THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING.
<PAGE>
<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, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
<CAPTION>
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., Caton, 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, 1999 was 192,726,681.
/TABLE
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended March 31, 1999
<CAPTION>
INDEX
Page
Part I. FINANCIAL INFORMATION
<S> <C>
American Electric Power Company, Inc. and Subsidiary Companies:
Consolidated Statements of Income and
Statements of Retained Earnings. . . . . . . . . . . . . . A-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2- A-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
Notes to Consolidated Financial Statements . . . . . . . . . A-5- A-13
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . A-14-A-28
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-8
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . C-9 - C-16
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-6
Management's Narrative Analysis of Results of Operations . . D-7
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-7
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . E-8 - 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-6
Management's Narrative Analysis of Results of Operations . . F-7 - F-8
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended March 31, 1999
INDEX
Page
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-6
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . G-7 - G-12
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>
<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,
1999 1998
<S> <C> <C>
REVENUES:
Domestic Regulated Electric Utilities. . . . . . . . . . $1,550 $1,509
Worldwide Non-regulated Electric and Gas Operations. . . 144 12
TOTAL REVENUES . . . . . . . . . . . . . . . . . 1,694 1,521
EXPENSES:
Fuel and Purchased Power . . . . . . . . . . . . . . . . 491 485
Maintenance and Other Operation. . . . . . . . . . . . . 427 411
Depreciation and Amortization. . . . . . . . . . . . . . 148 144
Taxes Other Than Income Taxes. . . . . . . . . . . . . . 124 122
Worldwide Non-regulated Electric and Gas Operations. . . 123 15
TOTAL EXPENSES. . . . . . . . . . . . . . . . . . 1,313 1,177
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 381 344
OTHER LOSS, net. . . . . . . . . . . . . . . . . . . . . . (5) (4)
INCOME BEFORE INTEREST, PREFERRED DIVIDENDS
AND INCOME TAXES . . . . . . . . . . . . . . . . . . . . 376 340
INTEREST AND PREFERRED DIVIDENDS . . . . . . . . . . . . . 132 106
INCOME BEFORE INCOME TAXES . . . . . . . . . . . . . . . . 244 234
INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . . 93 83
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 151 $ 151
AVERAGE NUMBER OF SHARES OUTSTANDING . . . . . . . . . . . 192 190
EARNINGS PER SHARE . . . . . . . . . . . . . . . . . . . . $0.79 $0.79
CASH DIVIDENDS PAID PER SHARE. . . . . . . . . . . . . . . $0.60 $0.60
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in millions)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $1,684 $1,605
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 151 151
DEDUCTIONS:
Cash Dividends Declared. . . . . . . . . . . . . . . . . 115 114
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $1,720 $1,642
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,
1999 1998
(in millions)
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . $ 280 $ 173
Accounts Receivable (net). . . . . . . . . . . . . . 854 879
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 262 216
Materials and Supplies . . . . . . . . . . . . . . . 282 280
Accrued Utility Revenues . . . . . . . . . . . . . . 183 214
Energy Marketing and Trading Contracts . . . . . . . 603 372
Prepayments. . . . . . . . . . . . . . . . . . . . . 126 84
TOTAL CURRENT ASSETS . . . . . . . . . . . . 2,590 2,218
PLANT, PROPERTY AND EQUIPMENT:
Electric:
Production . . . . . . . . . . . . . . . . . . . 9,805 9,615
Transmission . . . . . . . . . . . . . . . . . . 3,592 3,692
Distribution . . . . . . . . . . . . . . . . . . 5,395 5,125
Other (including gas and coal mining assets
and nuclear fuel) . . . . . . . . . . . . . . . . . 2,104 2,118
Construction Work in Progress. . . . . . . . . . . . 696 801
Total Plant, Property and Equipment. . . . . 21,592 21,351
Accumulated Depreciation and Amortization. . . . . . 8,777 8,549
NET PLANT, PROPERTY AND EQUIPMENT. . . . . . 12,815 12,802
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 1,908 1,847
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 2,817 2,616
TOTAL. . . . . . . . . . . . . . . . . . . $20,130 $19,483
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,
1999 1998
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts Payable . . . . . . . . . . . . . . . . . . $ 741 $ 618
Short-term Debt. . . . . . . . . . . . . . . . . . . 626 617
Long-term Debt Due Within One Year . . . . . . . . . 490 206
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 387 382
Interest Accrued . . . . . . . . . . . . . . . . . . 117 75
Obligations Under Capital Leases . . . . . . . . . . 83 82
Energy Marketing and Trading Contracts . . . . . . . 585 360
Other. . . . . . . . . . . . . . . . . . . . . . . . 540 461
TOTAL CURRENT LIABILITIES. . . . . . . . . . 3,569 2,801
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . 6,542 6,800
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,616 2,601
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 345 351
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 220 222
DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . 336 263
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,413 1,429
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . 174 174
CONTINGENCIES (Note 8)
COMMON SHAREHOLDERS' EQUITY
Common Stock-Par Value $6.50:
1999 1998
Shares Authorized . . . .600,000,000 600,000,000
Shares Issued . . . . . .201,561,414 200,816,469
(8,999,992 shares were held in treasury) . . . . . $ 1,310 $ 1,305
Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,885 1,853
Retained Earnings. . . . . . . . . . . . . . . . . . 1,720 1,684
TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . 4,915 4,842
TOTAL. . . . . . . . . . . . . . . . . . . $20,130 $19,483
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,
1999 1998
<S> <C> <C>
(in millions)
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 151 $ 151
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 172 153
Deferred Federal Income Taxes. . . . . . . . . . . . . . 30 8
Deferred Investment Tax Credits. . . . . . . . . . . . . (6) (6)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 25 (47)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (48) 7
Accrued Utility Revenues . . . . . . . . . . . . . . . . 31 26
Prepayments. . . . . . . . . . . . . . . . . . . . . . . (42) (11)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 123 (11)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 5 35
Interest Accrued . . . . . . . . . . . . . . . . . . . . 42 34
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 37 37
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (117) (37)
Net Cash Flows From Operating Activities . . . . . . 403 339
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (212) (153)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . (5) (8)
Net Cash Flows Used For Investing Activities . . . . (217) (161)
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . 31 19
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 7 184
Change in Short-term Debt (net). . . . . . . . . . . . . . 9 85
Retirement of Long-term Debt . . . . . . . . . . . . . . . (11) (310)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (115) (114)
Net Cash Flows Used For Financing Activities . . . . (79) (136)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 107 42
Cash and Cash Equivalents at Beginning of Period . . . . . . 173 91
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 280 $ 133
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $84 million and $66 million
and for income taxes was $3 million and $2 million in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $18 million and $47 million in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments should be
read in conjunction with the 1998 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 AND RELATED ACTIVITIES
In April 1999 subsidiaries called $243 million of
outstanding first mortgage bonds for early redemption in May
1999. Consequently the bonds were reclassified as a current
liability on the Consolidated Balance Sheets.
3. NEW ACCOUNTING STANDARD
In the first quarter of 1999 the Company adopted the
Financial Accounting Standards Board's Emerging Issues Task
Force Consensus (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities". The
EITF requires that all energy trading contracts be marked-to-market.
The effect on the Consolidated Statements of Income
from marking open trading contracts to market is deferred as
regulatory assets or liabilities for the portion of open
trading transactions that are included in cost of service on
a settlement basis for ratemaking purposes in jurisdictions
other than the Virginia retail jurisdiction. As a result of
a prohibition against establishing additional regulatory assets
contained in a Virginia settlement agreement, the Virginia
retail jurisdictional share of the mark-to-market adjustment
is included in net income. The adoption of the EITF did not
have a material effect on results of operations, cash flows or
financial condition.
4. 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 <PAGE>
AEP's consolidated
financial statements represent summarized
consolidated financial information of Yorkshire:
Three Months Ended
March 31,
1999 1998
(in millions)
Income Statement Data:
Operating Revenues $652.0 $663.2
Operating Income 113.5 89.7
Net Income 34.6 6.9
5. BUSINESS SEGMENTS
As of December 31, 1998, the Company adopted Statement of
Financial Accounting Standards (SFAS) 131, "Disclosure about
Segments of an Enterprise and Related Information." 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 electric power
wholesale marketing and trading activities that are conducted
as part of regulated operations and subject to regulatory
ratemaking oversight. The World Wide Energy Investments
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 1999
and 1998 is in the following table:
<TABLE>
<CAPTION>
Regulated
Domestic World
Electric Wide Energy Reconciling AEP
Utilities Investments Other Adjustments Consolidated
(in millions)
March 31, 1999
<S> <C> <C> <C> <C> <C>
Revenues from
external customers $ 1,550 $ 165 $ 27 $(48) $ 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
March 31, 1998
Revenues from
external customers 1,509 11 1 - 1,521
Revenues from
transactions with other
operating segments - - - - -
Segment net income (loss) 156 (2) (3) - 151
Total assets 16,340 406 52 - 16,798<PAGE>
6. MERGER
</TABLE>
As discussed in Note 5 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the Company and
Central and South West Corporation (CSW) announced plans to
merge in December 1997. In 1998 the appropriate shareholder
proposals for the consummation of the merger were approved.
Approval of the merger has been requested from the Federal
Energy Regulatory Commission (FERC), the Securities and
Exchange Commission (SEC), the Nuclear Regulatory Commission
(NRC) and all of CSW's state regulatory commissions: Arkansas,
Louisiana, Oklahoma and Texas. In the near future, AEP and CSW
plan to make the final two filings associated with approval of
the merger with the Federal Communications Commission and the
Department of Justice. The NRC and the Arkansas Public Service
Commission approved the merger in 1998. In 1998 the FERC
issued an order which confirmed that a 250 megawatt 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.
In 1998 the FERC issued an order establishing hearing
procedures for the merger and scheduled the hearings to begin
on June 1, 1999. Subsequently, the FERC postponed the hearings
until June 29, 1999. The 1998 FERC order indicated that the
review of the proposed merger will address the issues of
competition, market power and customer protection and
instructed the companies to refile an updated market power
study. On January 13, 1999, AEP and CSW filed an updated
market power study with the FERC.
On May 11, 1999, the Oklahoma Corporation Commission (OCC)
approved the proposed merger between the Company and CSW. The
approval follows an administrative law judge's oral decision
on a partial settlement between certain principal parties to
the Oklahoma merger proceeding which recommended that the OCC
approve the merger. The partial settlement provides for
sharing of net merger savings with Oklahoma customers; no
increase of Oklahoma base rates prior to January 1, 2003;
filing by December 31, 2001 with the FERC an application to
join a regional transmission organization; and implementing
additional quality of service standards for Oklahoma retail
customers. Oklahoma's share (approximately $50 million) of net
merger savings over the first five years after the merger is
consummated will be split between Oklahoma customers and AEP
shareholders, with customers receiving approximately 55% of the
net savings. The partial settlement agreement includes a
recommendation by the OCC staff that the OCC file with FERC
indicating that it does not oppose the merger, but reserves the
right to ensure that there are no adverse impacts on the
Oklahoma transmission system.
<PAGE>
On May 4, 1999, AEP and CSW announced that a stipulated
settlement had been reached in Texas. The agreement builds
upon an earlier settlement agreement signed by AEP, CSW and
certain parties to the Texas merger proceeding. In addition
to the parties that were signatories to the earlier agreement,
the staff of the Public Utility Commission of Texas is a
signatory to the new settlement as well as other key parties
to the merger proceeding. The stipulated settlement would
result in rate reductions totaling $221 million over a six-year
period for Texas customers after the merger is completed. The
$221 million rate reduction represents $84.4 million of net
merger savings and $136.6 million to resolve existing issues
associated with CSW operating subsidiaries' rate and fuel
reconciliation proceedings in Texas. Under the terms of the
settlement agreement, base rates would not be increased before
January 1, 2003 or three years after the merger, whichever is
later. The settlement also calls for the divestiture of a
total of 1,604 megawatts of existing and proposed generating
capacity within Texas. If it is determined that the
divestiture can proceed immediately after the merger closes
without jeopardizing pooling-of-interests accounting treatment
for the merger, sale of the plants would begin no later than
90 days after the merger closes. Absent that determination,
the divestiture would occur approximately two years after the
merger closes to satisfy the requirements to use pooling-of-interests
accounting treatment. Other provisions in the
settlement agreement provide for, among other things,
accelerated stranded cost recovery, quality-of-service
standards, continuation of programs for disadvantaged customers
and transfer of control of bulk transmission facilities to a
regional transmission organization.
The Indiana Utility Regulatory Commission (IURC) approved
a settlement agreement related to the merger on April 26, 1999.
The settlement agreement resulted from an investigation of the
proposed merger between AEP and CSW initiated by the IURC. The
terms of the settlement agreement provide for, among other
things, a sharing of net merger savings through reductions in
customers' bills of approximately $67 million over eight years
after the merger is completed; a one year extension through
January 1, 2005 of a freeze in base rates; additional annual
deposits of $5.5 million to the nuclear decommissioning trust
fund for the Indiana jurisdiction for the years 2001 through
2003; quality-of-service standards; and participation in a
regional transmission organization. As part of the settlement
agreement, the IURC agreed not to oppose the merger in FERC or
SEC proceedings.
AEP and CSW reached a settlement with the local unions of
the International Brotherhood of Electrical Workers (IBEW)
representing employees of AEP and CSW. Under the terms of the
settlement, AEP and CSW will not terminate any current IBEW
employee as a result of the merger and existing labor
agreements will be recognized by the merged company. As part
of the settlement, the IBEW local unions will withdraw their
opposition to completing the merger.
On April 15, 1999, in compliance with a request from the
staff of the Kentucky Public Service Commission (KPSC) AEP
filed an application seeking KPSC approval for the indirect
change in control of Kentucky Power Company that will occur as
a result of the proposed merger. AEP does not believe that the
KPSC has the jurisdictional authority to approve the merger.
Under the governing statute the KPSC must act on the
application within 60 days. Therefore the KPSC proceeding is
not expected to impact the timing of the merger.
In April 1999 AEP and CSW announced that settlements were
reached with certain wholesale customers that address issues
related to the proposed merger. Under the terms of the
settlements the wholesale customers agreed not to oppose the
merger in FERC or SEC proceedings.
The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (UK) regional electricity
companies (RECs), Yorkshire and Seeboard, plc. AEP has a 50%
ownership interest in Yorkshire and CSW has a 100% interest in
Seeboard. Although the merger of CSW into AEP is not subject
to approval by UK regulatory authorities, the common ownership
of two UK RECs could be referred by the UK Secretary of State
for Trade and Industry to the UK Competition Commission
(formerly Monopolies and Mergers Commission) for investigation.
The merger is conditioned upon, among other things, the
approval of the above state and federal regulatory agencies.
The transaction must satisfy many conditions, a number of which
may not be waived by the parties, including the condition that
the merger must be accounted for as a pooling of interests.
The merger agreement will terminate on December 31, 1999 unless
extended by either party as provided in the merger agreement.
Although consummation of the merger is expected to occur in the
fourth quarter of 1999, the Company is unable to predict the
outcome or the timing of the required regulatory proceedings
7. VIRGINIA RESTRUCTURING
In March 1999, a new law was enacted in Virginia to
restructure the electric utility industry. Under the
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. Provisions allowing for an
acceleration or limited delay in this schedule are also
contained in the law. Except as provided in the law, the
generation of electricity will not be subject to rate
regulation after January 1, 2002. Additionally, each Virginia
electric utility is required by 2001 to join or establish a
regional transmission entity which will manage and control
transmission assets.
<PAGE>
The Virginia restructuring law also provides an opportunity
for recovery of just and reasonable net stranded costs.
Stranded costs are those costs above market including
generation related net regulatory assets and impaired tangible
assets that potentially would not be recoverable in a
competitive market. 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. The
capped rates may be terminated after January 1, 2004, and prior
to July 1, 2007, based upon the Virginia SCC determining that
an effective competitive market exists. The wires charge will
be equal to the difference between the generation component of
the capped rates and the market price for generation service
and will be imposed upon departing customers through the
expiration of the rate cap period.
