THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO INCLUDED AS PART OF THE FILING.
<TABLE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended MARCH 31, 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.
<S> <C> <C>
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
1-2680 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
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>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended March 31, 2000
<CAPTION>
INDEX
Page
Part I. FINANCIAL INFORMATION
<S> <C>
American Electric Power Company, Inc. and Subsidiary Companies:
Consolidated Statements of Income and
Statements of Comprehensive Income . . . . . . . . . . . . A-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
Consolidated Statements of Retained Earnings . . . . . . . . A-5
Notes to Consolidated Financial Statements . . . . . . . . . A-6 - A-18
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . A-19- A-32
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
Management's Narrative Analysis of Results of Operations . . B-6 - B-7
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-20
Columbus Southern Power Company and Subsidiaries:
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-10
Management's Narrative Analysis of Results of Operations . . D-11- D-12
Indiana Michigan 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-8
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . E-9 - E-15
Kentucky Power Company:
Statements of Income and Statements of Retained Earnings . . F-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4
Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-7
Management's Narrative Analysis of Results of Operations . . F-8 - F-9
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended March 31, 2000
<CAPTION>
INDEX
Page
<S> <C>
Ohio Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . G-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3
Consolidated Statements of Cash Flows. . . . . . . . . . . G-4
Notes to Consolidated Financial Statements . . . . . . . . G-5 - G-10
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . G-11- G-18
Part II. OTHER INFORMATION
Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
This combined Form 10-Q is separately filed by American Electric Power Company,
Inc., AEP Generating Company, Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power 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>
<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 impact of the proposed merger with CSW including any regulatory
conditions imposed on the merger or the inability to consummate the
merger with CSW.
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 nuclear plant which is on an
extended
safety related shutdown.
Problems or failures related to Year 2000 readiness of computer
software and hardware.
Inflationary trends.
Electricity and gas market prices.
Interest rates
Other risks and unforeseen events.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
<S> <C> <C>
REVENUES:
Domestic Regulated Electric Utilities. . . . . . . . . . $1,546 $1,550
Worldwide Non-regulated Electric and Gas Operations. . . 200 144
TOTAL REVENUES . . . . . . . . . . . . . . . . . 1,746 1,694
EXPENSES:
Fuel and Purchased Power . . . . . . . . . . . . . . . . 511 491
Maintenance and Other Operation. . . . . . . . . . . . . 489 427
Depreciation and Amortization. . . . . . . . . . . . . . 154 148
Taxes Other Than Income Taxes. . . . . . . . . . . . . . 125 124
Worldwide Non-regulated Electric and Gas Operations. . . 164 127
TOTAL EXPENSES. . . . . . . . . . . . . . . . . . 1,443 1,317
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 303 377
OTHER INCOME (LOSS), net . . . . . . . . . . . . . . . . . 3 (1)
INCOME BEFORE INTEREST, PREFERRED DIVIDENDS
AND INCOME TAXES . . . . . . . . . . . . . . . . . . . . 306 376
INTEREST AND PREFERRED DIVIDENDS . . . . . . . . . . . . . 139 132
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . 167 244
INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . . 63 93
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 104 $ 151
AVERAGE NUMBER OF SHARES OUTSTANDING . . . . . . . . . . . 194 192
EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . . . $0.53 $0.79
CASH DIVIDENDS PAID PER SHARE. . . . . . . . . . . . . . . $0.60 $0.60
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(UNAUDITED)
Three Months Ended
March 31,
2000 1999
(in millions)
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 104 $ 151
OTHER COMPREHENSIVE INCOME (LOSS):
Foreign Currency Translation
Adjustment . . . . . . . . . . . . . . . . . . . . . . (22) -
COMPREHENSIVE INCOME . . . . . . . . . . . . . . . . . . . $ 82 $ 151
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in millions)
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . $ 364 $ 333
Accounts Receivable (net). . . . . . . . . . . . . . 993 910
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 260 307
Materials and Supplies . . . . . . . . . . . . . . . 311 311
Accrued Utility Revenues . . . . . . . . . . . . . . 204 246
Energy Trading Contracts . . . . . . . . . . . . . . 1,327 1,001
Prepayments and Other. . . . . . . . . . . . . . . . 116 108
TOTAL CURRENT ASSETS . . . . . . . . . . . . 3,575 3,216
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production . . . . . . . . . . . . . . . . . . . 9,984 9,949
Transmission . . . . . . . . . . . . . . . . . . 3,831 3,832
Distribution . . . . . . . . . . . . . . . . . . 5,536 5,536
Other (including gas and coal mining assets
and nuclear fuel) . . . . . . . . . . . . . . . . . 2,364 2,307
Construction Work in Progress. . . . . . . . . . . . 558 581
Total Property, Plant and Equipment. . . . . 22,273 22,205
Accumulated Depreciation and Amortization. . . . . . 9,254 9,150
NET PROPERTY, PLANT AND EQUIPMENT. . . . . . 13,019 13,055
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 2,202 2,171
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 3,106 3,046
TOTAL. . . . . . . . . . . . . . . . . . . $21,902 $21,488
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts Payable . . . . . . . . . . . . . . . . . . $ 729 $ 699
Short-term Debt. . . . . . . . . . . . . . . . . . . 1,118 888
Long-term Debt Due Within One Year . . . . . . . . . 978 1,111
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 416 414
Interest Accrued . . . . . . . . . . . . . . . . . . 114 78
Obligations Under Capital Leases . . . . . . . . . . 127 91
Energy Trading Contracts . . . . . . . . . . . . . . 1,203 964
Other. . . . . . . . . . . . . . . . . . . . . . . . 445 425
TOTAL CURRENT LIABILITIES. . . . . . . . . . 5,130 4,670
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . 6,239 6,336
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,664 2,745
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 321 326
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 210 213
DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . 716 517
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,487 1,511
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . 163 164
CONTINGENCIES (Note 9)
COMMON SHAREHOLDERS' EQUITY
Common Stock-Par Value $6.50:
2000 1999
Shares Authorized . . . .600,000,000 600,000,000
Shares Issued . . . . . .203,103,341 203,103,341
(8,999,992 shares were held in treasury) . . . . . $ 1,320 $ 1,320
Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,932 1,932
Accumulated Other Comprehensive Income(Loss)
Foreign Currency Translation Adjustments . . . . . (8) 14
Retained Earnings. . . . . . . . . . . . . . . . . . 1,728 1,740
TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . 4,972 5,006
TOTAL. . . . . . . . . . . . . . . . . . . $21,902 $21,488
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in millions)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 104 $ 151
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 195 172
Deferred Federal Income Taxes. . . . . . . . . . . . . . (23) 30
Deferred Investment Tax Credits. . . . . . . . . . . . . (5) (6)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (84) 25
Fuel, Materials and Supplies . . . . . . . . . . . . . . 47 (48)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 39 31
Prepayments. . . . . . . . . . . . . . . . . . . . . . . (12) (42)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 34 123
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2 5
Interest Accrued . . . . . . . . . . . . . . . . . . . . 36 42
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 37 37
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (82) (117)
Net Cash Flows From Operating Activities . . . . . . 288 403
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (186) (212)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (11) (5)
Net Cash Flows Used For Investing Activities . . . . (197) (217)
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . - 31
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 10 7
Change in Short-term Debt (net). . . . . . . . . . . . . . 230 9
Retirement of Long-term Debt . . . . . . . . . . . . . . . (184) (11)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (116) (115)
Net Cash Flows Used For Financing Activities . . . . (60) (79)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 31 107
Cash and Cash Equivalents at Beginning of Period . . . . . . 333 173
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 364 $ 280
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $98 million and $84 million
and for income taxes was $22 million and $3 million in 2000 and 1999,
respectively. Noncash acquisitions under capital leases were $17 million and $18
million in 2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in millions)
<S> <C> <C>
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $1,740 $1,684
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 104 151
DEDUCTIONS:
Cash Dividends Declared. . . . . . . . . . . . . . . . . 116 115
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $1,728 $1,720
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 ACTIVITIES
In the first quarter of 2000 subsidiaries retired $180
million principal amount of long-term debt and issued $10
million of long-term debt.
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 MW Cook Plant is owned
and operated by the Company's subsidiary, Indiana Michigan
Power Company (I&M).
In February 2000, I&M was notified by the NRC that the
Confirmatory Action Letter had been closed. Closing of the
Confirmatory Action Letter is one of the key approvals needed
to restart the nuclear units. The Confirmatory Action Letter
was issued in September 1997 requiring I&M to address certain
issues identified in the letter.
Progress to restart the units continues. Refueling of Unit
2, the first unit scheduled to restart, was completed on April
14, 2000. The NRC's final Unit 2 pre-restart inspection began
on May 8, 2000, which coincided with the reactor heat-up of
Unit 2 and the return to operational service of common plant
systems. When testing and other work required for restart are
complete, I&M will seek concurrence from the NRC to return Unit
2 to service. Refueling and maintenance work to restart Unit
1 will be performed after Unit 2 is returned to service. Any
issues or difficulties encountered in testing of equipment as
part of the restart process could delay the restart of the
units.
<PAGE>
Expenditures to restart the Cook units are estimated to
total approximately $574 million. Through March 31, 2000, $453
million has been spent. In 2000 $80 million of restart costs
were recorded in other operation and maintenance expense,
including amortization of $10 million of restart costs
previously deferred in accordance with settlement agreements
in the Indiana and Michigan retail jurisdictions.
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 units are restarted. The
amortization of restart costs deferred under Indiana and
Michigan retail jurisdiction settlement agreements will
adversely effect results of operations and possibly financial
condition through 2003 when the amortization period ends.
Management believes that the Cook units will be successfully
returned to service. However, if for some unknown reason the
units are not returned to service or their return is delayed
significantly it would have an even greater adverse effect on
future results of operations, cash flows and financial
condition.
4. 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 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 the July 30, 1999 order. Under terms of the
settlement, AEP will make refunds retroactive to September 7,
1993 to certain customers affected by the July 30, 1999 FERC
order. The refunds will be made in two payments. The first
payment was made February 2000 pursuant to a FERC order
granting AEP's request to make interim refunds. The remainder
is to be paid upon approval by the FERC. In addition, a new
lower rate of $1.55 kw/month was made effective January 1,
2000, for all transmission service customers and a future rate
of $1.42 kw/month was established to take effect upon the
consummation of the AEP and Central and South West Corporation
merger.
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 of
approximately 0.5 mills per kwh); annual ENEC recovery
proceedings are suspended and deferral accounting for over or
under recovery is discontinued effective January 1, 2000; the
net cumulative deferred ENEC recovery balance as established
by a WVPSC order on December 27, 1996, which is $66 million at
December 31, 1999, shall remain on the books as a regulatory
liability. However, if deregulation of generation occurs in
West Virginia (WV), APCo will use this regulatory liability to
reduce unrecoverable generation-related regulatory assets and,
to the extent possible, any additional cost or obligations that
deregulation may impose. Also under the Joint Stipulation
APCo's share of any net savings from the pending merger between
AEP Co., Inc. and Central and South West Corporation prior to
December 31, 2004 shall be retained by APCo. All cost incurred
in the merger that are allocated to APCo, whether the merger
is consummated or not, 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. If 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 a 0.5 mills
per kwh wires charge in the WV Restructuring Plan (see Note 5
for discussion of WV Restructuring Plan).
Because the Joint Stipulation incorporated rate issues that
will affect customers of Wheeling Power Company, another AEP
Co., Inc. subsidiary, the WVPSC determined that an opportunity
for hearing should be given to Wheeling Power's customers
before taking action on the Joint Stipulation. As a result
hearings were held on May 10, 2000.
<PAGE>
5. INDUSTRY RESTRUCTURING
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 impair-ments and other stranded costs,
employee severance and retraining costs, consumer education
costs and other costs. Stranded costs are generation costs
that would not be recoverable in a competitive market.
On March 28, 2000 the PUCO staff issued its report on the
Company's transition plan filings. 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. The key provisions of the stipulation agreement
are:
Recovery of regulatory assets over seven years for
Ohio Power Company (OPCo) and eight years for
Columbus Southern Companies (CSP).
A shopping incentive of 2.5 mills/kwh for the first
25% of CSP residential customers that switch
suppliers. No shopping incentive for OPCo customers.
The absorption by CSP and OPCo of 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 companies will make available a fund of up to $10
million for certain transmission charges imposed by
PJM and/or a Midwest ISO on generation originating
in the Midwest ISO or PJM.
The statutory 5% reduction in the generation component
of residential tariffs will remain in effect for
the entire transition period.
The companies' request for a $90 million gross
receipts tax rider will be litigated. Hearings to
address the gross receipts taxes issue are scheduled
for May 31, 2000.
The stipulation agreement is subject to approval by the
PUCO. Hearings on the stipulation are scheduled for June 7,
2000.
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 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.
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 provisions of the proposed 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 separation no later
than January 1, 2005; a transition period of up to 13 years,
during which the incumbent utility must provide default service
for customers who do not change suppliers unless an alternative
default supplier is selected through a WVPSC-sponsored bidding
process; capped and fixed rates for the 13-year transition
period as discussed below; deregulation of metering and
billing; a 0.5 mills per kwh wires charge applicable to all
retail customers for the period January 1, 2001 through
December 31, 2010 intended to provide for recovery of any
stranded cost including net regulatory assets; establishment
of a rate stabilization deferral balance of $81 million by the
end of year ten of the transition period to be used as
determined by the WVPSC to offset prices paid 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 increased 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. Currently the Company has a stipulation
agreement before the WVPSC in connection with a base rate
filing which provides mechanisms to recover the Company's
regulatory assets. The agreement requires the approval of the
WVPSC.
