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 SEPTEMBER 30, 1998
[ ] 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
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet
the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in General
Instruction H(2) to Form 10-Q.
Indicate by check mark whether the registrants (1) have filed all reports required to be
filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrants were required to file such
reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes X No
The number of shares outstanding of American Electric Power Company, Inc. Common Stock,
par value $6.50, at October 31, 1998 was 191,348,743.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 30, 1998
INDEX
<CAPTION>
Page
Part I. FINANCIAL INFORMATION
<S> <C>
American Electric Power Company, Inc. and Subsidiary Companies:
Consolidated Statements of Income. . . . . . . . . . . . . . A-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
Consolidated Statements of Retained Earnings . . . . . . . . A-5
Notes to Consolidated Financial Statements . . . . . . . . . A-6 - A-12
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . A-13- A-25
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-9
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . C-10- C-19
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-8
Management's Narrative Analysis of Results of Operations . . D-9 - D-10
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-10
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . E-11- E-23
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-8
Management's Narrative Analysis of Results of Operations . . F-9 - F-10
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 30, 1998
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-8
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . G-9 - G-18
Part II. OTHER INFORMATION
Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4
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 thousands, except per-share amounts)
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $4,638,133 $1,583,994 $9,546,566 $4,458,221
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 463,012 421,815 1,307,198 1,192,434
Purchased Power. . . . . . . . . . . . 2,982,625 100,961 5,015,690 156,917
Other Operation. . . . . . . . . . . . 365,563 302,307 968,011 904,892
Maintenance. . . . . . . . . . . . . . 130,710 123,781 376,158 347,894
Depreciation and Amortization. . . . . 145,315 144,342 433,584 447,843
Taxes Other Than Federal Income Taxes. 124,602 123,943 370,933 372,723
Federal Income Taxes . . . . . . . . . 114,727 91,755 280,291 267,195
TOTAL OPERATING EXPENSES . . . 4,326,554 1,308,904 8,751,865 3,689,898
OPERATING INCOME . . . . . . . . . . . . 311,579 275,090 794,701 768,323
NONOPERATING INCOME (LOSS) . . . . . . . (6,274) 32,835 (5,572) 43,030
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS. . . . . . . . . . 305,305 307,925 789,129 811,353
INTEREST CHARGES . . . . . . . . . . . . 107,153 103,378 316,938 300,851
PREFERRED STOCK DIVIDEND REQUIREMENTS
OF SUBSIDIARIES. . . . . . . . . . . . 2,787 2,801 8,155 15,056
INCOME BEFORE EXTRAORDINARY ITEM . . . . 195,365 201,746 464,036 495,446
EXTRAORDINARY ITEM - U. K. WINDFALL TAX. - (110,565) - (110,565)
NET INCOME . . . . . . . . . . . . . . . $ 195,365 $ 91,181 $ 464,036 $ 384,881
AVERAGE NUMBER OF SHARES OUTSTANDING . . 190,996 189,287 190,538 188,819
EARNINGS PER SHARE:
Before Extraordinary Item . . . . . . . $1.02 $1.07 $2.44 $2.62
Extraordinary Item - U. K. Windfall Tax - (0.59) - (0.58)
Net Income. . . . . . . . . . . . . . . $1.02 $0.48 $2.44 $2.04
CASH DIVIDENDS PAID PER SHARE. . . . . . $0.60 $0.60 $1.80 $1.80
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $ 9,560,684 $ 9,493,158
Transmission . . . . . . . . . . . . . . . . . . . . 3,572,360 3,501,580
Distribution . . . . . . . . . . . . . . . . . . . . 4,749,050 4,654,234
General (including mining assets and nuclear fuel) . 1,603,876 1,604,671
Construction Work in Progress. . . . . . . . . . . . 460,591 342,842
Total Electric Utility Plant . . . . . . . . 19,946,561 19,596,485