Management has reviewed all the evidence currently
available and concluded that as of March 31, 1999 the
requirements to apply SFAS 71, "Accounting for the Effects of
Certain Types of Regulation," continue to be met for the
Virginia retail jurisdiction. The Company's Virginia rates for
generation will continue to be cost-based regulated until the
establishment of capped rates as provided in the law. When
capped rates are established in Virginia, the application of
SFAS 71 would be discontinued for the Virginia retail
jurisdiction portion of the generating business. At that time
generation-related regulatory assets applicable to the Virginia
jurisdiction will be written off to the extent that they cannot
be recovered under the provisions of the restructuring law and
generating assets for the Virginia retail jurisdiction will be
evaluated for impairment. An impairment loss would be recorded
to the extent that such assets cannot be recovered through the
transition recovery mechanisms provided by the law. The amount
of regulatory assets applicable to the Virginia generating
business at March 31, 1999 is estimated to be $61 million
before related tax effects and any possible offsetting
regulatory liabilities. Regulatory liabilities applicable to
the Virginia generation business at March 31, 1999 are
estimated to be $38 million of which $25 million represents
deferred investment tax credits (ITC). The Company is
evaluating the tax normalization rules regarding the timing of
the reversal of deferred ITC in connection with the Virginia
restructuring law and the ability to record a reversal of
deferred ITC in the same accounting periods when any possible
losses from unrecovered regulatory assets are recorded. Should
it not be possible under the Virginia law to recover all or a
portion of the generation net regulatory assets, it could have
a material adverse impact on results of operations; however,
the amount of any impairment loss for Virginia retail
jurisdictional generating assets and any loss from a possible
inability to recover generation net regulatory assets cannot
be estimated until such time as capped rates are determined
under the law.
8. CONTINGENCIES
Litigation
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the
deductibility of certain interest deductions related to AEP's
corporate owned life insurance (COLI) program for taxable years
1991-1996 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 COLI
interest deductions through March 31, 1999 would reduce
earnings by approximately $316 million (including interest).
The Company has made no provision for any possible earnings
impact from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1997 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
These payments to the IRS are included on the Consolidated
Balance Sheets in other assets pending the resolution of this
matter. The Company will seek refund, either administratively
or through litigation, of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit
against the United States (US) in the US District Court for the
Southern District of Ohio in March 1998. Management believes
that it has a meritorious position and will vigorously pursue
this lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations.
Cook Plant Shutdown
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, both units of
the Cook Plant were shut down in September 1997 due to
questions regarding the operability of certain safety systems
which arose during a NRC architect engineer design inspection.
The NRC issued a Confirmatory Action Letter in September 1997
requiring the Company to address certain issues identified in
the letter. During 1998 the NRC notified the Company that it
had convened a Restart Panel for Cook Plant and provided a list
of required restart activities. In order to identify and
resolve all issues, including those in the letter, necessary
to restart the Cook units, the Company is working with the NRC
and will be meeting with the Panel on a regular basis, until
the units are returned to service.
In January 1999 the Company announced that additional
engineering reviews will be conducted at the Cook Plant
delaying the restart of the units. Previously, the units were
scheduled to return to service at the end of the first and
second quarters of 1999. The decision to delay restart
resulted from internal assessments that indicated a need to
conduct expanded system readiness reviews. A new restart
schedule will be developed based on the results of the expanded
reviews and should be available in June 1999. When maintenance
and other activities required for restart are complete, the
Company will seek concurrence from the NRC to return the Cook
Plant to service. Until these additional reviews are
completed, management is unable to determine when the units
will be returned to service.
In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant
as an "agency-focus plant." The NRC senior managers concluded
that continued agency-level oversight was appropriate; however,
the NRC required no additional action to redirect Cook Plant
activities. The letter states that the NRC staff will continue
to monitor Cook Plant performance through the Restart Panel
process and evaluate whether additional action may be
necessary.
The cost of electricity supplied to retail customers
remained higher due to the outage of the two Cook Plant nuclear
units since higher cost coal-fired generation and coal based
purchased power continue to be substituted for low cost nuclear
generation. The Indiana and Michigan retail jurisdictional
fuel cost recovery mechanisms permit the recovery, subject to
regulatory commission review and approval, of changes in fuel
costs including the fuel component of purchased power in the
Indiana jurisdiction and changes in replacement power in the
Michigan jurisdiction. Under these fuel cost recovery
mechanisms, retail rates contain a fuel cost adjustment factor
that reflects estimated fuel costs for the period during which
the factor will be in effect subject to reconciliation to
actual fuel costs in a future proceeding. When actual fuel
costs exceed the estimated costs reflected in the billing
factor a regulatory asset is recorded and revenues are accrued.
Therefore, a regulatory asset has been recorded and revenues
accrued in anticipation of the future reconciliation and
billing under the fuel cost recovery mechanisms of the higher
fuel costs to replace Cook energy during the extended outage.
At March 31, 1999, the regulatory asset was $118 million.
On March 30, 1999, the IURC approved a settlement agreement
that resolves all matters related to the reasonableness of fuel
costs and all outage issues during the extended outage of the
Cook Plant. The settlement agreement provides for, among other
things, a credit of $55 million, including interest, to Indiana
retail customers; authorization to defer any unrecovered fuel
revenues accrued between September 9, 1997 and December 31,
1999, including the $52.3 million revenue portion of the $55
million credit; authorization to defer up to $150 million of
incremental operation and maintenance costs for the Cook Plant
above the amount included in base rates; amortization of the
fuel recoveries and non-fuel operation and maintenance cost
deferrals over a five-year period ending December 31, 2003; a
freeze in base rates through December 31, 2003; and a fixed
fuel recovery charge through March 1, 2004. The $55 million
credit will be refunded through customers' bills during the
months of July, August and September 1999.
The incremental costs incurred in first quarter 1999 for
restart of the Cook units were $45 million of which $30 million
were deferred pursuant to the settlement agreement discussed
above.
Unless the costs of the extended outage and restart efforts
are recovered from customers, there would be a material adverse
effect on results of operations, cash flows, and possibly
financial condition.
Other
The Company continues to be involved in certain other
matters discussed in the 1998 Annual Report.
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
FIRST QUARTER 1999 vs. FIRST QUARTER 1998
RESULTS OF OPERATIONS
Net income was unchanged in spite of the extended Cook Nuclear
Plant outage and the expiration of a major wholesale power
contract.
Income statement line items which changed significantly were:
Increase
(in millions) %
Revenues:
Domestic Regulated Electric Utilities. . $ 41 3
Worldwide Non-regulated Operations . . . 132 N.M.
Maintenance and Other Operation Expense. . . 16 4
Worldwide Non-regulated Operations Expense . 108 N.M.
Interest and Preferred Dividends . . . . . . 26 25
Income Taxes . . . . . . . . . . . . . . . . 10 12
N.M. = Not Meaningful.
Revenues from domestic regulated electric utility operations
increased primarily due to a 4% increase in retail sales. Sales to
weather-sensitive residential and commercial customers increased
10% and 3%, respectively, reflecting colder winter weather in 1999.
Domestic regulated electric utility wholesale revenues declined
reflecting the loss of a contract which supplied power to several
municipal customers.
The increase in revenues from worldwide non-regulated
operations was predominantly due to the acquisitions of CitiPower,
an Australian electric distribution utility, and midstream
intrastate natural gas operations in December 1998. These new
revenues were offset by an increase in worldwide non-regulated
operations expenses.
Maintenance and other operation expense increased due to an
increase in nuclear engineering costs which were not subject to
deferral. The increase in such costs were due to the extended
outage of the Cook Nuclear Plant which was shutdown in September
1997.
<PAGE>
Worldwide non-regulated expenses increased as a result of the
expansion of business development activities and expenses from the
December 1998 acquisitions of CitiPower and the midstream gas
operations.
Additional borrowings to fund the Company's non-regulated
operations, primarily the acquisitions of CitiPower and midstream
natural gas assets in December 1998, were the primary reason for
the significant increase in interest and preferred dividends.
The increase in income taxes is primarily due to an increase
in United States (US) federal, state and local income taxes. The
increase is due to a rise in pre-tax income primarily from domestic
regulated electric utility operations.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the current period were $231 million.
In April 1999 subsidiaries called $243 million of outstanding
first mortgage bonds for early redemption in May 1999.
Consequently, the bonds were reclassified as a current liability on
the Consolidated Balance Sheets.
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
As discussed in Management's Discussion and Analysis of Results
of Operations and Financial Condition (MDA) in the 1998 Annual
Report, as a result of the Department of Energy's (DOE) failure to
make sufficient progress toward a permanent repository or otherwise
assume responsibility for SNF, the Company along with a number of
unaffiliated utilities and states filed suit in the US Court of
Appeals for the District of Columbia Circuit requesting, among
other things, that the court order DOE to meet its obligations
under the law. The court ordered the parties to proceed with
contractual remedies but declined to order DOE to begin accepting
SNF for disposal. DOE estimates its planned site for the nuclear
waste will not be ready until 2010. In June 1998, the Company
filed a complaint in the US Court of Federal Claims seeking damages
in excess of $150 million due to the DOE's partial material breach
of its unconditional contractual deadline to begin disposing of SNF
generated by the Cook Plant. Similar lawsuits have been filed by
other utilities. On April 6, 1999, the court granted DOE's motion
to dismiss a similar lawsuit filed by another utility. Indiana
Michigan Power Company's case has been suspended pending final
resolution of the other utility's case.
Cook Nuclear Plant Shutdown
As discussed in MDA in the 1998 Annual Report, management shut
down both units of the Cook Plant in September 1997 due to
questions, which arose during a Nuclear Regulatory Commission (NRC)
architect engineer design inspection, regarding the operability of
certain safety systems. The NRC issued a Confirmatory Action
Letter in September 1997 requiring the Company to address certain
issues identified in the letter. During 1998 the NRC notified the
Company that it had convened a Restart Panel for Cook Plant and
provided a list of required restart activities. In order to
identify and resolve all issues, including those in the letter,
necessary to restart the Cook units, the Company is working with
the NRC and will be meeting with the Panel on a regular basis,
until the units are returned to service.
In January 1999 the Company announced that additional
engineering reviews will be conducted at the Cook Plant delaying
the restart of the units. Previously, the units were scheduled to
return to service at the end of the first and second quarters of
1999. The decision to delay restart resulted from internal
assessments that indicated a need to conduct expanded system
readiness reviews. A new restart schedule will be developed based
on the results of the expanded reviews and should be available in
June 1999. When maintenance and other activities required for
restart are complete, the Company will seek concurrence from the
NRC to return the Cook Plant to service. Until these additional
reviews are completed, management is unable to determine when the
units will be returned to service.
In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant as an
"agency-focus plant." The NRC senior managers concluded that
continued agency-level oversight was appropriate; however, the NRC
required no additional action to redirect Cook Plant activities.
The letter states that the NRC staff will continue to monitor Cook
Plant performance through the Restart Panel process and evaluate
whether additional action may be necessary.
The cost of electricity supplied to retail customers remained
higher due to the outage of the two Cook Plant nuclear units since
higher cost coal-fired generation and coal based purchased power
continue to be substituted for low cost nuclear generation. The
Indiana and Michigan retail jurisdictional fuel cost recovery
mechanisms permit the recovery, subject to regulatory commission
review and approval, of changes in fuel costs including the fuel
component of purchased power in the Indiana jurisdiction and
changes in replacement power in the Michigan jurisdiction. Under
these fuel cost recovery mechanisms, retail rates contain a fuel
cost adjustment factor that reflects estimated fuel costs for the
period during which the factor will be in effect subject to
reconciliation to actual fuel costs in a future proceeding. When
actual fuel costs exceed the estimated costs reflected in the
billing factor a regulatory asset is recorded and revenues are
accrued. Therefore, a regulatory asset has been recorded and
revenues accrued in anticipation of the future reconciliation and
billing under the fuel cost recovery mechanisms of the higher fuel
costs to replace Cook energy during the extended outage. At March
31, 1999, this regulatory asset was $118 million.
On March 30, 1999 the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolves all matters
related to the reasonableness of fuel costs and all outage issues
during the extended outage of the Cook Plant. The settlement
agreement provides for, among other things, a credit of $55
million, including interest, to Indiana retail customers;
authorization to defer any unrecovered fuel revenues accrued
between September 9, 1997 and December 31, 1999, including the
$52.3 million revenue portion of the $55 million credit;
authorization to defer up to $150 million of incremental operation
and maintenance costs for the Cook Plant above the amount included
in base rates; amortization of the fuel recoveries and non-fuel
operation and maintenance cost deferrals over a five-year period
ending December 31, 2003; a freeze in base rates through December
31, 2003; and a fixed fuel recovery charge through March 1, 2004.
The $55 million credit will be refunded through customers' bills
during the months of July, August and September 1999.
The incremental costs incurred in first quarter of 1999 for
restart of the Cook units were $45 million of which $30 million
were deferred pursuant to the settlement agreement discussed above.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows, and possibly financial
condition.
Merger
As discussed in MDA in the 1998 Annual Report, the Company and
Central and South West Corporation (CSW) announced plans to merge
in December 1997. In 1998 the appropriate shareholder proposals
for the consummation of the merger were approved. Approval of the
merger has been requested from the Federal Energy Regulatory
Commission (FERC), the Securities and Exchange Commission (SEC),
the NRC and all of CSW's state regulatory commissions: Arkansas,
Louisiana, Oklahoma and Texas. In the near future, AEP and CSW
plan to make the final two filings associated with approval of the
merger with the Federal Communications Commission and the
Department of Justice. The NRC and the Arkansas Public Service
Commission approved the merger in 1998. In 1998 the FERC issued an
order which confirmed that a 250 megawatt 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.
In 1998 the FERC issued an order establishing hearing
procedures for the merger and scheduled the hearings to begin on
June 1, 1999. Subsequently, the FERC postponed the hearings until
June 29, 1999. The 1998 FERC order indicated that the review of
the proposed merger will address the issues of competition, market
power and customer protection and instructed the companies to
refile an updated market power study. On January 13, 1999, AEP and
CSW filed an updated market power study with the FERC.
On May 11, 1999, the Oklahoma Corporation Commission (OCC)
approved the proposed merger between the Company and CSW. The
approval follows an administrative law judge's oral decision on a
partial settlement between certain principal parties to the
Oklahoma merger proceeding which recommended that the OCC approve
the merger. The partial settlement provides for sharing of net
merger savings with Oklahoma customers; no increase of Oklahoma
base rates prior to January 1, 2003; filing by December 31, 2001
with the FERC an application to join a regional transmission
organization; and implementing additional quality of service
standards for Oklahoma retail customers. Oklahoma's share
(approximately $50 million) of net merger savings over the first
five years after the merger is consummated will be split between
Oklahoma customers and AEP shareholders, with customers receiving
approximately 55% of the net savings. The partial settlement
agreement includes a recommendation by the OCC staff that the OCC
file with FERC indicating that it does not oppose the merger, but
reserves the right to ensure that there are no adverse impacts on
the Oklahoma transmission system.
On May 4, 1999, AEP and CSW announced that a stipulated
settlement had been reached in Texas. The agreement builds upon an
earlier settlement agreement signed by AEP, CSW and certain parties
to the Texas merger proceeding. In addition to the parties that
were signatories to the earlier agreement, the staff of the Public
Utility Commission of Texas is a signatory to the new settlement as
well as other key parties to the merger proceeding. The stipulated
settlement would result in rate reductions totaling $221 million
over a six-year period for Texas customers after the merger is
completed. The $221 million rate reduction represents $84.4
million of net merger savings and $136.6 million to resolve
existing issues associated with CSW operating subsidiaries' rate
and fuel reconciliation proceedings in Texas. Under the terms of
the settlement agreement, base rates would not be increased before
January 1, 2003 or three years after the merger, whichever is
later. The settlement also calls for the divestiture of a total of
1,604 megawatts of existing and proposed generating capacity within
Texas. If it is determined that the divestiture can proceed
immediately after the merger closes without jeopardizing pooling-of-interests
accounting treatment for the merger, sale of the
plants would begin no later than 90 days after the merger closes.
Absent that determination, the divestiture would occur
approximately two years after the merger closes to satisfy the
requirements to use pooling-of-interests accounting treatment.
Other provisions in the settlement agreement provide for, among
other things, accelerated stranded cost recovery, quality-of-service standards,
continuation of programs for disadvantaged
customers and transfer of control of bulk transmission facilities
to a regional transmission organization.