Potential For Write Offs In Ohio, Virginia and West Virginia
Jurisdictions
Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting
Standard (SFAS) No. 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
in the Ohio, Virginia and West Virginia jurisdictions. The
Company's accounting for generation will continue to be in
accordance with SFAS 71 in the Ohio and Virginia jurisdictions
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. The
establishment of transition rates and wire charges should
enable management to determine the Company's 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 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 transition plan filings of the
Company's Ohio jurisdictional electric operating subsidiaries.
The Ohio Act requires that the PUCO issue its order to approve
transition plan filings no later than October 31, 2000. The
application of SFAS 71 will be discontinued in the Virginia
retail jurisdictional portion of the Company's generating
business when the capped rates and the wires charge are known
in Virginia which is expected to occur by the fourth quarter
of 2000. When the effects of implementation of the West
Virginia restructuring plan are known and measurable, the
application of SFAS 71 will be discontinued for the West
Virginia retail jurisdictional portion of the Company's
generating business.
Upon the discontinuance of SFAS 71 the Company will have
to write off its Ohio, Virginia and West Virginia
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 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. Absent the determination in the
legislative or regulatory process of transition rates, any
wires charge and other pertinent information, it is not
possible at this time for management to determine if any of the
Company's generating assets are impaired for accounting
purposes on an undiscounted cash flow basis.
The amount of regulatory assets recorded on the books at
March 31, 2000 applicable to the Ohio, Virginia and West
Virginia retail jurisdictional generating business is $724
million, $67 million and $131 million, respectively, 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
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 and whether the capped transition rates and allowed
wires charges in Virginia and West Virginia will permit their
recovery.
A determination of whether the Company will experience any
asset impairment loss regarding its Ohio, Virginia and West
Virginia retail jurisdictional generating assets and any loss
from a possible inability to recover Ohio, Virginia and West
Virginia 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 or legislative 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, it could have a material adverse effect on
results of operations, cash flows and possibly financial
condition.
6. INVESTMENT IN YORKSHIRE
The Company has a 50% ownership interest in Yorkshire Power
Group Limited (Yorkshire) which is accounted for using the
equity method of accounting. Equity income in Yorkshire is
included in revenues from worldwide non-regulated operations.
The following amounts which are not included in AEP's
consolidated financial statements represent summarized
consolidated financial information of total Yorkshire:
<PAGE>
Three Months Ended
March 31,
2000 1999
(in millions)
Income Statement Data:
Operating Revenues $662.5 $652.0
Operating Income 117.1 113.5
Net Income 48.3 34.6
<TABLE>
<CAPTION>
7. BUSINESS SEGMENTS
The Company's principal business segment is its cost based
rate regulated Domestic Electric Utility business consisting
of seven regulated utility operating companies providing
residential, commercial, industrial and wholesale electric
services in seven Atlantic and Midwestern states. Also
included in this segment are the Company's wholesale power
marketing and trading activities that are conducted as part of
regulated operations and subject to regulatory ratemaking
oversight. The World Wide Electric and Gas Operations segment
represents principally international investments in energy-related 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. Other business segments include non-regulated
electric and gas trading activities,
telecommunication services, and the marketing of various energy
saving products and services. Financial data for the business
segments for the first quarter of 2000 and 1999 is in the
following table:
Domestic
Regulated Worldwide Elimination
Electric Electric and Reconciling AEP
Utilities Gas Operations Other Adjustments Consolidated
(in millions)
<S> <C> <C> <C> <C> <C>
March 31, 2000
Revenues from
external unaffiliated
customers $ 1,546 $ 236 $(36) $ - $ 1,746
Revenues from
transactions with other
operating segments - 25 67 (92) -
Segment net income (loss) 87 24 (7) - 104
Total assets 18,596 2,368 938 - 21,902
March 31, 1999
Revenues from
external unaffiliated
customers 1,550 148 (4) - 1,694
Revenues from
transactions with other
operating segments - 17 31 (48) -
Segment net income (loss) 150 8 (7) - 151
Total assets 17,440 2,148 542 - 20,130
</TABLE>
<PAGE>
8. MERGER
As discussed in Note 8 of the Notes to Consolidated
Financial Statements in the 1999 Annual Report, the Company and
Central and South West Corporation (CSW) announced plans to
merge in December 1997. The appropriate shareholder proposals
for the consummation of the merger were approved in 1998. The
merger agreement was amended to extend the term of the original
agreement to June 30, 2000 and requires the Company to close
the merger before that date.
The merger has received approval from state regulatory
commissions in Arkansas, Louisiana, Oklahoma and Texas, the
four states within CSW's service territory which are required
to approve the merger. AEP has reached agreements with its
state regulatory commission in Indiana, Michigan, Ohio and
Kentucky regarding merger costs, savings and other merger
related rate matters. These AEP service territory state
commissions have agreed not to oppose the merger in federal
proceedings. In addition, the Nuclear Regulatory Commission
has approved a license transfer application for the transfer
of control of CSW subsidiary Central Power and Light's South
Texas Nuclear Plant to the Company and the Department of
Justice closed its investigation under the Hart-Scott-Rodino
Antitrust Improvements Act. Also, in 1998 the Federal Energy
Regulatory Commission (FERC) issued an order which confirmed
that a 250 MW firm contract path with the Ameren System was
available. The contract path was obtained by the Company and
CSW to meet the requirement of the Public Utility Holding
Company Act of 1935 that the two systems operate on an
integrated and coordinated basis.
On March 15, 2000, the FERC conditionally approved the
merger. Conditions placed on the merger include:
The transfer of operational control of AEP's east (the
current AEP transmission system) and west (the current
CSW transmission system) transmission systems to a
fully-functioning, FERC-approved regional transmission
organization by December 15, 2001, which is the same
implementation date included in the FERC's general
order for regional transmission organizations that
applies to all transmission-owning utilities.
The independent calculation and posting of available
transmission capacity to monitor the operation of
AEP's east transmission system.
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). 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. Alternatively, AEP and CSW may choose to
divest the same or a greater amount of capacity from
different generating units in their entirety.
However, such generating units must be of similar
cost, operation and location characteristics as the
generating units AEP and CSW originally agreed to
divest.
AEP and CSW must complete divestiture of the ERCOT
capacity by March 15, 2001 and divestiture of the SPP
capacity by July 1, 2002.
The FERC found that certain energy sales in SPP and ERCOT
would be reasonable and effective interim mitigation measures
until completion of the required SPP and ERCOT divestitures.
The FERC will require the proposed interim energy sales to be
in effect when the merger is consummated.
The Company and CSW submitted a compliance filing to the
FERC on March 31, 2000. The filing outlines the companies'
plans to comply with conditions placed on the merger in the
commission's March 15 conditional approval.
The FERC's merger order required the applicants to make the
compliance filing at least 60 days before consummating the
merger.
The two interim transmission - related mitigation measures
required as a condition for merger approval are to be in place
until the date that the post-merger AEP east transmission
system is under operational control of a FERC-approved regional
transmission organization (RTO). The conditions and the
companies's plans to comply are:
Independent calculation and posting of available trans
-mission capacity (ATC): AEP has contracted with the SPP to
perform independent ATC calculation and postings. The SPP will
also perform another critical open access same time information
system (OASIS) function -- the disposing of transmission
service requests from customers, including marketers affiliated
with AEP, seeking service over the AEP east transmission zone.
Independent market monitoring: an independent third party
will be responsible for reviewing transmission constraint data,
the effectiveness of redispatch to alleviate such constraints,
and the impacts of redispatch on the volume and price of energy
before and after redispatch.
The merger also requires approval of the SEC. In October
1998 AEP and CSW jointly filed an application with the SEC for
approval of the proposed merger under the Public Utility
Holding Company Act of 1935. The SEC merger filing requests
approval of the merger and related transactions and outlines
the expected combined company benefits of the merger to the
Company and CSW customers and shareholders. Since then, the
Company and CSW have filed several amendments to the
application. Approval of the merger by the SEC is pending.
As of March 31, 2000, AEP had deferred $47 million of
incremental costs related to the merger on its consolidated
balance sheet. Although consummation of the merger is expected
to occur in the second quarter of 2000, the Company is unable
to predict the outcome or the timing of the required regulatory
proceedings.
9. CONTINGENCIES
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 March 31, 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.
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 for the Southern District of
Ohio that alleges the Company made modifications to generating
units at certain of its 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.
Federal EPA also issued Notices of Violation, complaints
or administrative orders to eight unaffiliated utilities.
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. 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, the U.S. Court
of Appeals for the District of Columbia Circuit (Appeals Court)
issued a decision on March 3, 2000 generally upholding Federal
EPA's final rule (the NOx rule) that requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern
states, including the states in which the Company's generating
plants are located. A number of utilities, including the
Company, had filed petitions seeking a review of the final rule
in the 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. On
April 20, 2000, the Company and other industry petitioners
filed for rehearing of the March 3, 2000 decision including a
rehearing by the entire Appeals Court.
Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeals Court could result in required
capital expenditures of approximately $1.6 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 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 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
FIRST QUARTER 2000 vs. FIRST QUARTER 1999
RESULTS OF OPERATIONS
Net income declined by $47 million or 31% due predominately to
current expenditures and the amortization of previously deferred
expenditures in the Company's domestic regulated electric utility
operations to prepare the Cook Plant for restart following an
extended outage. The Cook Plant began an extended outage in
September 1997 when both generating units were shut down because of
questions regarding the operability of certain safety systems. In
the first quarter of 1999 certain restart expenses were deferred in
accordance with a settlement agreement in Indiana which resolved
all Indiana jurisdictional rate-related issues applicable to the
Cook Plant's extended outage.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Revenues - Worldwide
Non-regulated Operations. . . . . . . . . . $ 56 39
Fuel and Purchased Power Expense . . . . . . 20 4
Maintenance and Other Operation Expense. . . 62 15
Worldwide Non-regulated Operations Expense . 37 29
Income Taxes . . . . . . . . . . . . . . . . (30) (32)
Revenues from Worldwide Non-regulated Operations increased by
39% primarily due to increased natural gas and gas liquid product
prices. Volumes of natural gas remained consistent with prior year
however prices have increased approximately 50% rebounding from the
depressed market condition in the first quarter of 1999. The sales
volumes for gas liquids have also increased due to the additional
capacity of a gas processing facility which became operational in
February 1999.
The increase in fuel and purchased power expense was primarily
attributable to an increase in generation partially offset by
deferral of affiliated mine shutdown costs under the Ohio fuel
clause mechanism. Net generation increased 3% due to increased
availability of generation plant.
<PAGE>
Maintenance and other operation expense increased significantly
largely as a result of expenditures to prepare the Cook Nuclear
Plant units for restart following an extended Nuclear Regulatory
Commission (NRC) monitored outage which began in September 1997.
Worldwide Non-regulated Electric and Gas Operations expenses
rose in the current year as prices for natural gas increased
significantly.
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 current period were $203 million.
During the first three months of 2000 domestic subsidiaries
issued $10 million principal amount of long-term obligations at an
initial interest rate of 6.305% and retired $180 million amount of
long-term debt with interest rates ranging from 6.35% to 8.40% and
increased short-term debt by $230 million from year-end balances.
OTHER MATTERS
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 MW Cook Plant is owned and operated by the
Company's subsidiary, Indiana Michigan Power Company (I&M).
In February 2000, I&M was notified by the NRC that the
Confirmatory Action Letter had been closed. Closing of the
Confirmatory Action Letter is one of the key approvals needed to
restart the nuclear units. The Confirmatory Action Letter was
issued in September 1997 requiring I&M to address certain issues
identified in the letter.
Progress to restart the units continues. Refueling of Unit 2,
the first unit scheduled to restart, was completed on April 14,
2000. The NRC's final Unit 2 pre-restart inspection began on May
8, 2000, which coincided with the reactor heat-up of Unit 2 and the
return to operational service of common plant systems. When
testing and other work required for restart are complete, I&M will
seek concurrence from the NRC to return Unit 2 to service.
Refueling and maintenance work to restart Unit 1 will be performed
after Unit 2 is returned to service. Any issues or difficulties
encountered in testing of equipment as part of the restart process
could delay the restart of the units.
Expenditures to restart the Cook units are estimated to total
approximately $574 million. Through March 31, 2000, $453 million
has been spent. In 2000 $80 million of restart costs were recorded
in other operation and maintenance expense, including amortization
of $10 million of restart costs previously deferred in accordance
with settlement agreements in the Indiana and Michigan retail
jurisdictions.
The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations and cash
flows until the units are restarted. The amortization of restart
costs deferred under Indiana and Michigan retail jurisdiction
settlement agreements will adversely effect results of operations
and possibly financial condition through 2003 when the amortization
period ends. Management believes that the Cook units will be
successfully returned to service. However, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.
Merger
As discussed in Note 8 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Company and Central and
South West Corporation (CSW) announced plans to merge in December
1997. The appropriate shareholder proposals for the consummation
of the merger were approved in 1998. The merger agreement was
amended to extend the term of the original agreement to June 30,
2000 and requires the Company to close the merger before that date.
The merger has received approval from state regulatory
commissions in Arkansas, Louisiana, Oklahoma and Texas, the four
states within CSW's service territory which are required to approve
the merger. AEP has reached agreements with its state regulatory
commission in Indiana, Michigan, Ohio and Kentucky regarding merger
costs, savings and other merger related rate matters. These AEP
service territory state commissions have agreed not to oppose the
merger in federal proceedings. In addition, the Nuclear Regulatory
Commission has approved a license transfer application for the
transfer of control of CSW subsidiary Central Power and Light's
South Texas Nuclear Plant to the Company and the Department of
Justice closed its investigation under the Hart-Scott-Rodino
Antitrust Improvements Act. Also, in 1998 the Federal Energy
Regulatory Commission (FERC) issued an order which confirmed that
a 250 MW firm contract path with the Ameren System was available.
