESTRUCTURING
In June 1999 restructuring legislation was signed into law in Texas that
will restructure the electric utility industry (Texas Legislation). The Texas
Legislation, among other things:
o gives 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 nitrogen oxide and sulfur dioxide emissions;
o provides 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 sets an earnings test for the three years of rate freeze (1999 through 2001);
o sets certain limits for ownership and control of generation capacity by
companies; and
o requires a filing after January 10, 2004 to finalize stranded costs (2004
true-up proceeding) including final fuel recovery balances, 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 must submit a plan to unbundle its business activities into a
retail electric provider, a power generation company and a transmission and
distribution utility.
The Company and its affiliated electric utilities which operate in Texas
filed their business separation (unbundling) plan with the Public Utility
Commission of Texas (Texas Commission) on January 10, 2000. The filings
described a financial and accounting functional separation but not a legal or
structural separation, described how operations will be physically separated and
the functions they will perform, described competitive energy services, and
provided a code of conduct. In March 2000, the Texas Commission ruled that the
plan was not in compliance with the Texas Legislation and ordered revised plans
be submitted to separate the generation business from the wires business in
separate legal entities by January 1, 2002. In May 2000 a revised separation
plan was filed, which the Texas Commission approved on July 7, 2000 in an
interim order.
Under the Texas Legislation, electric utilities are allowed, with the
approval of the Texas Commission, 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 the Company filed an application with the
Texas Commission 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 Texas Commission tentatively approved a
settlement, which will permit the Company to securitize approximately $764
million of net regulatory assets. The Texas Commission'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.
The Company 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 requested by the Company in its 1999 securitization
request has been included in a March 2000 filing with the Texas Commission,
requesting recovery of an additional $1.1 billion of stranded costs. The March
2000 filing for $1.1 billion includes recovery of approximately $800 million of
South Texas Project (STP) nuclear plant costs included in utility plant on the
Balance Sheet and previously identified as "Excess Cost Over Market" (ECOM) by
the Texas Commission for regulatory purposes. A final determination on recovery
will occur as part of the 2004 true-up proceeding and the total amount
recoverable can be securitized.
On April 11, 2000, four parties appealed the Texas Commission's
securitization order to the Travis County District Court. One of these appeals
challenges the ability to recover securitization charges under the Texas
Constitution. The Company will not be able to issue the securitization bonds
until these appeals are resolved. As a result, the securitization bonds are not
likely to be issued until 2001.
The Company's financial statements have historically reflected the
effects of applying the requirements of Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation". Pursuant to those requirements, regulatory assets and liabilities
have been recorded to reflect the economic effect of cost-based regulation. When
a company determines that its operations or a segment of its operations are no
longer cost-based rate regulated, it is required to apply the provisions of SFAS
101 "Accounting for the Discontinuance of Application of Statement 71". Pursuant
to those requirements and further guidance provided in the Financial Accounting
Standards Board's Emerging Issues Task Force (EITF) Issue 97-4, a regulated
entity is required to write-off regulatory assets and liabilities related to the
portion of its operations whose rates will no longer be cost-based regulated,
unless recovery of such amounts is provided through rates to be collected in the
portion of the company's operations which continue to be regulated.
Additionally, the Company is required to determine if any plant assets are
impaired under SFAS 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and record any accounting impairment.
As a result of the scheduled deregulation of generation under the Texas
Legislation, the application of SFAS 71 for the generation portion of the
Company's business in Texas was discontinued in 1999. Under the provisions of
EITF 97-4, the Company's generation-related 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 of the
regulated distribution business. Since the Company has net stranded costs,
management currently believes that substantially all generation-related
regulatory assets should be recovered as provided by the Texas Legislation when
an electric utility has a stranded cost. If future events were to occur that
made the recovery of regulatory assets no longer probable, the Company would
write-off the portion of such assets deemed unrecoverable as a non-cash charge
to earnings.
Recovery of generation-related regulatory assets and stranded costs are
subject to a final determination by the Texas Commission in 2004. The Texas
Legislation provides that all such finally determined stranded costs will be
recovered.
An impairment analysis for generation assets under SFAS 121 was
completed which concluded there was no accounting impairment of generation
assets at the time the Company discontinued application of SFAS 71. An
impairment analysis involves estimating future net cash flows arising from the
use of an asset. If the undiscounted net cash flows exceed the net book value of
the asset, then there is no impairment of the asset to record for accounting
purposes. The Company will test its generation assets for impairment under SFAS
121 when circumstances change. However, on a discounted basis the cash flows are
less than the Company's generating asset's net book value and together with the
Company's generation-related regulatory assets create a recoverable stranded
cost under the Texas Legislation.
The Texas Legislation also 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 any earnings in excess of the
most recently approved cost of capital in its last rate case must be applied to
reduce stranded costs. As a result, the Company recorded a charge to earnings of
$32 million for the 1999 estimated excess earnings under the Texas Legislation.
The Texas Commission is required under the Texas Legislation to certify that the
Company's calculation of excess earnings for 1999 is correct by September 30,
2000.
A Texas settlement agreement in connection with the AEP and CSW merger
permits the Company 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, plant assets will be depreciated on a systematic and rational
basis unless impaired. To the extent excess earnings exceed $20 million in
2000 or 2001 the Company will establish a regulatory liability by a charge
to earnings.
Beginning January 1, 2002, fuel costs will not be subject to Texas
Commission fuel reconciliation proceedings. Consequently, the Company will file
a final fuel reconciliation with the Texas Commission which reconciles its fuel
costs through the period ending December 31, 2001. Any final fuel balances will
be included for recovery in the 2004 true-up proceeding.
<PAGE>
The Company continues to analyze the impact of the Texas electric utility
industry restructuring legislation on its operations. Although management
believes that the Texas Legislation provides for full recovery of the Company's
stranded costs and that the Company does not have a recordable accounting
impairment, a final determination of whether the Company will experience any
accounting loss from an inability to recover generation-related assets and other
restructuring related costs in Texas cannot be made until such time as the
litigation and the regulatory process are complete following the 2004 true-up
proceeding. In the event the Company is unable after the 2004 true-up proceeding
to recover all or a portion of its 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.
4. RATE MATTERS
Texas Base Rates
In November 1995 the Company filed with the Texas Commission a request
to increase its retail base rates by $71 million. In October 1997 the Texas
Commission issued a final order which lowered the Company's annual retail base
rates by $19 million from the rate level which existed prior to May 1996. The
Texas Commission 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.
The Company appealed the final order to the State District Court of
Travis County (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. The Company has a 25.2% ownership
interest in the 2,501 MW STP. As part of the appeal, the Company sought a
temporary injunction to prohibit the Texas Commission 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 District
Court affirmed the Texas Commission order in regard to the three major items
discussed above.
The Company appealed the District Court's findings to the Third
District of Texas Court of Appeals (Appeals Court) which in July 2000, issued
its opinion upholding the District Court except for the disallowance of an
affiliated service billings. Under Texas law, specific findings regarding
affiliate transactions must be made by the Texas Commission. In regards to the
affiliate expense issue, the findings were not complete in the opinion of the
Appeals Court who remanded the issue back to the Texas Commission. Management
intends to seek a rehearing of the Appeals Court's opinion and is unable to
predict the final resolution of its appeal. If the Company is unsuccessful in
its appeal it will continue to adversely affect the Company's results of
operations, cash flows and possibly financial condition.
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. The Company will continue its appeal of the
ECOM classification of STP property and the disallowed affiliated billings.
Fuel Factor Filings
In March 2000 the Texas Commission approved a settlement related to the
Company'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 surcharge to provide $24.7 million for under recovered fuel cost
beginning in April 2000.
In July 2000 the Company filed with the Texas Commission an application
for authority to implement an increase in fuel factors effective with the
September 2000 billing month. The Company 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 early August
2000, a settlement was reached between the various parties. The settlement
allows for an increase in fuel factor revenues of $173.5 million annually and
provides for a surcharge of $21.3 million for under-recovered fuel costs for the
period of December 1999 through May 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 will be made in September 2000. The settlement requires
the approval of the Texas Commission.
5. FINANCING ACTIVITIES
In February 2000 the Company sold $150 million of unsecured floating
rate notes. The notes have a two-year final maturity of February 22, 2002, but
may be redeemed at par after one year. The interest rate will reset quarterly at
the then current three-month London Inter-Bank Overnight Rate (LIBOR) plus
0.45%. The initial rate, set February 18, 2000, was 6.56%. Net proceeds of
$149.4 million were used to refund $100 million of Series HH, 6% First Mortgage
Bonds maturing April 1, 2000 and to repay a portion of short-term debt.
In March 2000 the Company reacquired $50 million of its 7-1/2% Series
AA First Mortgage Bonds due March 1, 2020. The reacquisition was funded from the
issuance of Series 1999B in December 1999 the proceeds of which were placed in a
special deposit for reacquisition.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
6. CONTINGENCIES
Municipal Franchise Fee Litigation
The Company 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 the Company underpaid
municipal franchise fees and seeks damages of up to $300 million plus attorney's
fees. The Company 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 the
Company. Over 90 of the 128 cities declined to participate in the lawsuit.
However, the Company has pledged that if any final, non-appealable court
decision in the litigation awards a judgement against it for a franchise
underpayment, the principles of that decision will be extended, with regard to
the franchise underpayment, to the cities that decline 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 the Company 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 the Company's results of operations, cash flows
or financial condition. If the Company is unsuccessful in defending itself
against these claims it could have a material adverse effect on results of
operations, cash flows and financial condition.
NOx Reductions
On April 19, 2000, the Texas Natural Resource Conservation Commission
adopted regulations that require reductions in nitrogen oxide (NOx) emissions
for existing permitted electric generating facilities in the East Texas Region.
The Company's implementation date for the regulations is 2003.
Preliminary estimates indicate that compliance with the NOx rule could
result in required capital expenditures of approximately $38 million for the
Company. Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's preliminary
estimate depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from customers
through regulated rates and/or reflected in the future market price of
electricity when generation is deregulated, they will have an adverse effect on
future results of operations and cash flows.
Other
The Company continues to be involved in other matters discussed in its
1999 Form 10-K.
<PAGE>
CENTRAL POWER AND LIGHT COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
-----------------------------------------------------------------------------
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
CPL's net income for the second quarter was $17 million or 32% higher
than the comparable period in 1999 and year-to-date net income was $8 million or
11% higher largely as a result of increased sales to residential and commercial
customers for the year-to-date period and reductions in operating expense for
the quarter and year-to-date periods.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $54 14 $88 13
Fuel Expense . . . . . . . . 34 32 56 32
Purchased Power Expense. . . 19 115 26 88
Other Operation Expense. . . (12) (18) 1 1
Maintenance Expense. . . . . (4) (22) (3) (9)
Depreciation Expense . . . . (2) (5) 9 10
Taxes Other Than Federal
Income Taxes . . . . . . . (3) (13) (9) (19)
Federal Income Taxes . . . . 7 23 - -
Preferred Stock Dividends. . (2) (96) (3) (97)
Operating revenues increased as a result of a rise in fuel related
revenue due primarily to increased fuel revenues to recover higher fuel and
purchased power expenses and increased energy sales reflecting a rise in
residential and commercial customer demand. Higher 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 additional economy, capacity and cogeneration purchase expenses.
Other operation expenses were reduced in the second quarter primarily
due to a reduction in transmission expenses that resulted from a new prices for
the Electric Reliability Council of Texas (ERCOT) transmission grid. Each year
ERCOT establishes new rates to allocate the costs of the Texas transmission
system to Texas electric utilities. The lower transmission expenses were offset
in part by higher administrative expenses resulting from a change in the method
of recording vacation expense, regulatory restructuring expense for unbundling,
consulting expenses for a sales tax audit and insurance expense. Other operation
expenses increased for the first six months due primarily to higher
administrative expenses resulting from increased consulting expense for a sales
tax audit, insurance expense, regulatory restructing expenses and a change in
the method of recording vacation expense. These increases were largely offset by
lower transmission expenses resulting from the new prices for the ERCOT
transmission grid.
Although STP Unit 1 underwent a maintenance outage in 2000, maintenance
expense declined due to a reduction in fossil power plant repairs and
maintenance activities. In 1999 maintenance activities included the refueling
and 10-year Nuclear Regulatory Commission required inspection of STP Unit 1.
Depreciation and amortization expenses decreased in the second quarter
reflecting the absence in 2000 of amortization for certain regulatory assets
that have been designated for securitization. The increase in depreciation and
amortization expenses for the year-to-date period reflects an accrual adjustment
in the first quarter of 2000 for a 1999 earnings cap imposed by the Texas
Commission and filed in March 2000, offset in part by the absence of
amortization in 2000 for certain regulatory assets designated for
securitization.
The decline in taxes other than federal income taxes was mainly
attributable to a favorable accrual adjustment to ad valorem tax expense in
2000.
Federal income tax expense attributable to utility operations increased
in the second quarter as a result of higher pre-tax income offset in part by the
absence of nondeductible amortization associated with certain assets designated
for securitization.
Preferred stock dividends decreased as a result of the redemption of
CPL's money market and auction preferred stock in fourth quarter of 1999.
FINANCIAL CONDITION
Total plant and property additions for the year to period were $85
million.
In February 2000 the Company sold $150 million of unsecured
floating rate notes. The notes have a two-year final maturity of February 22,
2002, but may be redeemed at par after one year. The interest rate will reset
quarterly at the then current three-month London Inter-Bank Overnight Rate
(LIBOR) plus 0.45%. The initial rate, set February 18, 2000, was 6.56%. Net
proceeds of $149.4 million were used to refund $100 million of Series HH, 6%
First Mortgage Bonds maturing April 1, 2000 and to repay a portion of short-term
debt.
In March 2000 the Company reacquired $50 million of its 7-1/2% Series
AA First Mortgage Bonds due March 1, 2020. The reacquisition was funded from the
issuance of Series 1999B in December 1999 the proceeds of which were placed in a
special deposit for reacquisition.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
MARKET RISKS
The Company has certain market risks inherent in its business
activities from changes in interest rates. Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
OTHER MATTERS
Texas Restructuring
In June 1999 restructuring legislation was signed into law in Texas that
will restructure the electric utility industry (Texas Legislation). The Texas
Legislation, among other things:
o gives 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 nitrogen oxide and sulfur dioxide emissions;
o provides 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 sets an earnings test for the three years of rate freeze (1999 through 2001);
o sets certain limits for ownership and control of generation capacity by
companies; and
o requires a filing after January 10, 2004 to finalize stranded costs (2004
true-up proceeding) including final fuel recovery balances, 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 must submit a plan to
unbundle its business activities into a retail electric provider, a power
generation company and a transmission and distribution utility.
The Company and its affiliated electric utilities which operate in Texas
filed their business separation (unbundling) plan with the Public Utility
Commission of Texas (Texas Commission) on January 10, 2000. The filings
described a financial and accounting functional separation but not a legal or
structural separation, described how operations will be physically separated and
the functions they will perform, described competitive energy services, and
provided a code of conduct. In March 2000, the Texas Commission ruled that the
plan was not in compliance with the Texas Legislation and ordered revised plans
be submitted to separate the generation business from the wires business in
separate legal entities by January 1, 2002. In May 2000 a revised separation
plan was filed, which the Texas Commission approved on July 7, 2000 in an
interim order.
Under the Texas Legislation, electric utilities are allowed, with the
approval of the Texas Commission, 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 the Company filed an application with the
Texas Commission 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 Texas Commission tentatively approved a
settlement, which will permit the Company to securitize approximately $764
million of net regulatory assets. The Texas Commission'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.
The Company 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 requested by the Company in its 1999 securitization
request has been included in a March 2000 filing with the Texas Commission,
requesting recovery of an additional $1.1 billion of stranded costs. The March
2000 filing for $1.1 billion includes recovery of approximately $800 million of
South Texas Project (STP) nuclear plant costs included in utility plant on the
Balance Sheet and previously identified as "Excess Cost Over Market" (ECOM) by
the Texas Commission for regulatory purposes. A final determination on recovery
will occur as part of the 2004 true-up proceeding and the total amount
recoverable can be securitized.
On April 11, 2000, four parties appealed the Texas Commission's
securitization order to the Travis County District Court. One of these appeals
challenges the ability to recover securitization charges under the Texas
Constitution. The Company will not be able to issue the securitization bonds
until these appeals are resolved. As a result, the securitization bonds are not
likely to be issued until 2001.
The Company's financial statements have historically reflected the
effects of applying the requirements of Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation". Pursuant to those requirements, regulatory assets and liabilities
have been recorded to reflect the economic effect of cost-based regulation. When
a company determines that its operations or a segment of its operations are no
longer cost-based rate regulated, it is required to apply the provisions of SFAS
101 "Accounting for the Discontinuance of Application of Statement 71". Pursuant
to those requirements and further guidance provided in the Financial Accounting
Standards Board's Emerging Issues Task Force (EITF) Issue 97-4, a regulated
entity is required to write-off regulatory assets and liabilities related to the
portion of its operations whose rates will no longer be cost-based regulated,
unless recovery of such amounts is provided through rates to be collected in the
portion of the company's operations which continue to be regulated.
Additionally, the Company is required to determine if any plant assets are
impaired under SFAS 121, "Accounting for the Impairment of Long-Lived Assets and
for Long-Lived Assets to be Disposed of" and record any accounting impairment.
As a result of the scheduled deregulation of generation under the Texas
Legislation, the application of SFAS 71 for the generation portion of the
Company's business in Texas was discontinued in 1999. Under the provisions of
EITF 97-4, the Company's generation-related 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 of the
regulated distribution business. Since the Company has net stranded costs,
management currently believes that substantially all generation-related
regulatory assets should be recovered as provided by the Texas Legislation when
an electric utility has a stranded cost. If future events were to occur that
made the recovery of regulatory assets no longer probable, the Company would
write-off the portion of such assets deemed unrecoverable as a non-cash charge
to earnings.
Recovery of generation-related regulatory assets and stranded costs are
subject to a final determination by the Texas Commission in 2004. The Texas
Legislation provides that all such finally determined stranded costs will be
recovered.
An impairment analysis for generation assets under SFAS 121 was
completed which concluded there was no accounting impairment of generation
assets at the time the Company discontinued application of SFAS 71. An
impairment analysis involves estimating future net cash flows arising from the
use of an asset. If the undiscounted net cash flows exceed the net book value of
the asset, then there is no impairment of the asset to record for accounting
purposes. The Company will test its generation assets for impairment under SFAS
121 when circumstances change. However, on a discounted basis the cash flows are
less than the Company's generating asset's net book value and together with the
Company's generation-related regulatory assets create a recoverable stranded
cost under the Texas Legislation.
The Texas Legislation also 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 any earnings in excess of the
most recently approved cost of capital in its last rate case must be applied to
reduce stranded costs. As a result, the Company recorded a charge to earnings of
$32 million for the 1999 estimated excess earnings under the Texas Legislation.