Accumulated Depreciation and Amortization. . . . . . 8,290,285 7,963,636
NET ELECTRIC UTILITY PLANT . . . . . . . . . 11,656,276 11,632,849
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 1,852,341 1,356,504
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 147,894 91,481
Accounts Receivable. . . . . . . . . . . . . . . . . 852,460 674,278
Allowance for Uncollectible Accounts . . . . . . . . (10,796) (6,760)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 195,539 224,967
Materials and Supplies . . . . . . . . . . . . . . . 278,825 263,613
Accrued Utility Revenues . . . . . . . . . . . . . . 190,425 189,191
Energy Marketing and Trading Contracts . . . . . . . 185,354 2,306
Prepayments and Other. . . . . . . . . . . . . . . . 81,259 81,366
TOTAL CURRENT ASSETS . . . . . . . . . . . . 1,920,960 1,520,442
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 1,820,407 1,817,540
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 226,263 288,011
TOTAL. . . . . . . . . . . . . . . . . . . $17,476,247 $16,615,346
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock-Par Value $6.50:
1998 1997
Shares Authorized . . . .600,000,000 300,000,000
Shares Issued . . . . . .200,335,149 198,989,981
(8,999,992 shares were held in treasury) . . . . . $ 1,302,178 $ 1,293,435
Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,832,744 1,778,782
Retained Earnings. . . . . . . . . . . . . . . . . . 1,726,249 1,605,017
Total Common Shareholders' Equity. . . . . . 4,861,171 4,677,234
Cumulative Preferred Stocks of Subsidiaries:
Not Subject to Mandatory Redemption. . . . . . . . 46,257 46,724
Subject to Mandatory Redemption. . . . . . . . . . 127,605 127,605
Long-term Debt . . . . . . . . . . . . . . . . . . . 5,408,997 5,129,463
TOTAL CAPITALIZATION . . . . . . . . . . . . 10,444,030 9,981,026
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,373,685 1,246,537
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 90,793 294,454
Short-term Debt. . . . . . . . . . . . . . . . . . . 535,408 555,075
Accounts Payable . . . . . . . . . . . . . . . . . . 460,917 353,256
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 299,784 380,771
Interest Accrued . . . . . . . . . . . . . . . . . . 105,966 76,361
Obligations Under Capital Leases . . . . . . . . . . 103,984 101,089
Energy Marketing and Trading Contracts . . . . . . . 180,689 1,983
Other. . . . . . . . . . . . . . . . . . . . . . . . 503,122 322,687
TOTAL CURRENT LIABILITIES. . . . . . . . . . 2,280,663 2,085,676
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,552,084 2,560,921
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 359,005 376,250
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 224,362 231,320
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 242,418 133,616
CONTINGENCIES (Note 7)
TOTAL. . . . . . . . . . . . . . . . . . . $17,476,247 $16,615,346
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 464,036 $ 384,881
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 462,843 455,494
Deferred Federal Income Taxes. . . . . . . . . . . . . . 34,486 (35,566)
Deferred Investment Tax Credits. . . . . . . . . . . . . (17,245) (17,510)
Amortization of Deferred Property Taxes. . . . . . . . . 135,324 132,251
Amortization of Operating Expenses and
Carrying Charges (net) . . . . . . . . . . . . . . . . 11,850 24,356
Extraordinary Loss - U.K. Windfall Tax . . . . . . . . . - 110,565
Deferred Costs Under Fuel Clause Mechanisms. . . . . . . (58,903) (22,393)
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (174,146) (42,336)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 14,216 10,353
Accrued Utility Revenues . . . . . . . . . . . . . . . . (1,234) 25,564
Accounts Payable . . . . . . . . . . . . . . . . . . . . 107,661 1,442
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (80,987) (153,434)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 29,605 36,919
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 54,554 (1,933)
Other Current Assets and Liabilities . . . . . . . . . . 124,541 79,056
Payment of Disputed Tax and Interest Related to COLI . . . (302,739) -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 41,533 (21,714)