The contract path was obtained by the Company and CSW to meet the
requirement of the Public Utility Holding Company Act of 1935 that
the two systems operate on an integrated and coordinated basis.
On March 15, 2000, the FERC conditionally approved the merger.
Conditions placed on the merger include:
The transfer of operational control of AEP's east (the
current AEP transmission system) and west (the current CSW
transmission system) transmission systems to a fully-functioning,
FERC-approved regional transmission
organization by December 15, 2001, which is the same
implementation date included in the FERC's general order
for regional transmission organizations that applies to
all transmission-owning utilities.
The independent calculation and posting of available
transmission capacity to monitor the operation of AEP's
east transmission system.
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). 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. Alternatively, AEP and CSW
may choose to divest the same or a greater amount of
capacity from different generating units in their
entirety. However, such generating units must be of
similar cost, operation and location characteristics as
the generating units AEP and CSW originally agreed to
divest.
AEP and CSW must complete divestiture of the ERCOT
capacity by March 15, 2001 and divestiture of the SPP
capacity by July 1, 2002.
The FERC found that certain energy sales in SPP and ERCOT would
be reasonable and effective interim mitigation measures until
completion of the required SPP and ERCOT divestitures. The FERC
will require the proposed interim energy sales to be in effect when
the merger is consummated.
The Company and CSW submitted a compliance filing to the FERC
on March 31, 2000. The filing outlines the companies' plans to
comply with conditions placed on the merger in the commission's
March 15 conditional approval.
The FERC's merger order required the applicants to make the
compliance filing at least 60 days before consummating the merger.
The two interim transmission - related mitigation measures
required as a condition for merger approval are to be in place
until the date that the post-merger AEP east transmission system is
under operational control of a FERC-approved regional transmission
organization (RTO). The conditions and the companies's plans to
comply are:
Independent calculation and posting of available trans-mission
capacity (ATC): AEP has contracted with the SPP to perform
independent ATC calculation and postings. The SPP will also
perform another critical open access same time information system
(OASIS) function -- the disposing of transmission service requests
from customers, including marketers affiliated with AEP, seeking
service over the AEP east transmission zone.
Independent market monitoring: an independent third party will
be responsible for reviewing transmission constraint data, the
effectiveness of redispatch to alleviate such constraints, and the
impacts of redispatch on the volume and price of energy before and
after redispatch.
The merger also requires approval of the SEC. In October 1998
AEP and CSW jointly filed an application with the SEC for approval
of the proposed merger under the Public Utility Holding Company Act
of 1935. The SEC merger filing requests approval of the merger and
related transactions and outlines the expected combined company
benefits of the merger to the Company and CSW customers and
shareholders. Since then, the Company and CSW have filed several
amendments to the application. Approval of the merger by the SEC
is pending.
As of March 31, 2000, AEP had deferred $47 million of
incremental costs related to the merger on its consolidated balance
sheet. Although consummation of the merger is expected to occur in
the second quarter of 2000, the Company is unable to predict the
outcome or the timing of the required regulatory proceedings.
Industry Restructuring
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 would not be recoverable in a competitive market.
On March 28, 2000 the PUCO staff issued its report on the
Company's transition plan filings. 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. The
key provisions of the stipulation agreement are:
Recovery of regulatory assets over seven years for
Ohio Power Company (OPCo)and
eight years for Columbus Southern Company (CSP).
A shopping incentive of 2.5 mills/kwh for the first 25% of
CSP residential customers that switch suppliers. No
shopping incentive for OPCo customers.
The absorption by CSP and OPCo of 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 companies will make available a fund of up to $10
million for certain transmission charges imposed by PJM and/or
Midwest ISO on generation originating in the Midwest ISO
or PJM.
The statutory 5% reduction in the generation component of
residential tariffs will remain in effect for the
entire transition period.
The companies' request for a $90 million gross receipts
tax rider will be litigated. Hearings to address the
gross receipts tax issue are scheduled for May 31, 2000.
The stipulation agreement is subject to approval by the PUCO.
Hearings on the stipulation are scheduled for June 7, 2000.
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, on January 1, 2004.
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 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.
West Virginia Restructuring Plan
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the Public Service Commission
of West Virginia (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 proposed 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 separation no later than January 1, 2005; a transition
period of up to 13 years, during which the incumbent utility must
provide default service for customers who do not change suppliers
unless an alternative default supplier is selected through a WVPSC
- -sponsored bidding process; capped and fixed rates for the 13-year
transition period as discussed below; deregulation of metering and
billing; a 0.5 mills per kwh wires charge applicable to all retail
customers for the period January 1, 2001 through December 31, 2010
intended to provide for recovery of any stranded cost including net
regulatory assets; establishment of a rate stabilization deferral
balance of $81 million by the end of year ten of the transition
period to be used as determined by the WVPSC to offset prices paid
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
increased 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. Currently the Company
has a stipulation agreement before the WVPSC in connection with a
base rate filing which provides mechanisms to recovery the
Company's regulatory assets. The agreement requires the approval
of the WVPSC.
<PAGE>
Potential For Write Offs In Ohio, Virginia and West Virginia
Jurisdictions
Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting Standard
(SFAS) No. 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 in the Ohio,
Virginia and West Virginia jurisdictions. The Company's accounting
for generation will continue to be in accordance with SFAS 71 in
the Ohio and Virginia jurisdictions 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. The establishment of transition rates and
wire charges should enable management to determine the Company's
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 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 transition plan filings for the Company's Ohio
jurisdictional electric operating subsidiaries. The Ohio Act
requires that the PUCO issue its order to approve transition plan
filings no later than October 31, 2000. The application of SFAS 71
will be discontinued in the Virginia retail jurisdictional portion
of the Company's generating business when the capped rates and the
wires charge are known in Virginia which is expected to occur by
the fourth quarter of 2000. When the effects of the West Virginia
restructuring plan are known and measurable, the application of
SFAS 71 will be discontinued for the West Virginia retail
jurisdictional portion of the Company's generating business.
Upon the discontinuance of SFAS 71 the Company will have to
write off its Ohio, Virginia and West Virginia 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 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. Absent the determination in the
legislative or regulatory process of transition rates, any wires
charge and other pertinent information, it is not possible at this
time for management to determine if any of the Company's generating
assets are impaired for accounting purposes on an undiscounted cash
flow basis.
The amount of regulatory assets recorded on the books at March
31, 2000 applicable to the Ohio, Virginia and West Virginia retail
jurisdictional generating business is $724 million, $67 million and
$131 million, respectively, 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
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 request for their
recovery and whether the capped transition rates and allowed wires
charges in Virginia and West Virginia will permit their recovery.
A determination of whether the Company will experience any
asset impairment loss regarding its Ohio, Virginia and West
Virginia retail jurisdictional generating assets and any loss from
a possible inability to recover Ohio, Virginia and West Virginia
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 or legislative
process. Should the PUCO or the Virginia SCC fail to approve
transition rates and wires charges that are sufficient to provide
for recovery or it not be possible under the West Virginia
restructuring plan to recover all or a portion 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.
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 March 31,
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.
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 for the Southern District of Ohio that alleges the Company
made modifications to generating units at certain of its 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.
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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. 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, the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including the states in which
the Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the 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. On April 20, 2000,
the Company and other industry petitioners filed for rehearing of
the March 3, 2000 decision including a rehearing by the entire
Appeals Court.
Preliminary estimates indicate that compliance with the NOx
rule upheld by the Appeals Court could result in required capital
expenditures of approximately $1.6 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 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.
<PAGE>
Market Risks
The Company has certain market risks inherent in its business
activities which represent the risk of loss that may impact the
Company due to adverse changes in electricity and gas commodity
prices, foreign currency exchange rates and interest rates. The
Company's European energy trading operations which commenced in
January 2000 are not material. The Company's exposure to market
risk from the trading of electricity and natural gas and related
financial derivative instruments has not changed materially since
December 31, 1999.
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 March 31, 2000 is not
materially different than at December 31, 1999.
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $56,866 $52,827
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 24,435 20,258
Rent - Rockport Plant Unit 2 . . . . . . . . . . . . . . . 17,071 17,071
Other Operation. . . . . . . . . . . . . . . . . . . . . . 3,098 3,370
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . 2,515 2,262
Depreciation . . . . . . . . . . . . . . . . . . . . . . . 5,505 5,440
Taxes Other Than Federal Income Taxes. . . . . . . . . . . 1,126 1,239
Federal Income Taxes . . . . . . . . . . . . . . . . . . . 721 827
TOTAL OPERATING EXPENSES . . . . . . . . . . . . . 54,471 50,467
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 2,395 2,360
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . 869 856
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 3,264 3,216
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . 819 602
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . $ 2,445 $ 2,614
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
2000 1999
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . $3,673 $2,770
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . 2,445 2,614
CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . . . . . 1,935 1,073
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . $4,183 $4,311
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production. . . . . . . . . . . . . . . . . . . . . . $631,434 $629,286
General . . . . . . . . . . . . . . . . . . . . . . . 2,620 2,400
Construction Work in Progress . . . . . . . . . . . . 5,497 8,407
Total Electric Utility Plant. . . . . . . . . 639,551 640,093
Accumulated Depreciation. . . . . . . . . . . . . . . 298,776 295,065
NET ELECTRIC UTILITY PLANT. . . . . . . . . . 340,775 345,028
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . 1,706 317
Accounts Receivable:
Affiliated Companies. . . . . . . . . . . . . . . . 16,695 22,464
Miscellaneous . . . . . . . . . . . . . . . . . . . 2,731 2,643
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . 17,002 17,505
Materials and Supplies. . . . . . . . . . . . . . . . 4,008 3,966
Prepayments . . . . . . . . . . . . . . . . . . . . . 116 150
TOTAL CURRENT ASSETS. . . . . . . . . . . . . 42,258 47,045
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . 5,684 5,744
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . 3,278 823
TOTAL . . . . . . . . . . . . . . . . . . . $391,995 $398,640
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares . . . . . $ 1,000 $ 1,000
Paid-in Capital . . . . . . . . . . . . . . . . . . . 27,235 29,235
Retained Earnings . . . . . . . . . . . . . . . . . . 4,183 3,673
Total Common Shareholder's Equity . . . . . . 32,418 33,908
TOTAL CAPITALIZATION. . . . . . . . . . . . . 32,418 33,908
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . 534 592
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . 44,802 44,800
Short-term Debt - Notes Payable . . . . . . . . . . . 7,050 24,700
Accounts Payable - General. . . . . . . . . . . . . . 6,068 7,539
Accounts Payable - Affiliated Companies . . . . . . . 16,236 19,451
Taxes Accrued . . . . . . . . . . . . . . . . . . . . 8,483 4,285
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . 23,427 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . 2,592 4,763
TOTAL CURRENT LIABILITIES . . . . . . . . . . 108,658 110,501
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . 126,366 127,759
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . 62,277 63,114
Amounts Due to Customers for Income Taxes . . . . . . 25,687 26,266
TOTAL REGULATORY LIABILITIES. . . . . . . . . 87,964 89,380
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . 35,705 36,500
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . 350 -
CONTINGENCIES (Note 2)
TOTAL . . . . . . . . . . . . . . . . . . . $391,995 $398,640
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 2,445 $ 2,614
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . 5,505 5,440
Deferred Federal Income Taxes. . . . . . . . . . . . . (1,374) (1,339)
Deferred Investment Tax Credits. . . . . . . . . . . . (837) (838)
Amortization of Deferred Gain on Sale and Leaseback -
Rockport Plant Unit 2. . . . . . . . . . . . . . . . (1,393) (1,393)
Deferred Property Taxes. . . . . . . . . . . . . . . . (2,489) (2,410)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . 5,681 2,700
Fuel, Materials and Supplies . . . . . . . . . . . . . 461 (7,863)
Accounts Payable . . . . . . . . . . . . . . . . . . . (4,686) 4,539
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 4,198 5,627
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . 18,464 18,464
Other (net). . . . . . . . . . . . . . . . . . . . . . . (1,735) (1,045)
Net Cash Flows From Operating Activities . . . . . 24,240 24,496
INVESTING ACTIVITIES - Net Cash Flows Used
for Construction. . . . . . . . . . . . . . . . . . . . . (1,266) (770)
FINANCING ACTIVITIES:
Return of Capital to Parent Company. . . . . . . . . . . (2,000) (2,000)
Change in Short-term Debt (net). . . . . . . . . . . . . (17,650) (18,875)
Dividends Paid . . . . . . . . . . . . . . . . . . . . . (1,935) (1,073)
Net Cash Flows Used For Financing Activities . . . (21,585) (21,948)
Net Increase (Decrease) in Cash and Cash Equivalents . . . 1,389 1,778
Cash and Cash Equivalents at Beginning of Period . . . . . 317 232
Cash and Cash Equivalents at End of Period . . . . . . . . $ 1,706 $ 2,010
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $732,000 and $470,000 in
2000 and 1999, respectively, and for income taxes was $678,000 in 2000.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 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. CONTINGENCIES
NOx Reductions
As discussed in Note 3 of the Notes of Financial Statements of the
1999 Annual Report, the U.S. Court of Appeals for the District of
Columbia Circuit (Appeals Court) issued a decision on March 3, 2000
generally upholding the United States Environmental Protection Agency's
final rule (the NOx rule) that requires substantial reductions in
nitrogen oxide (NOx) emissions in 22 eastern states, including the
states in which the AEP System's generating plants are located. A number
of utilities, including the AEP System companies, had filed petitions
seeking a review of the final rule in the 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. On
April 20, 2000, the AEP System companies and other industry petitioners
filed for rehearing of the March 3, 2000 decision including a rehearing
by the entire Appeals 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
FIRST QUARTER 2000 vs. FIRST QUARTER 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.