The Texas Commission is required under the Texas Legislation to certify that the
Company's calculation of excess earnings for 1999 is correct by September 30,
2000.
A Texas settlement agreement in connection with the AEP and CSW merger
permits the Company 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, plant assets will be depreciatied on a systematic and
rational basis unless impaired. To the extent excess earnings exceed
$20 million in 2000 or 2001 the Company will establish a regulatory liability
by a charge to earnings.
Beginning January 1, 2002, fuel costs will not be subject to Texas
Commission fuel reconciliation proceedings. Consequently, the Company will file
a final fuel reconciliation with the Texas Commission which reconciles its fuel
costs through the period ending December 31, 2001. Any final fuel balances will
be included for recovery in the 2004 true-up proceeding.
The Company continues to analyze the impact of the Texas electric utility
industry restructuring legislation on its operations. Although management
believes that the Texas Legislation provides for full recovery of the Company's
stranded costs and that the Company does not have a recordable accounting
impairment, a final determination of whether the Company will experience any
accounting loss from an inability to recover generation-related assets and other
restructuring related costs in Texas cannot be made until such time as the
litigation and the regulatory process are complete following the 2004 true-up
proceeding. In the event the Company is unable after the 2004 true-up proceeding
to recover all or a portion of its 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.
Municipal Franchise Fee Litigation
The Company 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 the Company underpaid
municipal franchise fees and seeks damages of up to $300 million plus attorney's
fees. The Company 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 the
Company. Over 90 of the 128 cities declined to participate in the lawsuit.
However, the Company has pledged that if any final, non-appealable court
decision in the litigation awards a judgement against it for a franchise
underpayment, the principles of that decision will be extended, with regard to
the franchise underpayment, to the cities that decline 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 the Company 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 the Company's results of operations, cash flows
or financial condition. If the Company is unsuccessful in defending itself
against these claims it could have a material adverse effect on results of
operations, cash flows and financial condition.
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ---------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $330,914 $301,419 $629,220 $580,486
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 48,581 49,144 89,329 95,000
Purchased Power. . . . . . . . . . . . 87,993 59,255 167,696 114,446
Other Operation. . . . . . . . . . . . 50,332 46,514 95,621 92,483
Maintenance. . . . . . . . . . . . . . 18,228 18,374 32,924 32,320
Depreciation . . . . . . . . . . . . . 24,896 23,522 49,440 46,706
Taxes Other Than Federal Income Taxes. 31,084 30,051 62,561 61,129
Federal Income Taxes . . . . . . . . . 19,002 20,086 36,727 37,882
-------- -------- -------- --------
TOTAL OPERATING EXPENSES . . . 280,116 246,946 534,298 479,966
-------- -------- -------- --------
OPERATING INCOME . . . . . . . . . . . . 50,798 54,473 94,922 100,520
NONOPERATING INCOME (LOSS) . . . . . . . 2,497 (478) 4,181 (117)
-------- -------- -------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 53,295 53,995 99,103 100,403
INTEREST CHARGES . . . . . . . . . . . . 17,960 19,436 36,297 38,426
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 35,335 34,559 62,806 61,977
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 532 532 1,065 1,065
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,803 $ 34,027 $ 61,741 $ 60,912
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
--------------------- ---------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $249,872 $191,327 $246,584 $186,441
NET INCOME . . . . . . . . . . . . . . . 35,335 34,559 62,806 61,977
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 23,650 21,999 47,300 43,998
Cumulative Preferred Stock . . . . . 438 438 875 875
Capital Stock Expense. . . . . . . . . 95 95 191 191
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $261,024 $203,354 $261,024 $203,354
======== ======== ======== ========
The common stock of the Company is wholly owned by American Electric Power
Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $1,554,376 $1,544,858
Transmission . . . . . . . . . . . . . . . . . . . . 354,598 350,826
Distribution . . . . . . . . . . . . . . . . . . . . 1,071,101 1,032,550
General. . . . . . . . . . . . . . . . . . . . . . . 146,656 141,137
Construction Work in Progress. . . . . . . . . . . . 73,370 82,248
---------- ----------
Total Electric Utility Plant . . . . . . . . 3,200,101 3,151,619
Accumulated Depreciation . . . . . . . . . . . . . . 1,253,003 1,210,994
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,947,098 1,940,625
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 178,934 101,286
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 9,319 5,107
Advances to Affiliates . . . . . . . . . . . . . . . 61,504 -
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 2,376 77,418
Affiliated Companies . . . . . . . . . . . . . . . 17,208 28,453
Miscellaneous. . . . . . . . . . . . . . . . . . . 8,976 8,887
Allowance for Uncollectible Accounts . . . . . . . (567) (3,045)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 18,106 21,484
Materials and Supplies . . . . . . . . . . . . . . . 43,627 41,696
Accrued Utility Revenues . . . . . . . . . . . . . . 1,701 48,117
Energy Marketing and Trading Contracts . . . . . . . 572,306 90,103
Prepayments. . . . . . . . . . . . . . . . . . . . . 49,868 37,969
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 784,424 356,189
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 340,005 339,103
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 41,862 72,787
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $3,292,323 $2,809,990
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
<S> <C> <C>
Outstanding - 16,410,426 Shares. . . . . . . . . . $ 41,026 $ 41,026
Paid-in Capital. . . . . . . . . . . . . . . . . . . 573,063 572,873
Retained Earnings. . . . . . . . . . . . . . . . . . 261,024 246,584
---------- ----------
Total Common Shareholder's Equity. . . . . . 875,113 860,483
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . . 15,000 25,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 917,832 924,545
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . 1,807,945 1,810,028
---------- ----------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 41,535 43,056
---------- ----------
CURRENT LIABILITIES:
Preferred Stock Due Within One Year. . . . . . . . . 10,000 -
Short-term Debt. . . . . . . . . . . . . . . . . . . - 45,500
Accounts Payable - General . . . . . . . . . . . . . 26,726 28,279
Accounts Payable - Affiliated Companies. . . . . . . 66,503 52,776
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 89,582 143,477
Interest Accrued . . . . . . . . . . . . . . . . . . 13,854 13,936
Energy Marketing and Trading Contracts . . . . . . . 564,793 87,911
Other. . . . . . . . . . . . . . . . . . . . . . . . 36,648 34,375
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 808,106 406,254
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 447,105 447,607
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 43,022 44,716
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 144,610 58,329
---------- ----------
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . . $3,292,323 $2,809,990
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 62,806 $ 61,977
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 49,709 46,837
Deferred Federal Income Taxes. . . . . . . . . . . . . . 6,783 2,697
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,694) (1,737)
Deferred Collection of Fuel Costs (net). . . . . . . . . (1,835) 4,252
Amortization of Deferred Property Taxes. . . . . . . . . 33,721 34,406
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 83,720 (801)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 1,447 (2,186)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 46,416 (13,498)
Prepayments. . . . . . . . . . . . . . . . . . . . . . . (11,899) (8,717)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 12,174 (6,685)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (53,895) (32,378)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (2,274) (10,806)
-------- --------
Net Cash Flows From Operating Activities . . . . . . 225,179 73,361
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (59,372) (46,005)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 463 261
-------- --------
Net Cash Flows Used For Investing Activities . . . . (58,909) (45,744)
-------- --------
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . . (45,500) 17,900
Change in Advances to Affiliates (net) . . . . . . . . . . (61,504) -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (6,879) -
Dividends Paid on Common Stock . . . . . . . . . . . . . . (47,300) (43,998)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (875) (875)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (162,058) (26,973)
-------- --------
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 4,212 644
Cash and Cash Equivalents at Beginning of Period . . . . . . 5,107 7,206
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 9,319 $ 7,850
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $34,547,000 and
$36,491,000 and for income taxes was $35,539,000 and $14,207,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $3,233,000
and $4,043,000 in 2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements
should be read in conjunction with the 1999 Annual Report as
incorporated in and filed with the Form 10-K. In the opinion of
management, the 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. MONEY POOL
On June 15, 2000, the Company became a participant in the American
Electric Power (AEP) System Money Pool (Money Pool). The Money Pool is a
mechanism structured to meet the short-term cash requirements of the
participants with AEP Company, Inc. acting as the primary borrower on
behalf of the Money Pool. The Company's affiliates that are U.S.
domestic electric utility operating companies are the primary
participants in the Money Pool.
The operation of the Money Pool is designed to match on a daily
basis the available cash and borrowing requirements of the participants.
Participants with excess cash loan funds to the Money Pool reducing the
amount of external funds AEP Company, Inc. needs to borrow to meet the
short-term cash requirements of other participants with advances from
the Money Pool. AEP Company, Inc. borrows the funds needed on a daily
basis 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 Company, Inc. is
applied to each Money Pool participant's daily outstanding investment or
debt position to determine interest income or interest expense. Interest
income is included in nonoperating income, and interest expense is
included in interest charges. As a result of becoming a Money Pool
participant, the Company retired its short-term debt. At June 30, 2000
the Company was a net investor in the Money Pool and reports its
investment in the Money Pool as Advances to Affiliates on the Balance
Sheets.
3. RATE MATTERS
As discussed in Note 2 of the Notes to Consolidated Financial
Statements of the 1999 Annual Report, the AEP System companies filed a
settlement agreement for Federal Energy Regulatory Commission (FERC)
approval related to an open access transmission tariff. The Company made a
provision in 1999 for an agreed to refund including interest.
<PAGE>
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, AEP is 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 and a rate of $1.42 kw/month was established and took effect on
June 16, 2000 after the consummation of the AEP and Central and South West
Corporation merger. Prior to January 1, 2000, the rate was $2.04 kw/month.
Unless the Company and the market grow the volume of physical power
transactions to increase utilization of the AEP System's transmission
lines, the new open access transmission rate will adversely impact future
results of operations and cash flows.
4. FACTORING OF RECEIVABLES
In June 2000, Columbus Southern Power Company entered into a factoring
arrangement with an affiliate, CSW Credit, Inc. Under this arrangement
the Company sells without recourse its retail customer accounts
receivable and accrued utility revenue balances to CSW Credit and is
charged a fee based on CSW Credit's financing costs, uncollectible
accounts experience for the Company's receivables and administrative
costs. The costs of factoring customer accounts receivable is reported as
an operating expense. At June 30, 2000 the amount of factored accounts
receivable and accrued utility revenues was $119 million.
<PAGE>
5. OHIO RESTRUCTURING LAW AND TRANSITION PLAN FILING
-------------------------------------------------
As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Ohio Electric Restructuring Act
of 1999 (the 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 Act also provides for a
five-year transition period to move from cost-based rates to market
pricing for generation services. It authorizes the Public Utilities
Commission of Ohio (PUCO) to address certain major transition issues
including unbundling of rates and the recovery of generation-related
transition costs which include regulatory assets, asset impairments and
other stranded costs, employee severance and retraining costs, consumer
education costs and other costs. Stranded costs are generation costs that
are not deemed to be recoverable in a competitive market.
On March 28, 2000 the PUCO staff issued its report on the Company's
transition plan filing. On May 8, 2000, a stipulation agreement between
the Company, the PUCO staff, the Ohio Consumers' Counsel and other
concerned parties was filed with the PUCO for approval. The key provisions
of the stipulation agreement are:
- Recovery of generation-related regulatory assets over eight years
will be through a frozen transition rate for the first five years
and a wires charge for the remaining years.
- A shopping incentive (a price credit) of 2.5 mills/kwh for the first 25%
of residential customers that switch suppliers. ? The Company is to absorb
the first $20 million 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.
- The Company and its affiliate, Ohio Power Company, 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 Pennsylvania - New Jersey - Maryland
transmission organization (PJM) and/or a midwest independent system
operator (Midwest ISO) on generation originating in the Midwest ISO
or PJM areas.
- The statutory 5% reduction in the generation component of
residential tariffs will remain in effect for the entire transition
period.
- The Company's request for a $40 million gross receipts tax
rider to recover duplicate gross receipts tax will be
separately litigated.
Hearings on the stipulation and the gross receipts tax issue were
held in June 2000. Approval of the stipulation agreement by the PUCO is
pending.
Management has concluded that as of June 30, 2000 the requirements
to apply Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation," continue to
be met since the Company's rates for generation will continue to be
cost-based regulated until the PUCO takes action on the transition plan as
required by the Act. The establishment of rates and wires charges under a
PUCO approved transition plan will enable the Company to determine its
ability to recover stranded costs including regulatory assets, and other
transition costs, a requirement to discontinue the application of SFAS 71.
When the transition plan and transition period tariff schedules are
approved, the application of SFAS 71 will be discontinued for the Ohio
retail jurisdictional portion of the generating business. Management
expects this to occur when the PUCO approves the stipulation agreement for
the Company's transition plan filing. The Act requires that the PUCO issue
its order to approve transition plan filings no later than October 31,
2000.
Upon the discontinuance of SFAS 71 the Company will have to write
off its Ohio jurisdictional generation-related regulatory assets to the
extent that they cannot be recovered under the tariff schedules in the
transition plan approved by the PUCO and record any asset accounting
impairments in accordance with SFAS 121, "Accounting for the Impairment of
Long-lived Assets and for Long-lived Assets to Be Disposed Of." An
impairment loss would be recorded, under SFAS 121, to the extent that the
cost of generating assets cannot be recovered through non-discounted
generation-related revenues during the transition period and future market
prices. Until the PUCO completes its regulatory process and issues an
order related to the Company's transition plan, it is not possible for
management to determine if any of the Company's generating assets are
impaired for accounting purposes in accordance with SFAS 121.
The amount of regulatory assets recorded on the books at June 30,
2000 applicable to the Ohio retail jurisdictional generating business is
$301 million before related tax effects. Recovery of these regulatory
assets is being sought as a part of the Company's Ohio transition plan
filing. Based on current projections of future market prices, the Company
does not anticipate that it will experience material tangible asset
accounting impairment write-offs. Whether the Company will experience
material regulatory asset write-offs will depend on whether the PUCO
approves the Company's stipulation agreement which provides for their
recovery.
A determination of whether the Company will experience any asset
impairment loss regarding its Ohio retail jurisdictional generating assets
and any loss from a possible inability to recover Ohio generation-related
regulatory assets and other transition costs cannot be made until the PUCO
takes action on the Company's stipulation agreement. Should the PUCO fail
to fully approve the Company's stipulation agreement and its transition
tariff schedules, which include recovery of the Company's
generation-related regulatory assets, stranded costs and other transition
costs, it could have a material adverse effect on results of operations,
cash flows and possibly financial condition.
<PAGE>
6. CONTINGENCIES
COLI Litigation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the deductibility of certain
interest deductions related to AEP?s corporate owned life insurance (COLI)
program for taxable years 1991 through 1996 is under review by the
Internal Revenue Service (IRS). Adjustments have been or will be proposed
by the IRS disallowing COLI interest deductions. A disallowance of the
COLI interest deductions through June 30, 2000 would reduce earnings by
approximately $43 million (including interest).
The Company 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 any additional above market rate
interest on the contested amount. The payments to the IRS are included on
the consolidated balance sheet in other property and investments pending
the resolution of this matter. The Company is seeking refund through
litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District of Ohio
in 1998. 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. Notwithstanding the Tax Court's decision in
Winn-Dixie, 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 will vigorously
pursue 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.
Federal EPA Complaint and Notice of Violation
<PAGE>
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company has been involved in
litigation regarding generating plant emissions. Notices of Violation were
issued and a complaint was filed by the U.S. Environmental Protection
Agency (Federal EPA) in the U.S. District Court for the Southern District
of Ohio that alleges the Company and certain other affiliated utilities
made modifications to generating units at certain of their coal-fired
generating plants over the course of the past 25 years that extend unit
operating lives or increase 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 Company under the Clean
Air Act. A lawsuit against power plants owned by the Company 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 Company 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 Company 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 transition rates, stranded costs wires
charges and/or future market prices for electricity.
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial
Statements of the 1999 Annual Report, the Federal EPA had issued a final
rule (the NOx rule) that requires substantial reductions in nitrogen oxide
(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, had filed petitions seeking a
review of the final rule in the U.S. Court of Appeals for the District of
Columbia Circuit (Appeals Court). In May 1999, the Appeals Court
indefinitely stayed the requirement that states develop revised air
quality programs to impose the NOx reductions but did not, however, stay
the final compliance date of May 1, 2003. In March 2000 the Appeals Court
issued a decision generally upholding the NOx rule. On April 20, 2000,
certain AEP System companies and other petitioners filed for rehearing of
this decision including a rehearing by the entire Appeals Court. On June
22, 2000, the Appeals Court denied the petition for rehearing and lifted
the stay related to the states' development of revised air quality
programs to impose the NOx reductions. The petition for a rehearing before
the entire Appeals Court was also denied. The AEP System companies subject
to the NOx rule plan to appeal to the U.S. Supreme Court.
<PAGE>
Preliminary estimates indicate that compliance with the NOx rule
upheld by the Appeals Court could result in required capital expenditures
of approximately $136 million for the Company. Since compliance costs
cannot be estimated with certainty, the actual cost to comply could be
significantly different than the Company's preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in NOx
emissions. Unless such costs are recovered from customers through
regulated transition rates, stranded costs wire charges and/or future
market prices for electricity, they will have an adverse effect on future
results of operations, cash flows and possibly financial condition.
Other
The Company continues to be involved in certain other matters
discussed in its 1999 Annual Report.
7. FINANCING ACTIVITIES
The Company redeemed 100,000 shares of its 7% series of preferred stock
on August 1, 2000. The Company has in the past, and may in the future,
acquire outstanding debt and preferred stock securities in open market
transactions.
<PAGE>
F-115
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Net income increased 2% for the quarter and 1% for the year-to-date period
reflecting an increase in nonoperating income and a reduction in interest
charges.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
------------- - ------------- -
Operating Revenues. . . . . $29 10 $49 8
Fuel. . . . . . . . . . . . (1) (1) (6) (6)
Purchased Power . . . . . . 29 48 53 47
Other Operation . . . . . . 4 8 3 3
Depreciation. . . . . . . . 1 6 3 6
Nonoperating Income . . . . 3 N.M. 4 N.M.
Interest Charges. . . . . . (1) (8) (2) (6)
N.M. = Not Meaningful
The increases in operating revenues and purchased power expense are due
to a significant increase in American Electric Power System Power Pool (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 and
forward trades to neighboring utility systems and power marketers. The Company's
share of these AEP Power Pool transactions within the AEP System traditional
marketing area (within two transmission systems of the AEP System) are recorded
as operating revenues and purchases. Forward trading sales and purchases 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 sale
on the wholesale market accounting for the increase in the Company's revenues
and purchased power expense.
Fuel expense decreased in the year-to-date period due to the operation
of the fuel clause adjustment mechanism which resulted in a credit to fuel
expense for under recovery of emission allowance costs which were deferred as a
regulatory asset for future recovery through the fuel clause or through
transition recovery mechanisms under Ohio restructuring legislation. The Company
has requested recovery of the projected deferred fuel cost regulatory asset
balance at December 31, 2000 as part of its transition plan filing discussed in
Note 5 of the Notes to Consolidated Financial Statements.