Net Cash Flows From Operating Activities . . . . . . 845,395 965,995
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (557,284) (496,155)
Investment in Yorkshire Electricity Group plc. . . . . . . - (361,795)
Other Investments. . . . . . . . . . . . . . . . . . . . . (9,968) (7,241)
Proceeds from Sale of Property . . . . . . . . . . . . . . 8,596 9,733
Net Cash Flows Used For Investing Activities . . . . (558,656) (855,458)
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . 62,897 58,045
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 617,656 776,441
Retirement of Cumulative Preferred Stock . . . . . . . . . (346) (433,234)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (548,062) (325,931)
Change in Short-term Debt (net). . . . . . . . . . . . . . (19,667) 188,055
Dividends Paid on Common Stock . . . . . . . . . . . . . . (342,804) (339,685)
Net Cash Flows Used For Financing Activities . . . . (230,326) (76,309)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 56,413 34,228
Cash and Cash Equivalents at Beginning of Period . . . . . . 91,481 57,539
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 147,894 $ 91,767
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $278,733,000 and $253,884,000
and for income taxes was $149,712,000 and $290,682,000 in 1998 and 1997, respectively.
Noncash acquisitions under capital leases were $93,823,000 and $171,947,000 in
1998 and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD . . . . . $1,645,466 $1,615,039 $1,605,017 $1,547,746
NET INCOME . . . . . . . . . . . . . . . 195,365 91,181 464,036 384,881
DEDUCTIONS:
Cash Dividends Declared. . . . . . . . 114,583 113,515 342,804 339,685
Other. . . . . . . . . . . . . . . . . (1) - - 237
BALANCE AT END OF PERIOD . . . . . . . . $1,726,249 $1,592,705 $1,726,249 $1,592,705
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments
should be read in conjunction with the 1997 Financial
Statements and Management's Discussion and Analysis of Results
of Operations and Financial Condition as incorporated in and
filed with the Form 10-K. In the opinion of management, the
financial statements reflect all adjustments (consisting of
only normal recurring accruals) which are necessary for a fair
presentation of the results of operations and financial
condition for interim periods.
2. FINANCING AND RELATED ACTIVITIES
During the first nine months of 1998, subsidiaries issued
$452 million of senior unsecured notes: two series totaling
$112 million at 6.51% and 6.55% due in 2008 and three series
totaling $340 million at 7.20%, 7.30% and 7-3/8% due in 2038;
$125 million of 7.60% junior subordinated deferrable interest
debentures due in 2038; and increased their outstanding balance
under a revolving credit agreement by $15 million.
The proceeds from the above financings were used during
1998 to retire: $472 million of first mortgage bonds with
interest rates ranging from 6-3/4% to 9.15% due from 1998 to
2023; $25 million of variable rate installment purchase
contracts due in 2025; a $16.7 million term loan with an
interest rate of 6.85% at maturity; and $10 million of a
variable rate term loan due in 1999.
As a result of the redemption of the 6-3/4% series first
mortgage bonds due in 1998, the restriction on the use of
retained earnings for the payment of common stock dividends was
reduced to $6 million.
3. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in
the first quarter of 1998. SFAS No. 130 established the
standards for reporting and displaying components of
"comprehensive income," which is the total of net income and
all transactions not included in net income affecting equity
except those with shareholders. For the quarter and year-to-date
periods ended September 30, 1998, there were no material
differences between comprehensive income and net income.
<PAGE>
<PAGE>
In the first quarter of 1998 the Company adopted the
American Institute of Certified Public Accountants' Statement
of Position (SOP) 98-1, "Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use". The SOP
requires the capitalization and amortization of certain costs
of acquiring or developing internal use computer software.