Although operating revenues increased 8%, net income declined $0.2
million or 6% for the first quarter 2000 as a result of the return of
capital to the parent company in February 1999, May 1999 and March 2000.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Operating Revenues $ 4.0 8
Fuel 4.2 21
Other Operation (0.3) (8)
Maintenance 0.3 11
Taxes Other Than Federal Income Taxes (0.1) (9)
Federal Income Taxes (0.1) (13)
Interest Charges 0.2 36
The increase in operating revenues resulted from an increase in
generation due to the availability of the Rockport Plant partially
offset by reduced billings for the return on equity component under the
unit power agreements, reflecting the return of capital. In 1999
planned outages reduced the availability of the Rockport Plant units.
Shorter outages in the first quarter of 2000 allowed the Rockport units
to generate 16% more electricity than in 1999.
Fuel expense increased due to the increase in generation and a rise
in the average cost of fuel. The increase in generation is attributable
to the increased availability of the Rockport Plant units. The rise in
the cost of fuel results from fluctuations in the market price of coal.
Changes in the cost of coal are reflected in the unit power bills and do
not affect net income.
The decrease in other operation expense is primarily due to a 1999
payment to the City of Rockport in settlement of an annexation issue.
Although the duration of the planned outages was shorter in 2000
than 1999, the nature of the work performed resulted in more maintenance
expense.
Taxes other than federal income taxes declined due to a decrease in
taxable income calculated for state taxes. Federal income taxes
attributable to operations decreased due to a decrease in pre-tax
operating income.
Interest charges increased due to an increase in average interest
rates on short-term and variable rate debt and an increase in the
average outstanding short-term debt balance reflecting market conditions
for short-term interest rates and the Company's short-term cash demands.
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $455,595 $427,702
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 98,557 123,573
Purchased Power. . . . . . . . . . . . . . . . . . . . . 92,564 50,591
Other Operation. . . . . . . . . . . . . . . . . . . . . 60,641 62,749
Maintenance. . . . . . . . . . . . . . . . . . . . . . . 28,325 28,511
Depreciation and Amortization. . . . . . . . . . . . . . 38,338 36,551
Taxes Other Than Federal Income Taxes. . . . . . . . . . 30,645 29,975
Federal Income Taxes . . . . . . . . . . . . . . . . . . 28,279 24,145
TOTAL OPERATING EXPENSES . . . . . . . . . . . . 377,349 356,095
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 78,246 71,607
NONOPERATING INCOME (LOSS) . . . . . . . . . . . . . . . . 781 (1,088)
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 79,027 70,519
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 31,363 31,258
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 47,664 39,261
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 633 675
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 47,031 $ 38,586
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
2000 1999
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $175,854 $179,461
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 47,664 39,261
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . . 31,653 30,348
Cumulative Preferred Stock . . . . . . . . . . . . . . 525 567
Capital Stock Expense. . . . . . . . . . . . . . . . . . 108 108
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $191,232 $187,699
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,027,997 $2,014,968
Transmission . . . . . . . . . . . . . . . . . . . . 1,155,336 1,151,377
Distribution . . . . . . . . . . . . . . . . . . . . 1,759,361 1,741,685
General. . . . . . . . . . . . . . . . . . . . . . . 251,634 247,798
Construction Work in Progress. . . . . . . . . . . . 94,906 107,123
Total Electric Utility Plant . . . . . . . . 5,289,234 5,262,951
Accumulated Depreciation and Amortization. . . . . . 2,104,479 2,079,490
NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,184,755 3,183,461
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 189,913 160,546
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 10,923 64,828
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 104,867 109,525
Affiliated Companies . . . . . . . . . . . . . . . 37,470 37,827
Miscellaneous. . . . . . . . . . . . . . . . . . . 9,254 9,154
Allowance for Uncollectible Accounts . . . . . . . (4,697) (2,609)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 49,260 58,161
Materials and Supplies . . . . . . . . . . . . . . . 56,261 56,917
Accrued Utility Revenues . . . . . . . . . . . . . . 38,120 53,418
Energy Trading Contracts . . . . . . . . . . . . . . 269,416 143,777
Prepayments. . . . . . . . . . . . . . . . . . . . . 6,848 7,713
TOTAL CURRENT ASSETS . . . . . . . . . . . . 577,722 538,711
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 436,744 436,894
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 40,737 34,788
TOTAL. . . . . . . . . . . . . . . . . . . $4,429,871 $4,354,400
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares. . . . . . . . . $ 260,458 $ 260,458
Paid-in Capital. . . . . . . . . . . . . . . . . . 714,434 714,259
Retained Earnings. . . . . . . . . . . . . . . . . 191,232 175,854
Total Common Shareholder's Equity. . . . . 1,166,124 1,150,571
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . 18,260 18,491
Subject to Mandatory Redemption. . . . . . . . . 20,310 20,310
Long-term Debt . . . . . . . . . . . . . . . . . . 1,535,052 1,539,302
TOTAL CAPITALIZATION . . . . . . . . . . . 2,739,746 2,728,674
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . 124,047 132,130
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . 48,005 126,005
Short-term Debt. . . . . . . . . . . . . . . . . . 128,425 123,480
Accounts Payable - General . . . . . . . . . . . . 43,369 59,150
Accounts Payable - Affiliated Companies. . . . . . 45,117 42,459
Taxes Accrued. . . . . . . . . . . . . . . . . . . 65,481 49,038
Customer Deposits. . . . . . . . . . . . . . . . . 12,764 12,898
Interest Accrued . . . . . . . . . . . . . . . . . 29,894 19,079
Energy Trading Contracts . . . . . . . . . . . . . 245,596 140,279
Other. . . . . . . . . . . . . . . . . . . . . . . 66,761 71,044
TOTAL CURRENT LIABILITIES. . . . . . . . . 685,412 643,432
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 676,645 671,917
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . 56,093 57,259
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . 147,928 120,988
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . $4,429,871 $4,354,400
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 47,664 $ 39,261
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . 38,366 36,814
Deferred Federal Income Taxes. . . . . . . . . . . . . 8,180 12,362
Deferred Investment Tax Credits. . . . . . . . . . . . (1,166) (1,172)
Deferred Power Supply Costs (net). . . . . . . . . . . (8,157) 14,706
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . 7,003 46,450
Fuel, Materials and Supplies . . . . . . . . . . . . . 9,557 (5,799)
Accrued Utility Revenues . . . . . . . . . . . . . . . 15,298 10,977
Prepayments. . . . . . . . . . . . . . . . . . . . . . 865 (6,348)
Accounts Payable . . . . . . . . . . . . . . . . . . . (13,123) (13,802)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 16,443 14,702
Interest Accrued . . . . . . . . . . . . . . . . . . . 10,815 9,298
Other (net). . . . . . . . . . . . . . . . . . . . . . . (35,164) (41,060)
Net Cash Flows From Operating Activities . . . . . 96,581 116,389
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . (39,901) (38,129)
Proceeds from Sale of Property . . . . . . . . . . . . . 16 127
Net Cash Flows Used For Investing Activities . . . (39,885) (38,002)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . 4,945 (19,125)
Retirement of Cumulative Preferred Stock . . . . . . . . (164) (4)
Retirement of Long-term Debt . . . . . . . . . . . . . . (83,201) -
Dividends Paid on Common Stock . . . . . . . . . . . . . (31,653) (30,348)
Dividends Paid on Cumulative Preferred Stock . . . . . . (528) (567)
Net Cash Flows Used For Financing Activities . . . (110,601) (50,044)
Net Increase (Decrease) in Cash and Cash Equivalents . . . (53,905) 28,343
Cash and Cash Equivalents at Beginning of Period . . . . . 64,828 7,755
Cash and Cash Equivalents at End of Period . . . . . . . . $ 10,923 $ 36,098
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $19,610,000 and $21,009,000
and for income taxes was $6,693,000 and $57,000 in 2000 and 1999, respectively.
Noncash acquisitions under capital leases were $3,361,000 and $2,453,000 in 2000
and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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. FINANCING ACTIVITIES
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.
3. RATE MATTERS
FERC
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 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 will make refunds retroactive to September 7,
1993 to certain customers affected by the July 30, 1999 FERC
order. The refunds will be made in two payments. The first
payment was made February 2000 pursuant to a FERC order
granting AEP's request to make interim refunds. The remainder
is to be paid upon approval by the FERC. In addition, a new
lower rate of $1.55 kw/month was made effective January 1,
2000, for all transmission service customers and a future rate
of $1.42 kw/month was established to take effect upon the
consummation of the AEP and Central and South West Corporation
merger.
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, 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 of 0.5 mills
per kwh); annual ENEC recovery proceedings are suspended and
deferral accounting for over or under recovery is discontinued
effective January 1, 2000; and the net cumulative deferred ENEC
recovery balance as established by a WVPSC order on December
27, 1996, which is $66 million at December 31, 1999, shall
remain on the books as a regulatory liability. If deregulation
of generation occurs in West Virginia (WV), the Company will
use this $66 million regulatory liability to reduce
unrecoverable 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 pending merger
between AEP Co., Inc. and Central and South West Corporation
prior to December 31, 2004 shall be retained by the Company.
All cost incurred in the merger that are allocated to the
Company, whether the merger is consummated or not, 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. If
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 the Company.
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 adjustments provided in the Joint Stipulation
and a 0.5 mills per kwh wires charge in the WV Restructuring
Plan (see Note 4 for discussion of WV Restructuring Plan).
Because the Joint Stipulation incorporated rate issues that
will affect customers of Wheeling Power Company, another AEP
Co., Inc. subsidiary, the WVPSC determined that an opportunity
for hearing should be given to Wheeling Power's customers
before taking action on the Joint Stipulation. Hearings were
held May 10, 2000.
<PAGE>
4. RESTRUCTURING
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 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 the establishment of a wires charge by the fourth
quarter of 2001.
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 for West Virginia. 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. Until the West Virginia legislature makes the
required tax law changes, the restructuring plan cannot take
effect.
The provisions of the proposed 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 generating assets on the
starting date; functional separation of the generation,
transmission and distribution businesses on the starting date
and their legal corporate 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; and establishment of a rate
stabilization deferral balance of $75.6 million by the end of
year ten of the transition period to be used as determined by
the WVPSC to offset prices paid 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 reduced 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.
Potential For Write Offs In Virginia and West Virginia
Jurisdictions
Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting
Standard (SFAS) No. 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
in the Virginia and West Virginia jurisdictions. The Company's
accounting for generation will continue to be in accordance
with SFAS 71 in the Virginia jurisdictions and will continue
to be considered to be cost-based regulated for accounting
purposes until the amount of capped rates and stranded cost
wires charges are determined and known. The establishment of
capped rates and wire charges should enable management to
determine the Company's ability to recover stranded costs
including regulatory assets and other transition costs, a
requirement to discontinue application of SFAS 71. The
application of SFAS 71 will be discontinued for the Virginia
retail jurisdictional portion of the Company's generating
business when the capped rates and the wires charge are known
in Virginia which is expected to occur by the fourth quarter
of 2000. In the West Virginia jurisdiction accounting for
generation will continue to be in accordance with SFAS 71 and
the generation business will continue to be considered to be
cost-based regulated for accounting purposes until the effects
of implementation of the West Virginia restructuring plan are
known and measurable.
Upon the discontinuance of SFAS 71 the Company will have
to write off its Virginia and West Virginia jurisdictional
generation-related regulatory assets to the extent that they
cannot be recovered under the frozen capped rates and stranded
cost distribution wires charges and record any asset accounting
impairments. An impairment loss would be recorded 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. Absent the
determination in the legislative or regulatory process of
transition rates, any wires charge and other pertinent
information, it is not possible at this time for management to
determine if any of the Company's generating assets are
impaired for accounting purposes on an undiscounted cash flow
basis.
The amount of regulatory assets recorded on the books at
March 31, 2000 applicable to the Virginia and West Virginia
retail jurisdictional generating business is $67 million and
$131 million, respectively, before related tax effects. 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 capped transition rates and allowed wires
charges in Virginia and West Virginia will permit their
recovery and whether the Company can reduce its cost under the
capped rates.
A determination of whether the Company will experience any
asset impairment loss regarding its Virginia and West Virginia
retail jurisdictional generating assets and any loss from a
possible inability to recover Virginia and West Virginia
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 or
legislative process. Should the Virginia SCC fail to approve
transition rates and wires charges that are sufficient to
provide for recovery or it not be possible under the West
Virginia restructuring plan to recover all or a portion 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.
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 March 31, 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.
<PAGE>
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 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.
Federal EPA also issued Notices of Violation, complaints
or administrative orders to eight unaffiliated utilities.
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. 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, unbundled transition period generation
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, the U.S. Court
of Appeals for the District of Columbia Circuit (Appeals Court)
issued a decision on March 3, 2000 generally upholding Federal
EPA's final rule (the NOx rule) that requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern
states, including the states in which the Company's generating
plants are located. A number of utilities, including the
Company, had filed petitions seeking a review of the final rule
in the 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. On
April 20, 2000, the AEP System companies and other industry
petitioners filed for rehearing of the March 3, 2000 decision
including a rehearing by the entire Appeals Court.
Preliminary estimates indicate that compliance with the 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 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 its 1999 Annual Report.