The cost of factoring of accounts receivable to an affiliate, CSW
Credit, Inc. accounted for the increase in other operation expense.
Additional investment in distribution plant resulted in the increase in
depreciation expense.
The increase in nonoperating income 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 Pool's forward electricity trading
transactions outside of the AEP System traditional marketing area (beyond two
transmission systems from the AEP System) and for speculative financial
transactions (options, futures, swaps) is included in nonoperating income. In
the year-to-date period the increase in nonoperating income is also attributable
to the reversal in the first quarter of 2000 of a 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 reflecting the partial redemption in 1999 without
replacement of three different series of first mortgage bonds totaling $36
million.
Market Risks
------------
The Company has certain market risks inherent in its business activities
from changes in electricity commodity prices and interest rates. Market risk
represents the risk of loss that may impact the Company due to adverse changes
in commodity market prices and interest rates. The Company's exposure to market
risk from the trading of electricity and related financial derivative
instruments, which are allocated to the Company through the American Electric
Power System Power Pool, were less than $5 million at June 30, 2000 and $3
million at December 31, 1999 based on the use of a risk measurement model which
calculates Value at Risk (VaR). The VaR is based on the variance - covariance
method using historical prices to estimate volatilities and correlations and
assuming a 95% confidence level and a three-day holding period.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ---------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $362,272 $336,553 $706,258 $670,666
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 43,844 42,123 91,704 83,923
Purchased Power. . . . . . . . . . . . 96,222 67,510 181,328 129,825
Other Operation. . . . . . . . . . . . 151,328 115,258 284,879 206,833
Maintenance. . . . . . . . . . . . . . 55,841 24,621 111,225 55,823
Depreciation and Amortization. . . . . 38,499 37,495 76,710 74,480
Taxes Other Than Federal Income Taxes. 16,787 17,256 33,996 36,285
Federal Income Tax Expense (Credit). . (21,650) 5,324 (39,734) 17,693
-------- -------- -------- --------
TOTAL OPERATING EXPENSES . . . 380,871 309,587 740,108 604,862
-------- -------- -------- --------
OPERATING INCOME (LOSS). . . . . . . . . (18,599) 26,966 (33,850) 65,804
NONOPERATING INCOME. . . . . . . . . . . 2,637 1,556 3,202 3,291
-------- -------- -------- --------
INCOME (LOSS) BEFORE INTEREST CHARGES. . (15,962) 28,522 (30,648) 69,095
INTEREST CHARGES . . . . . . . . . . . . 23,219 18,777 45,086 39,280
-------- -------- -------- --------
NET INCOME (LOSS). . . . . . . . . . . . (39,181) 9,745 (75,734) 29,815
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,153 1,215 2,313 2,429
-------- -------- -------- --------
EARNINGS (LOSS) APPLICABLE TO
COMMON STOCK . . . . . . . . . . . . . $(40,334) $ 8,530 $(78,047) $ 27,386
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $102,364 $243,346 $166,389 $253,154
NET INCOME (LOSS). . . . . . . . . . . . (39,181) 9,745 (75,734) 29,815
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . - 28,664 26,290 57,328
Cumulative Preferred Stock . . . . . 2,243 1,182 3,368 2,364
Capital Stock Expense. . . . . . . . . 10 33 67 65
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $ 60,930 $223,212 $ 60,930 $223,212
======== ======== ======== ========
The common stock of the Company is wholly owned by American Electric Power
Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $2,594,194 $2,587,288
Transmission . . . . . . . . . . . . . . . . . . . . 938,047 928,758
Distribution . . . . . . . . . . . . . . . . . . . . 839,648 818,697
General (including nuclear fuel) . . . . . . . . . . 266,626 244,981
Construction Work in Progress. . . . . . . . . . . . 228,404 190,303
---------- ----------
Total Electric Utility Plant . . . . . . . . 4,866,919 4,770,027
Accumulated Depreciation and Amortization. . . . . . 2,255,262 2,194,397
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,611,657 2,575,630
---------- ----------
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . 739,676 707,967
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 294,802 213,658
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 7,010 3,863
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 45,558 91,268
Affiliated Companies . . . . . . . . . . . . . . . 32,482 48,901
Miscellaneous. . . . . . . . . . . . . . . . . . . 18,120 18,644
Allowance for Uncollectible Accounts . . . . . . . (705) (1,848)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 28,026 27,597
Materials and Supplies . . . . . . . . . . . . . . . 85,184 84,149
Accrued Utility Revenues . . . . . . . . . . . . . . - 44,428
Energy Trading Contracts . . . . . . . . . . . . . . 622,135 97,946
Prepayments. . . . . . . . . . . . . . . . . . . . . 6,628 7,631
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 844,438 422,579
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 582,529 624,810
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 32,606 32,052
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $5,105,708 $4,576,696
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
<S> <C> <C>
Outstanding - 1,400,000 Shares . . . . . . . . . . $ 56,584 $ 56,584
Paid-in Capital. . . . . . . . . . . . . . . . . . . 733,005 732,739
Retained Earnings. . . . . . . . . . . . . . . . . . 60,930 166,389
---------- ----------
Total Common Shareholder's Equity. . . . . . 850,519 955,712
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 8,736 9,248
Subject to Mandatory Redemption. . . . . . . . . . 64,945 64,945
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,092,546 1,126,326
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,016,746 2,156,231
---------- ----------
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 531,760 501,185
Other. . . . . . . . . . . . . . . . . . . . . . . . 195,012 242,522
---------- ----------
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 726,772 743,707
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 190,000 198,000
Short-term Debt. . . . . . . . . . . . . . . . . . . - 224,262
Advances from Affiliates . . . . . . . . . . . . . . 331,852 -
Accounts Payable - General . . . . . . . . . . . . . 47,008 78,784
Accounts Payable - Affiliated Companies. . . . . . . 48,801 31,118
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 20,702 48,970
Interest Accrued . . . . . . . . . . . . . . . . . . 17,851 13,955
Obligations Under Capital Leases . . . . . . . . . . 46,763 11,072
Energy Trading Contracts . . . . . . . . . . . . . . 614,124 95,564
Other. . . . . . . . . . . . . . . . . . . . . . . . 101,669 91,684
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 1,418,770 793,409
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 600,343 622,157
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 117,854 121,627
---------- ----------
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 83,152 85,005
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 142,071 54,560
---------- ----------
COMMITMENTS AND CONTINGENCIES (Note 7)
TOTAL. . . . . . . . . . . . . . . . . . . $5,105,708 $4,576,696
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
-----------------
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income (Loss). . . . . . . . . . . . . . . . . $ (75,734) $ 29,815
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . 81,423 76,431
Amortization of Incremental Nuclear
Refueling Outage Expenses (net). . . . . . . . 3,722 4,695
Unrecovered Fuel and Purchased Power Costs . . . 18,751 (63,922)
Amortization (Deferral) of Nuclear
Outage Costs (net). . . . . . . . . . . . . . . 20,000 (60,000)
Deferred Federal Income Taxes. . . . . . . . . . (12,038) 23,448
Deferred Investment Tax Credits. . . . . . . . . (3,773) (3,796)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . 61,510 (10,474)
Fuel, Materials and Supplies . . . . . . . . . . (1,464) (23,541)
Accrued Utility Revenues . . . . . . . . . . . . 44,428 5,923
Accounts Payable . . . . . . . . . . . . . . . . (14,093) (7,232)
Taxes Accrued. . . . . . . . . . . . . . . . . . (28,268) (23,862)
Revenue Refunds Accrued. . . . . . . . . . . . . 8,365 55,000
Dividends Declared . . . . . . . . . . . . . . . 1,119 28,663
Other (net). . . . . . . . . . . . . . . . . . . . (39,123) (25,103)
--------- ---------
Net Cash Flows From Operating Activities . . 64,825 6,045
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . (93,002) (63,316)
Other. . . . . . . . . . . . . . . . . . . . . . . 587 1,198
--------- ---------
Net Cash Flows Used for Investing Activities (92,415) (62,118)
--------- ---------
FINANCING ACTIVITIES:
Retirement of Long-term Debt . . . . . . . . . . . (48,000) (65,000)
Change in Short-term Debt (net). . . . . . . . . . (224,262) 160,480
Change in Advances from Affiliates (net) . . . . . 331,852 -
Retirement of Cumulative Preferred Stock . . . . . (314) (5)
Dividends Paid on Common Stock . . . . . . . . . . (26,290) (28,664)
Dividends Paid on Cumulative Preferred Stock . . . (2,249) (2,364)
--------- ---------
Net Cash Flows From Financing Activities . . 30,737 64,447
--------- ---------
Net Increase in Cash and Cash Equivalents. . . . . . 3,147 8,374
Cash and Cash Equivalents at Beginning of Period . . 3,863 12,465
--------- ---------
Cash and Cash Equivalents at End of Period . . . . . $ 7,010 $ 20,839
========= =========
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $39,686,000
and $38,775,000 and for income taxes was $(2,365,000) and $19,217,000 in 2000
and 1999, respectively. Noncash acquisitions under capital leases were
$15,423,000 and $6,901,000 in 2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements
should be read in conjunction with the 1999 Annual Report as
incorporated in and filed with the Form 10-K. Certain prior-period
amounts have been reclassified to conform to current-period
presentation. In the opinion of management, the 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. COOK NUCLEAR PLANT SHUTDOWN
---------------------------
As discussed in Note 2 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Cook Nuclear Plant was shut down
in September 1997 due to questions regarding the operability of certain
safety systems that arose during a Nuclear Regulatory Commission (NRC)
architect engineer design inspection. Cook Plant is a two-unit, 2,110
megawatt plant.
On July 5, 2000, Cook Nuclear Plant Unit 2, the first unit scheduled
to restart, reached 100% power completing its restart process.
On July 26, 2000, the Company announced that the restart of Cook
Nuclear Plant Unit 1 would cost an additional $145 million and was
scheduled to occur in the first quarter of 2001. Unforeseen issues or
difficulties encountered in preparing Unit 1 for restart could potentially
delay its return to service.
Expenditures to restart the Cook units had been estimated to total
approximately $574 million. The additional $145 million raises the total
estimate to $719 million. Through June 30, 2000, $534 million has been
spent. For the six months ended June 30, 2000, restart costs of $181
million have been recorded in other operation and maintenance expense,
including amortization of $20 million of restart costs previously deferred
in accordance with settlement agreements in the Indiana and Michigan
retail jurisdictions. At June 30, 2000, deferred restart costs of $140
million are included in regulatory assets.
The costs of the extended outage and restart efforts will have a
material adverse effect on future results of operations, cash flows and
possibly financial condition until the second unit is restarted. The
amortization of restart costs deferred under Indiana and Michigan retail
jurisdiction settlement agreements will adversely effect results of
operations through 2003 when the amortization period ends. The annual
amortization of the restart cost deferrals is $40 million. Management
believes that Unit 1 of the Cook Plant 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.
<PAGE>
3. FINANCING ACTIVITIES
In March 2000 the Company redeemed $48 million of 6.40% series
first mortgage bonds at maturity. The Company has in the past, and may
in the future, acquire outstanding debt and preferred stock securities
in open market transactions.
4. MONEY POOL
On June 15, 2000, the Company became a participant in the American
Electric Power (AEP) System Money Pool (Money Pool). The Money Pool is a
mechanism structured to meet the short-term cash requirements of the
participants with AEP Company, Inc. acting as the primary borrower on
behalf of the Money Pool. The Company's affiliates that are U.S.
domestic electric utility operating companies are the primary
participants in the Money Pool.
The operation of the Money Pool is designed to match on a daily
basis the available cash and borrowing requirements of the participants.
Participants with excess cash loan funds to the Money Pool reducing the
amount of external funds AEP Company, Inc. needs to borrow to meet the
short-term cash requirements of other participants with advances from
the Money Pool. AEP Company, Inc. borrows the funds needed on a daily
basis 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 Company, Inc. is
applied to each Money Pool participant's daily outstanding investment or
debt position to determine interest income or interest expense. Interest
income is included in nonoperating income, and interest expense is
included in interest charges. As a result of becoming a Money Pool
participant, the Company retired its short-term debt and reports its
borrowing from the Money Pool as Advances from Affiliates on the Balance
Sheets.
5. RATE MATTERS
FERC
As discussed in Note 3 of the Notes to Consolidated Financial
Statements of the 1999 Annual Report, the AEP System companies filed a
settlement agreement for Federal Energy Regulatory Commission (FERC)
approval related to an open access transmission tariff. The Company made a
provision in 1999 for an agreed to refund including interest.
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, AEP is 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 and a rate of $1.42 kw/month was established and took effect on
June 16, 2000 after the consummation of the AEP and Central and South West
Corporation merger. Prior to January 1, 2000, the rate was $2.04 kw/month.
Unless the Company and the market grow the volume of physical power
transactions 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.
In connection with the merger, the Indiana Utility Regulatory
Commission and Michigan Public Service Commission approved settlement
agreements that, among other things, provides for sharing net merger
savings with 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. In the event that actual net merger savings are less than
the amounts credited to customers' bills, results of operations and cash
flows will be adversely affected.
6. FACTORING OF RECEIVABLES
------------------------
In June 2000, Indiana Michigan Power Company entered into a
factoring arrangement with an affiliate, CSW Credit, Inc. Under this
arrangement the Company sells without recourse its retail customer
accounts receivable and accrued utility revenue balances to CSW Credit
and is charged a fee based on CSW Credit's financing costs,
uncollectible accounts experience for the Company's receivables and
administrative costs. The costs of factoring customer accounts
receivable is reported as an operating expense. At June 30, 2000 the
amount of factored accounts receivable and accrued utility revenues was
$93.7 million.
7. CONTINGENCIES
COLI Litigation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the deductibility of certain
interest deductions related to AEP's corporate owned life insurance (COLI)
program for taxable years 1991 through 1996 is under review by the
Internal Revenue Service (IRS). Adjustments have been or will be proposed
by the IRS disallowing COLI interest deductions. A disallowance of the
COLI interest deductions through June 30, 2000 would reduce earnings by
approximately $66 million (including interest).
The Company 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 any additional above market rate
interest on the contested amount. The payments to the IRS are included on
the consolidated balance sheet in other property and investments pending
the resolution of this matter. The Company is seeking refund through
litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District of Ohio
in 1998. 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. Notwithstanding the Tax Court's decision in
Winn-Dixie, 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 will vigorously
pursue 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.
Federal EPA Complaint and Notice of Violation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company has been involved in
litigation regarding generating plant emissions. Notices of Violation were
issued and a complaint was filed by the U.S. Environmental Protection
Agency (Federal EPA) in the U.S. District Court that alleges the Company,
certain affiliates 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 extend unit operating lives or increase
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 Company under the Clean
Air Act. A lawsuit against power plants owned by certain AEP System
companies alleging similar violations to those in the Federal EPA
complaint and Notices of Violation was filed by a number of special
interest groups and has been consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per
day per violation at each generating unit ($25,000 per day prior to
January 30, 1997). Civil penalties, if ultimately imposed by the court,
and the cost of any required new pollution control equipment, if the court
accepts Federal EPA's contentions, could be substantial.
On May 10, 2000, the Company 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 Company 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 or future market prices for
energy if generation is deregulated.
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated
Financial Statements in the 1999 Annual Report, Federal EPA had issued a
final rule (the NOx rule) that requires substantial reductions in
nitrogen oxide (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, had filed
petitions seeking a review of the final rule in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court). In May
1999, the Appeals Court indefinitely stayed the requirement that states
develop revised air quality programs to impose the NOx reductions but
did not, however, stay the final compliance date of May 1, 2003. In
March 2000 the Appeals Court issued a decision generally upholding the
NOx rule. On April 20, 2000, certain AEP System companies and other
petitioners filed for rehearing of this decision including a rehearing
by the entire Appeals Court. On June 22, 2000, the Appeals Court denied
the petition for rehearing and lifted the stay related to the states'
development of revised air quality programs to impose the NOx
reductions. The petition for a rehearing before the entire Appeals Court
was also denied. The AEP System companies subject to the NOx rule plan
to appeal to the U.S. Supreme Court.
Preliminary estimates indicate that compliance with the NOx rule
upheld by the Appeals Court could result in required capital
expenditures of approximately $202 million for the Company. Since
compliance costs cannot be estimated with certainty, the actual costs to
comply could be significantly different than the Company's preliminary
estimate depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from
customers through regulated rates and/or future market prices for
electricity if generation is deregulated, they will have an adverse
effect on future results of operations, cash flows and possibly
financial condition.
Other
The Company continues to be involved in other matters discussed
in its 1999 Annual Report.
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
---------------------------------------
RESULTS OF OPERATIONS
The Company reported a loss of $39 million for the second quarter of
2000 compared with net income of $10 million in 1999 and a $76 million loss for
the year-to-date period compared to net income of $30 million in 1999. Increased
operating and maintenance expenses to prepare the Company's two unit Donald C.
Cook Nuclear Plant (Cook Plant) for restart following an extended outage is the
primary reason for the 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)
Second Quarter Year-to-Date
(in millions) % (in millions) %
-------------- - ------------- -
Operating Revenues $ 26 8 $ 36 5
Fuel 2 4 8 9
Purchased Power 29 43 52 40
Other Operation 36 31 78 38
Maintenance 31 127 55 99
Federal Income Taxes (27) N.M. (57) N.M.
Interest Charges 4 24 6 15
N.M. = Not Meaningful
The increase in operating revenues resulted from increased sales to the
American Electric Power System Power Pool (AEP Power Pool) and increased sales
and forward trades to neighboring utility systems and power marketers by the AEP
Power Pool on behalf of the Company. 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. The Company's share of these AEP Power Pool transactions
within the AEP System traditional marketing area (within two transmission
systems of AEP System) are recorded as operating revenues and purchases
accounting for the increases in revenues and purchased power expense. Forward
trading sales and purchases 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 in
2000 due to the expiration of that affiliate's agreement to supply power to an
unaffiliated utility. The Company, therefore, was able to deliver additional
power to the AEP Power Pool, accounting for the increase in sales to the AEP
Power Pool and operating revenues. The increase in operating revenues was also
due to a significant increase in AEP Power Pool transactions which resulted from
an affiliated company's major industrial customer's decision not to extend its
purchase power agreement which provided additional power to the AEP Power Pool
allowing the Power Pool to increase its wholesale sales.
Fuel expense increased for the year-to-date period due to a 12.5% rise
in generation reflecting increased availability of the Company's generating
units as a result of shorter planned maintenance outages.
The increases in other operation and maintenance expenses were primarily
caused by the expenses of continuing work to restart the Cook Plant and the
effect of deferring restart expenditures in 1999 under the terms of the approved
settlement agreement in Indiana.
The 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.