Previously the Company expensed all software acquisition and
development costs. The SOP must be adopted at the beginning
of a fiscal year with no restatement or retroactive adjustment
of prior periods. The adoption of the SOP effective January
1, 1998 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 which is accounted for using the equity method.
The Company's share of Yorkshire earnings are included in
nonoperating income. The following amounts which are not
included in AEP's consolidated financial statements represent
summarized consolidated financial information of Yorkshire
Power Group Limited for the quarter and nine months ended
September 30, 1998:
Quarter Year-to-Date
(in millions)
Income Statement Data:
Operating Revenues $510.2 $1,677.3
Operating Income 82.6 264.8
Net Income 21.5 13.6
5. ENERGY MARKETING AND TRADING
During 1998, the Company substantially increased the volume
of its electricity and gas marketing and trading. The purpose
of the marketing and trading business is to utilize the
Company's knowledge of the energy markets in order to improve
the competitiveness of its generation business and contribute
to net income, thereby enhancing both customer and shareholder
value.
The electricity and gas marketing and trading business
involves the marketing of energy under physical forward
contracts at fixed and variable prices and the trading of
options, futures, swaps and other financial derivative
contracts at both fixed and variable prices. Most contracts
represent physical forward electricity marketing contracts for
the purchase and sale of electricity in the Company's
traditional marketing area which are recorded as operating
revenues and purchased power expense when the contracts
settle. At September 30, 1998, the Company had open marketing
contracts, not on the balance sheet, in its traditional
marketing area through the year 2004 to sell electricity with
a notional value of approximately $1.1 billion and to purchase
electricity with a notional value of approximately $1.1
<PAGE>
billion.
The Company has also purchased and sold electricity and gas
options, futures and swaps, and entered into forward purchase
and sale contracts for the future delivery or receipt of
electricity and gas outside its traditional marketing area.
These transactions represent non-regulated trading activities
that are marked-to-market and recorded in nonoperating income.
The unrealized mark-to-market gains and losses from such
trading activity are reported as assets and liabilities,
respectively. At September 30, 1998, the Company has open
marketing contracts outside its traditional marketing area
through the year 2008 to sell electricity and gas with a
notional value of approximately $755 million and to purchase
electricity and gas with a notional value of approximately $585
million.
Dependent on future electricity and gas market conditions
these activities could produce material income or losses in
future periods.
6. PROPOSED MERGER AND ACQUISITION
As discussed in the Management's Discussion and Analysis
of Results of Operations and Financial Condition in the 1997
annual report and the Joint Proxy Statement/Prospectus dated
April 16, 1998, the Company and Central and South West
Corporation (CSW) have agreed to merge. At the May 1998 annual
meeting, AEP shareholders approved the issuance of AEP common
shares to effect the merger and approved an increase in the
authorized shares of AEP Common Stock from 300,000,000 to
600,000,000. CSW stockholders approved the merger at their May
1998 annual meeting. The companies have filed for necessary
approvals to merge with the Federal Energy Regulatory
Commission (FERC), the Securities and Exchange Commission, the
Nuclear Regulatory Commission (NRC) and all of CSW's state
regulatory commissions: Arkansas, Louisiana, Oklahoma and
Texas. Filings with the Federal Communications Commission and
the Department of Justice are expected to be made before the
end of 1998. The Company's target consummation date for the
merger is the second quarter of 1999.
In August 1998 the Arkansas Public Service Commission
approved the merger, subject to a number of conditions
including the approval of a regulatory plan for sharing net
merger savings. On November 3, 1998 the Company, CSW and CSW's
Arkansas operating subsidiary, Southwestern Electric Power
Company, filed a settlement agreement for approval with the
Arkansas Public Service Commission outlining a regulatory plan,
agreed to with the Commission staff, which provides for a
sharing of net merger savings through a reduction of rates for
Arkansas retail customers.