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
FIRST QUARTER 2000 vs. FIRST QUARTER 1999
RESULTS OF OPERATIONS
Net income increased due to a rise in operating income
reflecting a reduction in fuel costs and an increase in
nonoperating income. Income statement line items which changed
significantly were:
Increase (Decrease)
(in millions) %
Operating Revenues. . . . . . . . . . $ 27.9 7
Fuel. . . . . . . . . . . . . . . . . (25.0) (20)
Purchased Power . . . . . . . . . . . 42.0 83
Federal Income Taxes. . . . . . . . . 4.1 17
Nonoperating Income . . . . . . . . . 1.9 N.M.
N.M. = Not Meaningful
The increases in operating revenues and purchased power expense
reflect 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 cost of fuel and
purchase power expenses from the AEP Power Pool's wholesale sales
to neighboring utilities and marketers. As a result of an
affiliated company's major industrial customer's decision not to
extend its purchase power agreement, additional power was available
to the AEP Power Pool for sale on the wholesale market providing
the opportunity to increase Power Pool revenues. The increase in
operating revenues were partially offset by the effect of a
favorable adjustment in 1999 to a provision for revenue refunds in
the Company's Virginia jurisdiction in connection with the payment
of the refund.
Fuel expense decreased due to a discontinuance of deferral
accounting for the over or under recovery of fuel cost effective
January 1, 2000 as a result of a Joint Stipulation in the Company's
West Virginia jurisdiction. Fuel costs have declined since
discontinuance of deferral accounting favorably impacting fuel
expense.
<PAGE>
The increase in federal income tax expense attributable to
operations is primarily due to an increase in pre-tax operating
income.
Nonoperating income increased due to the favorable effect of
non-regulated power trading transactions outside the AEP Power
Pool's traditional marketing area and the effect of a provision for
loss related to litigation recorded in 1999.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first three months of 2000 were $43 million. Short-term debt
increased by $5 million during the quarter.
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.
OTHER MATTERS
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 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 the
establishment of a wires charge by the fourth quarter of 2001.
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 for
West Virginia. 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. Until the West
Virginia legislature makes the required tax law changes, the
restructuring plan cannot take effect.
The provisions of the proposed restructuring plan provide for
customer choice of electricity supplier 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 generating
assets on the starting date; functional separation of the
generation, transmission and distribution businesses on the
starting date and their legal corporate 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 choose to 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 stranded cost including net regulatory
assets; and establishment of a rate stabilization deferral balance
of $75.6 million by the end of year ten of the transition period to
be used as determined by the WVPSC to offset prices paid 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 reduced by 1% for
four and a half years, beginning July 1, 2000, and then increase to
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.
Potential For Write Offs In Virginia and West Virginia
Jurisdictions
Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting Standard
(SFAS) No. 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 in the Virginia
and West Virginia jurisdictions. The Company's accounting for
generation will continue to be in accordance with SFAS 71 in the
Virginia jurisdictions and will continue to be considered to be
cost-based regulated for accounting purposes until the amount of
capped rates and stranded cost wires charges are determined and
known. The establishment of capped rates and wire charges should
enable management to determine the Company's ability to recover
stranded costs including regulatory assets and other transition
costs, a requirement to discontinue application of SFAS 71. The
application of SFAS 71 will be discontinued for the Virginia retail
jurisdictional portion of the Company's generating business when
the capped rates and the wires charge are known in Virginia which
is expected to occur by the fourth quarter of 2000. In the West
Virginia jurisdiction accounting for generation will continue to be
in accordance with SFAS 71 and the generation business will
continue to be considered to be cost-based regulated for accounting
purposes until the effects of implementation of the West Virginia
restructuring plan are known and measurable.
Upon the discontinuance of SFAS 71 the Company will have to
write off its Virginia and West Virginia jurisdictional generation-related
regulatory assets to the extent that they cannot be
recovered under the frozen capped rates and stranded costs
distribution wires charges and record any asset accounting
impairments. An impairment loss would be recorded 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. Absent the determination in the
legislative or regulatory process of transition rates, wires charge
and other pertinent information, it is not possible at this time
for management to determine if any of the Company's generating
assets are impaired for accounting purposes on an undiscounted cash
flow basis.
The amount of regulatory assets recorded on the books at March
31, 2000 applicable to the Company's Virginia and West Virginia
retail jurisdictional generating business is $67 million and $131
million, respectively, before related tax effects. 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 capped transition rates and allowed wires charges in
Virginia and West Virginia will permit their recovery and whether
the Company can reduce its cost under the capped rates.
A determination of whether the Company will experience any
asset impairment loss regarding its Virginia and West Virginia
retail jurisdictional generating assets and any loss from a
possible inability to recover Virginia and West Virginia
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 or legislative
process. Should the Virginia SCC fail to approve transition rates
and wires charges that are sufficient to enable management to
provide for recovery or should it not be possible under the West
Virginia restructuring plan to recover all or a portion 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.
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 March 31,
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 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.
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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. 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 energy.
<PAGE>
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including the states in which
the Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the 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. On April 20, 2000,
the AEP System companies and other industry petitioners filed for
rehearing of the March 3, 2000 decision including a rehearing by
the entire Appeals Court.
Preliminary estimates indicate that compliance with the 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
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 which represent 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 AEP
Power Pool, has not changed materially since December 31, 1999.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at March 31, 2000 is not materially
different than at December 31, 1999.
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . $298,306 $279,067
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 40,748 45,856
Purchased Power. . . . . . . . . . . . . . . . . . . . . . 79,703 55,191
Other Operation. . . . . . . . . . . . . . . . . . . . . . 45,289 45,969
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . 14,696 13,946
Depreciation . . . . . . . . . . . . . . . . . . . . . . . 24,544 23,184
Taxes Other Than Federal Income Taxes. . . . . . . . . . . 31,477 31,078
Federal Income Taxes . . . . . . . . . . . . . . . . . . . 17,725 17,796
TOTAL OPERATING EXPENSES. . . . . . . . . . . . . . 254,182 233,020
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . 44,124 46,047
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . 1,684 361
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . 45,808 46,408
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . 18,337 18,990
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . 27,471 27,418
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . 533 533
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . $ 26,938 $ 26,885
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
2000 1999
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . $246,584 $186,441
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . 27,471 27,418
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . . . 23,650 21,999
Cumulative Preferred Stock . . . . . . . . . . . . . . . 437 437
Capital Stock Expense. . . . . . . . . . . . . . . . . . . 96 96
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . $249,872 $191,327
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,553,596 $1,544,858
Transmission . . . . . . . . . . . . . . . . . . . . 353,410 350,826
Distribution . . . . . . . . . . . . . . . . . . . . 1,049,831 1,032,550
General. . . . . . . . . . . . . . . . . . . . . . . 147,786 141,137
Construction Work in Progress. . . . . . . . . . . . 68,682 82,248
Total Electric Utility Plant . . . . . . . . 3,173,305 3,151,619
Accumulated Depreciation . . . . . . . . . . . . . . 1,231,138 1,210,994
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,942,167 1,940,625
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 115,406 101,286
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 7,451 5,107
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 66,557 77,418
Affiliated Companies . . . . . . . . . . . . . . . 17,987 28,453
Miscellaneous. . . . . . . . . . . . . . . . . . . 5,422 8,887
Allowance for Uncollectible Accounts . . . . . . . (2,310) (3,045)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 20,284 21,484
Materials and Supplies . . . . . . . . . . . . . . . 42,807 41,696
Accrued Utility Revenues . . . . . . . . . . . . . . 40,727 48,117
Energy Trading Contracts . . . . . . . . . . . . . . 156,270 90,103
Prepayments. . . . . . . . . . . . . . . . . . . . . 43,518 37,969
TOTAL CURRENT ASSETS . . . . . . . . . . . . 398,713 356,189
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 339,968 339,103
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 55,372 72,787
TOTAL. . . . . . . . . . . . . . . . . . . $2,851,626 $2,809,990
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares. . . . . . . . . $ 41,026 $ 41,026
Paid-in Capital. . . . . . . . . . . . . . . . . . 572,968 572,873
Retained Earnings. . . . . . . . . . . . . . . . . 249,872 246,584
Total Common Shareholder's Equity. . . . . 863,866 860,483
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . 25,000 25,000
Long-term Debt . . . . . . . . . . . . . . . . . . 922,690 924,545
TOTAL CAPITALIZATION . . . . . . . . . . . 1,811,556 1,810,028
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . 40,857 43,056
CURRENT LIABILITIES:
Short-term Debt. . . . . . . . . . . . . . . . . . 39,475 45,500
Accounts Payable - General . . . . . . . . . . . . 24,058 28,279
Accounts Payable - Affiliated Companies. . . . . . 46,557 52,776
Taxes Accrued. . . . . . . . . . . . . . . . . . . 113,923 143,477
Interest Accrued . . . . . . . . . . . . . . . . . 22,636 13,936
Energy Trading Contracts . . . . . . . . . . . . . 142,453 87,911
Other. . . . . . . . . . . . . . . . . . . . . . . 33,027 34,375
TOTAL CURRENT LIABILITIES. . . . . . . . . 422,129 406,254
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 448,453 447,607
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . 43,869 44,716
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . 84,762 58,329
CONTINGENCIES (Note 4)
TOTAL. . . . . . . . . . . . . . . . . . $2,851,626 $2,809,990
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 27,471 $ 27,418
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . 24,669 23,232
Deferred Federal Income Taxes. . . . . . . . . . . . . 5,072 (48)
Deferred Investment Tax Credits. . . . . . . . . . . . (847) (868)
Deferred Fuel Costs (net). . . . . . . . . . . . . . . (5,408) 836
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . 24,057 (1,756)
Fuel, Materials and Supplies . . . . . . . . . . . . . 89 1,616
Accrued Utility Revenues . . . . . . . . . . . . . . . 7,390 4,484
Prepayments. . . . . . . . . . . . . . . . . . . . . . (5,549) (9,228)
Accounts Payable . . . . . . . . . . . . . . . . . . . (10,440) (7,199)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . (29,554) (13,918)
Interest Accrued . . . . . . . . . . . . . . . . . . . 8,700 9,939
Other (net). . . . . . . . . . . . . . . . . . . . . . . 15,474 18,912
Net Cash Flows From Operating Activities . . . . . 61,124 53,420
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . (27,022) (16,908)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 330 246
Net Cash Flows Used For Investing Activities . . . (26,692) (16,662)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . (6,025) (6,800)
Retirement of Long-term Debt . . . . . . . . . . . . . . (1,976) -
Dividends Paid on Common Stock . . . . . . . . . . . . . (23,650) (21,999)
Dividends Paid on Cumulative Preferred Stock . . . . . . (437) (437)
Net Cash Flows Used For Financing Activities . . . (32,088) (29,236)
Net Increase in Cash and Cash Equivalents. . . . . . . . . 2,344 7,522
Cash and Cash Equivalents at Beginning of Period . . . . . 5,107 7,206
Cash and Cash Equivalents at End of Period . . . . . . . . $ 7,451 $ 14,728
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $8,684,000 and $8,115,000
and for income taxes was $6,607,000 and $44,000 in 2000 and 1999, respectively.
Noncash acquisitions under capital leases were $1,377,000 and $2,182,000 in 2000
and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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. 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.
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 will make
refunds retroactive to September 7, 1993 to certain customers
affected by the July 30, 1999 FERC order. The refunds will be made
in two payments. The first payment was made February 2000 pursuant
to a FERC order granting AEP's request to make interim refunds.
The remainder is to be paid upon approval by the FERC. In addition,
a new lower rate of $1.55 kw/month was made effective January 1,
2000, for all transmission service customers and a future rate of
$1.42 kw/month was established to take effect upon the consummation
of the AEP and Central and South West Corporation merger.
3. 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 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 would not 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. The
key provisions of the stipulation agreement are:
Recovery of regulatory assets over eight years.
A shopping incentive 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 for cerain transmission
charges imposed by PJM and/or Midwest ISO on generation
originating in the Midwest ISO or PJM.
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 will be litigated. Hearings to address the gross
receipts tax issue are scheduled for May 31, 2000.
The stipulation agreement is subject to approval by the PUCO.
Hearings on the stipulation are scheduled for June 7, 2000.
Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting Standard
(SFAS) No. 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 the transition plan
should 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 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 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 March
31, 2000 applicable to the Ohio retail jurisdictional generating
business is $302 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.
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 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.
4. 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 March 31,
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
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.
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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. 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 U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including Ohio where the
Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the Appeals Court. In May 1999, the Appeals Court had
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. On April 20, 2000,
the AEP System companies and other industry petitioners filed for
rehearing of the March 3, 2000 decision including a rehearing by the
entire Appeals Court.
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 the 1999 annual report.
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 2000 vs. FIRST QUARTER 1999
Net income was relatively unchanged in the first quarter as a
decline in operating income was offset by an increase in nonoperating
income and a reduction in interest charges.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Operating Revenues . . . . . . . . . . . $19.2 7
Fuel . . . . . . . . . . . . . . . . . . (5.1) (11)
Purchased Power. . . . . . . . . . . . . 24.5 44
Maintenance. . . . . . . . . . . . . . . 0.8 5
Depreciation . . . . . . . . . . . . . . 1.4 6
Nonoperating Income. . . . . . . . . . . 1.3 366
Interest Charges . . . . . . . . . . . . (0.7) (3)
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 sales to neighboring utility systems and power marketers. 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 due to the operation of the fuel clause
adjustment mechanism which resulted in a credit to fuel expense for
underrecovery of emission allowance costs which were deferred as a
regulatory asset.
Maintenance of distribution and transmission lines accounted for the
increase in maintenance expense.