Financial Condition
Total plant and property additions including capital leases for the
year-to-date period were $108 million. During the first six months of
2000 the Company retired $48 million principal amount of long-term and
decreased short-term
debt by $224 million from year-end balances. The Company has 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, including the Company. 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, the Money Pool
raises funds through external borrowing. If there is a net excess in cash,
existing external borrowings are paid down, or, if there are no external
borrowings maturing, the excess funds are invested.
CSW Credit, Inc., a subsidiary of AEP, factors electric customer accounts
receivable for affiliated operating companies and unaffiliated companies. CSW
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 to
include the Company.
The shutdown of the Cook Units and the related costs to restart the
Units have contributed to the reduction in the Company's retained earnings at
June 30, 2000 to $61 million. Unless approval is received from the Securities
and Exchange Commission (SEC) under the Public Utility Holding Company Act of
1935 and the Federal Energy Regulatory Commission (FERC) under the Federal Power
Act, the Company can only pay dividends on its outstanding common stock held by
its parent American Electric Power Company, Inc. and dividends on its
outstanding Preferred Stock out of retained earnings. To the extent that the
Company has insufficient retained earnings to make such preferred dividend
payments in the future, the Company intends to request SEC and FERC approval to
make preferred dividend payments out of capital surplus, which was $733 million
at June 30, 2000. Any failure to obtain such approvals would restrict for some
period of time the ability of the Company to continue to make such 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 the Company's common stock. As of June 30, 2000,
$5.9 million of retained earnings were restricted. Cook Nuclear Plant Shutdown
As discussed in Note 2 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the Cook Nuclear Plant was shut down in September
1997 due to questions regarding the operability of certain safety systems that
arose during a Nuclear Regulatory Commission (NRC) architect engineer design
inspection. Cook Plant is a two-unit, 2,110 megawatt plant.
On July 5, 2000, Cook Nuclear Plant Unit 2, the first unit scheduled to
restart, reached 100% power completing its restart process.
On July 26, 2000, the Company announced that the restart of Cook Nuclear
Plant Unit 1 would cost an additional $145 million and was scheduled to occur in
the first quarter of 2001. Unforeseen issues or difficulties encountered in
preparing Unit 1 for restart could potentially delay its return to service.
Expenditures to restart the Cook units had been estimated to total
approximately $574 million. The additional $145 million raises the total
estimate to $719 million. Through June 30, 2000, $534 million has been spent.
For the six months ended June 30, 2000, restart costs of $181 million have been
recorded in other operation and maintenance expense, including amortization of
$20 million of restart costs previously deferred in accordance with settlement
agreements in the Indiana and Michigan retail jurisdictions. At June 30, 2000,
deferred restart costs of $140 million are included in regulatory assets.
The costs of the extended outage and restart efforts will have a material
adverse effect on future results of operations, cash flows and possibly
financial condition until the second unit is restarted. The amortization of
restart costs deferred under Indiana and Michigan retail jurisdiction settlement
agreements will adversely effect results of operations through 2003 when the
amortization period ends. The annual amortization of the restart cost deferrals
is $40 million. Management believes that Unit 1 of the Cook Plant 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.
Litigation
As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the deductibility of certain interest deductions
related to AEP's corporate owned life insurance (COLI) program for taxable years
1991 through 1996 is under review by the Internal Revenue Service (IRS).
Adjustments have been or will be proposed by the IRS disallowing COLI interest
deductions. A disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $66 million (including interest).
The Company 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 any additional above market rate interest on the
contested amount. The payments to the IRS are included on the consolidated
balance sheet in other property and investments pending the resolution of this
matter. The Company is seeking refund through litigation of all amounts paid
plus interest.
In order to resolve this issue, the Company filed suit against the United
States in the U.S. District Court for the Southern District of Ohio in 1998. 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.
Notwithstanding the Tax Court?s decision in Winn-Dixie, 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 will vigorously pursue 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. Federal EPA Complaint
and Notice of Violation
As discussed in Note 5 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, the Company has been involved in litigation regarding
generating plant emissions. Notices of Violation were issued and a complaint was
filed by the U.S. Environmental Protection Agency (Federal EPA) in the U.S.
District Court that alleges the Company, certain affiliates 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
extend unit operating lives or increase 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 Company under the Clean Air
Act. A lawsuit against power plants owned by certain AEP System companies
alleging similar violations to those in the Federal EPA complaint and Notices of
Violation was filed by a number of special interest groups and has been
consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per day per
violation at each generating unit ($25,000 per day prior to January 30, 1997).
Civil penalties, if ultimately imposed by the court, and the cost of any
required new pollution control equipment, if the court accepts Federal EPA's
contentions, could be substantial.
On May 10, 2000, the Company 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 Company 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 or future market prices for energy if generation is
deregulated. NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial Statements
in the 1999 Annual Report, Federal EPA had issued a final rule (the NOx rule)
that requires substantial reductions in nitrogen oxide (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, had filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals Court). In May
1999, the Appeals Court indefinitely stayed the requirement that states develop
revised air quality programs to impose the NOx reductions but did not, however,
stay the final compliance date of May 1, 2003. In March 2000 the Appeals Court
issued a decision generally upholding the NOx rule. On April 20, 2000, certain
AEP System companies and other petitioners filed for rehearing of this decision
including a rehearing by the entire Appeals Court. On June 22, 2000, the Appeals
Court denied the petition for rehearing and lifted the stay related to the
states' development of revised air quality programs to impose the NOx
reductions. The petition for a rehearing before the entire Appeals Court was
also denied. The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.
Preliminary estimates indicate that compliance with the NOx rule upheld
by the Appeals Court could result in required capital expenditures of
approximately $202 million for the Company. Since compliance costs cannot be
estimated with certainty, the actual costs to comply could be significantly
different than the Company's preliminary estimate depending upon the compliance
alternatives selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates and/or future market prices
for electricity if generation is deregulated, they will have an adverse effect
on future results of operations, cash flows and possibly financial condition.
Market Risks
The Company has certain market risks inherent in its business activities
from changes in electricity commodity prices and interest rates. Market risk
represents the risk of loss that may impact the Company due to adverse changes
in commodity market prices and interest rates. The Company's exposure to market
risk from the trading of electricity and related financial derivative
instruments, which are allocated to the Company through the American Electric
Power System Power Pool, were less than $5 million at June 30, 2000 and $3
million at December 31, 1999 based on the use of a risk measurement model which
calculates Value at Risk (VaR). The VaR is based on the variance - covariance
method using historical prices to estimate volatilities and correlations and
assuming a 95% confidence level and a three-day holding period.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- ---------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $97,759 $86,231 $194,963 $176,972
------- ------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 17,871 22,284 34,673 41,975
Purchased Power. . . . . . . . . . . . . 38,752 25,920 72,234 50,347
Other Operation. . . . . . . . . . . . . 12,103 11,768 22,487 24,119
Maintenance. . . . . . . . . . . . . . . 8,438 5,047 14,805 9,838
Depreciation and Amortization. . . . . . 7,676 7,287 15,279 14,477
Taxes Other Than Federal Income Taxes. . 2,659 2,682 5,493 5,216
Federal Income Taxes . . . . . . . . . . 804 1,010 4,979 5,407
------- -------- -------- --------
TOTAL OPERATING EXPENSES. . . . . 88,303 75,998 169,950 151,379
------- ------- -------- --------
OPERATING INCOME . . . . . . . . . . . . . 9,456 10,233 25,013 25,593
NONOPERATING INCOME (LOSS) . . . . . . . . 671 (41) 625 (155)
------- ------- -------- --------
INCOME BEFORE INTEREST CHARGES . . . . . . 10,127 10,192 25,638 25,438
INTEREST CHARGES . . . . . . . . . . . . . 7,678 7,197 15,137 14,234
------- ------- -------- --------
NET INCOME . . . . . . . . . . . . . . . . $ 2,449 $ 2,995 $ 10,501 $ 11,204
======= ======= ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- ---------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $67,572 $72,218 $67,110 $71,452
NET INCOME . . . . . . . . . . . . . . . . 2,449 2,995 10,501 11,204
CASH DIVIDENDS DECLARED. . . . . . . . . . 7,590 7,443 15,180 14,886
------- ------- ------- -------
BALANCE AT END OF PERIOD . . . . . . . . . $62,431 $67,770 $62,431 $67,770
======= ======= ======= =======
The common stock of the Company is wholly owned by American Electric Power
Company, Inc.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . $ 270,799 $ 268,618
Transmission . . . . . . . . . . . . . . . . . . . . 357,252 355,442
Distribution . . . . . . . . . . . . . . . . . . . . 379,830 372,752
General. . . . . . . . . . . . . . . . . . . . . . . 66,767 67,608
Construction Work in Progress. . . . . . . . . . . . 11,197 14,628
---------- ----------
Total Electric Utility Plant . . . . . . . . 1,085,845 1,079,048
Accumulated Depreciation and Amortization. . . . . . 347,386 340,008
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . 738,459 739,040
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 51,805 20,416
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 692 674
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 2,412 18,952
Affiliated Companies . . . . . . . . . . . . . . . 20,156 15,223
Miscellaneous. . . . . . . . . . . . . . . . . . . 4,626 8,343
Allowance for Uncollectible Accounts . . . . . . . (261) (637)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 11,045 10,441
Materials and Supplies . . . . . . . . . . . . . . . 17,167 18,113
Accrued Utility Revenues . . . . . . . . . . . . . . - 13,737
Energy Trading Contracts . . . . . . . . . . . . . . 234,409 33,919
Prepayments. . . . . . . . . . . . . . . . . . . . . 998 1,450
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . 291,244 120,215
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 101,216 96,296
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 8,480 10,671
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . $1,191,204 $ 986,638
========== ==========
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
<S> <C> <C>
Outstanding - 1,009,000 Shares . . . . . . . . . . $ 50,450 $ 50,450
Paid-in Capital. . . . . . . . . . . . . . . . . . . 158,750 158,750
Retained Earnings. . . . . . . . . . . . . . . . . . 62,431 67,110
---------- --------
Total Common Shareholder's Equity. . . . . . 271,631 276,310
Long-term Debt . . . . . . . . . . . . . . . . . . . 200,921 260,782
---------- --------
TOTAL CAPITALIZATION . . . . . . . . . . . . 472,552 537,092
---------- --------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 22,404 23,797
---------- --------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 140,000 105,000
Short-term Debt. . . . . . . . . . . . . . . . . . . - 39,665
Advances from Affiliates . . . . . . . . . . . . . . 43,634 -
Accounts Payable - General . . . . . . . . . . . . . 7,004 9,923
Accounts Payable - Affiliated Companies. . . . . . . 23,438 19,743
Customer Deposits. . . . . . . . . . . . . . . . . . 4,234 4,143
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 5,856 9,860
Interest Accrued . . . . . . . . . . . . . . . . . . 4,814 4,843
Energy Trading Contracts . . . . . . . . . . . . . . 231,332 33,094
Other. . . . . . . . . . . . . . . . . . . . . . . . 10,936 12,020
---------- --------
TOTAL CURRENT LIABILITIES. . . . . . . . . . 471,248 238,291
---------- --------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 167,493 165,007
---------- --------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 12,312 12,908
---------- --------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 45,195 9,543
---------- --------
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . . $1,191,204 $986,638
========== ========
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 10,501 $ 11,204
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 15,279 14,480
Deferred Federal Income Taxes. . . . . . . . . . . . . . 2,563 912
Deferred Investment Tax Credits. . . . . . . . . . . . . (596) (601)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 14,948 442
Accrued Utility Revenues . . . . . . . . . . . . . . . . 13,737 508
Fuel, Materials and Supplies . . . . . . . . . . . . . . 342 (4,388)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 776 (1,202)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (4,004) 1,988
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (3,129) 1,258
-------- --------
Net Cash Flows From Operating Activities . . . . . . 50,417 24,601
-------- --------
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (14,188) (17,402)
-------- --------
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . - 10,000
Retirement of Long-term Debt . . . . . . . . . . . . . . . (25,000) (37,812)
Change in Short-term Debt (net). . . . . . . . . . . . . . (39,665) 36,000
Change in Advances from Affiliates (net) . . . . . . . . . 43,634 -
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (15,180) (14,886)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (36,211) (6,698)
-------- --------
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 18 501
Cash and Cash Equivalents at Beginning of Period . . . . . . 674 1,935
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 692 $ 2,436
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $15,046,000 and
$14,748,000 and for income taxes was $5,921,000 and $3,631,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $1,836,000
and $1,150,000 in 2000 and 1999, respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 1999 Annual Report as incorporated in and filed
with the Form 10-K. In the opinion of management, the 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. FINANCING ACTIVITIES
In April 2000 the Company redeemed a $25 million term loan note
with a rate of 6.57%. The Company has in the past, and may in the
future, acquire outstanding debt and preferred stock securities in open
market transactions.
3. MONEY POOL
On June 15, 2000, the Company became a participant in the American
Electric Power (AEP) System Money Pool (Money Pool). The Money Pool is a
mechanism structured to meet the short-term cash requirements of the
participants with AEP Company, Inc. acting as the primary borrower on
behalf of the Money Pool. The Company's affiliates that are U.S.
domestic electric utility operating companies are the primary
participants in the Money Pool.
The operation of the Money Pool is designed to match on a daily
basis the available cash and borrowing requirements of the participants.
Participants with excess cash loan funds to the Money Pool reducing the
amount of external funds AEP Company, Inc. needs to borrow to meet the
short-term cash requirements of other participants with advances from
the Money Pool. AEP Company, Inc. borrows the funds needed on a daily
basis 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 Company, Inc. is
applied to each Money Pool participant's daily outstanding investment or
debt position to determine interest income or interest expense. Interest
income is included in nonoperating income, and interest expense is
included in interest charges. As a result of becoming a Money Pool
participant, the Company retired its short-term debt and reports its
borrowing from the Money Pool as Advances from Affiliates on the Balance
Sheets.
<PAGE>
4. RATE MATTERS
FERC
As discussed in Note 3 of the Notes to Financial Statements of the
1999 Annual Report, the AEP System companies filed a settlement agreement
for Federal Energy Regulatory Commission (FERC) approval related to an
open access transmission tariff. The Company made a provision in 1999 for
an agreed to refund including interest under 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, AEP is 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 and a rate of $1.42 kw/month was established and took effect on
June 16, 2000 after the consummation of the AEP and Central and South West
Corporation merger. Prior to January 1, 2000, the rate was $2.04 kw/month.
Unless the Company and the market grow the volume of physical power
transactions to increase utilization of the AEP System's transmission
lines, the new open access transmission rate will adversely impact future
results of operations and cash flows.
Kentucky
In connection with the merger, the Kentucky Public Service
Commission approved a settlement agreement that, among other things,
provides for sharing net merger savings with Kentucky 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. In the event that actual net merger savings are less than the
amounts credited to customers' bills, results of operations and cash flows
will be adversely affected.
5. FACTORING OF RECEIVABLES
In June 2000, Kentucky Power Company entered into a factoring
arrangement with an affiliate, CSW Credit, Inc. Under this arrangement
the Company sells without recourse its retail customer accounts
receivable and accrued utility revenue balances to CSW Credit and is
charged a fee based on CSW Credit's financing costs, uncollectible
accounts experience for the Company's receivables and administrative
costs. The costs of factoring customer accounts receivable is reported
as an operating expense. At June 30, 2000 the amount of factored
accounts receivable and accrued utility revenues was $28.1 million.
6. CONTINGENCIES
COLI Litigation
As discussed in Note 4 of the Notes to Financial Statements in
the 1999 Annual Report, the deductibility of certain interest deductions
related to AEP's corporate owned life insurance (COLI) program for
taxable years 1992 through 1996 is under review by the Internal Revenue
Service (IRS). Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions. A disallowance of the COLI
interest deductions through June 30, 2000 would reduce earnings by
approximately $8 million (including interest).
The Company made payments of taxes and interest attributable to COLI
interest deductions for taxable years 1992 through 1998 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. The payments to the IRS are included
on the balance sheet in other property and investments pending the
resolution of this matter. The Company is seeking refund of all amounts
paid plus interest.
In order to resolve this issue, AEP Company, Inc. filed suit against the
United States in the U.S. District Court for the Southern District of
Ohio in 1998. 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. Notwithstanding the Tax Court's decision
in Winn-Dixie, 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 will
vigorously pursue its lawsuit. In the event the resolution of this
matter is unfavorable, it will have a material adverse impact on results
of operations and cash flows.
Federal EPA Complaint and Notice of Violation
As discussed in Note 4 of the Notes to Financial Statements in the 1999
Annual Report, the Company has been involved in litigation regarding
generating plant emissions. Notices of Violation were issued and a
complaint was filed by the U.S. Environmental Protection Agency (Federal
EPA) in the U.S. District Court that alleges certain AEP System
companies 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 extend unit operating lives or
increase 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 Company under the Clean
Air Act. A lawsuit against power plants owned by AEP System companies
alleging similar violations to those in the Federal EPA complaint and
Notices of Violation was filed by a number of special interest groups and
has been consolidated with the Federal EPA action.
The Clean Air Act authorizes civil penalties of up to $27,500 per
day per violation at each generating unit ($25,000 per day prior to
January 30, 1997). Civil penalties, if ultimately imposed by the court,
and the cost of any required new pollution control equipment, if the court
accepts Federal EPA's contentions, could be substantial.
On May 10, 2000, the Company 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 Company 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.
NOx Reductions
As discussed in Note 6 of the Notes to Financial Statements in
the 1999 Annual Report, Federal EPA had issued a final rule (the NOx
rule) that requires substantial reductions in nitrogen oxide (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, had filed petitions seeking a
review of the final rule in the U.S. Court of Appeals for the District
of Columbia Circuit (Appeals Court). In May 1999, the Appeals Court
indefinitely stayed the requirement that states develop revised air
quality programs to impose the NOx reductions but did not, however, stay
the final compliance date of May 1, 2003. In March 2000 the Appeals
Court issued a decision generally upholding the NOx rule. On April 20,
2000, certain AEP System companies and other petitioners filed for
rehearing of this decision including a rehearing by the entire Appeals
Court. On June 22, 2000, the Appeals Court denied the petition for
rehearing and lifted the stay related to the states' development of
revised air quality programs to impose the NOx reductions. The petition
for a rehearing before the entire Appeals Court was also denied. The AEP
System companies subject to the NOx rule plan to appeal to the U.S.
Supreme Court.
Preliminary estimates indicate that compliance with the NOx rule
upheld by the Appeals Court could result in required capital
expenditures of approximately $106 million for the Company. Since
compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the Company's preliminary
estimate depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from
customers through regulated rates, they will have an adverse effect on
future results of operations, cash flows and possibly financial
condition.
Other
The Company continues to be involved in certain other matters
discussed in its 1999 Annual Report.
<PAGE>
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
---------------------------------------
Although revenues rose 13% in the quarter and 10% year-to-date, net
income declined by $0.5 million or 18% and $0.7 million or 6%, respectively, as
increases in operating expense and interest expense offset the revenue increase.