<PAGE>
<PAGE>
In October 1998 the Oklahoma Corporation Commission (OCC)
approved plans by AEP and CSW to submit an amended filing
seeking approval of the proposed merger. The amended
application is being made as a result of an Oklahoma
administrative law judge's recommendation that the merger
filing be dismissed without prejudice for lack of information
regarding the potential impact of the merger on the retail
electric market in Oklahoma. Submission of the amended
application will reset Oklahoma's 90-day statutory time period
for OCC action on the merger phase of the application. The
filing of the amended application should not affect the timing
of the merger closing.
In July 1998 the FERC issued an order which confirmed that
the 250 megawatt firm contract path with the Ameren System is
available. The contract path is required for AEP and CSW to
meet the requirements of the Public Utility Holding Company Act
of 1935 that the two systems operate on an integrated and
coordinated basis. On November 10, 1998, the FERC issued an
order establishing hearing procedures for the merger. A
scheduling conference will be held in November 1998. The 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. The outcome of the FERC scheduling conference could
extend the targeted completion date of the merger.
A settlement agreement between AEP, CSW and certain key
parties to the Texas merger proceeding has been reached. The
staff of the Public Utility Commission of Texas was not a
signatory to the settlement agreement, which resolves all
issues for the signing parties. The settlement provides for,
among other things, the approval of rate reductions to share
net merger savings and settle existing rate reviews.
The application by CSW's operating subsidiary, Central
Power and Light Company, to the NRC requesting permission to
transfer control of the license for the South Texas Project
nuclear generating station to AEP was approved by the NRC.
AEP has a 50% interest in Yorkshire Electricity Group, plc
and CSW has a 100% interest in Seeboard, plc, two United
Kingdom (U.K.) regional electricity companies (RECs). The
proposed merger of CSW into AEP would result in common
ownership of these U.K. entities. As a result, the common
ownership of two U.K. RECs could be referred by the U.K.
Secretary of State for Trade and Industry to the U.K. Mergers
and Monopolies Commission for investigation.
<PAGE>
<PAGE>
The merger, which is to be accounted for as a pooling of
interests, is conditioned upon, among other things, the
approval of the above state and federal regulatory agencies.
The transaction must satisfy many conditions, including the
condition that it must be a pooling, and some of these
conditions may not be waived by the parties. The Company is
unable to predict the outcome or the timing of the required
regulatory proceedings.
In September 1998 the Company and Equitable Resources, Inc.
signed a definitive agreement for the Company to purchase
Equitable's natural gas midstream assets and operations for
approximately $320 million. The purchase includes an
intrastate pipeline system, five natural gas processing plants,
one natural gas storage facility and an energy trading
business. The transaction is expected to close in the fourth
quarter of 1998 and be accounted for as a purchase.
7. CONTINGENCIES
Taxes
As discussed in Note 10, "Federal Income Taxes", of the
Notes to Consolidated Financial Statements in the 1997
Financial Statements and Management's Discussion and Analysis
of Results of Operations and Financial Condition, the Internal
Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating
to corporate owned life insurance (COLI) claimed by the Company
should not be allowed. As a result of a suit filed in United
States District Court (discussed below) this request for ruling
has been withdrawn. Adjustments have been or will be proposed
by the IRS disallowing COLI interest deductions for taxable
years 1991-96. A disallowance of the COLI interest deductions
through September 30, 1998 would reduce earnings by
approximately $310 million (including interest). The Company
has made no provision for any possible adverse earnings impact
from this matter.
In order to resolve this issue without further delay, on
March 24, 1998, the Company filed suit against the United
States in the United States District Court for the Southern
District of Ohio. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit.
In July 1998 the Company made a payment of taxes and interest
attributable to COLI interest deductions for taxable years
1991-96 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
In September 1998 the Company made an additional payment for
the 1997 tax year. The payments were included on the balance
sheet 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.
In the event the resolution of this matter is unfavorable, it
<PAGE>
will have a material adverse impact on results of operations
and cash flows.