Additional investment in distribution plant resulted in the increase
in depreciation expense.
<PAGE>
The increase in nonoperating income was due to the reversal 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.
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $343,986 $334,113
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 47,860 41,800
Purchased Power. . . . . . . . . . . . . . . . . . . . . 85,106 62,315
Other Operation. . . . . . . . . . . . . . . . . . . . . 133,551 91,575
Maintenance. . . . . . . . . . . . . . . . . . . . . . . 55,384 31,202
Depreciation and Amortization. . . . . . . . . . . . . . 38,211 36,985
Taxes Other Than Federal Income Taxes. . . . . . . . . . 17,209 19,029
Federal Income Tax Expense (Credit). . . . . . . . . . . (18,084) 12,369
TOTAL OPERATING EXPENSES . . . . . . . . . . . . 359,237 295,275
OPERATING INCOME (LOSS). . . . . . . . . . . . . . . . . . (15,251) 38,838
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . 565 1,735
INCOME (LOSS) BEFORE INTEREST CHARGES. . . . . . . . . . . (14,686) 40,573
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 21,867 20,503
NET INCOME (LOSS). . . . . . . . . . . . . . . . . . . . . (36,553) 20,070
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 1,160 1,214
EARNINGS (LOSS) APPLICABLE TO COMMON STOCK . . . . . . . . $(37,713) $ 18,856
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
2000 1999
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $166,389 $253,154
NET INCOME (LOSS). . . . . . . . . . . . . . . . . . . . . (36,553) 20,070
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . . 26,290 28,664
Cumulative Preferred Stock . . . . . . . . . . . . . . 1,125 1,182
Capital Stock Expense. . . . . . . . . . . . . . . . . . 57 32
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $102,364 $243,346
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,593,200 $2,587,288
Transmission . . . . . . . . . . . . . . . . . . . . 934,200 928,758
Distribution . . . . . . . . . . . . . . . . . . . . 826,783 818,697
General (including nuclear fuel) . . . . . . . . . . 252,702 244,981
Construction Work in Progress. . . . . . . . . . . . 212,810 190,303
Total Electric Utility Plant . . . . . . . . 4,819,695 4,770,027
Accumulated Depreciation and Amortization. . . . . . 2,222,404 2,194,397
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,597,291 2,575,630
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS . . . . . . . . . . . . . . . . 723,697 707,967
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 226,373 213,658
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 8,244 3,863
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 90,706 91,268
Affiliated Companies . . . . . . . . . . . . . . . 37,655 48,901
Miscellaneous. . . . . . . . . . . . . . . . . . . 17,516 18,644
Allowance for Uncollectible Accounts . . . . . . . (1,622) (1,848)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 23,720 27,597
Materials and Supplies . . . . . . . . . . . . . . . 83,417 84,149
Accrued Utility Revenues . . . . . . . . . . . . . . 41,992 44,428
Energy Trading Contracts . . . . . . . . . . . . . . 169,876 97,946
Prepayments. . . . . . . . . . . . . . . . . . . . . 10,205 7,631
TOTAL CURRENT ASSETS . . . . . . . . . . . . 481,709 422,579
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 598,632 624,810
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 43,072 32,052
TOTAL. . . . . . . . . . . . . . . . . . . $4,670,774 $4,576,696
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares . . . . . . . . . . $ 56,584 $ 56,584
Paid-in Capital. . . . . . . . . . . . . . . . . . . 732,802 732,739
Retained Earnings. . . . . . . . . . . . . . . . . . 102,364 166,389
Total Common Shareholder's Equity. . . . . . 891,750 955,712
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 8,989 9,248
Subject to Mandatory Redemption. . . . . . . . . . 64,945 64,945
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,129,334 1,126,326
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,095,018 2,156,231
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 515,587 501,185
Other. . . . . . . . . . . . . . . . . . . . . . . . 198,129 242,522
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 713,716 743,707
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 150,000 198,000
Short-term Debt. . . . . . . . . . . . . . . . . . . 348,393 224,262
Accounts Payable - General . . . . . . . . . . . . . 51,533 78,784
Accounts Payable - Affiliated Companies. . . . . . . 39,437 31,118
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 52,764 48,970
Interest Accrued . . . . . . . . . . . . . . . . . . 17,101 13,955
Obligations Under Capital Leases . . . . . . . . . . 47,081 11,072
Energy Trading Contracts . . . . . . . . . . . . . . 154,856 95,564
Other. . . . . . . . . . . . . . . . . . . . . . . . 107,891 91,684
TOTAL CURRENT LIABILITIES. . . . . . . . . . 969,056 793,409
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 609,435 622,157
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 119,740 121,627
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 84,079 85,005
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 79,730 54,560
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $4,670,774 $4,576,696
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income (Loss). . . . . . . . . . . . . . . . . . . . . $(36,553) $ 20,070
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 39,191 37,995
Amortization of Incremental Nuclear
Refueling Outage Expenses (net). . . . . . . . . . . . 2,035 2,347
Unrecovered Fuel and Purchased Power Costs . . . . . . . 9,375 (52,664)
Amortization (Deferral) of Nuclear Outage Costs (net). . 10,000 (30,000)
Deferred Federal Income Taxes. . . . . . . . . . . . . . (7,801) 5,365
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,887) (1,898)
Deferred Property Taxes. . . . . . . . . . . . . . . . . (10,241) (9,325)
Rate Refunds . . . . . . . . . . . . . . . . . . . . . . (3,740) -
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 12,710 (1,247)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 4,609 (15,154)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 2,436 9,094
Accounts Payable . . . . . . . . . . . . . . . . . . . . (18,932) 5,225
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 3,794 14,541
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 8,296 55,000
Other Current Liabilities. . . . . . . . . . . . . . . . (16,095) 14,308
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (9,787) (7,492)
Net Cash Flows From Operating Activities . . . . . . 5,874 64,629
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (51,435) (30,114)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 250 903
Net Cash Flows Used For Investing Activities . . . . (51,185) (29,211)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . . 124,131 1,595
Retirement of Long-term Debt . . . . . . . . . . . . . . . (48,000) -
Retirement of Cumulative Preferred Stock . . . . . . . . . (149) (5)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (26,290) (28,664)
Dividends Paid on Cumulative Preferred Stock . . . . . . . - (1,182)
Net Cash Flows From (Used For) Financing Activities. 49,692 (28,256)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 4,381 7,162
Cash and Cash Equivalents at Beginning of Period . . . . . . 3,863 5,424
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 8,244 $ 12,586
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $17,965,000 and
$18,527,000 in 2000 and 1999, respectively and for income taxes was $(8,966,000)in
2000. Noncash acquisitions under capital leases were $1,184,000 and $3,783,000 in
2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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 March 2000 the Company redeemed at maturity $48 million
of its 6.40% series of first mortgage bonds.
3. RATE MATTERS
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 will make refunds retroactive to September 7,
1993 to certain customers affected by the July 30, 1999 FERC
order. The refunds will be made in two payments. The first
payment was made February 2000 pursuant to a FERC order
granting AEP's request to make interim refunds. The remainder
is to be paid upon approval by the FERC. In addition, a new
lower rate of $1.55 kw/month was made effective January 1, 2000,
for all transmission service customers and a future rate of
$1.42 kw/month was established to take effect upon the
consummation of the AEP and Central and South West Corporation
merger.
4. 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.
In February 2000, the Company was notified by the NRC that
the Confirmatory Action Letter had been closed. Closing of the
Confirmatory Action Letter is one of the key approvals needed
to restart the nuclear units. The Confirmatory Action Letter
was issued in September 1997 requiring the Company to address
certain issues identified in the letter.
Progress to restart the units continues. Refueling of Unit
2, the first unit scheduled to restart, was completed on April
14, 2000. The NRC's final Unit 2 pre-restart inspection began
on May 8, 2000, which coincided with the reactor heat-up of Unit
2 and the return to operational service of common plant systems.
When testing and other work required for restart are complete,
the Company will seek concurrence from the NRC to return Unit
2 to service. Refueling and maintenance work to restart Unit
1 will be performed after Unit 2 is returned to service. Any
issues or difficulties encountered in testing of equipment as
part of the restart process could delay the restart of the
units.
Expenditures to restart the Cook units are estimated to
total approximately $574 million. Through March 31, 2000, $453
million has been spent. In 2000 $80 million of restart costs
were recorded in other operation and maintenance expense,
including amortization of $10 million of restart costs
previously deferred in accordance with settlement agreements in
the Indiana and Michigan retail jurisdictions.
The costs of the extended outage and restart efforts will
have a material adverse effect on future results of operations
and cash flows until the units are restarted. The amortization
of restart costs deferred under Indiana and Michigan retail
jurisdiction settlement agreements will adversely effect results
of operations and possibly financial condition through 2003 when
the amortization period ends. Management believes that the Cook
units will be successfully returned to service. However, if for
some unknown reason the units are not returned to service or
their return is delayed significantly it would have an even
greater adverse effect on future results of operations, cash
flows and financial condition.
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 March 31, 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 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.
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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.
<PAGE>
On May 10, 2000, the Company filed motions to dismiss all or
portions of the complaints. 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 energy.
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated
Financial Statements in the 1999 Annual Report, the U.S. Court
of Appeals for the District of Columbia Circuit (Appeals Court)
issued a decision on March 3, 2000 generally upholding Federal
EPA's final rule (the NOx rule) that requires substantial
reductions in nitrogen oxide (NOx) emissions in 22 eastern
states, including the states in which the Company's generating
plants are located. A number of utilities, including the
Company, had filed petitions seeking a review of the final rule
in the 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. On
April 20, 2000, the AEP System companies and other industry
petitioners filed for rehearing of the March 3, 2000 decision
including a rehearing by the entire Appeals 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 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 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
FIRST QUARTER 2000 vs. FIRST QUARTER 1999
RESULTS OF OPERATIONS
The Company reported a loss of $37 million for the first quarter
of 2000 compared with net income of $20 million in 1999.
Expenditures to prepare the Company's two unit Donald C. Cook
Nuclear Plant (Cook Plant) for restart following an extended outage
are the primary reasons for the loss. 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. In accordance with a settlement
agreement in Indiana which resolved all Indiana jurisdictional
rate-related issues applicable to the Cook Plant's extended outage
certain restart expenses were deferred in the first quarter of
1999. A settlement to resolve all rate-related issues in the
Michigan jurisdiction was approved in December 1999 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)
(in millions) %
Operating Revenues. . . . . . . . . . . . $ 9.9 3
Fuel. . . . . . . . . . . . . . . . . . . 6.1 14
Purchased Power . . . . . . . . . . . . . 22.8 37
Other Operation . . . . . . . . . . . . . 42.0 46
Maintenance . . . . . . . . . . . . . . . 24.2 78
Federal Income Tax. . . . . . . . . . . . (30.5) N.M.
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 to neighboring utility systems and power
marketers by the AEP Power Pool on behalf of the Company offset in
part by the amortization of previously accrued fuel-related
revenues. As a member of the AEP Power Pool, the Company shares in
the revenues and costs of the AEP Power Pool's wholesale sales.
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 more energy due to the expiration
of that affiliate's unit power 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. The increase in operating revenues
from sales by the AEP Power Pool is due to the significant increase
in AEP Power Pool transactions, which also contributed to the
increase in purchased power. As a result of an affiliated
company's major industrial customer's decision not to extend its
purchase power agreement, additional power was delivered to the AEP
Power Pool allowing the Power Pool to increase its wholesale sales.
The decrease in revenues caused by the amortization of previously
accrued fuel-related revenues resulted from the amortization in the
current period of revenues accrued through 1999 for the increased
cost of replacement power and increased fossil fuel usage
necessitated by the extended outage of the Cook Nuclear Plant. The
accrual of revenues was authorized under the terms of approved
settlement agreements for the Indiana and Michigan jurisdictions.
Fuel expense increased due to a 13.9% rise in generation
reflecting the higher availability of the Company's coal-fired
generating units due to shorter planned maintenance outages.
The increase in other operation and maintenance expense was
primarily caused by the continuing work to restart the Cook Plant,
combined with the amortization of deferred expenditures under the
terms of the approved settlement agreements in Indiana and
Michigan.
The decrease in federal income tax expense attributable to
operations was primarily due to a decrease in pre-tax operating
income.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the period were $53 million. During the first three months of 2000
short-term debt outstanding increased by $124 million. In March
the Company redeemed at maturity $48 million of 6.40% first
mortgage bonds.
<PAGE>
OTHER MATTERS
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.
In February 2000, the Company was notified by the NRC that the
Confirmatory Action Letter had been closed. Closing of the
Confirmatory Action Letter is one of the key approvals needed to
restart the nuclear units. The Confirmatory Action Letter was
issued in September 1997 requiring the Company to address certain
issues identified in the letter.
Progress to restart the units continues. Refueling of Unit 2,
the first unit scheduled to restart, was completed on April 14,
2000. The NRC's final Unit 2 pre-restart inspection began on May
8, 2000, which coincided with the reactor heat-up of Unit 2 and the
return to operational service of common plant systems. When
testing and other work required for restart are complete, the
Company will seek concurrence from the NRC to return Unit 2 to
service. Refueling and maintenance work to restart Unit 1 will be
performed after Unit 2 is returned to service. Any issues or
difficulties encountered in testing of equipment as part of the
restart process could delay the restart of the units.
Expenditures to restart the Cook units are estimated to total
approximately $574 million. Through March 31, 2000, $453 million
has been spent. In 2000 $80 million of restart costs were recorded
in other operation and maintenance expense, including amortization
of $10 million of restart costs previously deferred in accordance
with settlement agreements in the Indiana and Michigan retail
jurisdictions.