Income statement line items which changed significantly were:
Increase(Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $11.5 13 $18.0 10
Fuel Expense . . . . . . . . (4.4) (20) (7.3) (17)
Purchased Power Expense. . . 12.8 50 21.9 43
Other Operation Expense. . . 0.3 3 (1.6) (7)
Maintenance Expense. . . . . 3.4 67 5.0 50
Depreciation . . . . . . . . 0.4 5 0.8 6
Interest Charges . . . . . . 0.5 7 0.9 6
Nonoperating Income. . . . . 0.7 N.M. 0.8 N.M.
N.M. = Not Meaningful
The increases in operating revenues and purchased power expense are due
to a significant increase in American Electric Power System Power Pool (AEP
Power Pool) transactions and affiliated 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 and forward trades to
neighboring utility systems and power marketers. The Company's share of these
AEP Power Pool transactions within the AEP System traditional marketing area
(within two transmission systems of AEP System) are recorded as operating
revenues and purchases accounting for the increases in revenues and purchased
power expense. Forward trading sales and purchases 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 for AEP Power Pool transactions and accounted for 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
the plant. Rockport Plant, which is owned and operated by affiliates, generated
22% more kwh in the six months ended June 2000 than in the six months ended June
1999.
Fuel expense decreased due 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. Unit 1 started a
planned outage April 21, 2000 and returned to service the second week in May
after completion of boiler inspection and repairs.
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. Like the AEP Power Pool the
sharing is based upon each company's member load ratio (MLR) and investment.
Other operation expense decreased for the year-to-date period due to an increase
in transmission equalization credits as a result of an increase in MLR and
increased investment in transmission plant. Member load ratio is calculated
monthly on the basis of each AEP Pool members maximum peak demand in relation to
the sum of the maximum peak demands of all five Pool member companies during the
preceding twelve months.
The outages at Big Sandy caused maintenance expense to increase in the
quarter and year-to-date periods.
The increase in transmission plant investment and improvements to
distribution facilities caused the increase in depreciation expense.
Interest charges increased due to an increase in the average outstanding
short-term debt balances and an increase in average short-term debt interest
rates.
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.
Market Risks
The Company has certain market risks inherent in its business activities
from changes in electricity commodity prices and interest rates. Market risk
represents the risk of loss that may impact the Company due to adverse changes
in commodity market prices and interest rates. The Company's exposure to market
risk from the trading of electricity and related financial derivative
instruments, which are allocated to the Company through the American Electric
Power System Power Pool, were less than $2 million at June 30, 2000 and $1
million at December 31, 1999 based on the use of a risk measurement model which
calculates Value at Risk (VaR). The VaR is based on the variance - covariance
method using historical prices to estimate volatilities and correlations and
assuming a 95% confidence level and a three-day holding period.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ----------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $540,321 $498,587 $1,085,732 $1,016,808
-------- -------- ---------- ----------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 177,314 169,055 392,562 358,218
Purchased Power. . . . . . . . . . . . . 47,051 35,699 82,353 56,972
Other Operation. . . . . . . . . . . . . 86,244 82,829 170,696 167,890
Maintenance. . . . . . . . . . . . . . . 33,595 28,501 61,625 53,991
Depreciation and Amortization. . . . . . 38,843 37,397 77,332 74,182
Taxes Other Than Federal Income Taxes. . 41,055 41,952 84,787 85,805
Federal Income Taxes . . . . . . . . . . 36,251 29,826 71,296 67,466
-------- -------- ---------- ----------
TOTAL OPERATING EXPENSES . . . . 460,353 425,259 940,651 864,524
-------- -------- ---------- ----------
OPERATING INCOME . . . . . . . . . . . . . 79,968 73,328 145,081 152,284
NONOPERATING INCOME (LOSS) . . . . . . . . 1,250 (492) 4,150 1,508
-------- -------- ---------- ----------
INCOME BEFORE INTEREST CHARGES . . . . . . 81,218 72,836 149,231 153,792
INTEREST CHARGES . . . . . . . . . . . . . 22,985 20,971 44,782 41,106
-------- -------- ---------- ----------
NET INCOME . . . . . . . . . . . . . . . . 58,233 51,865 104,449 112,686
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . 315 367 636 734
-------- -------- ---------- ----------
EARNINGS APPLICABLE TO COMMON STOCK. . . . $ 57,918 $ 51,498 $ 103,813 $ 111,952
======== ======== ========== ==========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ----------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $595,620 $590,251 $587,424 $587,500
NET INCOME . . . . . . . . . . . . . . . . 58,233 51,865 104,449 112,686
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . 37,703 57,703 75,406 115,406
Cumulative Preferred Stock . . . . . . 316 368 633 735
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . . $615,834 $584,045 $615,834 $584,045
======== ======== ======== ========
The common stock of the Company is wholly owned by American Electric Power
Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production . . . . . . . . . . . . . . . . . . . . . . . . $2,736,713 $2,713,421
Transmission . . . . . . . . . . . . . . . . . . . . . . . 865,548 857,420
Distribution . . . . . . . . . . . . . . . . . . . . . . . 1,019,733 999,679
General (including mining assets). . . . . . . . . . . . . 716,380 713,882
Construction Work in Progress. . . . . . . . . . . . . . . 119,152 116,515
---------- ----------
Total Electric Utility Plant . . . . . . . . . . . 5,457,526 5,400,917
Accumulated Depreciation and Amortization. . . . . . . . . 2,694,902 2,621,711
---------- ----------
NET ELECTRIC UTILITY PLANT . . . . . . . . . . . . 2,762,624 2,779,206
---------- ----------
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . 370,948 253,668
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . . . . 25,300 157,138
Advances to Affiliates . . . . . . . . . . . . . . . . . . 148,965 -
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . . . . 248,834 246,310
Affiliated Companies . . . . . . . . . . . . . . . . . . 154,502 89,215
Miscellaneous. . . . . . . . . . . . . . . . . . . . . . 41,319 22,055
Allowance for Uncollectible Accounts . . . . . . . . . . (957) (2,223)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 97,933 146,317
Materials and Supplies . . . . . . . . . . . . . . . . . . 96,671 95,967
Accrued Utility Revenues . . . . . . . . . . . . . . . . . - 45,575
Energy Trading Contracts . . . . . . . . . . . . . . . . . 858,345 134,567
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . 44,691 38,472
---------- ----------
TOTAL CURRENT ASSETS . . . . . . . . . . . . . . . 1,715,603 973,393
---------- ----------
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . . 782,102 577,090
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . . 65,565 93,852
---------- ----------
TOTAL. . . . . . . . . . . . . . . . . . . . . . $5,696,842 $4,677,209
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
---------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
<S> <C> <C>
Outstanding - 27,952,473 Shares. . . . . . . . . . . . . $ 321,201 $ 321,201
Paid-in Capital. . . . . . . . . . . . . . . . . . . . . . 462,469 462,376
Retained Earnings. . . . . . . . . . . . . . . . . . . . . 615,834 587,424
---------- ----------
Total Common Shareholder's Equity. . . . . . . . . 1,399,504 1,371,001
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . . . . 16,683 16,937
Subject to Mandatory Redemption. . . . . . . . . . . . . 8,850 8,850
Long-term Debt . . . . . . . . . . . . . . . . . . . . . . 1,127,612 1,139,834
---------- ----------
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . 2,552,649 2,536,622
---------- ----------
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . . 406,495 414,837
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . . . . 87,085 11,677
Short-term Debt. . . . . . . . . . . . . . . . . . . . . . - 194,918
Accounts Payable . . . . . . . . . . . . . . . . . . . . . 374,738 244,982
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . 134,983 179,112
Interest Accrued . . . . . . . . . . . . . . . . . . . . . 18,197 16,863
Obligations Under Capital Leases . . . . . . . . . . . . . 34,419 34,284
Energy Trading Contracts . . . . . . . . . . . . . . . . . 847,076 131,844
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 109,106 96,445
---------- ----------
TOTAL CURRENT LIABILITIES. . . . . . . . . . . . . 1,605,604 910,125
---------- ----------
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . 667,093 676,460
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . . 34,204 35,838
---------- ----------
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . . 430,797 103,327
---------- ----------
CONTINGENCIES (Note 7)
TOTAL. . . . . . . . . . . . . . . . . . . . . . $5,696,842 $4,677,209
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
----------------
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 104,449 $ 112,686
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . . . 100,439 93,008
Deferred Federal Income Taxes. . . . . . . . . . . . . . . . (6,387) 1,603
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . . . (8,844) (23,695)
Amortization of Deferred Property Taxes. . . . . . . . . . . 39,944 39,464
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . . (88,341) (84,397)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . . 47,680 (55,037)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . . 45,575 (5,410)
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . (6,219) (6,881)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . 129,756 25,478
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . (44,129) 1,170
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . 2,443 44,808
--------- ---------
Net Cash Flows From Operating Activities . . . . . . . . 316,366 142,797
--------- ---------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . . (91,118) (83,279)
Proceeds from Sale of Property and Other . . . . . . . . . . . - 670
--------- ---------
Net Cash Flows Used For Investing Activities . . . . . . (91,118) (82,609)
--------- ---------
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . 74,748 148,215
Change in Short-term Debt (net). . . . . . . . . . . . . . . . (194,918) 71,085
Change in Advances to Affiliates (net) . . . . . . . . . . . . (148,965) -
Retirement of Cumulative Preferred Stock . . . . . . . . . . . (160) (128)
Retirement of Long-term Debt . . . . . . . . . . . . . . . . . (11,752) (151,223)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . (75,406) (115,406)
Dividends Paid on Cumulative Preferred Stock . . . . . . . . . (633) (735)
--------- ---------
Net Cash Flows Used For Financing Activities . . . . . . (357,086) (48,192)
--------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents . . . . . . (131,838) 11,996
Cash and Cash Equivalents at Beginning of Period . . . . . . . . 157,138 89,652
--------- ---------
Cash and Cash Equivalents at End of Period . . . . . . . . . . . $ 25,300 $ 101,648
========= =========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $40,791,000 and
$40,816,000 and for income taxes was $64,597,000 and $24,645,000 in 2000 and
1999, respectively. Noncash acquisitions under capital leases were $8,422,000
and $11,849,000 in 2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments
should be read in conjunction with the 1999 Annual Report as
incorporated in and filed with the Form 10-K. Certain prior-period
amounts have been reclassified to conform to current-period
presentation. In the opinion of management, the 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. FINANCING ACTIVITY
In May 2000 the Company issued $75 million of senior unsecured
notes with a floating interest rate due 2001. The Company has in the
past, and may in the future, acquire outstanding debt and preferred
stock securities in open market transactions.
<PAGE>
3. OHIO RESTRUCTURING LEGISLATION AND TRANSITION PLAN FILING
As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Ohio Electric Restructuring
Act of 1999 (the 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 Act also provides for a
five-year transition period to move from cost-based rates to market
pricing for generation services. It authorizes the Public Utilities
Commission of Ohio (PUCO) to address certain major transition issues
including unbundling of rates and the recovery of generation-related
transition costs which include regulatory assets, asset impairments and
other stranded costs, employee severance and retraining costs, consumer
education costs and other costs. Stranded costs are generation costs
that are not deemed to be recoverable in a competitive market.
On March 28, 2000, the PUCO staff issued its report on the Company's
transition plan filing. On May 8, 2000, a stipulation agreement between
the Company, the PUCO staff, the Ohio Consumers' Counsel and other
concerned parties was filed with the PUCO for approval. The key
provisions of the stipulation agreement are:
- Recovery of generation-related regulatory assets over seven
years will be through a frozen transition rate for the first
five years and a wires charge for the remaining years.
- There will be no shopping incentive for the Company's customers.
- The Company is to absorb the first $20 million 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.
- The Company and its affiliate, Columbus Southern Power
Company, 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
the Pennsylvania - New Jersey - Maryland transmission
organization (PJM) and/or a midwest independent system
operator (Midwest ISO) on generation originating in the
Midwest ISO or PJM areas.
- The statutory 5% reduction in the generation component of
residential tariffs will remain in effect for the entire
transition period.
- The Company's request for a $50 million gross receipts tax
rider to recover duplicate gross receipts tax will be
separately litigated.
Hearings on the stipulation and the gross receipts tax issue
were held in June 2000. Approval of the stipulation agreement by the
PUCO and a decision on the gross receipts tax are pending.
Management has concluded that as of June 30, 2000 the
requirements to apply Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of Regulation,"
continue to be met since the Company's rates for generation will
continue to be cost-based regulated until the PUCO takes action on the
transition plan as required by the Act. The establishment of rates and
wires charges under a PUCO approved transition plan will enable the
Company to determine its ability to recover stranded costs including
regulatory assets, and other transition costs, a requirement to
discontinue application of SFAS 71.
When the transition plan and transition period tariff
schedules are approved, the application of SFAS 71 will be discontinued
for the Ohio retail jurisdictional portion of the generating business.
Management expects this to occur when the PUCO approves the stipulation
agreement for the Company's transition plan filing. The Act requires
that the PUCO issue its order to approve transition plan filings no
later than October 31, 2000.
<PAGE>
Upon the discontinuance of SFAS 71 the Company will have to
write off its Ohio jurisdictional generation-related regulatory assets
to the extent that they cannot be recovered under the tariff schedules
in the transition plan approved by the PUCO and record any asset
accounting impairments in accordance with SFAS 121, "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to Be
Disposed Of." An impairment loss would be recorded, under SFAS 121, to
the extent that the cost of generating assets cannot be recovered
through non-discounted generation-related revenues during the
transition period and future market prices.
The amount of regulatory assets recorded on the books at June
30, 2000 applicable to the Ohio retail jurisdictional generating
business is $456 million before related tax effects. Due to the planned
closing of the Company's affiliated mines, including the Meigs mine,
projected generation-related regulatory assets as of December 31, 2000
(the date that recoverable generation-related regulatory assets are
measured under the Ohio law) allocable to the Ohio retail jurisdiction
are estimated to exceed $520 million, before income tax effects.
Recovery of these regulatory assets is being sought as a part of the
Company's Ohio transition plan filing. Based on transition rates and
wires charges in the stipulation agreement and management's current
projections of future market prices, management does not anticipate
that the Company will experience material tangible asset accounting
impairment write-offs. Whether the Company will experience material
regulatory asset write-offs will depend on whether the PUCO approves
the Company's stipulation agreement which provides for their recovery.
A determination of whether the Company will experience any
asset impairment loss regarding its Ohio retail jurisdictional
generating assets and any loss from a possible inability to recover
Ohio generation-related regulatory assets and other transition costs
cannot be made until the PUCO takes action on the Company's stipulation
agreement. Should the PUCO fail to fully approve the Company's
stipulation agreement and its transition tariff schedules, which
include recovery of the Company's generation-related regulatory assets,
stranded costs and other transition costs including the duplicate gross
receipts tax, it could have a material adverse effect on results of
operations, cash flows and possibly financial condition.
4. MONEY POOL
On June 15, 2000, the Company became a participant in the
American Electric Power (AEP) System Money Pool (Money Pool). The Money
Pool is a mechanism structured to meet the short-term cash requirements
of the participants with AEP Company, Inc. acting as the primary
borrower on behalf of the Money Pool. The Company's affiliates that are
U.S. domestic electric utility operating companies are the primary
participants in the Money Pool.
The operation of the Money Pool is designed to match on a
daily basis the available cash and borrowing requirements of the
participants. Participants with excess cash loan funds to the Money Pool
reducing the amount of external funds AEP Company, Inc. needs to borrow
to meet the short-term cash requirements of other participants with
advances from the Money Pool. AEP Company, Inc. borrows the funds needed
on a daily basis 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 Company,
Inc. is applied to each Money Pool participant's daily outstanding
investment or debt position to determine interest income or interest
expense. Interest income is included in nonoperating income, and
interest expense is included in interest charges. As a result of
becoming a Money Pool participant, the Company retired its short-term
debt. At June 30, 2000 the Company was a net investor in the Money Pool
and reports its investment in the Money Pool as Advances to Affiliates
on the Balance Sheets.
5. FACTORING OF RECEIVABLES
In June 2000, Ohio Power Company entered into a factoring
arrangement with an affiliate, CSW Credit, Inc. Under this arrangement
the Company sells without recourse its retail customer accounts
receivable and accrued utility revenue balances to CSW Credit and is
charged a fee based on CSW Credit's financing costs, uncollectible
accounts experience for the Company's receivables and administrative
costs. The costs of factoring customer accounts receivable is reported
as an operating expense. At June 30, 2000 the amount of factored
accounts receivable and accrued utility revenues was $106.2 million.
<PAGE>
6. RATE MATTERS
As discussed in Note 2 of the Notes to Consolidated Financial
Statements of the 1999 Annual Report, the AEP System companies filed a
settlement agreement with the Federal Energy Regulatory Commission (FERC)
for their approval to establish an open access transmission tariff. The
Company made a provision in 1999 for a refund including interest for
amounts paid in excess of the agreed to rate.
On March 16, 2000, the FERC approved the settlement agreement filed
in December 1999 resolving the issues on rehearing raised in a July 30,
1999 order. Under terms of the settlement, AEP is required to make refunds
retroactive to September 7, 1993 to certain customers affected by the July
30, 1999 FERC order. Pursuant to FERC orders the refunds were made in two
payments, 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 became effective on January 1, 2000, for all transmission service
customers and a rate of $1.42 kw/month was established and took effect on
June 16, 2000 in connection with the consummation of the AEP and Central
and South West Corporation merger. Prior to January 1, 2000, the rate was
$2.04 kw/month. Unless the Company and the market grow the volume of
physical power transactions 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.
<PAGE>
7. CONTINGENCIES
Litigation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the deductibility of certain
interest deductions related to AEP's corporate owned life insurance
(COLI) program for taxable years 1991 through 1996 is under review by
the Internal Revenue Service (IRS). Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions. A
disallowance of the COLI interest deductions through June 30, 2000
would reduce earnings by approximately $118 million (including
interest).
The Company 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 any additional above
market rate interest on the contested amount. The payments to the IRS
are included on the consolidated balance sheet in other property and
investments pending the resolution of this matter. The Company is
seeking refund through litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against
the United States in the U.S. District Court for the Southern District
of Ohio in 1998. 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. Notwithstanding the Tax
Court's decision in Winn-Dixie, 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 will vigorously pursue 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.
Federal EPA Complaint and Notice of Violation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company has been involved in
litigation regarding generating plant emissions. Notices of Violation
were issued and a complaint was filed by the U.S. Environmental
Protection Agency (Federal EPA) in the U.S. District Court that alleges
the Company, certain affiliates 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 extend unit
operating lives or increase 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 Company under the
Clean Air Act. A lawsuit against power plants owned by the Company
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 Company 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 Company 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, stranded
cost wires charges and future market prices for energy.