The IURC approved a settlement agreement related to the merger
on April 26, 1999. The settlement agreement resulted from an
investigation of the proposed merger between AEP and CSW initiated
by the IURC. The terms of the settlement agreement provide for,
among other things, a sharing of net merger savings through
reductions in customers' bills of approximately $67 million over
eight years after the merger is completed; a one year extension
through January 1, 2005 of a freeze in base rates; additional
annual deposits of $5.5 million to the nuclear decommissioning
trust fund for the Indiana jurisdiction for the years 2001 through
2003; quality-of-service standards; and participation in a regional
transmission organization. As part of the settlement agreement,
the IURC agreed not to oppose the merger in FERC or SEC
proceedings.
AEP and CSW reached a settlement with the local unions of the
International Brotherhood of Electrical Workers (IBEW) representing
employees of AEP and CSW. Under the terms of the settlement, AEP
and CSW will not terminate any current IBEW employee as a result of
the merger and existing labor agreements will be recognized by the
merged company. As part of the settlement, the IBEW local unions
will withdraw their opposition to completing the merger.
On April 15, 1999, in compliance with a request from the staff
of the Kentucky Public Service Commission (KPSC) AEP filed an
application seeking KPSC approval for the indirect change in
control of Kentucky Power Company that will occur as a result of
the proposed merger. AEP does not believe that the KPSC has the
jurisdictional authority to approve the merger. Under the
governing statute the KPSC must act on the application within 60
days. Therefore the KPSC proceeding is not expected to impact the
timing of the merger.
In April 1999 AEP and CSW announced that settlements were
reached with certain wholesale customers that address issued
related to the proposed merger. Under the terms of the settlements
the wholesale customers agreed not to oppose the merger in FERC or
SEC proceedings.
The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (UK) regional electricity companies
(RECs), Yorkshire Power Group Limited (Yorkshire) and Seeboard,
plc. AEP has a 50% ownership interest in Yorkshire and CSW has a
100% interest in Seeboard. Although the merger of CSW into AEP is
not subject to approval by UK regulatory authorities, the common
ownership of two UK RECs could be referred by the UK Secretary of
State for Trade and Industry to the UK Competition Commission
(formerly Monopolies and Mergers Commission) for investigation.
The merger is conditioned upon, among other things, the
approval of the above state and federal regulatory agencies. The
transaction must satisfy many conditions, a number of which may not
be waived by the parties, including the condition that the merger
must be accounted for as a pooling of interests. The merger
agreement will terminate on December 31, 1999 unless extended by
either party as provided in the merger agreement. Although
consummation of the merger is expected to occur in the fourth
quarter of 1999, the Company is unable to predict the outcome or
the timing of the required regulatory proceedings
Virginia Restructuring
In March 1999, a new law was enacted in Virginia to restructure
the electric utility industry. Under the 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.
Provisions allowing for an acceleration or limited delay in this
schedule are also contained in the law. Except as provided in the
law, the generation of electricity will not be subject to rate
regulation after January 1, 2002. Additionally, each Virginia
electric utility is required by 2001 to join or establish a
regional transmission entity which will manage and control
transmission assets.
The Virginia restructuring law also provides an opportunity for
recovery of just and reasonable net stranded costs. Stranded costs
are those costs above market including generation related net
regulatory assets and impaired tangible assets that potentially
would not be recoverable in a competitive market. 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. The capped
rates may be terminated after January 1, 2004, and prior to July 1,
2007, based upon the Virginia SCC determining that an effective
competitive market exists. The wires charge will be equal to the
difference between the generation component of the capped rates and
the market price for generation service and will be imposed upon
departing customers through the expiration of the rate cap period.
Management has reviewed all the evidence currently available
and concluded that as of March 31, 1999 the requirements to apply
Statement of Financial Accounting Standards (SFAS) 71, "Accounting
for the Effects of Certain Types of Regulation," continue to be met
for the Virginia retail jurisdiction. The Company's Virginia rates
for generation will continue to be cost-based regulated until the
establishment of capped rates as provided in the law. When capped
rates are established in Virginia, the application of SFAS 71 would
be discontinued for the Virginia retail jurisdiction portion of the
generating business. At that time generation-related regulatory
assets applicable to the Virginia jurisdiction will be written off
to the extent that they cannot be recovered under the provisions of
the restructuring law and generating assets for the Virginia retail
jurisdiction will be evaluated for impairment. An impairment loss
would be recorded to the extent that such assets cannot be
recovered through the transition recovery mechanisms provided by
the law. The amount of regulatory assets applicable to the
Virginia generating business at March 31, 1999 is estimated to be
$61 million before related tax effects and any possible offsetting
regulatory liabilities. Regulatory liabilities applicable to the
Virginia generation business at March 31, 1999 are estimated to be
$38 million of which $25 million represents deferred investment tax
credits (ITC). The Company is evaluating the tax normalization
rules regarding the timing of the reversal of deferred ITC in
connection with the Virginia restructuring law and the ability to
record a reversal of deferred ITC in the same accounting periods
when any possible losses from unrecovered regulatory assets are
recorded. Should it not be possible under the Virginia law to
recover all or a portion of the generation net regulatory assets,
it could have a material adverse impact on results of operations;
however, the amount of any impairment loss for Virginia retail
jurisdictional generating assets and any loss from a possible
inability to recover generation net regulatory assets cannot be
estimated until such time as capped rates are determined under the
law.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices, foreign
currency exchange rates and interest rates. 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, 1998. Market risk represents the risk of loss
that may impact the Company due to adverse changes in commodity
market prices, foreign currency exchange rates and interest rates.
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, 1998.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at March 31, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date. In
addition, certain systems may fail to detect that the year 2000 is
a leap year. Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Y2K-related failures and repair such failures if they occur. This
includes both information technology (IT) systems, which are
mainframe and client server applications, and embedded logic
(non-IT) systems, such as process controls for energy production
and delivery. Externally, the problem is being addressed with
entities that interact with the Company, including suppliers,
customers, creditors, financial service organizations and other
parties essential to the Company's operations. In the course of
the external evaluation, the Company has sought written assurances
from third parties regarding their state of Y2K readiness.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
AEP, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reports summary information to the DOE regarding
the Y2K readiness of electric utilities. AEP participated in an
industry-wide NERC-sponsored drill on April 9, 1999 simulating the
partial loss of voice and data communications. There were no major
problems encountered with relaying information with the use of
backup telecommunications systems. AEP and other utilities plan to
participate in a more comprehensive second NERC-sponsored drill on
September 8-9, 1999, to prepare for operations under Y2K
conditions.
The NERC report, dated April 30, 1999 and entitled: Preparing
the Electric Power Systems of North America for Transition to the
Year 2000 - A Status Report and Work Plan, First Quarter 1999
states that: "With more than 75% of mission critical components
tested through March 31, 1999, findings in the field continue to
indicate that the transition through critical Y2K dates is expected
to have minimal impact on electric system operations in North
America." The report also indicates that, "the risk of electrical
outages by Y2K appears to be no higher than the risks we already
experience" from incidents such as severe wind, ice, floods,
equipment failures and power shortages during an extremely hot or
cold period.
Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems. Under this effort,
participating utilities, including AEP, are working together to
assess specific vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk. The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
<PAGE>
The following chart shows our progress toward becoming ready
for Y2K as of March 31, 1999:
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
Launch: Initiation of 2/24/1998 100% 5/31/1998 100%
the Y2K activities
within the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999 100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65%
replacing or retiring 94%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 56%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
*The Company is upgrading its 800 MHZ trunked radio system, a mission critical
non-IT system, for Y2K readiness and it is anticipated that the upgrade should
be complete by September 30, 1999.
The Company continues to make steady progress toward the June
30, 1999 target date and anticipates completing the
remediation/testing work for mission critical and high-priority
systems by the June 30, 1999 target date except as noted in the
table.
<PAGE>
The above chart does not reflect progress of midstream gas
operations and CitiPower acquired in December 1998. The mission
critical systems for the midstream gas operations are expected to
be ready by June 30, 1999 and the mission critical systems for
CitiPower are expected to be ready by October 1, 1999.
Costs to Address the Company's Y2K Issues - Through March 31,
1999, the Company has spent $27 million on the Y2K project and
estimates spending an additional $29 million to $41 million to
achieve Y2K readiness. Most Y2K costs are for software, IT
consultants and salaries and are expensed; however, in certain
cases the Company has acquired hardware that was capitalized. The
Company intends to fund these expenditures through internal
sources. Although significant, the cost of becoming Y2K compliant
is not expected to have a material impact on the Company's results
of operations, cash flows or financial condition.
Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
Automated power generation, transmission and distribution
systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for
commercial and industrial customers
Work management and billing systems.
The potential problems related to erroneous processing by, or
failure of, these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restorable in a reasonable
period of time.
CitiPower operates under a legal and regulatory regime which
may expose it to customer claims, that may differ from claims under
the US legal and regulatory regime, for service interruptions
and/or power quality problems resulting from Y2K problems.
In addition, although the Company is monitoring its
relationships with third parties, such as suppliers, customers and
other electric utilities, these third parties nonetheless represent
a risk that cannot be assessed with precision or controlled with
certainty.
Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others not affiliated with AEP, fail for critical
applications, Y2K-related issues may materially adversely affect
AEP.
Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a draft Y2K contingency plan
and submitted it to the East Central Area Reliability Council
(ECAR) in December 1998 as part of NERC's review of regional and
individual electric utility contingency plans in 1999. NERC's
target date is June 1999 for the completion of this contingency
plan. In addition, the Company intends to establish contingency
plans for its business units to address alternatives if Y2K related
failures occur. These contingency plans will be developed by the
end of 1999.
AEP's Y2K contingency plans build upon the disaster recovery,
system restoration, and contingency planning that we have had in
place and include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, with key employees
on duty at those locations during the Y2K transition.
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $52,827 $54,052
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 20,258 22,501
Rent - Rockport Plant Unit 2 . . . . . . . . . . . . . . 17,071 17,071
Other Operation. . . . . . . . . . . . . . . . . . . . . 3,370 2,649
Maintenance. . . . . . . . . . . . . . . . . . . . . . . 2,262 2,178
Depreciation . . . . . . . . . . . . . . . . . . . . . . 5,440 5,412
Taxes Other Than Federal Income Taxes. . . . . . . . . . 1,239 943
Federal Income Taxes . . . . . . . . . . . . . . . . . . 827 962
TOTAL OPERATING EXPENSES . . . . . . . . . . . . 50,467 51,716
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 2,360 2,336
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . 856 829
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 3,216 3,165
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 602 785
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . $ 2,614 $ 2,380
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $2,770 $2,528
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 2,614 2,380
CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . . . . 1,073 3,176
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $4,311 $1,732
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,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production. . . . . . . . . . . . . . . . . . . . . . $630,240 $630,260
General . . . . . . . . . . . . . . . . . . . . . . . 2,068 2,009
Construction Work in Progress . . . . . . . . . . . . 4,513 4,191
Total Electric Utility Plant. . . . . . . . . 636,821 636,460
Accumulated Depreciation. . . . . . . . . . . . . . . 283,005 277,855
NET ELECTRIC UTILITY PLANT. . . . . . . . . . 353,816 358,605
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . 2,010 232
Accounts Receivable - Affiliated Companies. . . . . . 20,194 22,894
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . 19,159 11,308
Materials and Supplies. . . . . . . . . . . . . . . . 3,912 3,900
Prepayments . . . . . . . . . . . . . . . . . . . . . 70 267
TOTAL CURRENT ASSETS. . . . . . . . . . . . . 45,345 38,601
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . 5,924 5,984
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . 3,248 702
TOTAL . . . . . . . . . . . . . . . . . . . $408,333 $403,892
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE> AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
1999 1998
(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 . . . . . . . . . . . . . . . . . . . 33,235 35,235
Retained Earnings . . . . . . . . . . . . . . . . . . 4,311 2,770
Total Common Shareholder's Equity . . . . . . 38,546 39,005
Long-term Debt. . . . . . . . . . . . . . . . . . . . 44,794 44,792
TOTAL CAPITALIZATION. . . . . . . . . . . . . 83,340 83,797
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . 824 896
CURRENT LIABILITIES:
Short-term Debt - Notes Payable . . . . . . . . . . . 5,575 24,450
Accounts Payable:
General . . . . . . . . . . . . . . . . . . . . . . 8,911 6,419
Affiliated Companies. . . . . . . . . . . . . . . . 8,224 6,177
Taxes Accrued . . . . . . . . . . . . . . . . . . . . 8,854 3,227
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . 23,427 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . 4,808 6,023
TOTAL CURRENT LIABILITIES . . . . . . . . . . 59,799 51,259
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . 131,937 133,330
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . 65,724 66,562
Amounts Due to Customers for Income Tax . . . . . . . 28,066 28,644
TOTAL REGULATORY LIABILITIES. . . . . . . . . 93,790 95,206
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . 38,643 39,404
TOTAL . . . . . . . . . . . . . . . . . . . $408,333 $403,892
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE> AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
<CAPTION>
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . $ 2,614 $ 2,380
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . 5,440 5,412
Deferred Federal Income Taxes. . . . . . . . . . . . (1,339) 1,446
Deferred Investment Tax Credits. . . . . . . . . . . (838) (841)
Amortization of Deferred Gain on Sale
and Leaseback - Rockport Plant Unit 2. . . . . . . (1,393) (1,393)
Deferred Property Taxes. . . . . . . . . . . . . . . (2,410) (2,385)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . 2,700 2,979
Fuel, Materials and Supplies . . . . . . . . . . . . (7,863) (3,821)
Accounts Payable . . . . . . . . . . . . . . . . . . 4,539 4,119
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 5,627 2,716
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 18,464 18,464
Other (net). . . . . . . . . . . . . . . . . . . . . . (1,045) (3,019)
Net Cash Flows From Operating Activities . . . . 24,496 26,057
INVESTING ACTIVITIES - Net Cash Flows Used
for Construction . . . . . . . . . . . . . . . . . . . (770) (1,416)
FINANCING ACTIVITIES:
Return of Capital to Parent Company. . . . . . . . . . (2,000) -
Retirement of Long-term Debt . . . . . . . . . . . . . - (25,000)
Change in Short-term Debt (net). . . . . . . . . . . . (18,875) 3,425
Dividends Paid . . . . . . . . . . . . . . . . . . . . (1,073) (3,176)
Net Cash Flows Used For Financing Activities . . (21,948) (24,751)
Net Increase (Decrease) in Cash and Cash Equivalents . . 1,778 (110)
Cash and Cash Equivalents at Beginning of Period . . . . 232 237
Cash and Cash Equivalents at End of Period . . . . . . . $ 2,010 $ 127
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $470,000 and $982,000 in
1999 and 1998, respectively, and for income taxes was $15,000 in 1998.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 1998 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.
<PAGE>
<PAGE> AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 1999 vs. FIRST QUARTER 1998
Operating revenues are derived from the sale of Rockport Plant
energy and capacity to two affiliated companies and one unaffiliated
utility pursuant to Federal Energy Regulatory Commission (FERC) approved
long-term unit power agreements. The unit power agreements provide for
recovery of the cost of producing the power including a FERC approved
rate of return on common equity and a return on other capital net of
temporary cash investments. A monthly power bill for energy supplied
is issued based on estimated expenses for the month and adjusted to
actual amounts in the following month.
Net income increased $0.2 million or 10% primarily as a result of
the use of estimates for power production operation and maintenance
expenses to bill customers which were in excess of the actual expenses
incurred and included in the Statements of Income. The estimates will
be adjusted to actual amounts in the customers' April bills.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Operating Revenues $(1.2) (2)
Fuel Expense (2.2) (10)
Other Operation Expense 0.7 27
Taxes Other Than Federal Income Taxes 0.3 31
Federal Income Taxes (0.1) (14)
Interest Charges (0.2) (23)
The decrease in operating revenues reflects recovery of lower
operating expenses primarily reduced fuel expense.
Fuel expense decreased due to a reduction in generation in the first
quarter of 1999 as a result of reduced availability of the Rockport
Plant. In 1999 outages of the Rockport Plant units were of longer
duration than in 1998 causing the reduction in Rockport Plant
availability.
<PAGE>
The increase in other operation expense is primarily due to the
Company's allocated share of Rockport Plant's employee severance expense
incurred in 1999 in excess of amounts accrued at December 31, 1998 and
a payment to the City of Rockport in settlement of an annexation issue.