The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations and cash
flows until the units are restarted. The amortization of restart
costs deferred under Indiana and Michigan retail jurisdiction
settlement agreements will adversely effect results of operations
and possibly financial condition through 2003 when the amortization
period ends. Management believes that the Cook units will be
successfully returned to service. However, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater 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 March 31,
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 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.
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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. 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 energy.
NOx Reductions
As discussed in Note 6 of the Notes to Consolidated Financial
Statements in the 1999 Annual Report, the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including the states in which
the Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the 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. On April 20, 2000,
the AEP System companies and other industry petitioners filed for
rehearing of the March 3, 2000 decision including a rehearing by
the entire Appeals 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
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 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 which represent 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 AEP
Power Pool, has not changed materially since December 31, 1999.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at March 31, 2000 is not materially
different than at December 31, 1999.
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . $97,204 $90,741
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . 16,802 19,691
Purchased Power. . . . . . . . . . . . . . . . . . 33,482 24,427
Other Operation. . . . . . . . . . . . . . . . . . 10,384 12,351
Maintenance. . . . . . . . . . . . . . . . . . . . 6,367 4,791
Depreciation and Amortization. . . . . . . . . . . 7,603 7,190
Taxes Other Than Federal Income Taxes. . . . . . . 2,834 2,534
Federal Income Taxes . . . . . . . . . . . . . . . 4,175 4,397
TOTAL OPERATING EXPENSES . . . . . . . . . 81,647 75,381
OPERATING INCOME . . . . . . . . . . . . . . . . . . 15,557 15,360
NONOPERATING LOSS. . . . . . . . . . . . . . . . . . (46) (114)
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . 15,511 15,246
INTEREST CHARGES . . . . . . . . . . . . . . . . . . 7,459 7,037
NET INCOME . . . . . . . . . . . . . . . . . . . . . $ 8,052 $ 8,209
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
2000 1999
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . $67,110 $71,452
NET INCOME . . . . . . . . . . . . . . . . . . . . . 8,052 8,209
CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . 7,590 7,443
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . $67,572 $72,218
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . $ 269,012 $ 268,618
Transmission . . . . . . . . . . . . . . . . 356,402 355,442
Distribution . . . . . . . . . . . . . . . . 375,974 372,752
General. . . . . . . . . . . . . . . . . . . 67,866 67,608
Construction Work in Progress. . . . . . . . 13,837 14,628
Total Electric Utility Plant . . . . 1,083,091 1,079,048
Accumulated Depreciation and Amortization. . 344,027 340,008
NET ELECTRIC UTILITY PLANT . . . . . 739,064 739,040
OTHER PROPERTY AND INVESTMENTS . . . . . . . . 25,692 20,416
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . 1,384 674
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . 20,287 18,952
Affiliated Companies . . . . . . . . . . . 14,335 15,223
Miscellaneous. . . . . . . . . . . . . . . 7,979 8,343
Allowance for Uncollectible Accounts . . . (615) (637)
Fuel . . . . . . . . . . . . . . . . . . . . 11,954 10,441
Materials and Supplies . . . . . . . . . . . 17,397 18,113
Accrued Utility Revenues . . . . . . . . . . 10,463 13,737
Energy Trading Contracts . . . . . . . . . . 64,006 33,919
Prepayments. . . . . . . . . . . . . . . . . 947 1,450
TOTAL CURRENT ASSETS . . . . . . . . 148,137 120,215
REGULATORY ASSETS. . . . . . . . . . . . . . . 98,289 96,296
DEFERRED CHARGES . . . . . . . . . . . . . . . 9,136 10,671
TOTAL. . . . . . . . . . . . . . . $1,020,318 $ 986,638
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - Par Value $50:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares . . . . . . $ 50,450 $ 50,450
Paid-in Capital. . . . . . . . . . . . . . . 158,750 158,750
Retained Earnings. . . . . . . . . . . . . . 67,572 67,110
Total Common Shareholder's Equity. . 276,772 276,310
Long-term Debt . . . . . . . . . . . . . . . 260,852 260,782
TOTAL CAPITALIZATION . . . . . . . . 537,624 537,092
OTHER NONCURRENT LIABILITIES . . . . . . . . . 22,456 23,797
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . 105,000 105,000
Short-term Debt. . . . . . . . . . . . . . . 37,600 39,665
Accounts Payable - General . . . . . . . . . 6,666 9,923
Accounts Payable - Affiliated Companies. . . 20,666 19,743
Customer Deposits. . . . . . . . . . . . . . 4,168 4,143
Taxes Accrued. . . . . . . . . . . . . . . . 10,573 9,860
Interest Accrued . . . . . . . . . . . . . . 7,199 4,843
Energy Trading Contracts . . . . . . . . . . 58,347 33,094
Other. . . . . . . . . . . . . . . . . . . . 10,684 12,020
TOTAL CURRENT LIABILITIES. . . . . . 260,903 238,291
DEFERRED INCOME TAXES. . . . . . . . . . . . . 166,931 165,007
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . 12,610 12,908
DEFERRED CREDITS . . . . . . . . . . . . . . . 19,794 9,543
CONTINGENCIES (Note 3)
TOTAL. . . . . . . . . . . . . . . $1,020,318 $986,638
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . $ 8,052 $ 8,209
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . 7,605 7,192
Deferred Federal Income Taxes. . . . . . . . . . 1,961 (254)
Deferred Investment Tax Credits. . . . . . . . . (298) (300)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . (105) 4,039
Fuel, Materials and Supplies . . . . . . . . . . (797) (1,893)
Accrued Utility Revenues . . . . . . . . . . . . 3,274 (13)
Accounts Payable . . . . . . . . . . . . . . . . (2,334) (1,542)
Taxes Accrued. . . . . . . . . . . . . . . . . . 713 5,131
Interest Accrued . . . . . . . . . . . . . . . . 2,356 2,554
Other (net). . . . . . . . . . . . . . . . . . . . (2,489) 1,519
Net Cash Flows From Operating Activities . . 17,938 24,642
INVESTING ACTIVITIES - Construction Expenditures . . (7,573) (6,483)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . (2,065) (8,400)
Dividends Paid . . . . . . . . . . . . . . . . . . (7,590) (7,443)
Net Cash Flows Used For
Financing Activities . . . . . . . . . . . (9,655) (15,843)
Net Increase in Cash and Cash Equivalents. . . . . . 710 2,316
Cash and Cash Equivalents at Beginning of Period . . 674 1,935
Cash and Cash Equivalents at End of Period . . . . . $ 1,384 $ 4,251
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $5,029,000 and
$4,374,000 in 2000 and 1999, respectively and for income taxes was
$2,001,000 in 2000. Noncash acquisitions under capital leases were $374,000
and $568,000 in 2000 and 1999, respectively.
See Notes to Financial Statements.
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 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. RATE MATTERS
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.
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 will make refunds retroactive to September 7,
1993 to certain customers affected by the July 30, 1999 FERC
order. The refunds will be made in two payments. The first
payment was made February 2000 pursuant to a FERC order
granting AEP's request to make interim refunds. The remainder
is to be paid upon approval by the FERC. In addition, a new
lower rate of $1.55 kw/month was made effective January 1, 2000,
for all transmission service customers and a future rate of
$1.42 kw/month was established to take effect upon the
consummation of the AEP and Central and South West Corporation
merger.
3. 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 March 31, 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 Co., 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 for the Southern District of Ohio that alleges
certain AEP System companies 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.
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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. 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
of the 1999 Annual Report, the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule
(the NOx rule) that requires substantial reductions in nitrogen
oxide (NOx) emissions in 22 eastern states, including Kentucky
where the Company's generating plant is located. A number of
utilities, including the Company, had filed petitions seeking
a review of the final rule in the Appeals Court. In May 1999,
the Appeals Court had 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. On April 20, 2000, the AEP System companies and
other industry petitioners filed for rehearing of the March 3,
2000 decision including a rehearing by the entire Appeals 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
FIRST QUARTER 2000 vs. FIRST QUARTER 1999
Although revenues rose 7%, net income decreased in the first
quarter primarily as a result of increased interest expense.
Income statement line items which changed significantly were:
Increase(Decrease)
(in millions) %
Operating Revenues. . . . . . . . . . . $ 6.5 7
Fuel. . . . . . . . . . . . . . . . . . (2.9) (15)
Purchased Power . . . . . . . . . . . . 9.1 37
Other Operation . . . . . . . . . . . . (2.0) (16)
Maintenance . . . . . . . . . . . . . . 1.6 33
Depreciation. . . . . . . . . . . . . . 0.4 6
Net Interest Charges. . . . . . . . . . 0.4 6
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) wholesale electricity sales. The
Company as a member of the AEP Power Pool shares in the revenues
and costs of the AEP Power Pool's wholesale electricity marketing
to neighboring utility system and power marketers. 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 sales. Purchased power also increased
due to an increase in the availability of the Rockport Plant.
Under a non-AEP Power Pool purchase power agreement with an
affiliate, the Company purchases 15% of the available power of the
Rockport Plant. Rockport Plant generated 16% more kwh in 2000 than
1999.
Fuel expense decreased due to an outage of the Company's Big
Sandy Plant Unit 2 which began in March 2000.
The Company as a party to the AEP System's Transmission
Agreement shares the costs associated with the ownership of the AEP
System's 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 applicable
investment in transmission facilities. The decrease in other
operation expense was primarily due to an increase in transmission
equalization credits as a result of an increase in the Company's
MLR and increased investment in transmission facilities. Member
load ratio is calculated monthly on the basis of each company's
maximum peak demand in relation to the sum of the maximum peak
demands of all five signatories to the agreement during the
preceding 12 months.
The Big Sandy Plant began an outage in March 2000 for the
repair and maintenance of Unit 2. Unit 2 returned to service in
April 2000.
The increase in transmission plant investment 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 reflecting the Company's short-term
cash demands and short-term debt interest market conditions.
<PAGE>
<PAGE>
</TABLE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . $545,411 $518,221
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . 215,248 189,163
Purchased Power. . . . . . . . . . . . . . . . . . . . . . . 35,302 21,273
Other Operation. . . . . . . . . . . . . . . . . . . . . . . 84,452 85,061
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . 28,030 25,490
Depreciation and Amortization. . . . . . . . . . . . . . . . 38,489 36,785
Taxes Other Than Federal Income Taxes. . . . . . . . . . . . 43,732 43,853
Federal Income Taxes . . . . . . . . . . . . . . . . . . . . 35,045 37,640
TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . 480,298 439,265
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . 65,113 78,956
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . 2,900 2,000
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . 68,013 80,956
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . 21,797 20,135
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . 46,216 60,821
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . . 321 367
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . $ 45,895 $ 60,454
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
2000 1999
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . . $587,424 $587,500
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . 46,216 60,821
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . . . . 37,703 57,703
Cumulative Preferred Stock . . . . . . . . . . . . . . . . 317 367
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . . $595,620 $590,251
The common stock of the Company is wholly owned by American Electric Power Company,
Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,722,614 $2,713,421
Transmission . . . . . . . . . . . . . . . . . . . . 860,900 857,420
Distribution . . . . . . . . . . . . . . . . . . . . 1,010,110 999,679
General (including mining assets). . . . . . . . . . 715,814 713,882
Construction Work in Progress. . . . . . . . . . . . 114,260 116,515
Total Electric Utility Plant . . . . . . . . 5,423,698 5,400,917
Accumulated Depreciation and Amortization. . . . . . 2,668,873 2,621,711
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,754,825 2,779,206
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 277,790 253,668
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 226,877 157,138
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 235,875 246,310
Affiliated Companies . . . . . . . . . . . . . . . 158,457 89,215
Miscellaneous. . . . . . . . . . . . . . . . . . . 27,395 22,055
Allowance for Uncollectible Accounts . . . . . . . (2,100) (2,223)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 131,478 146,317
Materials and Supplies . . . . . . . . . . . . . . . 97,092 95,967
Accrued Utility Revenues . . . . . . . . . . . . . . 33,056 45,575
Energy Trading Contracts . . . . . . . . . . . . . . 234,374 134,567
Prepayments and Other. . . . . . . . . . . . . . . . 43,413 38,472
TOTAL CURRENT ASSETS . . . . . . . . . . . . 1,185,917 973,393
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 584,216 577,090
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 80,289 93,852
TOTAL. . . . . . . . . . . . . . . . . . . $4,883,037 $4,677,209
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
2000 1999
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares. . . . . . . . . . $ 321,201 $ 321,201
Paid-in Capital. . . . . . . . . . . . . . . . . . . 462,402 462,376
Retained Earnings. . . . . . . . . . . . . . . . . . 595,620 587,424
Total Common Shareholder's Equity. . . . . . 1,379,223 1,371,001
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 16,865 16,937
Subject to Mandatory Redemption. . . . . . . . . . 8,850 8,850
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,130,492 1,139,834
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,535,430 2,536,622
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 431,672 414,837
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 11,881 11,677
Short-term Debt. . . . . . . . . . . . . . . . . . . 241,424 194,918
Accounts Payable - General . . . . . . . . . . . . . 183,173 180,383
Accounts Payable - Affiliated Companies. . . . . . . 81,424 64,599
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 160,788 179,112
Interest Accrued . . . . . . . . . . . . . . . . . . 23,412 16,863
Obligations Under Capital Leases . . . . . . . . . . 34,166 34,284
Energy Trading Contracts . . . . . . . . . . . . . . 213,651 131,844
Other. . . . . . . . . . . . . . . . . . . . . . . . 110,299 96,445
TOTAL CURRENT LIABILITIES. . . . . . . . . . 1,060,218 910,125
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 666,369 676,460
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 35,021 35,838
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 154,327 103,327
CONTINGENCIES (Note 4)
TOTAL. . . . . . . . . . . . . . . . . . . $4,883,037 $4,677,209
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
2000 1999
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 46,216 $ 60,821
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . 60,294 45,129
Deferred Federal Income Taxes. . . . . . . . . . . . . (14,957) (3,601)
Deferred Fuel Costs (net). . . . . . . . . . . . . . . (3,961) (7,227)
Amortization of Deferred Property Taxes. . . . . . . . 19,666 19,426
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . (64,270) (107,053)
Fuel, Materials and Supplies . . . . . . . . . . . . . 13,714 (20,409)
Accrued Utility Revenues . . . . . . . . . . . . . . . 12,519 4,082
Prepayments and Other. . . . . . . . . . . . . . . . . (4,941) (13,013)
Accounts Payable . . . . . . . . . . . . . . . . . . . 19,615 6,374
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . (18,324) 3,019
Interest Accrued . . . . . . . . . . . . . . . . . . . 6,549 9,025
Operating Reserves . . . . . . . . . . . . . . . . . . . 22,694 17,519
Other (net). . . . . . . . . . . . . . . . . . . . . . . 16,082 24,364
Net Cash Flows From Operating Activities . . . . . 110,896 38,456
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . (40,684) (41,888)
Proceeds from Sale of Property and Other . . . . . . . . - 629
Net Cash Flows Used For Investing Activities . . . (40,684) (41,259)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . 46,506 96,695
Retirement of Cumulative Preferred Stock . . . . . . . . (46) (10)
Retirement of Long-term Debt . . . . . . . . . . . . . . (8,883) (10,679)
Dividends Paid on Common Stock . . . . . . . . . . . . . (37,733) (57,703)
Dividends Paid on Cumulative Preferred Stock . . . . . . (317) (367)
Net Cash Flows From (Used For)
Financing Activities . . . . . . . . . . . . . . (473) 27,936
Net Increase in Cash and Cash Equivalents. . . . . . . . . 69,739 25,133
Cash and Cash Equivalents at Beginning of Period . . . . . 157,138 89,652
Cash and Cash Equivalents at End of Period . . . . . . . . $ 226,877 $ 114,785
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $15,043,000 and $10,562,000
and for income taxes was $20,652,000 and $2,219,000 in 2000 and 1999,
respectively. Noncash acquisitions under capital leases were $2,791,000 and
$5,634,000 in 2000 and 1999, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 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. 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.