Cook Nuclear Plant Shutdown
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1997 Financial Statements and
Management's Discussion and Analysis of Results of Operations
and Financial Condition, both units of the Cook Nuclear Plant
were shut down by Indiana Michigan Power Company (I&M) 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 I&M to address the
issues identified in the letter. I&M is working with the NRC
to resolve the one remaining issue in the letter.
On April 17, 1998, the NRC notified I&M that it had
convened a Restart Panel for Cook Plant. On July 30, 1998, I&M
received a letter from the NRC providing the NRC's list of
required restart activities. I&M is and will be meeting with
the Panel on a regular basis, until the Cook Plant units are
returned to service, to identify and address the items that
need to be addressed in order to restart the units. When
maintenance and other activities required for restart are
complete, I&M will seek concurrence from the NRC to return the
Cook Plant to service.
I&M's current restart schedule indicates Unit 1 is expected
to return to service by the end of the first quarter of 1999.
The restart schedule for Unit 2 has not been completed;
however, management anticipates that Unit 2 may return to
service 90 days after Unit 1. If the units are not returned
to service, there could be a material adverse effect on
financial condition.
The incremental cost expected to be incurred to restart the
Cook units is approximately $70 million for 1998, of which $34
million has been incurred through September 30, 1998. However,
approximately $20 million of previously budgeted work for 1998
at the Cook Plant will not be incurred and will partially
mitigate the incremental restart costs. The cost and schedule
for the outage during 1999 could be significantly impacted if
additional work is identified beyond the $35 million planned
for the first quarter.
On July 24, 1998, I&M received an "adverse trend letter"
from the NRC indicating that NRC senior managers had determined
that there had been a slow decline in performance at the Cook
Plant during the 18 month period preceding the letter. The
letter indicated that the NRC will closely monitor efforts to
address issues at Cook Plant through additional inspection
activities.
<PAGE>
<PAGE>
In a letter dated October 13, 1998, the NRC issued to I&M
a Notice of Violation and a proposed $500,000 civil penalty for
alleged violations at the Cook Plant discovered during five
inspections conducted between August 4, 1997 and April 15,
1998. I&M paid the penalty.
The cost of electricity supplied to I&M's retail customers
rose due to the outage of the two units since higher cost coal-fired
generation and purchased power were substituted for low
cost nuclear generation. In the Indiana and Michigan retail
jurisdictions 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 the 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 as was the case with regard to the Cook
outage, a regulatory asset is recorded and revenues are
accrued.
Due to the unscheduled Cook Plant outage, I&M's actual fuel
costs significantly exceeded the estimated fuel costs reflected
in its fuel cost adjustment factors. A regulatory asset has
been recorded for revenues accrued in anticipation of future
reconciliation and billing of the higher fuel costs to
customers. At September 30, 1998, the regulatory asset was $61
million.
The Indiana Utility Regulatory Commission approved two
agreements authorizing I&M during the billing months of July
through December 1998 to apply a fuel cost adjustment factor
less than that requested by I&M, subject to future
reconciliation or refund. The agreements provide the parties
to the proceedings with the opportunity to conduct discovery
regarding certain issues that were raised in the proceedings,
including the appropriateness of recovery of replacement energy
cost due to the extended Cook Plant outage, in anticipation of
resolving the issues in a future fuel cost adjustment
proceeding. Management believes that it should be able to
recover the Cook replacement energy costs; however, if recovery
of the replacement costs is denied, results of operations and
cash flows would be adversely affected.
Revised Air Quality Standards
The United States Environmental Protection Agency (Federal
EPA) published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state
implementation plans (SIPs). SIPs are a procedural method used
by each state to comply with Federal EPA rules. Eight
northeastern states also filed petitions in 1997 with Federal
<PAGE>
EPA claiming NOx emissions from plants in midwestern states prevent
them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states,
including the states in which the Company's generating plants
are located. The implementation of the final rules would be
achieved through the revision of SIPs by September 1999 that,
by the year 2003, anticipate the imposition of a NOx reduction
on utility sources of approximately 85% below 1990 emission
levels. On October 30, 1998, a number of utilities, including
the operating companies of the AEP System, filed a petition in
the U.S. Court of Appeals for the District of Columbia Circuit
seeking a review of the final rules.