Taxes other than federal income taxes increased due to an increase
in state income taxes which resulted from an increase in pre-tax
operating income in 1999 due to the cessation of tax depreciation for
Rockport Plant Unit 1.
The decline in federal income taxes attributable to operations was
due to the reversal of deferred taxes in excess of the statutory tax
rate partially offset by an increase in pre-tax operating income.
Interest charges decreased due to a reduction in outstanding long-term debt
balances reflecting the redemption of $25 million in March
1998 of pollution control revenue bonds.
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $427,702 $415,366
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 123,573 108,209
Purchased Power. . . . . . . . . . . . . . . . . . . . . 50,591 69,262
Other Operation. . . . . . . . . . . . . . . . . . . . . 62,749 54,867
Maintenance. . . . . . . . . . . . . . . . . . . . . . . 28,511 35,352
Depreciation and Amortization. . . . . . . . . . . . . . 36,551 35,405
Taxes Other Than Federal Income Taxes. . . . . . . . . . 29,975 30,244
Federal Income Taxes . . . . . . . . . . . . . . . . . . 24,145 17,778
TOTAL OPERATING EXPENSES . . . . . . . . . . . . 356,095 351,117
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 71,607 64,249
NONOPERATING LOSS. . . . . . . . . . . . . . . . . . . . . (1,088) (387)
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 70,519 63,862
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 31,258 30,663
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 39,261 33,199
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 675 469
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 38,586 $ 32,730
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $179,461 $207,544
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 39,261 33,199
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . . 30,348 29,729
Cumulative Preferred Stock . . . . . . . . . . . . . . 567 362
Capital Stock Expense. . . . . . . . . . . . . . . . . . 108 107
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $187,699 $210,545
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,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,996,848 $1,979,180
Transmission . . . . . . . . . . . . . . . . . . . . 1,122,987 1,118,726
Distribution . . . . . . . . . . . . . . . . . . . . 1,650,705 1,641,523
General. . . . . . . . . . . . . . . . . . . . . . . 229,512 228,464
Construction Work in Progress. . . . . . . . . . . . 121,376 119,466
Total Electric Utility Plant . . . . . . . . 5,121,428 5,087,359
Accumulated Depreciation and Amortization. . . . . . 2,018,326 1,984,856
NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,103,102 3,102,503
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 120,748 111,020
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 36,098 7,755
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 88,504 122,746
Affiliated Companies . . . . . . . . . . . . . . . 23,084 35,802
Miscellaneous. . . . . . . . . . . . . . . . . . . 9,335 8,572
Allowance for Uncollectible Accounts . . . . . . . . (2,487) (2,234)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 54,937 49,826
Materials and Supplies . . . . . . . . . . . . . . . 61,128 60,440
Accrued Utility Revenues . . . . . . . . . . . . . . 35,008 45,985
Energy Marketing and Trading Contracts . . . . . . . 138,195 22,436
Prepayments. . . . . . . . . . . . . . . . . . . . . 14,499 8,151
TOTAL CURRENT ASSETS . . . . . . . . . . . . 458,301 359,479
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 424,314 433,516
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 43,529 40,520
TOTAL. . . . . . . . . . . . . . . . . . . $4,149,994 $4,047,038
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
1999 1998
(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. . . . . . . . . . . . . . . . . . 663,743 663,633
Retained Earnings. . . . . . . . . . . . . . . . . 187,699 179,461
Total Common Shareholder's Equity. . . . . 1,111,900 1,103,552
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . 19,353 19,359
Subject to Mandatory Redemption. . . . . . . . . 22,310 22,310
Long-term Debt . . . . . . . . . . . . . . . . . . 1,395,477 1,472,451
TOTAL CAPITALIZATION . . . . . . . . . . . 2,549,040 2,617,672
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . 123,043 120,281
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . 157,239 80,004
Short-term Debt. . . . . . . . . . . . . . . . . . 57,275 76,400
Accounts Payable . . . . . . . . . . . . . . . . . 97,080 110,882
Taxes Accrued. . . . . . . . . . . . . . . . . . . 50,421 35,719
Customer Deposits. . . . . . . . . . . . . . . . . 13,537 14,123
Interest Accrued . . . . . . . . . . . . . . . . . 29,288 19,990
Revenue Refunds Accrued. . . . . . . . . . . . . . 44,818 95,267
Energy Marketing and Trading Contracts . . . . . . 138,960 24,076
Other. . . . . . . . . . . . . . . . . . . . . . . 84,242 78,808
TOTAL CURRENT LIABILITIES. . . . . . . . . 672,860 535,269
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . 653,896 643,711
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . 61,059 62,231
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . 90,096 67,874
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . $4,149,994 $4,047,038
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,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . $ 39,261 $ 33,199
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . 36,814 35,731
Deferred Federal Income Taxes. . . . . . . . . . . . . 12,362 (2,138)
Deferred Investment Tax Credits. . . . . . . . . . . . (1,172) (1,182)
Deferred Power Supply Costs (net). . . . . . . . . . . 14,706 7,390
Provision for Revenue Refunds. . . . . . . . . . . . . - 14,965
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . 46,450 (4,682)
Fuel, Materials and Supplies . . . . . . . . . . . . . (5,799) (2,968)
Accrued Utility Revenues . . . . . . . . . . . . . . . 10,977 15,450
Prepayments. . . . . . . . . . . . . . . . . . . . . . (6,348) 465
Accounts Payable . . . . . . . . . . . . . . . . . . . (13,802) (15,103)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . 14,702 23,570
Interest Accrued . . . . . . . . . . . . . . . . . . . 9,298 8,780
Other (net). . . . . . . . . . . . . . . . . . . . . . . (41,060) (14,392)
Net Cash Flows From Operating Activities . . . . . 116,389 99,085
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . (38,129) (40,066)
Proceeds from Sale of Property . . . . . . . . . . . . . 127 535
Net Cash Flows Used For Investing Activities . . . (38,002) (39,531)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . - 96,781
Change in Short-term Debt (net). . . . . . . . . . . . . (19,125) 12,100
Retirement of Cumulative Preferred Stock . . . . . . . . (4) (117)
Retirement of Long-term Debt . . . . . . . . . . . . . . - (138,470)
Dividends Paid on Common Stock . . . . . . . . . . . . . (30,348) (29,729)
Dividends Paid on Cumulative Preferred Stock . . . . . . (567) (572)
Net Cash Flows Used For Financing Activities . . . (50,044) (60,007)
Net Increase (Decrease) in Cash and Cash Equivalents . . . 28,343 (453)
Cash and Cash Equivalents at Beginning of Period . . . . . 7,755 6,947
Cash and Cash Equivalents at End of Period . . . . . . . . $ 36,098 $ 6,494
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $21,009,000 and $20,933,000
and for income taxes was $57,000 and $570,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $2,453,000 and $6,120,000 in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements
should be read in conjunction with the 1998 Annual Report as
incorporated in and filed with the Form 10-K. Certain prior-period
amounts have been reclassified to agree with 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 April 1999 the Company called $77 million of first mortgage
bonds, $37 million of 8.43% series due 2022, $30 million of 7.90%
series due 2023 and $10 million of 7.80% series due 2023, for early
redemption in May. Consequently, the bonds were reclassified as a
current liability on the Consolidated Balance Sheets.
3. VIRGINIA RESTRUCTURING
As discussed in Note 2 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, in February 1999 the Virginia
legislature passed comprehensive legislation, which became law upon
the Governor's signature in March 1999, to restructure the electric
utility industry. Under the 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. Provisions allowing for an
acceleration or limited delay in this schedule are also contained
in the law. Except as provided in the law, the generation of
electricity will not be subject to rate regulation after January 1,
2002. Additionally, each Virginia electric utility is required by
2001 to join or establish a regional transmission entity which will
manage and control transmission assets.
The Virginia restructuring law also provides an opportunity for
recovery of just and reasonable net stranded costs. Stranded costs
are those costs above market including generation related net
regulatory assets and impaired tangible assets that potentially
would not be recoverable in a competitive market. 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. The capped rates may be
terminated after January 1, 2004, and prior to July 1, 2007, based
upon the Virginia SCC determining that an effective competitive
market exists. The wires charge will be equal to the difference
between the generation component of the capped rates and the market
price for generation service and will be imposed upon departing
customers through the expiration of the rate cap period.
Management has reviewed all the evidence currently available and
concluded that as of March 31, 1999 the requirements to apply
Statement of Financial Accounting Standards (SFAS) 71, "Accounting
for the Effects of Certain Types of Regulation," continue to be met.
The Company's Virginia rates for generation will continue to be
cost-based regulated until the establishment of capped rates as
provided in the law. When capped rates are established in Virginia,
the application of SFAS 71 would be discontinued for the Virginia
retail jurisdiction portion of the generating business. At that
time generation-related regulatory assets applicable to the Virginia
jurisdiction will have to be written off to the extent that they
cannot be recovered under the provisions of the restructuring law
and generating assets for the Virginia retail jurisdiction will have
to be evaluated for impairment. An impairment loss would be
recorded to the extent that such assets cannot be recovered through
the transition recovery mechanisms provided by the law. The amount
of regulatory assets applicable to the Virginia generating business
at March 31, 1999 is estimated to be $61 million before related tax
effects and any possible offsetting regulatory liabilities.
Regulatory liabilities applicable to the Virginia generation
business at March 31, 1999 are estimated to be $38 million of which
$25 million represents deferred investment tax credits (ITC). The
Company is evaluating the tax normalization rules regarding the
timing of the reversal of deferred ITC in connection with the
Virginia restructuring law and the ability to record a reversal of
deferred ITC in the same accounting periods when any possible losses
from unrecovered regulatory assets are recorded. Should it not be
possible under the Virginia law to recover all or a portion of the
generation net regulatory assets, it could have a material adverse
impact on results of operations; however, the amount of any
impairment loss for Virginia retail jurisdictional generating assets
and any loss from a possible inability to recover generation net
regulatory assets cannot be estimated until such time as capped
rates are determined under the law.
4. RATE MATTERS
Virginia Jurisdiction
As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the Company and the staff of
the Virginia SCC filed a settlement agreement with the Virginia SCC
in January 1999. The settlement agreement was approved by the
Virginia SCC in February 1999. It required a refund to customers
of all amounts collected in excess of the settlement rates. In
February 1999 new rates were implemented, and in March 1999 refunds
of $48.8 million including interest were made to customers. A
liability for the refunds and interest had previously been recorded
by the Company.
Wholesale Jurisdiction
As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the Company had requested a
rehearing of a June 1998 Federal Energy Regulatory Commission (FERC)
order which granted an annual rate increase of $3.4 million in
response to a request for an $8.7 million annual rate increase. The
FERC had authorized the Company to implement the $8.7 million annual
rate increase subject to refund in 1992. On April 5, 1999, the FERC
denied the rehearing request. As a result the Company will make the
refund to customers following FERC approval of the Company's
compliance filing of proposed new rates as ordered by the FERC. A
refund liability of $44.4 million, including interest, has been
accrued.
West Virginia Jurisdiction
On May 12, 1999, the Company filed with the West Virginia Public
Service Commission for a base rate increase of $50.3 million
annually and a reduction in expanded net energy cost rates of $37.9
million annually. The filings request that the new rates become
effective January 1, 2000 when the current rate freeze expires.
5. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". The EITF requires that all energy
trading contracts be marked-to-market. The effect on the
Consolidated Statements of Income of marking open trading contracts
to market is deferred as regulatory assets or liabilities for the
portion of open trading transactions that are included in cost of
service on a settlement basis for ratemaking purposes in the
Company's non-Virginia jurisdictions. The Virginia jurisdiction net
mark-to-market pre-tax gain of $1.5 million for the first quarter
of 1999 is included in net income as a result of an agreed
prohibition against establishing regulatory assets in a February
1999 Virginia SCC ordered settlement agreement. The adoption of the
EITF did not have a material effect on results of operations, cash
flows or financial condition.
6. CONTINGENCIES
Litigation
As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate
owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through
March 31, 1999 would reduce earnings by approximately $79 million
(including interest). The Company has made no provision for any
possible earnings impact from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-1997
to avoid the potential assessment by the IRS of any additional above
market rate interest on the contested amount. These payments to the
IRS are included on the Consolidated Balance Sheets in other
property and investments pending the resolution of this matter. The
Company will seek refund, either administratively or through
litigation, of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against
the United States in the US District Court for the Southern District
of Ohio in March 1998. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit. In
the event the resolution of this matter is unfavorable, it will have
a material adverse impact on results of operations.
The Company continues to be involved in certain other matters
discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
FIRST QUARTER 1999 vs. FIRST QUARTER 1998
RESULTS OF OPERATIONS
Net income increased $6.1 million or 18% as a result of increased
retail sales reflecting colder winter weather and a favorable accrual
adjustment to a revenue refund provision, partially offset by decreased
wholesale sales reflecting the loss of certain wholesale customers.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Operating Revenues. . . . . . . . . . $ 12.3 3
Fuel Expense. . . . . . . . . . . . . 15.4 14
Purchased Power Expense . . . . . . . (18.7) (27)
Other Operation Expense . . . . . . . 7.9 14
Maintenance Expense . . . . . . . . . (6.8) (19)
Federal Income Taxes. . . . . . . . . 6.4 36
The increase in operating revenues is attributable to a 5% increase
in retail revenues, reflecting increased sales to residential customers
of 15% due to colder winter weather, and the effect of a favorable
adjustment to a provision for revenue refunds in the Company's Virginia
jurisdiction in connection with the execution of the refund. A 26%
reduction in wholesale revenues, reflecting the loss of a contract which
supplied power to several municipal customers, partly offset the
increase in retail revenues.
The increase in fuel expense was primarily due to an increase in
generation to meet the increased retail demand for electricity.
Purchased power expense decreased due to a decrease in purchases of
energy from the American Electric Power (AEP) System Power Pool (AEP
Power Pool).
The increase in other operation expense primarily reflects an
increase in employee benefit costs as a result of incentive compensation
plan accrual adjustments in connection with the payment of such
compensation, which adjustments were unfavorable in 1999 and favorable
in 1998, and an increase in workers' compensation accruals.
<PAGE>
Maintenance expense decreased significantly due to reduced
expenditures resulting from costs incurred in 1998 to repair overhead
transmission and distribution lines following two severe snowstorms.
The increase in federal income tax expense attributable to
operations was primarily due to an increase in pre-tax operating income
and changes in certain book/tax differences accounted for on a flow-through
basis for rate-making purposes.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
first three months of 1999 were $41 million. Short-term debt decreased
by $19 million during the quarter.
In April 1999 the Company called $77 million of first mortgage
bonds, $37 million of 8.43% series due 2022, $30 million of 7.90% series
due 2023 and $10 million of 7.80% series due 2023, for early redemption
in May. Consequently, the bonds were reclassified as a current
liability on the Consolidated Balance Sheets.
OTHER MATTERS
Virginia Restructuring
As discussed in Management's Discussion and Analysis of Results of
Operations and Financial Condition in the 1998 Annual Report, in
February 1999 the Virginia legislature passed comprehensive legislation,
which became law in March 1999, to restructure the electric utility
industry in Virginia. Under the 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. Provisions allowing for an acceleration or limited
delay in this schedule are also contained in the law. Except as
provided in the law, the generation of electricity will not be subject
to rate regulation after January 1, 2002. Additionally, each Virginia
electric utility is required by 2001 to join or establish a regional
transmission entity which will manage and control transmission assets.
<PAGE>
The Virginia restructuring law also provides an opportunity for
recovery of just and reasonable net stranded costs. Stranded costs are
those costs above market including generation related net regulatory
assets and impaired tangible assets that potentially would not be
recoverable in a competitive market. 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.
The capped rates may be terminated after January 1, 2004, and prior to
July 1, 2007, based upon the Virginia SCC determining that an effective
competitive market exists. The wires charge will be equal to the
difference between the generation component of the capped rates and the
market price for generation service and will be imposed upon departing
customers through the expiration of the rate cap period.