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 will make
refunds retroactive to September 7, 1993 to certain customers
affected by the July 30, 1999 FERC order. The refunds will be made
in two payments. The first payment was made February 2000 pursuant
to a FERC order granting AEP's request to make interim refunds.
The remainder is to be paid upon approval by the FERC. In addition,
a new lower rate of $1.55 kw/month was made effective January 1,
2000, for all transmission service customers and a future rate of
$1.42 kw/month was established to take effect upon the consummation
of the AEP and Central and South West Corporation merger.
3. 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 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 would not 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. The
key provisions of the stipulation agreement are:
Recovery of regulatory assets over seven years.
No shopping incentive for the Company's customers.
The Company is to absorb 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
for certain transmission charges imposed by PJM and/or
Midwest ISO on generation originating in the Midwest
ISO or PJM.
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 will be litigated. Hearings to address the gross
receipts tax issue are scheduled for May 31, 2000.
The stipulation agreement is subject to approval by the PUCO.
Hearings on the stipulation are scheduled for June 7, 2000.
Management has concluded that as of March 31, 2000 the
requirements to apply Statement of Financial Accounting Standard
(SFAS) No. 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 the transition plan
should 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 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 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 March
31, 2000 applicable to the Ohio retail jurisdictional generating
business is $422 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 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.
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 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.
4. 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 March 31,
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 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.
<PAGE>
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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. 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, the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court) issued a decision
on March 3, 2000 generally upholding Federal EPA's final rule (the
NOx rule) that requires substantial reductions in nitrogen oxide
(NOx) emissions in 22 eastern states, including the states in which
the Company's generating plants are located. A number of utilities,
including the Company, had filed petitions seeking a review of the
final rule in the 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. On April 20, 2000,
the AEP System companies and other industry petitioners filed for
rehearing of the March 3, 2000 decision including a rehearing by the
entire Appeals Court.
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
FIRST QUARTER 2000 vs. FIRST QUARTER 1999
RESULTS OF OPERATIONS
Net income decreased $15 million or 24% due mainly to an increase
in fuel and purchased power expense.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Operating Revenues . . . . . . . . . . $27.2 5
Fuel . . . . . . . . . . . . . . . . . 26.1 14
Purchased Power. . . . . . . . . . . . 14.0 66
Maintenance. . . . . . . . . . . . . . 2.5 10
Federal Income Taxes . . . . . . . . . (2.5) (7)
The increase in operating revenues resulted from increased sales to
the American Electric Power System Power Pool (AEP Power Pool) and the
Company's share of revenues from increased sales to neighboring utility
systems and power marketers by the AEP Power Pool. As a member of the
AEP Power Pool, the Company shares in the revenues and costs of the AEP
Power Pool's wholesale sales. 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
a major industrial customer's decision not to continue its purchased
power agreement with the Company, additional power was delivered to the
AEP Power Pool, accounting for the increase in sales to the AEP Power
Pool.
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.
The significant increase in purchased power expense resulted from
the shared costs of AEP Power Pool purchases and power purchased from
non-associated companies for sale in the wholesale market.
Additional boiler repairs accounted for the increase in maintenance
expense.
<PAGE>
The decrease in federal income tax expense attributable to
operations was primarily due to a decrease in pre-tax operating income
offset in part by changes in certain book/tax differences accounted for
on a flow-through basis.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
current period were $43 million. Short-term debt increased by $47
million from the beginning of 2000.
OTHER MATTERS
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 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 would not 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. The key provisions of the
stipulation agreement are:
Recovery of regulatory assets over seven years.
No shopping incentive for the Company's customers.
The Company is to absorb 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 for certain
transmission charges imposed by PJM and/or Midwest ISO
on generation originating in the Midwest ISO or PJM.
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
will be litigated. Hearings to address the gross receipts tax
issue are scheduled for May 31, 2000.
The stipulation agreement is subject to approval by the PUCO.
Hearings on the stipulation are scheduled for June 7, 2000.
Management has concluded that as of March 31, 2000 the requirements
to apply Statement of Financial Accounting Standard (SFAS) No. 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 the transition plan should 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 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 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 March 31,
2000 applicable to the Ohio retail jurisdictional generating business is
$422 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 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.
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 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.
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 March 31, 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 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.
Federal EPA also issued Notices of Violation, complaints or
administrative orders to eight unaffiliated utilities.
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. 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, the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court) issued a decision on March
3, 2000 generally upholding Federal EPA's final rule (the NOx rule) that
requires substantial reductions in nitrogen oxide (NOx) emissions in 22
eastern states, including the states in which the Company's generating
plants are located. A number of utilities, including the Company, had
filed petitions seeking a review of the final rule in the 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. On
April 20, 2000, the AEP System companies and other industry petitioners
filed for rehearing of the March 3, 2000 decision including a rehearing
by the entire Appeals Court.
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 which represent the risk of loss that may impact the Company
due to adverse changes in commodity market prices and interest rates
from changes in electricity commodity 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, has not
changed materially since December 31, 1999. The exposure to changes in
interest rates from the Company's short-term and long-term borrowings at
March 31, 2000 is not materially different than at December 31, 1999.
<PAGE>
<PAGE>
PART II. OTHER INFORMATION
Item 5. Other Information.
American Electric Power Company, Inc. ("AEP"), AEP Generating Company
("AEGCo"), Appalachian Power Company ("APCo"), Columbus Southern Power
Company ("CSPCo"), Indiana Michigan Power Company ("I&M"), Kentucky
Power Company ("KEPCo") and Ohio Power Company ("OPCo")
Reference is made to page 36 of the Annual Report on Form 10-K for
the year ended December 31, 1999 ("1999 10-K") for a discussion of the
review by the United States Environmental Protection Agency ("Federal
EPA") of low volume coal combustion wastes. On April 25, 2000, Federal
EPA issued a regulatory determination that low volume wastes from coal
combustion that are mixed with and co-treated or co-disposed with high
volume coal combustion wastes do not warrant regulation under RCRA
Subtitle C as hazardous waste. Instead, Federal EPA indicated that it
would develop national Subtitle D solid waste standards applicable to
disposal of all coal combustion wastes in surface impoundments and
landfills. According to Federal EPA's regulatory determination, Federal
EPA intends to apply these national regulations to both high volume coal
combustion wastes co-managed with low volume wastes and high volume coal
combustion wastes previously addressed in the 1993 regulatory
determination that are separately disposed of. Federal EPA also
determined that additional regulation would be necessary for use of coal
combustion by-products to fill surface or underground mines.
If the RCRA Subtitle D national standards that are to be developed
by Federal EPA for coal combustion wastes would be more stringent than
currently applicable state regulations, AEP System facilities could
incur additional waste management expenses. The significance of these
cost increases, or the timing of Federal EPA's finalization of these
national standards, cannot be determined at this time.
AEP and OPCo
Reference is made to page 43 of the 1999 10-K for a discussion of
litigation with Ormet Corporation involving the ownership of sulfur
dioxide allowances. On March 27, 2000, the U.S. Court of Appeals for
the Fourth Circuit issued a decision affirming the judgment of the
District Court that granted the motion of OPCo and AEP Service
Corporation for summary judgment.
<PAGE>
<PAGE>
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
APCo, CSPCo, I&M, KEPCo and OPCo
Exhibit 12 - Statement re: Computation of Ratios.
AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo
Exhibit 27 - Financial Data Schedule.
(b) Reports on Form 8-K:
AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo
No reports on Form 8-K were filed during the quarter ended
March 31, 2000.
<PAGE>
<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 signature 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 Controller and
Chief Accounting Officer
(Duly Authorized Officer) (Chief Accounting Officer)
AEP GENERATING COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
By: /s/ Armando A. Pena By: /s/ Leonard V. Assante
Armando A. Pena Leonard V. Assante
Vice President, Treasurer, Controller and
and Chief Financial Officer Chief Accounting Officer
(Duly Authorized Officer) (Chief Accounting Officer)
Date: May 11, 2000
II-3
<TABLE>
EXHIBIT 12
COLUMBUS SOUTHERN POWER COMPANY
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Twelve
Months
Year Ended December 31, Ended
1995 1996 1997 1998 1999 3/31/00
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . $66,811 $59,711 $55,156 $47,323 $43,207 $42,496
Interest on Other Long-term Debt. . . . . . . . 8,829 12,125 15,525 23,594 25,878 25,878
Interest on Short-term Debt . . . . . . . . . . 1,328 2,400 5,104 3,493 2,460 2,528
Miscellaneous Interest Charges. . . . . . . . . 4,657 4,374 4,729 4,459 4,659 4,485
Estimated Interest Element in Lease Rentals . . 4,100 4,600 4,100 5,300 4,600 4,600
Total Fixed Charges. . . . . . . . . . . . $85,725 $83,210 $84,614 $84,169 $80,804 $79,987
Earnings:
Net Income (Loss) . . . . . . . . . . . . . . .$110,616 $107,108 $119,379 $133,044 $150,270 $150,323
Plus Federal Income Taxes . . . . . . . . . . . 58,648 60,302 69,760 71,202 82,686 83,587
Plus State Income Taxes . . . . . . . . . . . . 7 11 6 3 89 87
Plus Fixed Charges (as above) . . . . . . . . . 85,725 83,210 84,614 84,169 80,804 79,987
Total Earnings . . . . . . . . . . . . . .$254,996 $250,631 $273,759 $288,418 $313,849 $313,984
Ratio of Earnings to Fixed Charges. . . . . . . . 2.97 3.01 3.23 3.42 3.88 3.92
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000022198
<NAME> COLUMBUS SOUTHERN POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-END> MAR-31-2000
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,942,167
<OTHER-PROPERTY-AND-INVEST> 115,406
<TOTAL-CURRENT-ASSETS> 398,713
<TOTAL-DEFERRED-CHARGES> 55,372
<OTHER-ASSETS> 339,968
<TOTAL-ASSETS> 2,851,626
<COMMON> 41,026
<CAPITAL-SURPLUS-PAID-IN> 572,968
<RETAINED-EARNINGS> 249,872
<TOTAL-COMMON-STOCKHOLDERS-EQ> 863,866
25,000
0
<LONG-TERM-DEBT-NET> 922,690
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 39,475
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 32,519
<LEASES-CURRENT> 7,337
<OTHER-ITEMS-CAPITAL-AND-LIAB> 960,739
<TOT-CAPITALIZATION-AND-LIAB> 2,851,626
<GROSS-OPERATING-REVENUE> 298,306
<INCOME-TAX-EXPENSE> 17,726
<OTHER-OPERATING-EXPENSES> 236,456
<TOTAL-OPERATING-EXPENSES> 254,182
<OPERATING-INCOME-LOSS> 44,124
<OTHER-INCOME-NET> 1,684
<INCOME-BEFORE-INTEREST-EXPEN> 45,808
<TOTAL-INTEREST-EXPENSE> 18,337
<NET-INCOME> 27,471
533
<EARNINGS-AVAILABLE-FOR-COMM> 26,938
<COMMON-STOCK-DIVIDENDS> 23,650
<TOTAL-INTEREST-ON-BONDS> 10,375
<CASH-FLOW-OPERATIONS> 61,124
<EPS-BASIC> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