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, Federal EPA had issued a final
rule (the NOx rule) that requires substantial reductions in nitrogen
oxide (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, had filed petitions
seeking a review of the final rule in the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court). In May 1999, the Appeals
Court indefinitely stayed the requirement that states develop revised
air quality programs to impose the NOx reductions but did not, however,
stay the final compliance date of May 1, 2003. In March 2000 the
Appeals Court issued a decision generally upholding the NOx rule. On
April 20, 2000, certain AEP System companies and other petitioners
filed for rehearing of this decision including a rehearing by the
entire Appeals Court. On June 22, 2000, the Appeals Court denied the
petition for rehearing and lifted the stay related to the states'
development of revised air quality programs to impose the NOx
reductions. The petition for a rehearing before the entire Appeals
Court was also denied. The AEP System companies subject to the NOx rule
plan to appeal to the U.S. Supreme Court.
In June 2000 the Company announced that it was beginning a
$175 million installation of selective catalytic reduction (SCR)
technology to reduce NOx emissions on its two-unit 2,600 megawatt Gavin
Plant. The Company intends to have the SCR equipment operational in
2001.
Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeals Court could result in required capital
expenditures of approximately $624 million for the Company. Since
compliance costs cannot be estimated with certainty, the actual cost to
comply could be significantly different than the Company's preliminary
estimate depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from
customers through regulated rates and/or future market prices for
electricity, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
Other
The Company continues to be involved in certain other matters
discussed in the 1999 Annual Report.
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
---------------------------------------
RESULTS OF OPERATIONS
Net income increased $6 million or 12% for the quarter due to an
increase in wholesale sales. For the year-to-date period increases in operating
expenses more than offset the effects of the increase in wholesale sales
resulting in a decline in net income of $8 million or 7%.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $42 8 $69 7
Fuel Expense . . . . . . . 8 5 34 10
Purchased Power Expense. . 11 32 25 45
Maintenance Expense. . . . 5 18 8 14
Federal Income Tax . . . . 6 22 4 6
The increase in operating revenues resulted from increased sales to the
American Electric Power System Pool (AEP Power Pool) and the Company's share of
increased transactions to neighboring utility systems and power marketers by the
AEP Power Pool. The Company as a member of the AEP Power Pool shares in the
revenues and cost of the AEP Power Pool's wholesale sales and forward trades to
neighboring utility systems and power marketers. The Company's share of these
AEP Power Pool transactions within the AEP System traditional marketing area
(within two transmission systems of AEP System) are recorded as operating
revenues and purchases accounting for the increases in revenues and purchased
power expense. Forward trading sales and purchases 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 major
industrial customer's decision not to continue its purchase power agreement,
additional power was delivered to AEP Power Pool accounting for part of the
increase in revenues.
Fuel expense increased due to an increase in the average cost of fuel
consumed reflecting shutdown costs included in the cost of coal delivered from
affiliated mining operations.
Additional boiler repairs accounted for the increase in maintenance
expense.
The increase in operating federal income tax expense was primarily due
to an increase in pre-tax operating book income.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
year-to-date period were $100 million. During the first six months of
2000 the Company's subsidiaries issued $75 million principal amount of
long-term obligations
at variable interest rates and retired $12 million principal amount of long-term
debt with interest rates ranging from 7.10% to 7.30% and decreased short-term
debt by $195 million from year-end balances. The Company has 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, including the Company. 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, the Money Pool
raises funds through external borrowing. If there is a net excess in cash,
existing external borrowings are paid down, or, if there are no external
borrowings maturing, the excess funds are invested.
CSW Credit, Inc., a subsidiary of AEP, factors electric customer
accounts receivable for affiliated operating companies and unaffiliated
companies. In June 2000 the factoring of customer accounts receivable for
affiliated companies was expanded as a result of the merger to include the
Company. At June 30, 2000 the amount factored was $106 million.
OTHER MATTERS
Ohio Restructuring Legislation and Transition Plan Filing
As discussed in Note 4 of the Notes to Consolidated Financial Statements in
the 1999 Annual Report, the Ohio Electric Restructuring Act of 1999 (the 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 Act also provides for a five-year transition period to move from cost-based
rates to market pricing for generation services. It authorizes the Public
Utilities Commission of Ohio (PUCO) to address certain major transition issues
including unbundling of rates and the recovery of generation-related transition
costs which include regulatory assets, asset impairments and other stranded
costs, employee severance and retraining costs, consumer education costs and
other costs. Stranded costs are generation costs that are not deemed to be
recoverable in a competitive market.
On March 28, 2000, the PUCO staff issued its report on the Company's
transition plan filing. On May 8, 2000, a stipulation agreement between the
Company, the PUCO staff, the Ohio Consumers' Counsel and other concerned parties
was filed with the PUCO for approval. The key provisions of the stipulation
agreement are:
o Recovery of generation-related regulatory assets over seven years will be
through a frozen transition rate for the first five years and a wires charge for
the remaining years. o There will be no shopping incentive for the Company's
customers.
o The Company is to absorb the first $20 million 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 The Company and its affiliate, Columbus Southern Power
Company, 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 the Pennsylvania - New Jersey - Maryland transmission
organization (PJM) and/or a midwest independent system operator (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 transition period. o The Company's request
for a $50 million gross receipts tax rider to recover duplicate gross receipts
tax will be separately litigated.
Hearings on the stipulation and the gross receipts tax issue were held
in June 2000. Approval of the stipulation agreement by the PUCO and a decision
on the gross receipts tax are pending.
Management has concluded that as of June 30, 2000 the requirements to
apply Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the
Effects of Certain Types of Regulation," continue to be met since the Company's
rates for generation will continue to be cost-based regulated until the PUCO
takes action on the transition plan as required by the Act. The establishment of
rates and wires charges under a PUCO approved transition plan will enable the
Company to determine its ability to recover stranded costs including regulatory
assets, and other transition costs, a requirement to discontinue application of
SFAS 71.
When the transition plan and transition period tariff schedules are
approved, the application of SFAS 71 will be discontinued for the Ohio retail
jurisdictional portion of the generating business. Management expects this to
occur when the PUCO approves the stipulation agreement for the Company's
transition plan filing. The Act requires that the PUCO issue its order to
approve transition plan filings no later than October 31, 2000.
Upon the discontinuance of SFAS 71 the Company will have to write off
its Ohio jurisdictional generation-related regulatory assets to the extent that
they cannot be recovered under the tariff schedules in the transition plan
approved by the PUCO and record any asset accounting impairments in accordance
with SFAS 121, "Accounting for the Impairment of Long-lived Assets and for
Long-lived Assets to Be Disposed Of." An impairment loss would be recorded,
under SFAS 121, to the extent that the cost of generating assets cannot be
recovered through non-discounted generation-related revenues during the
transition period and future market prices.
The amount of regulatory assets recorded on the books at June 30, 2000
applicable to the Ohio retail jurisdictional generating business is $456 million
before related tax effects. Due to the planned closing of the Company's
affiliated mines, including the Meigs mine, projected generation-related
regulatory assets as of December 31, 2000 (the date that recoverable
generation-related regulatory assets are measured under the Ohio law) allocable
to the Ohio retail jurisdiction are estimated to exceed $520 million, before
income tax effects. Recovery of these regulatory assets is being sought as a
part of the Company's Ohio transition plan filing. Based on transition rates and
wires charges in the stipulation agreement and management's current projections
of future market prices, management does not anticipate that the Company will
experience material tangible asset accounting impairment write-offs. Whether the
Company will experience material regulatory asset write-offs will depend on
whether the PUCO approves the Company's stipulation agreement which provides for
their recovery.
A determination of whether the Company will experience any asset
impairment loss regarding its Ohio retail jurisdictional generating assets and
any loss from a possible inability to recover Ohio generation-related regulatory
assets and other transition costs cannot be made until the PUCO takes action on
the Company's stipulation agreement. Should the PUCO fail to fully approve the
Company's stipulation agreement and its transition tariff schedules, which
include recovery of the Company's generation-related regulatory assets, stranded
costs and other transition costs including the duplicate gross receipts tax, it
could have a material adverse effect on results of operations, cash flows and
possibly financial condition.
COLI Litigation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the deductibility of certain interest
deductions related to AEP's corporate owned life insurance (COLI) program for
taxable years 1991 through 1996 is under review by the Internal Revenue Service
(IRS). Adjustments have been or will be proposed by the IRS disallowing COLI
interest deductions. A disallowance of the COLI interest deductions through June
30, 2000 would reduce earnings by approximately $118 million (including
interest).
The Company 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 any additional above market rate interest on the
contested amount. The payments to the IRS are included on the consolidated
balance sheet in other property and investments pending the resolution of this
matter. The Company is seeking refund through litigation of all amounts paid
plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District of Ohio in
1998. 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. Notwithstanding the Tax Court's decision in Winn-Dixie, 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 will vigorously pursue 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. Federal
EPA Complaint and Notice of Violation
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company has been involved in
litigation regarding generating plant emissions. Notices of Violation were
issued and a complaint was filed by the U.S. Environmental Protection Agency
(Federal EPA) in the U.S. District Court that alleges the Company, certain
affiliates 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 extend unit operating lives or increase 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 Company under the Clean Air
Act. A lawsuit against power plants owned by the Company 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 Company 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 Company 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, stranded cost wires charges and future market prices
for energy.
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, Federal EPA had issued a final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide (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, had filed petitions seeking a review of the final rule in the
U.S. Court of Appeals for the District of Columbia Circuit (Appeals Court). In
May 1999, the Appeals Court indefinitely stayed the requirement that states
develop revised air quality programs to impose the NOx reductions but did not,
however, stay the final compliance date of May 1, 2003. In March 2000 the
Appeals Court issued a decision generally upholding the NOx rule. On April 20,
2000, certain AEP System companies and other petitioners filed for rehearing of
this decision including a rehearing by the entire Appeals Court. On June 22,
2000, the Appeals Court denied the petition for rehearing and lifted the stay
related to the states' development of revised air quality programs to impose the
NOx reductions. The petition for a rehearing before the entire Appeals Court was
also denied. The AEP System companies subject to the NOx rule plan to appeal to
the U.S. Supreme Court.
In June 2000 the Company announced that it was beginning a $175 million
installation of selective catalytic reduction (SCR) technology to reduce NOx
emissions on its two-unit 2,600 megawatt Gavin Plant. The Company intends to
have the SCR equipment operational in 2001.
Preliminary estimates indicate that compliance with the NOx rule upheld
by the Appeals Court could result in required capital expenditures of
approximately $624 million for the Company. Since compliance costs cannot be
estimated with certainty, the actual cost to comply could be significantly
different than the Company's preliminary estimate depending upon the compliance
alternatives selected to achieve reductions in NOx emissions. Unless such costs
are recovered from customers through regulated rates and/or future market prices
for electricity, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
Market Risks
The Company has certain market risks inherent in its business activities
from changes in electricity commodity prices and interest rates. Market risk
represents the risk of loss that may impact the Company due to adverse changes
in commodity market prices and interest rates. The Company's exposure to market
risk from the trading of electricity and related financial derivative
instruments, which are allocated to the Company through the American Electric
Power System Power Pool, were less than $7 million at June 30, 2000 and $4
million at December 31, 1999 based on the use of a risk measurement model which
calculates Value at Risk (VaR). The VaR is based on the variance - covariance
method using historical prices to estimate volatilities and correlations and
assuming a 95% confidence level and a three-day holding period.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $209,172 $178,699 $370,501 $329,729
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 75,808 64,916 147,394 126,797
Purchased Power. . . . . . . . . . . . 31,541 16,128 52,207 30,172
Other Operation. . . . . . . . . . . . 28,476 27,140 52,232 53,658
Maintenance. . . . . . . . . . . . . . 13,408 12,720 21,995 21,927
Depreciation and Amortization. . . . . 18,926 18,544 37,838 36,999
Taxes Other Than Federal Income Taxes. 8,819 9,217 16,058 19,238
Federal Income Taxes . . . . . . . . . 7,692 6,862 7,415 5,735
-------- -------- --------- --------
TOTAL OPERATING EXPENSES . . . 184,670 155,527 335,139 294,526
-------- -------- --------- --------
OPERATING INCOME . . . . . . . . . . . . 24,502 23,172 35,362 35,203
NONOPERATING INCOME (LOSS) . . . . . . . 494 11 716 (510)
-------- -------- --------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 24,996 23,183 36,078 34,693
INTEREST CHARGES . . . . . . . . . . . . 10,296 9,228 20,213 18,315
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 14,700 13,955 15,865 16,378
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 53 53 106 106
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 14,647 $ 13,902 $ 15,759 $ 16,272
======== ======== ======== ========
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD
AS PREVIOUSLY REPORTED . . . . . . . . $126,642 $132,493 $142,018 $144,626
CONFORMING CHANGE IN ACCOUNTING POLICY . (3,294) (2,183) (2,782) (1,686)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. 123,348 130,310 139,236 142,940
NET INCOME . . . . . . . . . . . . . . . 14,700 13,955 15,865 16,378
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 17,000 15,000 34,000 30,000
Preferred Stock. . . . . . . . . . . 53 53 106 106
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $120,995 $129,212 $120,995 $129,212
======== ======== ======== ========
The common stock of the Company is wholly owned by American Electric Power
Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $ 914,172 $ 916,889
Transmission. . . . . . . . . . . . . . . . . . . . . . . 393,352 392,029
Distribution. . . . . . . . . . . . . . . . . . . . . . . 917,585 897,516
General . . . . . . . . . . . . . . . . . . . . . . . . . 208,235 217,368
Construction Work in Progress . . . . . . . . . . . . . . 84,471 35,903
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 2,517,815 2,459,705
Accumulated Depreciation and Amortization . . . . . . . . 1,125,365 1,114,255
---------- ----------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 1,392,450 1,345,450
---------- ----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 43,814 46,205
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 1,976 3,077
Accounts Receivable:
Customers . . . . . . . . . . . . . . . . . . . . . . . 33,159 32,301
Affiliated Companies. . . . . . . . . . . . . . . . . . 4,033 2,283
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 23,254 24,143
Materials and Supplies. . . . . . . . . . . . . . . . . . 33,246 34,289
Under-recovered Fuel Costs. . . . . . . . . . . . . . . . 32,040 6,469
Tax Benefits Receivable . . . . . . . . . . . . . . . . . 3,933 -
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 2,099 1,668
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 133,740 104,230
---------- ----------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 10,494 12,124
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . . . . . . . $1,580,498 $1,508,009
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $15 Par Value:
Authorized Shares: 11,000,000
Issued 10,482,000 shares and
<S> <C> <C>
Outstanding Shares: 9,013,000 . . . . . . . . . . . . . $ 157,230 $ 157,230
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 180,000 180,000
Retained Earnings . . . . . . . . . . . . . . . . . . . . 120,995 139,236
---------- ----------
Total Common Shareholder's Equity . . . . . . . . 458,225 476,466
---------- ----------
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. . . . . . . . . . . . . . . . . . . . . . 344,669 364,516
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 883,177 921,268
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . 30,000 20,000
Advances from Affiliates. . . . . . . . . . . . . . . . . 148,859 79,169
Accounts Payable - General. . . . . . . . . . . . . . . . 85,019 44,088
Accounts Payable - Affiliated Companies . . . . . . . . . 43,374 35,195
Customer Deposits . . . . . . . . . . . . . . . . . . . . 18,149 17,752
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . - 18,480
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 7,716 5,420
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 11,711 8,381
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 344,828 228,485
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 302,213 281,916
---------- ----------
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . 36,678 37,574
---------- ----------
REGULATORY LIABILITIES AND DEFERRED CREDITS . . . . . . . . 13,602 38,766
---------- ----------
CONTINGENCIES (Note 4)
TOTAL . . . . . . . . . . . . . . . . . . . . . $1,580,498 $1,508,009
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 15,865 $ 16,378
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 39,039 37,488
Deferred Income Taxes. . . . . . . . . . . . . . . . . . 17,079 3,156
Deferred Investment Tax Credits. . . . . . . . . . . . . (896) (896)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (2,608) 2,983
Fuel, Materials and Supplies . . . . . . . . . . . . . . 1,932 (2,286)
Equity and Other Investments . . . . . . . . . . . . . . 3,504 (4,831)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 49,110 (7,499)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (22,413) (7,474)
Other Deferred Credits . . . . . . . . . . . . . . . . . (18,599) 4,791
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (25,571) (252)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 2,567 (1,595)
-------- --------
Net Cash Flows From Operating Activities . . . . . . 59,009 39,963
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (80,997) (48,495)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (4,694) (184)
-------- --------
Net Cash Flows Used For Investing Activities . . . . (85,691) (48,679)
-------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt . . . . . . . . . . . . . . . (10,000) -
Retirement of Cumulative Preferred Stock . . . . . . . . . (1) -
Advances from Affiliates . . . . . . . . . . . . . . . . . 69,690 37,381
Dividends Paid on Common Stock . . . . . . . . . . . . . . (34,000) (30,000)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (108) (106)
-------- --------
Net Cash Flows From Financing Activities . . . . . . 25,581 7,275
-------- --------
Net Decrease in Cash and Cash Equivalents. . . . . . . . . . (1,101) (1,441)
Cash and Cash Equivalents at Beginning of Period . . . . . . 3,077 4,670
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,976 $ 3,229
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $16,754,000 and
$17,649,000 and for income taxes was $11,725,000 and $13,603,000 in 2000 and
1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
PUBLIC SERVICE COMPANY OF OKLAHOMA AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements should be
read in conjunction with the Company's 1999 Form 10-K. Certain prior-period
amounts have been reclassified to conform to current-period presentation. In the
opinion of management, the 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.
6. MERGER
In June 2000 the merger of American Electric Power Company,
Inc. and Central and South West Corporation, the parent company of Public
Service Company of Oklahoma, was completed. As part of the change in control, an
adjustment to conform the Company's accounting for vacation pay accruals with
American Electric Power's accounting policy was necessary.
The effect of the conforming entry was to reduce net assets by $2.8
million at December 31, 1999 and reduce net income by $0.5 million for the three
months ended March 31, 2000 and by $0.2 million and $0.7 million for the three
months and six months ended June 30, 1999, respectively.
In connection with the merger, a settlement agreement was approved by
the Oklahoma Corporation Commission that, among other things, provides for
sharing $50.2 million in guaranteed net merger savings over five years, with
Oklahoma customers receiving approximately 55% of the savings. In the event that
actual net merger savings are less than the guaranteed net merger savings,
results of operations and cash flows will be adversely affected.
7. FINANCING ACTIVITIES
In March 2000 the Company redeemed $10 million of 6.43% medium-term
notes at maturity.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
4. CONTINGENCIES
The Company continues to be involved in certain matters discussed in its
Form 10-K.
<PAGE>
PUBLIC SERVICE COMPANY OF OKLAHOMA
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
-------------------------------------------------------------------------------
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Net income for the second quarter of 2000 rose $0.7 million or 5% as a
result of increased service revenues and nonoperating service income. Net income
for the first half of 2000 declined $0.5 million or 3% primarily as a result of
increased interest on short-term debt.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $30 17 $41 12
Fuel Expense . . . . . . . 11 17 21 16
Purchased Power Expense. . 15 96 22 73
Other Operation Expense. . 1 5 (1) (3)
Taxes Other Than Federal
Income Taxes . . . . . . - N.M. (3) (17)
Federal Income Taxes . . . 1 12 2 29
Nonoperating Income (Loss) - N.M. 1 N.M.