Management has reviewed all the evidence currently available and
concluded that as of March 31, 1999 the requirements to apply Statement
of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects
of Certain Types of Regulation," continue to be met. The Company's
Virginia rates for generation will continue to be cost-based regulated
until the establishment of capped rates as provided in the law. When
capped rates are established in Virginia, the application of SFAS 71
would be discontinued for the Virginia retail jurisdiction portion of
the generating business, generation-related regulatory assets applicable
to the Virginia jurisdiction will have to be written off to the extent
that they cannot be recovered under the provisions of the restructuring
law and generating assets for the Virginia retail jurisdiction will have
to be evaluated for impairment. An impairment loss would be recorded
to the extent that such assets cannot be recovered through the
transition recovery mechanisms provided by the law. The amount of
regulatory assets applicable to the Virginia generating business at
March 31, 1999 is estimated to be $61 million before related tax effects
and any possible offsetting regulatory liabilities. Regulatory
liabilities applicable to the Virginia generation business at March 31,
1999 are estimated to be $38 million of which $25 million represents
deferred investment tax credits (ITC). The Company is evaluating the
tax normalization rules regarding the timing of the reversal of deferred
ITC in connection with the Virginia restructuring law and the ability
to record a reversal of deferred ITC in the same accounting periods when
any possible losses from unrecovered regulatory assets are recorded.
Should it not be possible under the Virginia law to recover all or a
portion of the generation net regulatory assets, it could have a
material adverse impact on results of operations; however, the amount
of any impairment loss for Virginia retail jurisdictional generating
assets and any loss from a possible inability to recover net generation
regulatory assets cannot be estimated until such time as capped rates
are determined under the law.
Market Risks
The Company has certain market risks inherent in its business
activities 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 AEP Power Pool, has not changed
materially since December 31, 1998. Market risk represents the risk of
loss that may impact the Company due to adverse changes in commodity
market prices and interest rates.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at March 31, 1999 is not materially
different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing systems
may begin to produce erroneous results or fail, unless these systems are
modified or replaced, because such systems may be programmed incorrectly
and interpret the date of January 1, 2000 as being January 1st of the
year 1900 or another incorrect date. In addition, certain systems may
fail to detect that the year 2000 is a leap year. Problems can also
arise earlier than January 1, 2000, as dates in the next millennium are
entered into non-Y2K ready programs.
Readiness Program - Internally, the Company, through the AEP System, is
modifying or replacing its computer hardware and software programs to
minimize Y2K-related failures and repair such failures if they occur.
This includes both information technology (IT) systems, which are
mainframe and client server applications, and embedded logic (non-IT)
systems, such as process controls for energy production and delivery.
Externally, the problem is being addressed with entities that interact
with the Company, including suppliers, customers, creditors, financial
service organizations and other parties essential to the Company's
operations. In the course of the external evaluation, the Company has
sought written assurances from third parties regarding their state of
Y2K readiness.
Another issue we are addressing is the impact of electric power grid
problems that may occur outside of our transmission system. The
Company, along with other electric utilities in North America, regularly
submits information to the North American Electric Reliability Council
(NERC) as part of NERC's Y2K readiness program. NERC then publicly
reports summary information to the U.S. Department of Energy (DOE)
regarding the Y2K readiness of electric utilities. AEP participated in
an industry-wide NERC-sponsored drill on April 9, 1999 simulating the
partial loss of voice and data communications. There were no major
problems encountered with relaying information with the use of backup
telecommunications systems. AEP and other utilities plan to participate
in a more comprehensive second NERC-sponsored drill on September 8-9,
1999, to prepare for operations under Y2K conditions.
The NERC report, dated April 30, 1999 and entitled: Preparing the
Electric Power Systems of North America for Transition to the Year 2000
- - A Status Report and Work Plan, First Quarter 1999, states that: "With
more than 75% of mission critical components tested through March 31,
1999, findings in the field continue to indicate that the transition
through critical Y2K dates is expected to have minimal impact on
electric system operations in North America." The report also indicates
that, "the risk of electrical outages by Y2K appears to be no higher
than the risks we already experience" from incidents such as severe
wind, ice, floods, equipment failures and power shortages during an
extremely hot or cold period.
Through the Electric Power Research Institute, an electric utility
industry-wide effort has been established to deal with Y2K problems
affecting embedded systems. Under this effort, participating utilities
are working together to assess specific vendors' system problems and
test plans.
The state regulatory commissions in the Company's service territory
are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in accordance
with business risk. The highest priority has been assigned to
activities that potentially affect safety, the physical generation and
delivery of energy, and communications; followed by back office
activities such as customer service/billing, regulatory reporting,
internal reporting and administrative activities (e.g., payroll,
procurement, accounts payable); and finally, those activities that would
cause inconvenience or productivity loss in normal business operations.
<PAGE>
The following chart shows our progress toward becoming ready for the
Y2K as of March 31, 1999:
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
Launch: Initiation of 2/24/1998 100% 5/31/1998 100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999 100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65%
replacing or retiring 94%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 56%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
*The Company is upgrading its 800 MHZ trunked radio system, a mission
critical non-IT system, for Y2K readiness and it is anticipated that the
upgrade should be complete by September 30, 1999.
The Company continues to make steady progress toward the June 30, 1999 target
date and anticipates completing the remediation/testing work for mission
critical and high-priority systems by the June 30, 1999 target date except as
noted in the table.
Costs to Address the Company's Year 2000 Issues - Through March 31, 1999, the
Company has spent $8 million on the Y2K project and, estimates spending an
additional $9 million to $12 million to achieve Y2K readiness. Most Y2K
costs are for software modifications, IT consultants and salaries and are
expensed; however, in certain cases the Company has acquired hardware that was
capitalized. The Company intends to fund these expenditures through
internal sources. Although significant, the cost of becoming Y2K compliant
is not expected to have a material impact on the Company's results of
operations, cash flows or financial condition.
Risks of the Company's Y2K Issues - The applications posing the greatest
business risk to the Company's operations should they experience Y2K
problems are:
Automated power generation, transmission and distribution systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for commercial
and industrial customers and
Work management and billing systems.
The potential problems related to erroneous processing by, or failure
of, these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably likely worst
case Y2K scenario with any degree of certainty, management believes that
such a scenario would be small, localized interruptions of service,
which would be restorable in a reasonable period of time.
In addition, although relationships with third parties, such as suppliers,
customers and other electric utilities, are being monitored, these third parties
nonetheless represent a risk that cannot be assessed with precision or
controlled with certainty.
Due to the complexity of the problem and the interdependent nature of
computer systems, if our corrective actions, and/or the actions of others
who impact the AEP System's operations but are not affiliated with the AEP
System, fail for critical applications, Y2K-related issues may materially
adversely affect the Company.
<PAGE>
Company's Contingency Plans - To address possible failures of electric
generation and delivery of electrical energy due to Y2K related failures,
we have established a draft Y2K contingency plan and submitted it to the
East Central Area Reliability Council in
December 1998 as part of NERC's review of regional and individual electric
utility contingency plans in 1999. NERC's target date is June 1999 for the
completion of this contingency plan. In addition, the Company intends to
establish contingency plans for its business units to address alternatives
if Y2K related failures occur. Contingency plans will be developed by the
end of 1999.
The Company's plans build upon the disaster recovery, system restoration,
and contingency planning that we have had in place and include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, with key employees on duty at
those locations during the Y2K transition.
<PAGE>
<PAGE>
<TABLE> COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . $279,067 $266,399
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . 45,856 46,980
Purchased Power. . . . . . . . . . . . . . . . . . . . 55,191 47,837
Other Operation. . . . . . . . . . . . . . . . . . . . 45,969 44,582
Maintenance. . . . . . . . . . . . . . . . . . . . . . 13,946 14,307
Depreciation . . . . . . . . . . . . . . . . . . . . . 23,184 22,850
Taxes Other Than Federal Income Taxes. . . . . . . . . 31,078 29,936
Federal Income Taxes . . . . . . . . . . . . . . . . . 17,796 14,678
TOTAL OPERATING EXPENSES. . . . . . . . . . . . 233,020 221,170
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . 46,047 45,229
NONOPERATING INCOME (LOSS) . . . . . . . . . . . . . . . 361 (28)
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . 46,408 45,201
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . 18,990 19,556
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . 27,418 25,645
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . 533 533
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . $ 26,885 $ 25,112
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . $186,441 $138,172
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . 27,418 25,645
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . 21,999 20,661
Cumulative Preferred Stock . . . . . . . . . . . . . 437 437
Capital Stock Expense. . . . . . . . . . . . . . . . . 96 96
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . $191,327 $142,623
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,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,533,468 $1,526,869
Transmission . . . . . . . . . . . . . . . . . . . . 341,734 339,934
Distribution . . . . . . . . . . . . . . . . . . . . 947,759 938,283
General. . . . . . . . . . . . . . . . . . . . . . . 131,789 130,002
Construction Work in Progress. . . . . . . . . . . . 114,899 118,477
Total Electric Utility Plant . . . . . . . . 3,069,649 3,053,565
Accumulated Depreciation . . . . . . . . . . . . . . 1,155,909 1,134,348
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,913,740 1,919,217
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 79,670 73,088
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 14,728 7,206
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 85,674 89,522
Affiliated Companies . . . . . . . . . . . . . . . 24,514 17,966
Miscellaneous. . . . . . . . . . . . . . . . . . . 11,440 11,989
Allowance for Uncollectible Accounts . . . . . . . (2,993) (2,598)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 22,604 22,140
Materials and Supplies . . . . . . . . . . . . . . . 31,183 33,263
Accrued Utility Revenues . . . . . . . . . . . . . . 35,643 40,127
Energy Marketing and Trading Contracts . . . . . . . 79,987 12,670
Prepayments. . . . . . . . . . . . . . . . . . . . . 38,312 29,084
TOTAL CURRENT ASSETS . . . . . . . . . . . . 341,092 261,369
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 346,940 353,369
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 56,185 74,647
TOTAL. . . . . . . . . . . . . . . . . . . $2,737,627 $2,681,690
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,
1999 1998
(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. . . . . . . . . . . . . . . . . . . 572,587 572,492
Retained Earnings. . . . . . . . . . . . . . . . . . 191,327 186,441
Total Common Shareholder's Equity. . . . . . 804,940 799,959
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 959,922 959,786
TOTAL CAPITALIZATION . . . . . . . . . . . . 1,789,862 1,784,745
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 43,866 42,176
CURRENT LIABILITIES:
Short-term Debt. . . . . . . . . . . . . . . . . . . 45,700 52,500
Accounts Payable - General . . . . . . . . . . . . . 23,416 34,631
Accounts Payable - Affiliated Companies. . . . . . . 41,148 37,132
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 127,913 141,831
Interest Accrued . . . . . . . . . . . . . . . . . . 24,294 14,355
Energy Marketing and Trading Contracts . . . . . . . 80,429 13,682
Other. . . . . . . . . . . . . . . . . . . . . . . . 33,053 37,197
TOTAL CURRENT LIABILITIES. . . . . . . . . . 375,953 331,328
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 438,645 442,100
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 47,842 48,710
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 41,459 32,631
CONTINGENCIES (Note 3)
TOTAL. . . . . . . . . . . . . . . . . . . $2,737,627 $2,681,690
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,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 27,418 $ 25,645
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 23,232 22,907
Deferred Federal Income Taxes. . . . . . . . . . . . . . (48) 1,481
Deferred Investment Tax Credits. . . . . . . . . . . . . (868) (888)
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . 836 (522)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (1,756) (35,821)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 1,616 (2,455)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 4,484 4,439
Prepayments. . . . . . . . . . . . . . . . . . . . . . . (9,228) (3,683)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (7,199) 34,627
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (13,918) (15,181)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 9,939 11,857
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 18,912 7,568
Net Cash Flows From Operating Activities . . . . . . 53,420 49,974
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (16,908) (22,113)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 246 2,129
Net Cash Flows Used For Investing Activities . . . . (16,662) (19,984)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 51,552
Change in Short-term Debt (net). . . . . . . . . . . . . . (6,800) (6,550)
Retirement of Long-term Debt . . . . . . . . . . . . . . . - (57,000)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (21,999) (20,661)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (437) (437)
Net Cash Flows Used For Financing Activities . . . . (29,236) (33,096)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 7,522 (3,106)
Cash and Cash Equivalents at Beginning of Period . . . . . . 7,206 12,626
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 14,728 $ 9,520
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $8,115,000 and $6,744,000 and
for income taxes was $44,000 and $129,000 in 1999 and 1998, respectively. Noncash
acquisitions under capital leases were $2,182,000 and $3,378,000 in 1999 and 1998,
respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements
should be read in conjunction with the 1998 Annual Report as
incorporated in and filed with the Form 10-K. Certain prior-period
amounts have been reclassified to conform with 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. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". The EITF requires that all energy
trading contracts be marked-to-market. The effect on the
Consolidated Statements of Income of marking open trading contracts
to market is deferred as regulatory assets or liabilities for those
open trading transactions that are included in cost of service on
a settlement basis for ratemaking purposes. The adoption of the
EITF did not have a material effect on results of operations, cash
flows or financial condition.
3. CONTINGENCIES
As discussed in Note 3, of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate
owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through
March 31, 1999 would reduce earnings by approximately $43 million
(including interest). The Company has made no provision for any
possible earnings impact from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-1997
to avoid the potential assessment by the IRS of any additional above
market rate interest on the contested amount. These payments to the
IRS are included on the Consolidated Balance Sheets in other
property and investments pending the resolution of this matter. The
Company will seek refund, either administratively or through
litigation, of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against
the United States in the US District Court for the Southern District
of Ohio in March 1998. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit. In
the event the resolution of this matter is unfavorable, it will have
a material adverse impact on results of operations.
The Company continues to be involved in certain other matters
discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 1999 vs. FIRST QUARTER 1998
Net income increased $1.8 million or 7% in the first quarter due
primarily to increased retail sales.
Income statement line items which changed significantly were:
Increase
(in millions) %
Operating Revenues . . . . . . . . . . . $12.7 5
Purchased Power Expense. . . . . . . . . 7.4 15
Federal Income Taxes . . . . . . . . . . 3.1 21
Operating revenues from retail customers increased $12.4 million
reflecting increased sales to residential and commercial customers of
13% and 5%, respectively. Colder winter weather and customer growth
were the main reasons for the increased sales.
The increase in purchased power expense is primarily due to
increased capacity charges from the American Electric Power (AEP) System
Power Pool (AEP Power Pool). Under the terms of the AEP Power Pool,
capacity credits and charges are designed to allocate the cost of the
AEP System's capacity among the AEP Power Pool members based on their
relative peak demands and generating reserves. The increase in capacity
charges can be attributed to an increase in the Company's prior twelve
month peak demand relative to the total peak demand of all AEP Power
Pool members.
Federal income taxes attributable to operations increased primarily
due to an increase in pre-tax operating income and changes in certain
book/tax differences accounted for on a flow-through basis for rate-making
purposes.