Interest Charges . . . . . 1 12 2 10
N.M. = Not Meaningful
Operating revenues were higher due primarily to an increase in
fuel-related revenues resulting from increased fuel expenses explained below.
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.
Also, contributing to the increase in revenues in the quarter were higher
non-kwh related service revenues.
The increase in fuel was due primarily to a rise in the average unit
fuel cost due primarily to an increase in spot market natural gas prices.
Purchased power expenses increased due primarily to higher economy
energy purchases.
Other operation expenses were higher in the second quarter due
primarily to higher employee and customer related expenses as well as increased
transmission and overhead distribution expenses.
<PAGE>
Taxes other than federal income taxes decreased for the year- to-date
period due primarily to a favorable accrual adjustment to ad valorem tax expense
in 2000.
Income tax expense associated with utility operations increased as a
result of an increase in pre-tax book income. The increase in
nonoperating income for the first six months of 2000 primarily resulted
from non-utility services to improve
energy efficiency.
Interest charges increased reflecting additional short-term borrowings.
FINANCIAL CONDITION
Total plant and property additions for the year to date period were $81
million. In March 2000 the Company redeemed $10 million of 6.43%
medium-term notes at maturity.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
MARKET RISKS
The Company has certain market risks inherent in its business
activities from changes in interest rates. Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $272,409 $242,888 $484,565 $439,952
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 113,773 91,690 203,125 167,961
Purchased Power. . . . . . . . . . . . 19,252 10,573 30,950 16,766
Other Operation. . . . . . . . . . . . 37,362 33,225 72,060 64,266
Maintenance. . . . . . . . . . . . . . 20,906 22,018 35,212 34,262
Depreciation and Amortization. . . . . 27,525 25,319 54,882 51,524
Taxes Other Than Federal Income Taxes. 13,455 16,876 24,116 33,334
Federal Income Taxes . . . . . . . . . 6,840 7,918 8,193 10,760
-------- -------- --------- --------
TOTAL OPERATING EXPENSES . . . 239,113 207,619 428,538 378,873
-------- -------- --------- --------
OPERATING INCOME . . . . . . . . . . . . 33,296 35,269 56,027 61,079
NONOPERATING INCOME. . . . . . . . . . . 678 509 445 785
-------- -------- --------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 33,974 35,778 56,472 61,864
INTEREST CHARGES . . . . . . . . . . . . 15,188 14,367 30,023 28,358
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 18,786 21,411 26,449 33,506
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 57 57 114 115
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK . . $ 18,729 $ 21,354 $ 26,335 $ 33,391
======== ======== ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD AS
PREVIOUSLY REPORTED. . . . . . . . . . $280,751 $286,188 $288,018 $300,592
Conforming Change in Accounting . . .
Policy. . . . . . . . . . . . . . . (5,099) (4,569) (4,472) (4,010)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. 275,652 281,619 283,546 296,582
NET INCOME . . . . . . . . . . . . . . . 18,786 21,411 26,449 33,506
DEDUCTIONS:
Cash Dividends Declared:
Common Stock. . . . . . . . . . . . . 15,000 27,000 31,000 54,000
Preferred Stock . . . . . . . . . . . 57 57 114 115
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $278,881 $275,973 $278,881 $275,973
======== ======== ======== ========
The Company is a wholly owned subsidiary of American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $1,406,484 $1,402,062
Transmission. . . . . . . . . . . . . . . . . . . . . . . 512,270 484,327
Distribution. . . . . . . . . . . . . . . . . . . . . . . 976,612 958,318
General . . . . . . . . . . . . . . . . . . . . . . . . . 334,538 333,949
Construction Work in Progress . . . . . . . . . . . . . . 53,672 52,775
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 3,283,576 3,231,431
Accumulated Depreciation. . . . . . . . . . . . . . . . . 1,425,987 1,384,242
---------- ----------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 1,857,589 1,847,189
---------- ----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 38,436 37,080
---------- ----------
CURRENT ASSETS:
Cash. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,014 2,018
Accounts Receivable . . . . . . . . . . . . . . . . . . . 39,291 45,511
Accounts Receivable - Affiliated Companies. . . . . . . . 3,898 6,053
Materials and Supplies. . . . . . . . . . . . . . . . . . 25,968 26,420
Fuel Inventory. . . . . . . . . . . . . . . . . . . . . . 67,186 60,844
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 18,825 16,978
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 157,182 157,824
---------- ----------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 52,450 47,180
---------- ----------
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . 35,103 16,942
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . $2,140,760 $2,106,215
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $18 Par Value:
Authorized - 7,600,000 Shares
<S> <C> <C>
Outstanding - 7,536,640 Shares. . . . . . . . . . . . . $ 135,660 $ 135,660
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 245,000 245,000
Retained Earnings . . . . . . . . . . . . . . . . . . . . 278,881 283,546
---------- ----------
TOTAL COMMON SHAREHOLDER'S EQUITY . . . . . . . . 659,541 664,206
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. . . . . . . . . . . . . . . . . . . . 1,419,772 1,274,885
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . 595 45,595
Advances from Affiliates. . . . . . . . . . . . . . . . . 63,242 140,897
Accounts Payable - General. . . . . . . . . . . . . . . . 78,896 60,689
Accounts Payable - Affiliated Companies . . . . . . . . . 50,899 39,117
Customer Deposits . . . . . . . . . . . . . . . . . . . . 15,037 14,236
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 15,900 24,374
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 13,232 9,792
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 22,883 18,990
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 260,684 353,690
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 390,645 376,504
DEFERRED INVESTMENT TAX CREDITS . . . . . . . . . . . . . . 55,408 57,649
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 14,251 43,487
---------- ----------
TOTAL DEFERRED CREDITS. . . . . . . . . . . . . . 460,304 477,640
---------- ----------
CONTINGENCIES (Note 5)
TOTAL . . . . . . . . . . . . . . . . . . . . . $2,140,760 $2,106,215
========== ==========
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIAREIS
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 26,449 $ 33,506
Adjustments for Non-Cash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 57,310 54,337
Deferred Income Taxes. . . . . . . . . . . . . . . . . . 10,575 (7,018)
Deferred Investment Tax Credits . . . . . . . . . . . . (2,241) (2,282)
Changes in Certain Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 8,375 (19,190)
Fuel Inventory . . . . . . . . . . . . . . . . . . . . . (6,342) (20,547)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 29,989 (8,263)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (8,474) 17,614
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (18,218) 419
Other Current Liabilities. . . . . . . . . . . . . . . . 3,892 1,629
Other Deferred Credits . . . . . . . . . . . . . . . . . (29,236) 5,317
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (1,008) (497)
-------- --------
Net Cash Flows From Operating Activities . . . . . . 71,071 55,025
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (61,879) (45,989)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (4,338) (596)
-------- --------
Net Cash Flows Used For Investing Activities . . . . (66,217) (46,585)
-------- --------
FINANCING ACTIVITIES:
Redemption of Preferred Stock. . . . . . . . . . . . . . . (1) (1)
Proceeds from Issuance of Long-term Debt . . . . . . . . . 149,367 -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (45,450) (1,635)
Changes in Advances from Affiliates. . . . . . . . . . . . (77,655) 46,649
Dividends Paid on Common Stock . . . . . . . . . . . . . . (31,000) (54,000)
Dividends Paid on Preferred Stock. . . . . . . . . . . . . (119) (114)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (4,858) (9,101)
-------- --------
Net Decrease in Cash and Cash Equivalents. . . . . . . . . . (4) (661)
Cash and Cash Equivalents at Beginning of Period . . . . . . 2,018 4,444
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 2,014 $ 3,783
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $20,711,000 and
$26,152,000 and for income taxes was $14,270,000 and $18,031,000 in 2000 and
1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements should be
read in conjunction with the Company's 1999 Form 10-K. Certain prior-period
amounts have been reclassified to conform to current-period presentation. In the
opinion of management, the 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. MERGER
In June 2000 the merger of American Electric Power Company, Inc. and
Central and South West Corporation, the parent company of Southwestern Electric
Power Company, was completed. As part of the change in control, an adjustment to
conform the Company's accounting for vacation pay accruals with American
Electric Power's accounting policy was necessary.
The effect of the conforming change in accounting was to reduce net
assets by $4.5 million at December 31, 1999 and reduce net income by $0.6
million for the three months ended March 31, 2000 and by $0.2 million and $0.8
million for the three months and six months ended June 30, 1999, respectively.
In connection with the merger, the regulatory commissions for the
Company's retail jurisdictions approved settlement agreements that provides for,
among other things, sharing net merger savings with customers over five to eight
year periods after consummation of the merger through rate reduction riders or
credits. In the event that actual net merger savings are less than the rate
reductions, results of operations and cash flows will be adversely affected.
3. TEXAS AND ARKANSAS RESTRUCTURING
In June 1999 legislation was signed into law in Texas that will
restructure the electric utility industry (Texas Legislation). The Texas
Legislation, among other things:
o gives 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 other stranded costs
through securitization and non-bypassable wires charges;
o requires reductions in nitrogen oxide and sulfur dioxide emissions;
o provides 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 sets an earnings test for the three years of rate freeze (1999 through 2001);
o sets certain limits for ownership and control of generation capacity by
companies; and
o requires a filing after January 10, 2004 to finalize stranded costs (2004
true-up proceeding) including final fuel recovery balances, 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 must submit a plan to unbundle its business activities into a
retail electric provider, a power generation company and a transmission and
distribution utility.
In 1999 legislation was enacted in Arkansas that will ultimately
restructure the electric utility industry (Arkansas Legislation). Major points
of the Arkansas Legislation are:
o Retail competition begins January 1, 2002 but can be delayed until
as late as June 30, 2003 by the Arkansas Public Service Commission
(Arkansas Commission).
o Transmission facilities must be operated by an independent system operator
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.
The Company filed a business rate unbundling plan in Arkansas on June 30,
2000.
The Company and its affiliated electric utilities which operate in Texas
filed their business separation (unbundling) plan with the Public Utility
Commission of Texas (Texas Commission) on January 10, 2000. The filing described
a financial and accounting functional separation but not a legal or structural
separation, described how operations will be physically separated and the
functions they will perform, described competitive energy services, and provided
a code of conduct. In March 2000 the Texas Commission ruled that the
subsidiaries' plans were not in compliance with the Texas Legislation and
ordered revised plans be submitted to separate the generation business from the
wires business in separate legal entities by January 1, 2002. In May 2000 a
revised separation plan was filed, which the Texas Commission approved on July
7, 2000 in an interim order.
The Company's financial statements have historically reflected the
effects of applying the requirements of Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation". Pursuant to those requirements, regulatory assets and liabilities
had been recorded to reflect the economic effect of cost-based regulation. When
a company determines that its operations or a segment of its operations are no
longer cost-based rate regulated, it is required to apply the provisions of SFAS
101 "Accounting for the Discontinuance of Application of Statement 71". Pursuant
to those requirements and further guidance provided in the Financial Accounting
Standards Board's Emerging Issues Task Force (EITF) Issue 97-4, a regulated
entity is required to write-off regulatory assets and liabilities related to
operations that are no longer cost-based regulated, unless recovery of such
amounts is provided through rates to be collected in a portion of the entity
operations which continues to be regulated. Additionally, it is required to
determine if any plant assets are impaired under SFAS 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of."
As a result of the scheduled deregulation of generation in Texas and
Arkansas, the application of SFAS 71 for the generation portion of the Company's
business in those state was discontinued in 1999. Since the Company does not
expect to be able to recover generation-related regulatory assets, they were
written off in 1999.
An impairment analysis for generation assets under SFAS 121 was
completed which concluded there was no accounting impairment of generation
assets at the time the company ceased application of SFAS 71. An impairment
analysis involves estimating future net cash flows arising from the use of an
asset. If the undiscounted net cash flows exceed the net book value of the
asset, then there is no impairment of the asset for accounting purposes. The
Company will test its generation assets for impairment under SFAS 121 when
circumstances change.
The Texas Legislation also provides that each year during the 1999
through 2001 rate freeze period, electric utilities are subject to an earnings
test. For electric utilities without stranded costs any earnings in excess of
the most recently approved cost of capital in its last rate case or the
statutorily mandated 9.6% in SWEPCo's situation since it has not had a rate case
since 1992 must either flow back to customers or make capital expenditures, at
no charge to customers, to improve transmission or distribution facilities or to
improve air quality. As a result, the Company established a liability of $2.1
million for the 1999 estimated effect of the earnings cap under the Texas
Legislation. The Texas Commission is required under the Texas Legislation to
certify that the Company's calculation of excess earnings for 1999 is correct by
September 30, 2000. The Company must dispose of the liability by the end of
2000.
Beginning January 1, 2002, fuel costs will not be subject to Texas
Commission fuel reconciliation proceedings. Consequently, the Company will file
a final fuel reconciliation with the Texas Commission which reconciles their
fuel costs through the period ending December 31, 2001. Any final fuel balances
will be included in the 2004 true-up proceeding.
4. FINANCING ACTIVITIES
In March 2000, the Company sold $150 million of unsecured floating rate
notes. The notes have a two-year final maturity of March 1, 2002, but may be
redeemed at par after one year. The interest rate will reset quarterly at the
then current three-month London Inter-Bank Overnight Rate (LIBOR) plus 0.23%.
The initial rate set March 1, 2000 was 6.34%. Net proceeds of $149 million were
used to refund $45 million of first mortgage bonds maturing April 1, 2000 and to
repay a portion of outstanding short-term indebtedness.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
5. CONTINGENCIES
Lignite Mining Agreement Litigation
The Company and Central Louisiana Electric Company, Inc. (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, the Company
and CLECO entered into a lignite mining agreement with the Dolet Hills Mining
Venture (DHMV), a partnership for the mining and delivery of lignite from a
portion of these reserves.
In April 1997, the Company 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
the Company and CLECO. The Company and CLECO have denied the allegations
contained in the counterclaims. In January 1999, the Company 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 the Company and CLECO. The closing date
for the settlement is December 31, 2000. The court has stayed the litigation
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 the Company's results of operations, cash flows or financial
condition.
NOx Reductions
On April 19, 2000, the Texas Natural Resource Conservation Commission
adopted regulations that require reductions in nitrogen oxide (NOx) emissions
for existing permitted electric generating facilities in the East Texas Region.
The Company's implementation date for the regulations is 2005.
Preliminary estimates indicate that compliance with the NOx rule could
result in required capital expenditures of approximately $151 million for the
Company. Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's 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 reflected in the future market
price of electricity when generation is deregulated, they will have an adverse
effect on future results of operations, cash flows and possibly financial
condition.
Other
The Company continues to be involved in other matters discussed in its
1999 Form 10-K.
<PAGE>
SOUTHWESTERN ELECTRIC POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
------------------------------------------------------------------------------
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
SWEPCO's net income was $2.6 million, or 12%, lower for the quarter and
was $7.1 million, or 21%, lower for the six months ended June 30, 2000. The
decreases resulted primarily from increased operating expenses and interest
charges.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $ 30 12 $ 45 10
Fuel Expense . . . . . . . 22 24 35 21
Purchased Power. . . . . . 9 82 14 85
Other Operation Expense. . 4 12 8 12
Maintenance Expense. . . . (1) (5) 1 3
Taxes Other Than Federal
Income Taxes . . . . . . (3) (20) (9) (28)
Federal Income Taxes . . . (1) (14) (3) (24)
Interest Charges . . . . . 1 6 2 6
The increase in operating revenues resulted from higher fuel related
revenues due to increased fuel and purchased power expenses and an increase in
retail energy sales. Energy sales to retail customers increased 4% and 2% for
the quarter and year-to-date periods, respectively, reflecting an increase in
average customer usage.
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 and an
increase in generation to meet the increased retail demand for electricity.
The increase in purchased power expenses was primarily caused by an
increase in firm energy contract purchases, increased capacity charges and
increased economy energy purchases to meet the increased retail demand.
Other operation expenses were higher due primarily to increased customer
accounts expenses, increased insurance expenses, increased employee related
expenses due to a change in the method of accruing vacation pay and increased
regulatory and consulting expenses for a sales tax audit.
A reduction in generating station maintenance activity caused the decrease
in maintenance expenses in the second quarter. Depreciation and amortization
expenses increased due to changes in depreciation rates associated with
rate-related settlements in Arkansas and Louisiana in 1999.
The decrease in taxes other than federal income taxes was due to a decrease
in ad valorem taxes and franchise taxes. The decline in federal income taxes
attributable to operations is the result of a decline in pre-tax book income.
Interest expense on long-term debt increased as a result of the issuance of
unsecured floating rate notes in March 2000.
Interest on short-term borrowings for the six months ended June 30, 2000
increased $1.1 million due primarily to increases in the average outstanding
balance of short-term borrowings.
FINANCIAL CONDITION
Total plant and property additions for the year to date period were $62
million.
In March 2000, the Company sold $150 million of unsecured floating rate
notes. The notes have a two-year final maturity of March 1, 2002, but may be
redeemed at par after one year. The interest rate will reset quarterly at the
then current three-month London Inter-Bank Overnight Rate (LIBOR) plus 0.23%.
The initial rate set March 1, 2000 was 6.34%. Net proceeds of $149 million were
used to refund $45 million of first mortgage bonds maturing April 1, 2000 and to
repay a portion of outstanding short-term indebtedness.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
MARKET RISKS
The Company has certain market risks inherent in its business
activities from changes in interest rates. Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 30, 2000 is not materially different than at
December 31, 1999.
OTHER MATTERS
NOx Reductions
On April 19, 2000, the Texas Natural Resource Conservation Commission
adopted regulations that require reductions in nitrogen oxide (NOx) emissions
for existing permitted electric generating facilities in the East Texas Region.
The Company's implementation date for the regulations is 2005.
Preliminary estimates indicate that compliance with the NOx rule could
result in required capital expenditures of approximately $151 million for the
Company. Since compliance costs cannot be estimated with certainty, the actual
cost to comply could be significantly different than the Company's 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 reflected in the future market
price of electricity when generation is deregulated, they will have an adverse
effect on future results of operations, cash flows and possibly financial
condition.
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $130,742 $107,782 $227,277 $188,834
-------- -------- -------- --------
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 47,207 29,208 75,787 52,343
Purchased Power. . . . . . . . . . . . 22,455 12,474 37,348 20,768
Other Operation. . . . . . . . . . . . 15,751 20,364 36,055 41,075
Maintenance. . . . . . . . . . . . . . 5,045 6,282 9,907 10,460
Depreciation and Amortization. . . . . 11,292 10,850 22,533 21,624
Taxes Other Than Federal Income Taxes. 6,653 7,097 11,616 14,585
Federal Income Taxes . . . . . . . . . 5,401 5,146 7,312 4,696
-------- -------- --------- --------
TOTAL OPERATING EXPENSES . . . 113,804 91,421 200,558 165,551
-------- -------- --------- --------
OPERATING INCOME . . . . . . . . . . . . 16,938 16,361 26,719 23,283
NONOPERATING INCOME (LOSS) . . . . . . . (3,149) 55 (3,239) 172
-------- -------- --------- --------
INCOME BEFORE INTEREST CHARGES . . . . . 13,789 16,416 23,480 23,455
INTEREST CHARGES . . . . . . . . . . . . 5,719 6,300 11,577 12,407
-------- -------- -------- --------
NET INCOME . . . . . . . . . . . . . . . 8,070 10,116 11,903 11,048
PREFERRED STOCK DIVIDENDS REQUIREMENTS . 26 26 52 52
-------- -------- -------- --------
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 8,044 $ 10,090 $ 11,851 $ 10,996
======== ======== ======== ========
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ --------------
2000 1999 2000 1999
---- ---- ---- ----
(in thousands)
BALANCE AT BEGINNING OF PERIOD
AS PREVIOUSLY REPORTED. . . .. . . . . $115,515 $111,470 $115,856 $117,189
CONFORMING CHANGE IN ACCOUNTING POLICY . (2,966) (2,624) (2,614) (2,249)
-------- -------- -------- --------
ADJUSTED BALANCE AT BEGINNING OF PERIOD. 112,549 108,846 113,242 114,940
NET INCOME . . . . . . . . . . . . . . . 8,070 10,116 11,903 11,048
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 4,500 7,000 9,000 14,000
Preferred Stock. . . . . . . . . . . 26 26 52 52
-------- -------- -------- --------
BALANCE AT END OF PERIOD . . . . . . . . $116,093 $111,936 $116,093 $111,936
======== ======== ======== ========
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
ASSETS
ELECTRIC UTILITY PLANT:
<S> <C> <C>
Production. . . . . . . . . . . . . . . . . . . . . . . . $ 426,968 $ 429,783
Transmission. . . . . . . . . . . . . . . . . . . . . . . 230,340 220,479
Distribution. . . . . . . . . . . . . . . . . . . . . . . 408,805 403,206
General . . . . . . . . . . . . . . . . . . . . . . . . . 110,123 113,945
Construction Work in Progress . . . . . . . . . . . . . . 26,944 15,131
---------- ----------
Total Electric Utility Plant. . . . . . . . . . . 1,203,180 1,182,544
Accumulated Depreciation. . . . . . . . . . . . . . . . . 502,328 495,847
---------- ----------
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 700,852 686,697
---------- ----------
OTHER PROPERTY AND INVESTMENTS. . . . . . . . . . . . . . . 22,372 21,570
---------- ----------
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 4,065 3,810
Accounts Receivable:
Customers . . . . . . . . . . . . . . . . . . . . . . . 34,031 45,742
Affiliated Companies. . . . . . . . . . . . . . . . . . 7,904 4,837
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 12,912 17,133
Materials and Supplies. . . . . . . . . . . . . . . . . . 12,568 14,029
Under-recovered Fuel Costs. . . . . . . . . . . . . . . . 20,007 14,652
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 4,468 2,883
---------- ----------
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 95,955 103,086
---------- ----------
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 9,220 16,687
---------- ----------
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 11,449 20,108
---------- ----------
TOTAL . . . . . . . . . . . . . . . . . . . . . $ 839,848 $ 848,148
========== ==========
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
2000 1999
-------- --------
(in thousands)
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common Stock - $25 Par Value:
Authorized - 7,800,000 Shares
<S> <C> <C>
Outstanding - 5,488,560 Shares. . . . . . . . . . . . . $ 137,214 $ 137,214
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 2,236 2,236
Retained Earnings . . . . . . . . . . . . . . . . . . . . 116,093 113,242
---------- ----------
Total Common Shareholder's Equity . . . . . . . . 255,543 252,692
Preferred Stock . . . . . . . . . . . . . . . . . . . . . . 2,482 2,482
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . . 263,760 263,686
---------- ----------
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 521,785 518,860
---------- ----------
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . - 40,000
Advances from Affiliates. . . . . . . . . . . . . . . . . 40,456 21,408
Accounts Payable - General. . . . . . . . . . . . . . . . 47,167 39,611
Accounts Payable - Affiliated Companies . . . . . . . . . 23,841 19,770
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 10,477 12,458
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 4,701 4,165
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 12,437 13,906
---------- ----------
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 139,079 151,318
---------- ----------
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 147,204 148,992
---------- ----------
INVESTMENT TAX CREDITS. . . . . . . . . . . . . . . . . . . 24,687 25,323
---------- ----------
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 7,093 3,655
---------- ----------
CONTINGENCIES (Note 5)
TOTAL . . . . . . . . . . . . . . . . . . . . . $ 839,848 $ 848,148
========== ==========
See Notes to Financial Statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
WEST TEXAS UTILITIES COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
Six Months Ended
June 30,
2000 1999
---- ----
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 11,903 $ 11,048
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 22,959 22,086
Deferred Income Taxes. . . . . . . . . . . . . . . . . . (2,138) (263)
Investment Tax Credits . . . . . . . . . . . . . . . . . (636) (637)
Changes in Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . . 8,644 9,580
Fuel, Materials and Supplies . . . . . . . . . . . . . . 5,682 (722)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 11,627 4,511
Accrued Taxes. . . . . . . . . . . . . . . . . . . . . . (1,981) (1,189)
Fuel Recovery. . . . . . . . . . . . . . . . . . . . . . (5,355) (1,042)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 13,905 270
-------- --------
Net Cash Flows From Operating Activities . . . . . . 64,610 43,642
-------- --------
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (32,470) (25,527)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (1,878) (2,295)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (34,348) (27,822)
-------- --------
FINANCING ACTIVITIES:
Retirement of Long-term Debt . . . . . . . . . . . . . . . (40,000) -
Change in Advances from Affiliates (net) . . . . . . . . . 19,048 4,536
Dividends Paid on Common Stock . . . . . . . . . . . . . . (9,000) (14,000)
Dividends Paid on Preferred Stock. . . . . . . . . . . . . (55) (52)
-------- --------
Net Cash Flows Used For Financing Activities . . . . (30,007) (9,516)
-------- --------
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 255 6,304
Cash and Cash Equivalents at Beginning of Period . . . . . . 3,810 2,093
-------- --------
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 4,065 $ 8,397
======== ========
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $9,053,000 and
$9,022,000 and for income taxes was $5,442,000 and $4,589,000 in 2000 and
1999, respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
WEST TEXAS UTILITIES COMPANY
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 2000
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the Company's 1999 Form 10-K. Certain prior-period amounts have
been reclassified to conform to current-period presentation. In the opinion of
management, the 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. MERGER
In June 2000 the merger of American Electric Power Company, Inc. and
Central and South West Corporation, the parent company of West Texas Utilities
Company, was completed. As part of the change in control, an adjustment to
conform the Company's accounting for vacation pay accruals with American
Electric Power's accounting policy was necessary.
The effect of the conforming change in accounting was to reduce net
assets by $2.6 million at December 31, 1999 and reduce net income by $0.4
million for the three months ended March 31, 2000 and by $0.2 million and $0.6
million for the three months and six months ended June 30, 1999, respectively.
In connection with the merger, the Texas Commission approved a
settlement agreement that provides for, among other things, sharing net merger
savings with customers over six years after consummation of the merger through
rate reduction riders. In the event that actual net merger savings are less than
the rate reduction riders, results of operations and cash flows will be
adversely affected.
3. TEXAS RESTRUCTURING
In 1999 legislation was signed into law in Texas that will restructure the
electric utility industry (Texas Legislation). The Texas Legislation, among
other things:
o gives 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 other stranded costs
through securitization and non-bypassable wires charges;
o requires reductions in nitrogen oxide and sulfur dioxide emissions;
o provides 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 sets an earnings test for the three years of rate freeze (1999 through
2001);
o sets certain limits for ownership and control of generation capacity by
companies; and
o requires a filing after January 10, 2004 to finalize stranded costs (2004
true-up proceeding) including final fuel recovery balances, regulatory
assets, certain environmental costs, accumulated excess earnings and other
issues.
Delivery of electricity will continue to be the responsibility of the local
regulated electric transmission and distribution utility company. Each electric
utility must submit a plan to unbundle its business activities into a retail
electric provider, a power generation company and a transmission and
distribution utility.
The Company and its affiliated electric utilities which operate in Texas
filed their joint business separation (unbundling) plan with the Public Utility
Commission of Texas (Texas Commission) on January 10, 2000. The filing described
a financial and accounting functional separation but not a legal or structural
separation, described how operations will be physically separated and the
functions they will perform, described competitive energy services, and provided
a code of conduct. In March 2000, the Texas Commission ruled that the
subsidiaries' plans were not in compliance with the Texas Legislation and
ordered revised plans be submitted to separate the generation business from the
wires business in separate legal entities by January 1, 2002. In May 2000 a
revised separation plan was filed, which the Texas Commission approved on July
7, 2000 in an interim order.
The Company's financial statements have historically reflected the effects
of applying the requirements of Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of Regulation". Pursuant
to those requirements, regulatory assets and liabilities had been recorded to
reflect the economic effect of cost-based regulation. When a company determines
that its operations or a segment of its operations are no longer cost-based rate
regulated, it is required to apply the provisions of SFAS 101 "Accounting for
the Discontinuance of Application of Statement 71". Pursuant to those
requirements and further guidance provided in the Financial Accounting Standards
Board's Emerging Issues Task Force (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 the company's operations which continues to be regulated.
Additionally, it is required to determine if any plant assets are impaired under
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed of."
As a result of the scheduled deregulation of generation in Texas, the
application of SFAS 71 for the generation portion of the business was
discontinued in 1999. Since the Company does not expect to be able to recover
generation-related regulatory assets, they were written off in 1999.
An impairment analysis for generation assets under SFAS 121 was completed
which concluded there was no accounting impairment of generation assets at the
time the Company ceased application of SFAS 71. An impairment analysis involves
estimating future net cash flows arising from the use of an asset. If the
undiscounted net cash flows exceed the net book value of the asset, then there
is no impairment of the asset for accounting purposes. The Company will test its
generation assets for impairment under SFAS 121 when circumstances change.
The Texas Legislation also provides that each year during the 1999
through 2001 rate freeze period, electric utilities are subject to an earnings
test. For electric utilities without stranded costs any earnings in excess of
the most recently approved cost of capital in its last rate case must either
flow back to customers or make capital expenditures, at no charge to customers,
to improve transmission or distribution facilities or to improve air quality. As
a result, the Company established a liability of $2.8 million for the 1999
estimated effect of the earnings cap under the Texas Legislation. The Texas
Commission is required under the Texas Legislation to certify that the Company's
calculation of excess earnings for 1999 is correct by September 30, 2000. The
Company must dispose of the liability by the end of 2000.
Beginning January 1, 2002, fuel costs will not be subject to Texas
Commission fuel reconciliation proceedings. Consequently, the Company will file
its final fuel reconciliation with the Texas Commission which reconciles its
fuel costs through the period ending December 31, 2001. Any final fuel balances
will be included in the 2004 true-up proceeding.
4. FINANCING ACTIVITIES
In April 2000 the Company retired $40 million of Series T, 7-1/2% first
mortgage bonds at maturity.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
5. CONTINGENCIES
The Company continues to be involved in matters discussed in its 1999
Form 10-K.
<PAGE>
WEST TEXAS UTILITIES COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 2000 vs. SECOND QUARTER 1999
AND
YEAR-TO-DATE 2000 vs. YEAR-TO-DATE 1999
Net income decreased $2 million to $8.1 million for the second quarter
of 2000 and increased $0.9 million to $11.9 million for the six months ended
June 30, 2000. A decrease in other operation expenses and interest expenses was
mostly offset by a loss incurred in the second quarter with the phasing out of
merchandise sales.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $ 23 21 $38 20
Fuel Expense . . . . . . . . 18 62 23 45
Purchased Power Expense. . . 10 80 17 80
Other Operation Expense. . . (5) (23) (5) (12)
Taxes Other Than Federal
Income Taxes . . . . . . . - - (3) (20)
Federal Income Taxes . . . . - - 3 56
Nonoperating Income. . . . . (3) N.M. (3) N.M.
Interest Charges . . . . . . (1) (9) (1) (7)
N.M. = Not Meaningful
Operating revenues increased due in part to increased fuel-related
revenues due primarily to higher fuel and purchased power expenses as discussed
below. Due to the operation of a fuel clause mechanism in Texas, revenues are
accrued to reflect fuel cost increases. Non-fuel revenues increased $6.6 million
for the year-to-date period as a result of increased retail sales resulting from
favorable weather conditions and a true-up adjustment under the final 1999
earnings cap filing required by the Texas Legislation.
The increase in fuel expense was due to a rise in the average unit fuel
costs resulting from an increase in the spot market price of natural gas.
Purchased power expense increased due primarily to increased economy
energy purchases.
<PAGE>
Other Operation expenses decreased due primarily to a reduction in
transmission expenses that resulted from new prices for the Electric Reliability
Council of Texas (ERCOT) transmission grid. Each year ERCOT establishes new
rates to allocate the costs of the Texas transmission system to Texas electric
utilities. The lower transmission expense was partially offset by increases in
generation expense related to drought related conditions, outside services,
regulatory services, and a change in the method of recording vacation expense.
Taxes other than federal income taxes decreased due primarily to lower
ad valorem and state franchise taxes. Federal income taxes attributable
to operations increased due primarily to increased income. Nonoperating
income decreased due primarily to the termination of merchandise sales
and the costs of phasing out these sales. Interest charges decreased as
a result of reduction in long-term borrowings.
FINANCIAL CONDITION
Total plant and property additions for the year to date period were $32
million. In April 2000 the Company retired $40 million of Series T,
7-1/2% first mortgage bonds at maturity.
The Company has in the past, and may in the future, acquire outstanding
debt and preferred stock securities in open market transactions.
MARKET RISKS
The Company has certain market risks inherent in its business
activities from changes in interest rates. Market risk represents the risk of
loss that may impact the Company due to adverse changes in interest rates.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at June 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")
A discussion of litigation regarding the Cook Nuclear Plant appearing
under the caption "Shareholders' Litigation" in Part I - Note 9."Contingencies"
is incorporated by reference herein.
<TABLE>
<CAPTION>
Item 4. Submission of Matters to a Vote of Security Holders.
---------------------------------------------------
AEP
The annual meeting of shareholders was held in Columbus, Ohio on April
26, 2000. The holders of shares entitled to vote at the meeting or their proxies
cast votes at the meeting with respect to the following three matters, as
indicated below:
1. Election of nine directors to hold office until the next annual
meeting and until their successors are duly elected. Each nominee
for director received the votes of shareholders as follows:
Number of Shares Number of
Nominee Voted For Votes Withheld
<S> <C> <C>
John P. DesBarres 154,751,346 3,670,260
E. Linn Draper, Jr. 154,730,659 3,690,947
Robert W. Fri 154,701,286 3,720,320
Lester A. Hudson, Jr. 154,730,472 3,691,134
Leonard J. Kujawa 154,684,336 3,737,270
Donald G. Smith 154,765,861 3,655,745
Linda Gillespie Stuntz 154,732,029 3,689,577
Kathryn D. Sullivan 154,625,005 3,796,601
Morris Tanenbaum 154,584,762 3,836,844
Ronald Marsico 34,295
2. Approve the appointment by the Board of Directors of Deloitte & Touche LLP as
independent auditors of AEP for the year 2000.
The proposal was approved by a vote of the shareholders as follows:
Votes FOR 153,696,363
Votes AGAINST 1,250,752
Votes ABSTAINED 3,474,491
Broker NON-VOTES* 0
3. Approve the AEP 2000 Long-Term Incentive Plan.
The proposal was approved by a vote of the shareholders as follows:
Votes FOR 140,505,343
Votes AGAINST 14,430,621
Votes ABSTAINED 3,485,642
Broker NON-VOTES* 0
*A non-vote occurs when a nominee holding shares
for a beneficial owner votes on one proposal, but does
not vote on another proposal because the nominee does not have
discretionary voting power and has not received instructions from the
beneficial owner.
</TABLE>
Appalachian Power Company ("APCo")
The annual meeting of stockholders was held on April 25, 2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500 votes were cast FOR
each of the following five 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. Armando A. Pena
Henry W. Fayne Joseph H. Vipperman
William J. Lhota
No other business was transacted at the meeting.
Indiana Michigan Power Company ("I&M")
The annual meeting of stockholders was held on April 25, 2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 1,400,000 votes were cast FOR
each of the following twelve 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:
Karl G. Boyd Armando A. Pena
E. Linn Draper, Jr. John R. Sampson
Jeffrey A. Drozda David B. Synowiec
Henry W. Fayne Joseph H. Vipperman
William J. Lhota William E. Walters
Mark W. Marano Earl H. Wittkamper
No other business was transacted at the meeting.
Ohio Power Company ("OPCo")
The annual meeting of shareholders was held on May 2, 2000 at 1
Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,473 votes were cast FOR
each of the following five 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. Armando A. Pena
Henry W. Fayne Joseph H. Vipperman
William J. Lhota
No other business was transacted at the meeting.
Item 5. Other Information.
AEP, AEP Generating Company ("AEGCo"), APCo, Columbus Southern Power Company
("CSPCo"), I&M, Kentucky Power Company ("KEPCo") and OPCo
Reference is made to pages 29 and 30 of the Annual Report on Form 10-K
for the year ended December 31, 1999 ("1999 10-K") for a discussion of the
remand of the federal ozone and particulate matter National Ambient Air Quality
Standards by the U.S. Court of Appeals for the District of Columbia Circuit. In
May 2000, the U.S. Supreme Court granted petitions of the U.S. Environmental
Protection Agency, several states and the U.S. Chamber of Commerce seeking
review of the Circuit Court's opinion.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
APCo, Central Power and Light Company ("CPL"), CSPCo, I&M, KEPCo, OPCo,
Public Service Company of Oklahoma ("PSO"), Southwestern Electric Power
Company ("SWEPCo") and West Texas Utilities Company ("WTU")
Exhibit 12 - Computation of Consolidated Ratio of
Earnings to Fixed Charges.
AEP, AEGCo, APCo, CPL, CSPCo, I&M, KEPCo, OPCo, PSO, SWEPCo and WTU
Exhibit 27 - Financial Data Schedule.
(b) Reports on Form 8-K:
Companies Reporting Date of Report Items Reported
AEP, CSPCo and OPCo May 8, 2000 Item 5. Other Events
Item 7. Financial Statements and
Exhibits
AEP June 15, 2000 Item 2. Acquisition or Disposition of
Assets
Item 7. Financial Statements and
Exhibits
AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo
June 15, 2000
Item 5. Other Events
Item 7. Financial Statements and
Exhibits
CPL, PSO, SWEPCo and WTU
June 15, 2000 Item 1. Changes in Control of
Registrant
<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: August 11, 2000