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . $334,113 $328,468
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 41,800 44,879
Purchased Power. . . . . . . . . . . . . . . . . . . . . 62,315 58,159
Other Operation. . . . . . . . . . . . . . . . . . . . . 91,575 76,433
Maintenance. . . . . . . . . . . . . . . . . . . . . . . 31,202 27,078
Depreciation and Amortization. . . . . . . . . . . . . . 36,985 35,793
Taxes Other Than Federal Income Taxes. . . . . . . . . . 19,029 18,697
Federal Income Taxes . . . . . . . . . . . . . . . . . . 12,369 18,366
TOTAL OPERATING EXPENSES . . . . . . . . . . . . 295,275 279,405
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . 38,838 49,063
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . 1,735 1,315
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . 40,573 50,378
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . 20,503 16,634
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 20,070 33,744
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . 1,214 1,217
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . $ 18,856 $ 32,527
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . $253,154 $278,814
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . 20,070 33,744
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . . 28,664 29,366
Cumulative Preferred Stock . . . . . . . . . . . . . . 1,182 1,184
Capital Stock Expense. . . . . . . . . . . . . . . . . . 32 33
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . $243,346 $281,975
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,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,580,567 $2,565,041
Transmission . . . . . . . . . . . . . . . . . . . . 917,008 913,495
Distribution . . . . . . . . . . . . . . . . . . . . 773,187 768,888
General (including nuclear fuel) . . . . . . . . . . 227,347 228,013
Construction Work in Progress. . . . . . . . . . . . 161,984 156,411
Total Electric Utility Plant . . . . . . . . 4,660,093 4,631,848
Accumulated Depreciation and Amortization. . . . . . 2,113,688 2,081,355
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,546,405 2,550,493
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS . . . . . . . . . . . . . . . . 672,940 648,307
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 207,609 197,368
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 26,851 12,465
Accounts Receivable (net). . . . . . . . . . . . . . 124,769 130,746
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 30,482 20,857
Materials and Supplies . . . . . . . . . . . . . . . 83,538 78,009
Accrued Utility Revenues . . . . . . . . . . . . . . 28,183 37,277
Energy and Marketing Trading Contracts . . . . . . . 87,354 14,105
Prepayments. . . . . . . . . . . . . . . . . . . . . 8,572 4,848
TOTAL CURRENT ASSETS . . . . . . . . . . . . 389,749 298,307
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 493,496 421,475
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 40,737 32,573
TOTAL. . . . . . . . . . . . . . . . . . . $4,350,936 $4,148,523
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,
1999 1998
(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. . . . . . . . . . . . . . . . . . . 732,639 732,605
Retained Earnings. . . . . . . . . . . . . . . . . . 243,346 253,154
Total Common Shareholder's Equity. . . . . . 1,032,569 1,042,343
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 9,266 9,273
Subject to Mandatory Redemption. . . . . . . . . . 68,445 68,445
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,030,093 1,140,789
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,140,373 2,260,850
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 468,181 445,934
Other. . . . . . . . . . . . . . . . . . . . . . . . 243,836 240,320
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 712,017 686,254
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 148,000 35,000
Short-term Debt. . . . . . . . . . . . . . . . . . . 110,295 108,700
Accounts Payable - General . . . . . . . . . . . . . 67,724 53,187
Accounts Payable - Affiliated Companies. . . . . . . 28,335 37,647
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 49,702 35,161
Interest Accrued . . . . . . . . . . . . . . . . . . 16,537 15,279
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 23,427 4,963
Revenue Refunds Accrued . . . . . . . . . . . . . . 55,000 -
Obligations Under Capital Leases . . . . . . . . . . 10,681 9,667
Energy and Marketing Trading Contracts . . . . . . . 87,838 15,228
Other. . . . . . . . . . . . . . . . . . . . . . . . 77,234 67,102
TOTAL CURRENT LIABILITIES. . . . . . . . . . 674,773 381,934
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 560,136 559,288
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 127,881 129,779
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 87,785 88,712
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 47,971 41,706
CONTINGENCIES (Note 4)
TOTAL. . . . . . . . . . . . . . . . . . . $4,350,936 $4,148,523
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,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 20,070 $ 33,744
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 37,995 36,889
Amortization of Incremental Nuclear
Refueling Outage Expenses (net). . . . . . . . . . . . 2,347 4,777
Unrecovered Fuel and Purchased Power Costs . . . . . . . (52,664) (22,203)
Deferred Nuclear Outage Costs (net). . . . . . . . . . . (30,000) -
Deferred Federal Income Taxes. . . . . . . . . . . . . . 5,365 6,494
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,898) (1,909)
Deferred Property Taxes. . . . . . . . . . . . . . . . . (9,325) (8,185)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 5,977 96
Fuel, Materials and Supplies . . . . . . . . . . . . . . (15,154) (5,839)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 9,094 (964)
Prepayments. . . . . . . . . . . . . . . . . . . . . . . (3,724) (1,223)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 5,225 10,571
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 14,541 17,551
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 55,000 -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 10,540 (18,242)
Net Cash Flows From Operating Activities . . . . . . 71,853 70,021
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (30,114) (25,290)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 903 698
Net Cash Flows Used For Investing Activities . . . . (29,211) (24,592)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . . 1,595 (9,125)
Retirement of Cumulative Preferred Stock . . . . . . . . . (5) -
Dividends Paid on Common Stock . . . . . . . . . . . . . . (28,664) (29,366)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,182) (1,184)
Net Cash Flows Used For Financing Activities . . . . (28,256) (39,675)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 14,386 5,754
Cash and Cash Equivalents at Beginning of Period . . . . . . 12,465 5,860
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 26,851 $ 11,614
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $18,527,000 and $14,412,000,
respectively and for income taxes was $125,000 in 1998. Noncash acquisitions under
capital leases were $3,783,000 and $16,630,000 in 1999 and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements
should be read in conjunction with the 1998 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 April 1999 the Company called $65 million of first mortgage
bonds, $20 million of 6.80% series due 2003, $20 million of 6.55%
series due 2003 and $25 million of 6.55% series due 2004, for early
redemption in May. Consequently, the bonds were reclassified as a
current liability on the Consolidated Balance Sheets.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". The EITF requires that all energy
trading contracts be marked-to-market. The effect on the
Consolidated Statements of Income of marking open trading contracts
to market is deferred as regulatory assets or liabilities for those
open trading transactions that are included in cost of service on a
settlement basis for ratemaking purposes. The adoption of the EITF
did not have a material effect on results of operations, cash flows
or financial condition.
4. CONTINGENCIES
Litigation
As discussed in Note 3, of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate
owned life insurance (COLI) program for taxable years 1991-1996 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 COLI interest deductions through March
31, 1999 would reduce earnings by approximately $66 million
(including interest). The Company has made no provision for any
possible earnings impact from this matter.
<PAGE>
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1991-1997
to avoid the potential assessment by the IRS of any additional above
market rate interest on the contested amount. These payments to the
IRS are included on the Consolidated Balance Sheets in other property
and investments pending the resolution of this matter. The Company
will seek refund, either administratively or through litigation, of
all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against
the United States in the US District Court for the Southern District
of Ohio in March 1998. Management believes that it has a meritorious
position and will vigorously pursue this lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations.
Cook Plant Shutdown
As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, both units of the Cook Plant
were 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 NRC issued a Confirmatory Action Letter in September 1997
requiring the Company to address certain issues identified in the
letter. During 1998 the NRC notified the Company that it had
convened a Restart Panel for Cook Plant and provided a list of
required restart activities. In order to identify and resolve all
issues, including those in the letter, necessary to restart the Cook
units, the Company is working with the NRC and will be meeting with
the Panel on a regular basis, until the units are returned to
service.
In January 1999 the Company announced that additional engineering
reviews will be conducted at the Cook Plant delaying the restart of
the units. Previously, the units were scheduled to return to service
at the end of the first and second quarters of 1999. The decision
to delay restart resulted from internal assessments that indicated
a need to conduct expanded system readiness reviews. A new restart
schedule will be developed based on the results of the expanded
reviews and should be available in June 1999. When maintenance and
other activities required for restart are complete, the Company will
seek concurrence from the NRC to return the Cook Plant to service.
Until these additional reviews are completed, management is unable
to determine when the units will be returned to service.
In May 1999 the Company received a letter from the NRC indicating
that NRC senior managers had identified Cook Plant as an "agency-focus
plant." The senior managers concluded that continued agency-level
oversight was appropriate; however, the NRC required no
additional action to redirect Cook Plant activities. The letter
states that the NRC staff will continue to monitor Cook Plant
performance through the Restart Panel process and evaluate whether
additional action may be necessary.
The cost of electricity supplied to retail customers remained
higher due to the outage of the two Cook Plant nuclear units since
higher cost coal-fired generation and coal based purchased power
continue to be substituted for low cost nuclear generation. The
Indiana and Michigan retail jurisdictional fuel cost recovery
mechanisms permit the recovery, subject to regulatory commission
review and approval, of changes in fuel costs including the fuel
component of purchased power in the Indiana jurisdiction and changes
in replacement power in the Michigan jurisdiction. Under these fuel
cost recovery mechanisms, retail rates contain a fuel cost adjustment
factor that reflects estimated fuel costs for the period during which
the factor will be in effect subject to reconciliation to actual fuel
costs in a future proceeding. When actual fuel costs exceed the
estimated costs reflected in the billing factor a regulatory asset
is recorded and revenues are accrued. Therefore, a regulatory asset
has been recorded and revenues accrued in anticipation of the future
reconciliation and billing under the fuel cost recovery mechanisms
of the higher fuel costs to replace Cook energy during the extended
outage. At March 31, 1999, the regulatory asset was $118 million.
On March 30, 1999 the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolves all matters
related to the reasonableness of fuel costs and all outage issues
during the extended outage of the Cook Plant. The settlement
agreement provides for, among other things, a credit of $55 million,
including interest, to Indiana retail customers; authorization to
defer any unrecovered fuel revenues accrued between September 9, 1997
and December 31, 1999, including the $52.3 million revenue portion
of the $55 million credit; authorization to defer up to $150 million
of incremental operation and maintenance costs for the Cook Plant
above the amount included in base rates; amortization of the fuel
recoveries and non-fuel operation and maintenance cost deferrals over
a five-year period ending December 31, 2003; a freeze in base rates
through December 31, 2003; and a fixed fuel recovery charge through
March 1, 2004. The $55 million credit will be refunded through
customers' bills during the months of July, August and September
1999.
The incremental costs incurred in first quarter 1999 for restart
of the Cook units were $45 million of which $30 million were deferred
pursuant to the settlement agreement discussed above.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect
on results of operations, cash flows, and possibly financial
condition.
Other
The Company continues to be involved in other matters discussed
in its 1998 Annual Report.
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
FIRST QUARTER 1999 vs. FIRST QUARTER 1998
RESULTS OF OPERATIONS
Although operating revenues increased $5.6 million or 2%, net income
decreased $13.7 million or 41% due to increased operation and
maintenance expense related to an extended outage of the Cook Nuclear
Plant which was shut down in September 1997.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Operating Revenues. . . . . . . . . . . . $ 5.6 2
Fuel Expense. . . . . . . . . . . . . . . (3.1) (7)
Purchased Power Expense . . . . . . . . . 4.2 7
Other Operation Expense . . . . . . . . . 15.1 20
Maintenance Expense . . . . . . . . . . . 4.1 15
Federal Income Taxes. . . . . . . . . . . (6.0) (33)
Interest Charges. . . . . . . . . . . . . 3.9 23
Operating revenues increased due to increased capacity credits from
the American Electric Power (AEP) System Power Pool (AEP Power Pool) and
an increase in transmission and business development revenues. Under
the terms of the AEP Power Pool, capacity credits and charges are
designed to allocate the cost of the AEP System's capacity among the AEP
Power Pool members based on their relative peak demands and generating
reserves. The increase in capacity credits received can be attributed
to a decrease in the Company's prior twelve month peak demand relative
to the total peak demand of all Power Pool members.
Fuel expense decreased as a result of a decline in generation
reflecting reduced availability of coal-fired generation due to outages
in the first quarter of 1999.
The increase in purchased power expense resulted from increased
purchases from the AEP Power Pool to replace power that would have been
generated by the coal fired units which were unavailable.
Other operation expense increased due to increased nuclear operation
expenses for engineering costs incurred as a result of the extended
shutdown. The extended shutdown of the Cook Plant also accounted for
the increase in maintenance expense.
Federal income taxes attributable to operations decreased due to a
decrease in pre-tax operating income.
Interest charges increased due to an accrual of interest for revenue
refunds ordered by the Indiana commission as part of a settlement
agreement and due to higher outstanding balances of long-term debt.
FINANCIAL CONDITION
Total plant and property additions including capital leases for the
period were $34 million. During the first three months of 1999 short-term
debt outstanding increased by $2 million.
In April 1999 the Company called $65 million of first mortgage bonds,
$20 million of 6.80% series due 2003, $20 million of 6.55% series due
2003 and $25 million of 6.55% series due 2004, for early redemption in
May. Consequently, the bonds were reclassified as a current liability
on the Consolidated Balance Sheets.
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
As discussed in Management's Discussion and Analysis of Results of
Operations and Financial Condition (MDA) in the 1998 Annual Report, as
a result of the Department of Energy's (DOE) failure to make sufficient
progress toward a permanent repository or otherwise assume
responsibility for SNF, the Company along with a number of unaffiliated
utilities and states filed suit in the United States (US) Court of
Appeals for the District of Columbia Circuit requesting, among other
things, that the court order DOE to meet its obligations under the law.
The court ordered the parties to proceed with contractual remedies but
declined to order DOE to begin accepting SNF for disposal. DOE
estimates its planned site for the nuclear waste will not be ready until
2010. In June 1998, the Company filed a complaint in the US Court of
Federal Claims seeking damages in excess of $150 million due to the
DOE's partial material breach of its unconditional contractual deadline
to begin disposing of SNF generated by the Cook Plant. Similar lawsuits
have been filed by other utilities. On April 6, 1999, the court granted
DOE's motion to dismiss a lawsuit filed by another utility. I&M's case
has been suspended pending final resolution of the other utility's case.
<PAGE>
Cook Nuclear Plant Shutdown
As discussed in MDA in the 1998 Annual Report, management shut down
both units of the Cook Plant in September 1997 due to questions, which
arose during a Nuclear Regulatory Commission (NRC) architect engineer
design inspection, regarding the operability of certain safety systems.
The NRC issued a Confirmatory Action Letter in September 1997 requiring
the Company to address certain issues identified in the letter. During
1998 the NRC notified the Company that it had convened a Restart Panel
for Cook Plant and provided a list of required restart activities. In
order to identify and resolve all issues, including those in the letter,
necessary to restart the Cook units, the Company is working with the NRC
and will be meeting with the Panel on a regular basis, until the units
are returned to service.
In January 1999 the Company announced that additional engineering
reviews will be conducted at the Cook Plant delaying the restart of the
units. Previously, the units were scheduled to return to service at the
end of the first and second quarters of 1999. The decision to delay
restart resulted from internal assessments that indicated a need to
conduct expanded system readiness reviews. A new restart schedule will
be developed based on the results of the expanded reviews and should be
available in June 1999. When maintenance and other activities required
for restart are complete, the Company will seek concurrence from the NRC
to return the Cook Plant to service. Until these additional reviews are
completed, management is unable to determine when the units will be
returned to service.
In May 1999 the Company received a letter from the NRC indicating
that NRC senior managers had identified Cook Plant as an "agency-focus
plant." The senior managers concluded that continued agency-level
oversight was appropriate; however, the NRC required no additional
action to redirect Cook Plant activities. The letter states that the
NRC staff will continue to monitor Cook Plant performance through the
Restart Panel process and evaluate whether additional action may be
necessary.
The cost of electricity supplied to retail customers remained higher
due to the outage of the two Cook Plant nuclear units since higher cost
coal-fired generation and coal based purchased power continue to be
substituted for low cost nuclear generation. The Indiana and Michigan
retail jurisdictional fuel cost recovery mechanisms permit the recovery,
subject to regulatory commission review and approval, of changes in fuel
costs including the fuel component of purchased power in the Indiana
jurisdiction and changes in replacement power in the Michigan
jurisdiction. Under these fuel cost recovery mechanisms, retail rates
contain a fuel cost adjustment factor that reflects estimated fuel costs
for the period during which the factor will be in effect subject to
reconciliation to actual fuel costs in a future proceeding. When actual
fuel costs exceed the estimated costs reflected in the billing factor
a regulatory asset is recorded and revenues are accrued. Therefore, a
regulatory asset has been recorded and revenues accrued in anticipation
of the future reconciliation and billing under the fuel cost recovery
mechanisms of the higher fuel costs to replace Cook energy during the
extended outage. At March 31, 1999, the regulatory asset was $118
million.
On March 30, 1999 the Indiana Utility Regulatory Commission (IURC)
approved a settlement agreement that resolves all matters related to the
reasonableness of fuel costs and all outage issues during the extended
outage of the Cook Plant. The settlement agreement provides for, among
other things, a credit of $55 million, including interest, to Indiana
retail customers; authorization to defer any unrecovered fuel revenues
accrued between September 9, 1997 and December 31, 1999, including the
$52.3 million revenue portion of the $55 million credit; authorization
to defer up to $150 million of incremental operation and maintenance
costs for the Cook Plant above the amount included in base rates;
amortization of the fuel recoveries and non-fuel operation and
maintenance cost deferrals over a five-year period ending December 31,
2003; a freeze in base rates through December 31, 2003; and a fixed fuel
recovery charge through March 1, 2004. The $55 million credit will be
refunded through customers' bills during the months of July, August and
September 1999.
The incremental costs incurred in first quarter 1999 for restart of
the Cook units were $45 million of which $30 million were deferred
pursuant to the settlement agreement discussed above.
Unless the costs of the extended outage and restart efforts are
recovered from customers, there would be a material adverse effect on
results of operations, cash flows, and possibly financial condition.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and interest
rates. 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, 1998. Market risk represents the risk of
loss that may impact the Company due to adverse changes in commodity
market prices and interest rates.
The exposure to changes in interest rates from the Company's short-term
and long-term borrowings at March 31, 1999 is not materially
different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing systems
may begin to produce erroneous results or fail, unless these systems are
modified or replaced, because such systems may be programmed incorrectly
and interpret the date of January 1, 2000 as being January 1st of the
year 1900 or another incorrect date. In addition, certain systems may
fail to detect that the year 2000 is a leap year. Problems can also
arise earlier than January 1, 2000, as dates in the next millennium are
entered into non-Y2K ready programs.
Readiness Program - Internally, the Company, through the AEP System, is
modifying or replacing its computer hardware and software programs to
minimize Y2K-related failures and repair such failures if they occur.
This includes both information technology (IT) systems, which are
mainframe and client server applications, and embedded logic (non-IT)
systems, such as process controls for energy production and delivery.
Externally, the problem is being addressed with entities that interact
with the Company, including suppliers, customers, creditors, financial
service organizations and other parties essential to the Company's
operations. In the course of the external evaluation, the Company has
sought written assurances from third parties regarding their state of
Y2K readiness.
Another issue we are addressing is the impact of electric power grid
problems that may occur outside of our transmission system. The
Company, along with other electric utilities in North America, regularly
submits information to the North American Electric Reliability Council
(NERC) as part of NERC's Y2K readiness program. NERC then publicly
reports summary information to the US DOE regarding the Y2K readiness
of electric utilities. AEP participated in an industry-wide
NERC-sponsored drill on April 9, 1999 simulating the partial loss of
voice and data communications. There were no major problems encountered
with relaying information with the use of backup telecommunications
systems. AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999, to
prepare for operations under Y2K conditions.
The NERC report, dated April 30, 1999 and entitled: Preparing the
Electric Power Systems of North America for Transition to the Year 2000
- - A Status Report and Work Plan, First Quarter 1999, states that: "With
more than 75% of mission critical components tested through March 31,
1999, findings in the field continue to indicate that the transition
through critical Y2K dates is expected to have minimal impact on
electric system operations in North America." The report also indicates
that, "the risk of electrical outages by Y2K appears to be no higher
than the risks we already experience" from incidents such as severe
wind, ice, floods, equipment failures and power shortages during an
extremely hot or cold period.
Through the Electric Power Research Institute, an electric utility
industry-wide effort has been established to deal with Y2K problems
affecting embedded systems. Under this effort, participating utilities
are working together to assess specific vendors' system problems and
test plans.
The state regulatory commissions in the Company's service territory
are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in accordance
with business risk. The highest priority has been assigned to
activities that potentially affect safety, the physical generation and
delivery of energy, and communications; followed by back office
activities such as customer service/billing, regulatory reporting,
internal reporting and administrative activities (e.g., payroll,
procurement, accounts payable); and finally, those activities that would
cause inconvenience or productivity loss in normal business operations.
The following chart shows our progress toward becoming ready for the
Y2K as of March 31, 1999:
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
Launch: Initiation of 2/24/1998 100% 5/31/1998 100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999 100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65%
replacing or retiring 94%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 56%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
*The Company is upgrading its 800 MHZ trunked radio system, a mission
critical non-IT system, for Y2K readiness and it is anticipated that the
upgrade should be complete by September 30, 1999.
The Company continues to make steady progress toward the June 30, 1999
target date andanticipates completing the remediation/testing work for mission
critical and high-priority systems by the June 30, 1999 target date except as
noted in the table.<PAGE>
Costs to Address the Company's Year 2000 Issues - Through
March 31, 1999, the Company has spent $5 million on the Year 2000 project
and, estimates spending an additional $5 million to $7 million to achieve
Y2K readiness. Most Y2K costs are for software modifications, IT
consultants and salaries and are expensed; however, in certain cases
the Company has acquired hardware that was capitalized. The Company intends
to fund these expenditures through internal sources. Although significant,
the cost of becoming Y2K compliant is not expected to have a material impact
on the Company's results of operations, cash flows or financial condition.
Risks of the Company's Y2K Issues - The applications posing the greatest
business risk to the Company's operations should they experience Y2K problems
are:
Automated power generation, transmission and distribution systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for commercial and
industrial customers and
Work management and billing systems.
The potential problems related to erroneous processing by, or failure of,
these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably likely worst case
Y2K scenario with any degree of certainty, management believes that such
a scenario would be small, localized interruptions of service, which
would be restored.
In addition, although relationships with third parties, such as suppliers,
customers and other electric utilities, are being monitored, these third parties
nonetheless represent a risk that cannot be assessed with precision or
controlled with certainty.
<PAGE>
Due to the complexity of the problem and the interdependent nature of
computer systems, if our corrective actions, and/or the actions of others
who impact the AEP System's operations but are not affiliated with the AEP
System, fail for critical applications, Y2K-related issues may materially
adversely affect the Company.
Company's Contingency Plans - To address possible failures of electric
generation and delivery of electrical energy due to Y2K related failures, we
have established a draft Y2K contingency plan and submitted it to the East
Central Area Reliability Council in December 1998 as part of NERC's review
of regional and individual electric utility contingency plans in 1999.
NERC's target date is June 1999 for the completion of this contingency plan.
In addition, the Company intends to establish contingency plans for
its business units to address alternatives if Y2K related failures occur.
Contingency plans will be developed by the end of 1999.
The Company's plans build upon the disaster recovery, system restoration, and
contingency planning that we have had in place and include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, with key employees on duty
at those locations during the Y2K transition.
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . $90,741 $87,345
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . 19,691 22,301
Purchased Power. . . . . . . . . . . . . . . . . . 24,427 21,211
Other Operation. . . . . . . . . . . . . . . . . . 12,351 10,994
Maintenance. . . . . . . . . . . . . . . . . . . . 4,791 9,166
Depreciation and Amortization. . . . . . . . . . . 7,190 6,910
Taxes Other Than Federal Income Taxes. . . . . . . 2,534 2,492
Federal Income Taxes . . . . . . . . . . . . . . . 4,397 2,180
TOTAL OPERATING EXPENSES . . . . . . . . . 75,381 75,254
OPERATING INCOME . . . . . . . . . . . . . . . . . . 15,360 12,091
NONOPERATING LOSS. . . . . . . . . . . . . . . . . . (114) (71)
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . 15,246 12,020
INTEREST CHARGES . . . . . . . . . . . . . . . . . . 7,037 7,003
NET INCOME . . . . . . . . . . . . . . . . . . . . . $ 8,209 $ 5,017
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . $71,452 $78,076
NET INCOME . . . . . . . . . . . . . . . . . . . . . 8,209 5,017
CASH DIVIDENDS DECLARED. . . . . . . . . . . . . . . 7,443 7,075
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . $72,218 $76,018
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,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . $ 267,282 $ 267,201
Transmission . . . . . . . . . . . . . . . . 327,989 326,989
Distribution . . . . . . . . . . . . . . . . 353,918 351,407
General. . . . . . . . . . . . . . . . . . . 68,259 68,038
Construction Work in Progress. . . . . . . . 31,954 30,076
Total Electric Utility Plant . . . . 1,049,402 1,043,711
Accumulated Depreciation and Amortization. . 322,483 315,546
NET ELECTRIC UTILITY PLANT . . . . . 726,919 728,165
OTHER PROPERTY AND INVESTMENTS . . . . . . . . 15,126 12,078
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . 4,251 1,935
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . 22,919 23,295
Affiliated Companies . . . . . . . . . . . 6,084 8,797
Miscellaneous. . . . . . . . . . . . . . . 3,151 4,019
Allowance for Uncollectible Accounts . . . (930) (848)
Fuel . . . . . . . . . . . . . . . . . . . . 9,895 7,888
Materials and Supplies . . . . . . . . . . . 13,538 13,652
Accrued Utility Revenues . . . . . . . . . . 13,573 13,560
Energy Marketing and Trading Contracts . . . 32,257 4,726
Prepayments. . . . . . . . . . . . . . . . . 1,339 1,657
TOTAL CURRENT ASSETS . . . . . . . . 106,077 78,681
REGULATORY ASSETS. . . . . . . . . . . . . . . 91,785 92,447
DEFERRED CHARGES . . . . . . . . . . . . . . . 8,684 10,476
TOTAL. . . . . . . . . . . . . . . $ 948,591 $ 921,847
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE> KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
1999 1998
(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. . . . . . . . . . . . . . . 148,750 148,750
Retained Earnings. . . . . . . . . . . . . . 72,218 71,452
Total Common Shareholder's Equity. . 271,418 270,652
Long-term Debt . . . . . . . . . . . . . . . 296,089 308,838
TOTAL CAPITALIZATION . . . . . . . . 567,507 579,490
OTHER NONCURRENT LIABILITIES . . . . . . . . . 26,124 26,827
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . 72,797 60,000
Short-term Debt. . . . . . . . . . . . . . . 11,950 20,350
Accounts Payable - General . . . . . . . . . 9,919 12,917
Accounts Payable - Affiliated Companies. . . 13,270 11,814
Customer Deposits. . . . . . . . . . . . . . 3,961 4,038
Taxes Accrued. . . . . . . . . . . . . . . . 12,387 7,256
Interest Accrued . . . . . . . . . . . . . . 8,795 6,241
Energy Marketing and Trading Contracts . . . 32,431 5,089
Other. . . . . . . . . . . . . . . . . . . . 12,505 13,612
TOTAL CURRENT LIABILITIES. . . . . . 178,015 141,317
DEFERRED INCOME TAXES. . . . . . . . . . . . . 158,415 158,706
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . 13,900 14,200
DEFERRED CREDITS . . . . . . . . . . . . . . . 4,630 1,307
CONTINGENCIES (Note 4)
TOTAL. . . . . . . . . . . . . . . $948,591 $921,847
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . $ 8,209 $ 5,017
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . 7,192 6,913
Deferred Federal Income Taxes. . . . . . . . . . (254) 32
Deferred Investment Tax Credits. . . . . . . . . (300) (305)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . 4,039 (5,100)
Fuel, Materials and Supplies . . . . . . . . . . (1,893) 542
Accrued Utility Revenues . . . . . . . . . . . . (13) 2,726
Accounts Payable . . . . . . . . . . . . . . . . (1,542) (6,221)
Taxes Accrued. . . . . . . . . . . . . . . . . . 5,131 2,695
Interest Accrued . . . . . . . . . . . . . . . . 2,554 1,971
Other (net). . . . . . . . . . . . . . . . . . . . 1,519 2,192
Net Cash Flows From Operating Activities . . 24,642 10,462
INVESTING ACTIVITIES - Construction Expenditures . . (6,483) (6,553)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . (8,400) 2,775
Dividends Paid . . . . . . . . . . . . . . . . . . (7,443) (7,075)
Net Cash Flows Used For
Financing Activities . . . . . . . . . . . (15,843) (4,300)
Net Increase (Decrease) in Cash and Cash Equivalents 2,316 (391)
Cash and Cash Equivalents at Beginning of Period . . 1,935 1,381
Cash and Cash Equivalents at End of Period . . . . . $ 4,251 $ 990
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $4,374,000 and
$4,931,000 in 1999 and 1998, respectively. Noncash acquisitions under
capital leases were $568,000 and $1,568,000 in 1999 and 1998, respectively.
See Notes to Financial Statements.
/TABLE
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 1998 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 April 1999 the Company called $13 million of 7.90% First
Mortgage Bonds due 2023 for early redemption in May. Consequently,
the bonds were reclassified as a current liability on the Balance
Sheets.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus
(EITF) 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities". The EITF requires that all energy
trading contracts be marked-to-market. The effect on the Statements
of Income of marking open trading contracts to market is deferred as
regulatory assets or liabilities for those open trading transactions
that are included in cost of service on a settlement basis for
ratemaking purposes. The adoption of the EITF did not have a
material effect on results of operations, cash flows or financial
condition.
4. CONTINGENCIES
As discussed in Note 3, of the Notes to Financial Statements in
the 1998 Annual Report, the deductibility of certain interest
deductions related to American Electric Power's corporate owned life
insurance (COLI) program for taxable years 1992-1996 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 COLI interest deductions through March 31, 1999 would
reduce earnings by approximately $8 million (including interest).
The Company has made no provision for any possible earnings impact
from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years 1992-1997
to avoid the potential assessment by the IRS of any additional above
market rate interest on the contested amount. These payments to the
IRS are included on the Balance Sheets in other property and
investments pending the resolution of this matter. The Company will
seek refund, either administratively or through litigation, of all
amounts paid plus interest.
In order to resolve this issue, the Company filed suit against
the United States in the US District Court for the Southern District
of Ohio in March 1998. Management believes that it has a meritorious
position and will vigorously pursue this lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations.
The Company continues to be involved in certain other matters
discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
FIRST QUARTER 1999 vs. FIRST QUARTER 1998
Net income increased $3.2 million or 64% due to an increase in
sales to retail customers reflecting colder weather.
Income statement line items which changed significantly were:
Increase(Decrease)
(in millions) %
Operating Revenues. . . . . . . . . . . $ 3.4 4
Fuel Expense. . . . . . . . . . . . . . (2.6) (12)
Purchased Power Expense . . . . . . . . 3.2 15
Other Operation Expense . . . . . . . . 1.4 12
Maintenance Expense . . . . . . . . . . (4.4) (48)
Federal Income Taxes. . . . . . . . . . 2.2 102
Operating revenues increased due to a 7% increase in retail sales.
Sales to residential and commercial customers increased 12% and 13%,
respectively, due primarily to colder winter weather.
The decrease in fuel expense is primarily attributable to a decrease
in generation reflecting reduced availability of the Company's Big Sandy
Plant in 1999 due to forced outages.
Purchased power expense increased primarily due to increased energy
purchases and capacity charges from the American Electric Power System
Power Pool (AEP Power Pool). The increase in purchases from the AEP
Power Pool were required to meet increased demand for energy and to
replace power not available due to the Big Sandy Plant and an
affiliate's plant outages. The affiliate, who is not a member of the
AEP Power Pool, has an agreement with the Company to sell a percentage
of its generation to the Company when the affiliate's generation is
available. Under the terms of the AEP Power Pool, capacity credits and
charges are designed to allocate the cost of the AEP System's capacity
among the AEP Power Pool members based on their relative peak demands
and generating reserves. The increase in capacity charges can be
attributed to an increase in the Company's prior twelve month peak
demand relative to the total peak demand of all AEP Power Pool members.
<PAGE>
The increase in other operation expense is due to accrual
adjustments for employee pensions and benefits recorded in 1999 and
1998. The 1999 adjustment was unfavorable while the 1998 adjustment was
favorable.
The decrease in maintenance expense was primarily due to decreased
overhead distribution line maintenance expenditures resulting from
maintenance costs incurred in 1998 to repair and restore customers'
service after winter storm damage.
An increase in pre-tax operating income was the primary cause of the
increase in federal income taxes attributable to operations.
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended
March 31,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . $518,221 $515,672
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 189,163 193,275
Purchased Power. . . . . . . . . . . . . . . . . . . . . . . . 21,273 19,590
Other Operation. . . . . . . . . . . . . . . . . . . . . . . . 85,061 80,901
Maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . 25,490 30,593
Depreciation and Amortization. . . . . . . . . . . . . . . . . 36,785 35,863
Taxes Other Than Federal Income Taxes. . . . . . . . . . . . . 43,853 42,658
Federal Income Taxes . . . . . . . . . . . . . . . . . . . . . 37,640 33,723
TOTAL OPERATING EXPENSES . . . . . . . . . . . . . . . 439,265 436,603
OPERATING INCOME . . . . . . . . . . . . . . . . . . . . . . . . 78,956 79,069
NONOPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . 2,000 1,238
INCOME BEFORE INTEREST CHARGES . . . . . . . . . . . . . . . . . 80,956 80,307
INTEREST CHARGES . . . . . . . . . . . . . . . . . . . . . . . . 20,135 19,871
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,821 60,436
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . . . . . . . . . . . . 367 370
EARNINGS APPLICABLE TO COMMON STOCK. . . . . . . . . . . . . . . $ 60,454 $ 60,066
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended
March 31,
1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . . . . . . . . . . . . $587,500 $590,151
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . 60,821 60,436
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . . . . . . . . . . . . 57,703 52,775
Cumulative Preferred Stock . . . . . . . . . . . . . . . . . 367 370
BALANCE AT END OF PERIOD . . . . . . . . . . . . . . . . . . . . $590,251 $597,442
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,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,677,630 $2,646,597
Transmission . . . . . . . . . . . . . . . . . . . . 845,755 842,318
Distribution . . . . . . . . . . . . . . . . . . . . 954,198 949,224
General (including mining assets). . . . . . . . . . 680,173 689,815
Construction Work in Progress. . . . . . . . . . . . 115,146 129,887
Total Electric Utility Plant . . . . . . . . 5,272,902 5,257,841
Accumulated Depreciation and Amortization. . . . . . 2,493,936 2,461,376
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,778,966 2,796,465
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 230,832 218,311
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 114,785 89,652
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 255,995 215,665
Affiliated Companies . . . . . . . . . . . . . . . 118,333 63,922
Miscellaneous. . . . . . . . . . . . . . . . . . . 41,063 28,139
Allowance for Uncollectible Accounts . . . . . . . (2,290) (1,678)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 117,956 94,914
Materials and Supplies . . . . . . . . . . . . . . . 84,237 86,870
Accrued Utility Revenues . . . . . . . . . . . . . . 39,419 43,501
Energy Marketing and Trading Contracts . . . . . . . 125,927 19,790
Prepayments. . . . . . . . . . . . . . . . . . . . . 47,536 34,523
TOTAL CURRENT ASSETS . . . . . . . . . . . . 942,961 675,298
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 549,597 551,776
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 88,536 102,830
TOTAL. . . . . . . . . . . . . . . . . . . $4,590,892 $4,344,680
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
March 31, December 31,
1999 1998
(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. . . . . . . . . . . . . . . . . . . 462,338 462,335
Retained Earnings. . . . . . . . . . . . . . . . . . 590,251 587,500
Total Common Shareholder's Equity. . . . . . 1,373,790 1,371,036
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 17,357 17,370
Subject to Mandatory Redemption. . . . . . . . . . 11,850 11,850
Long-term Debt . . . . . . . . . . . . . . . . . . . 975,452 1,073,456
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,378,449 2,473,712
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 374,244 360,330
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 98,958 11,472
Short-term Debt. . . . . . . . . . . . . . . . . . . 219,700 123,005
Accounts Payable . . . . . . . . . . . . . . . . . . 242,161 235,787
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 164,425 161,406
Interest Accrued . . . . . . . . . . . . . . . . . . 23,212 14,187
Obligations Under Capital Leases . . . . . . . . . . 28,283 28,310
Energy Marketing and Trading Contracts . . . . . . . 126,567 22,480
Other. . . . . . . . . . . . . . . . . . . . . . . . 92,614 97,916
TOTAL CURRENT LIABILITIES. . . . . . . . . . 995,920 694,563
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 702,248 711,913
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 38,458 39,296
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 101,573 64,866
CONTINGENCIES (Note 4)
TOTAL. . . . . . . . . . . . . . . . . . . $4,590,892 $4,344,680
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,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 60,821 $ 60,436
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . 45,129 43,259
Deferred Federal Income Taxes. . . . . . . . . . . . . . (3,601) 3,466
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . (7,227) (11,000)
Amortization of Deferred Property Taxes. . . . . . . . . 19,426 19,344
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (107,053) (36,126)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (20,409) 21,530
Accrued Utility Revenues . . . . . . . . . . . . . . . . 4,082 2,491
Prepayments. . . . . . . . . . . . . . . . . . . . . . . (13,013) (4,930)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 6,374 (7,222)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 3,019 (3,917)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 9,025 8,771
Operating Reserves . . . . . . . . . . . . . . . . . . . . 17,519 9,548
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 24,364 6,164
Net Cash Flows From Operating Activities . . . . . . 38,456 111,814
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (41,888) (35,186)
Proceeds from Sale of Property and Other . . . . . . . . . 629 2,413
Net Cash Flows Used For Investing Activities . . . . (41,259) (32,773)
FINANCING ACTIVITIES:
Change in Short-term Debt (net). . . . . . . . . . . . . . 96,695 88,800
Retirement of Cumulative Preferred Stock . . . . . . . . . (10) -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (10,679) (75,237)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (57,703) (52,775)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (367) (370)
Net Cash Flows From (Used For) Financing Activities. 27,936 (39,582)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 25,133 39,459
Cash and Cash Equivalents at Beginning of Period . . . . . . 89,652 44,203
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 114,785 $ 83,662
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $10,562,000 and $10,377,000
and for income taxes was $2,219,000 and $539,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $5,634,000 and $10,294,000 in
1999 and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
MARCH 31, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial
statements should be read in conjunction with the 1998 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 April 1999 the Company called $88 million of first
mortgage bonds, $40 million of 7.85% series due 2023, $40
million of 6.875% series due 2003 and $8 million of 6.55%
series due 2003, for early redemption in May. Consequently,
the bonds were reclassified as a current liability on the
Consolidated Balance Sheets.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the
Financial Accounting Standards Board's Emerging Issues Task
Force Consensus (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities". The
EITF requires that all energy trading contracts be marked-to-market.
The effect on the Consolidated Statements of Income
of marking open trading contracts to market is deferred as
regulatory assets or liabilities for those open trading
transactions that are included in cost of service on a
settlement basis for ratemaking purposes. The adoption of the
EITF did not have a material effect on results of operations,
cash flows or financial condition.
4. CONTINGENCIES
As discussed in Note 4, of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the
deductibility of certain interest deductions related to
American Electric Power's corporate owned life insurance (COLI)
program for taxable years 1991-1996 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 COLI interest deductions through March 31,
1999 would reduce earnings by approximately $117 million
(including interest). The Company has made no provision for
any possible earnings impact from this matter.
<PAGE>
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1997 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
These payments to the IRS are included on the Consolidated
Balance Sheets in other property and investments pending the
resolution of this matter. The Company will seek refund,
either administratively or through litigation, of all amounts
paid plus interest.
In order to resolve this issue, the Company filed suit
against the United States in the US District Court for the
Southern District of Ohio in March 1998. Management believes
that it has a meritorious position and will vigorously pursue
this lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations.
The Company continues to be involved in certain other
matters discussed in the 1998 Annual Report.
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
FIRST QUARTER 1999 vs. FIRST QUARTER 1998
RESULTS OF OPERATIONS
Net income was virtually unchanged as operating income was
static reflecting flat operating revenues and steady operating
expenses.
Income statement line items which changed significantly were:
Increase (Decrease)
(in millions) %
Fuel Expense . . . . . . . . . . . . . $(4.1) (2)
Other Operation Expense. . . . . . . . 4.2 5
Maintenance Expense. . . . . . . . . . (5.1) (17)
Federal Income Taxes . . . . . . . . . 3.9 12
The decrease in fuel expense is primarily due to a decrease in
the average cost of fuel consumed.
Other operation expense increased due to accrual adjustments
related to incentive compensation payments made in the first
quarter. The 1999 adjustment was unfavorable and the 1998
adjustment was favorable.
The decrease in maintenance expense was primarily due to a
reduction in scheduled boiler plant maintenance at the Company's
generating plants in 1999.
The increase in federal income taxes attributable to operations
is primarily due to an increase in pre-tax operating income and
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 $48 million. Short-term debt increased by
$97 million from the beginning of 1999.
In April 1999 the Company called $88 million of first mortgage
bonds, $40 million of 7.85% series due 2023, $40 million of 6.875%
series due 2003 and $8 million of 6.55% series due 2003, for early
redemption in May. Consequently, the bonds were reclassified as a
current liability on the Consolidated Balance Sheets.<PAGE>
OTHER MATTERS
Market Risks
The Company has certain market risks inherent in its business
activities 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, 1998. Market risk represents the
risk of loss that may impact the Company due to adverse changes in
commodity market prices and interest rates.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at March 31, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date. In
addition, certain systems may fail to detect that the year 2000 is
a leap year. Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur. This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery. Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations. In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The Company, along with other electric utilities in North America,
regularly submits information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reports summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities. AEP participated in an industry-wide NERC-sponsored
drill on April 9, 1999 simulating the partial loss of voice and
data communications. There were no major problems encountered with
relaying information with the use of backup telecommunications
systems. AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.
The NERC report, dated April 30, 1999 and entitled: Preparing
the Electric Power Systems of North America for Transition to the
Year 2000 - A Status Report and Work Plan, First Quarter 1999,
states that: "With more than 75% of mission critical components
tested through March 31, 1999, findings in the field continue to
indicate that the transition through critical Y2K dates is expected
to have minimal impact on electric system operations in North
America." The report also indicates that, "the risk of electrical
outages by Y2K appears to be no higher than the risks we already
experience" from incidents such as severe wind, ice, floods,
equipment failures and power shortages during an extremely hot or
cold period.
Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
<PAGE>
Company's State of Readiness - Work has been prioritized in
accordance with business risk. The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
The following chart shows our progress toward becoming ready
for the Y2K as of March 31, 1999:
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
Launch: Initiation of 2/24/1998 100% 5/31/1998 100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999 100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe: 6/30/1999* 65%
replacing or retiring 94%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 56%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
*The Company is upgrading its 800 MHz trunked radio system, a mission critical
non-IT system, for Y2K readiness and it is anticipated that the upgrade should
be complete by September 30, 1999.
<PAGE>
The Company continues to make steady progress toward the June
30, 1999 target date and anticipates completing the
remediation/testing work for mission critical and high-priority
systems by the June 30, 1999 target date except as noted in the
table.
Costs to Address the Company's Year 2000 Issues - Through March 31,
1999, the Company has spent $8 million on the Year 2000 project
and, estimates spending an additional $9 million to $12 million to
achieve Y2K readiness. Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized. The Company intends to fund these expenditures
through internal sources. Although significant, the cost of
becoming Y2K compliant is not expected to have a material impact on
the Company's results of operations, cash flows or financial
condition.
Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
Automated power generation, transmission and distribution systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for commercial
and industrial customers and
Work management and billing systems.
The potential problems related to erroneous processing by, or
failure of, these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues may materially adversely affect the Company.
Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a draft Y2K contingency plan
and submitted it to the East Central Area Reliability Council in
December 1998 as part of NERC's review of regional and individual
electric utility contingency plans in 1999. NERC's target date is
June 1999 for the completion of this contingency plan. In
addition, the Company intends to establish contingency plans for
its business units to address alternatives if Y2K related failures
occur. Contingency plans will be developed by the end of 1999.
The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, with key employees
on duty at those locations during the Y2K transition.
<PAGE>
<PAGE>
PART II. OTHER INFORMATION
Item 5. Other Information.
American Electric Power Company, Inc. ("AEP") and Appalachian Power
Company ("APCo")
Reference is made to pages 17 and 18 of the Annual Report on
Form 10-K for the year ended December 31, 1998 ("1998 10-K") for a
discussion of APCo's proposed transmission facilities. On May 7,
1999, APCo filed its report on the Wyoming-Jacksons Ferry 765kV
line with the State Corporation Commission of Virginia as requested
by the Hearing Examiner in September 1998. The report states that
the Wyoming-Jacksons Ferry line would cost approximately
$232,000,000 and recommends the use of a 90-mile long corridor.
The revised estimated cost for the Wyoming-Cloverdale line is
$283,000,000.
AEP, AEP Generating Company ("AEGCo"), 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 pages 30 and 31 of the 1998 10-K for a
discussion of the NOx SIP Call issued by the U.S. Environmental
Protection Agency ("Federal EPA") and the Section 126 petitions
filed by eight northeastern states. In April 1999, the states of
Maryland and New Jersey also filed Section 126 petitions.
On April 30, 1999, Federal EPA took final action with respect
to the Section 126 petitions filed by the eight northeastern
states. Federal EPA determined that six of the eight petitions
were partially approvable, thus triggering a determination that the
coal-fired generating plants in upwind states (including those of
the AEP System) would be subject to a 0.15 lbs. of NOx per million
Btu of heat input emission rate. This emission rate will become
effective if the states in which the sources are located do not
submit an approvable State Implementation Plan by September 30,
1999 and if Federal EPA elects not to adopt a Federal
Implementation Plan by November 30, 1999.
Reference is made to pages 31 and 32 of the 1998 10-K for a
discussion of global climate change. As of April 9, 1999, 84
countries have signed the Kyoto Protocol and 8 countries have
ratified it.
<PAGE>
Reference is made to page 33 of the 1998 10-K for a discussion
of a request issued to AEP under Section 114 of the Clean Air Act
focused on assessing compliance with the New Source Review and
Performance Standard provisions. In April 1999, Federal EPA,
Regions III and V, issued additional requests seeking
identification of personnel at Sporn, Mitchell and Muskingum River
plants having knowledge of plant operations, including production,
maintenance and staff functions. Federal EPA has also requested
information regarding projects at Tanners Creek Plant.
AEP and OPCo
Reference is made to page 42 of the 1998 10-K for a discussion
of litigation with Ormet Corporation involving the ownership of
sulfur dioxide allowances. On March 25, 1999, Ormet appealed the
March 1999 District Court's decision to the U.S. Court of Appeals
for the Fourth Circuit. The District Court decision had granted
summary judgment to OPCo and the AEP Service Corporation.
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, 1999.
<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 12, 1999
II-3
<TABLE>
EXHIBIT 12
INDIANA MICHIGAN POWER COMPANY
Computation of Consolidated Ratio of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Twelve
Months
Year Ended December 31, Ended
1994 1995 1996 1997 1998 3/31/99
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . $ 43,564 $ 43,410 $ 41,209 $ 39,678 $ 35,910 $ 34,926
Interest on Other Long-term Debt. . . 24,725 23,564 20,100 21,064 27,457 30,509
Interest on Short-term Debt . . . . . 1,883 2,003 2,982 3,248 4,903 4,559
Miscellaneous Interest Charges. . . . 3,520 3,472 3,262 3,187 3,113 5,999
Estimated Interest Element in
Lease Rentals . . . . . . . . . . . 85,000 82,700 82,600 79,700 79,300 79,300
Total Fixed Charges. . . . . . . $158,692 $155,149 $150,153 $146,877 $150,683 $155,293
Earnings:
Net Income. . . . . . . . . . . . . . $157,502 $141,092 $157,153 $146,740 $ 96,628 $ 82,954
Plus Federal Income Taxes . . . . . . 32,303 55,990 76,899 74,223 47,210 42,167
Plus State Income Taxes . . . . . . . 6,063 7,058 9,270 7,519 4,938 7,371
Plus Fixed Charges (as above) . . . . 158,692 155,149 150,153 146,877 150,683 155,293
Total Earnings . . . . . . . . . $354,560 $359,289 $393,475 $375,359 $299,459 $287,785
Ratio of Earnings to Fixed Charges. . . 2.23 2.31 2.62 2.55 1.98 1.85
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000050172
<NAME> INDIANA MICHIGAN POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,546,405
<OTHER-PROPERTY-AND-INVEST> 880,549
<TOTAL-CURRENT-ASSETS> 389,749
<TOTAL-DEFERRED-CHARGES> 40,737
<OTHER-ASSETS> 493,496
<TOTAL-ASSETS> 4,350,936
<COMMON> 56,584
<CAPITAL-SURPLUS-PAID-IN> 732,639
<RETAINED-EARNINGS> 243,346
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,032,569
68,445
9,266
<LONG-TERM-DEBT-NET> 1,030,093
<SHORT-TERM-NOTES> 725
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 109,570
<LONG-TERM-DEBT-CURRENT-PORT> 148,000
0
<CAPITAL-LEASE-OBLIGATIONS> 178,698
<LEASES-CURRENT> 10,681
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,762,889
<TOT-CAPITALIZATION-AND-LIAB> 4,350,936
<GROSS-OPERATING-REVENUE> 334,113
<INCOME-TAX-EXPENSE> 14,718
<OTHER-OPERATING-EXPENSES> 280,557
<TOTAL-OPERATING-EXPENSES> 295,275
<OPERATING-INCOME-LOSS> 38,838
<OTHER-INCOME-NET> 1,735
<INCOME-BEFORE-INTEREST-EXPEN> 40,573
<TOTAL-INTEREST-EXPENSE> 20,503
<NET-INCOME> 20,070
1,214
<EARNINGS-AVAILABLE-FOR-COMM> 18,856
<COMMON-STOCK-DIVIDENDS> 28,664
<TOTAL-INTEREST-ON-BONDS> 8,576
<CASH-FLOW-OPERATIONS> 71,853
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