Should the states fail to adopt the required revisions to
their SIPs within one year of the date of the final rules
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions. Federal EPA
also proposed the approval of portions of the petitions filed
by the eight northeastern states that would result in
imposition of NOx emission reductions on utility and industrial
sources. These reductions are substantially the same as those
required by the final rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance
with the final rules.
Based on initial studies, preliminary estimates indicate
that compliance costs could result in required capital
expenditures by the Company of approximately $1.2 billion.
Compliance costs can not be estimated with certainty and the
actual costs incurred to comply could be significantly
different from the preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions. Unless such costs are recovered from customers,
they would have 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 1997 Financial Statements and
Management's Discussion and Analysis of Results of Operations
and Financial Condition.
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
Net income increased by $104.2 million or 114% for the quarter
and $79.2 million or 21% for the year-to-date period due
predominantly to the effect of an extraordinary loss from a United
Kingdom (U.K.) one-time windfall tax enacted during the third
quarter of 1997 and a significant increase in net revenues from
energy sales due to favorable weather and energy marketing and
trading activities within AEP's traditional marketing area. The
windfall tax was based on a revision or recomputation of the
original 1990 privatization value of certain privatized regional
electric companies in the U.K. including Yorkshire Electricity
Group. Income before extraordinary item decreased $6.4 million for
the third quarter and $31.4 million for the year-to-date period as
a result of a write-down of Yorkshire Electricity Group's
investment in Ionica, a U.K. telecommunications company,
expenditures to prepare the Cook Plant for restart following an
extended outage and certain losses on energy trades outside of
AEP's traditional marketing area.
The significant changes in income statement line items and net
revenues were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $3,054.1 193 $5,088.3 114
Fuel Expense . . . . . . . 41.2 10 114.8 10
Purchased Power Expense. . 2,881.7 N.M. 4,858.8 N.M.
Net Revenues . . . . . . 131.2 114.7
Other Operation Expense. . 63.3 21 63.1 7
Maintenance Expense. . . . 6.9 6 28.3 8
Federal Income Taxes . . . 23.0 25 13.1 5
Nonoperating Income. . . . (39.1) (119) (48.6) (113)
N.M. = Not Meaningful
<PAGE>
<PAGE>
Operating revenues increased significantly in both the third
quarter and the year-to-date periods due predominantly to increased
sales to retail and wholesale customers. Energy sales to retail
customers rose 6% in the quarter and 4% in the year-to-date period
primarily due to warmer summer weather in 1998 and increased
industrial customer usage. The significant increases in wholesale
sales and wholesale revenues are attributable to growth in the
power marketing and trading business in AEP's marketing area.
The increases in fuel expense were primarily attributable to
an increase in coal-fired generation to meet the increased demand
for electricity and an increase in the average cost of fuel
consumed reflecting the unavailability of lower cost nuclear
generation due to the unplanned outage of both Cook Plant nuclear
units in 1998.
Purchases of electricity by the wholesale power marketing and
trading business accounted for the significant increase in
purchased power expense.
The increase in net revenues of $131 million for the quarter
and $115 million for the year-to-date period is due to the impact
of warmer summer weather and increased industrial usage on retail
sales and the successful trading of wholesale energy in a volatile
market.
The increases in other operation expenses are related to the
increases in energy sales and the extended Cook Plant outage and in
the third quarter increased incentive pay accruals.
Maintenance expense increased for the year-to-date period
largely as a result of expenditures to prepare the Cook Plant units
for restart and to repair and restore service interruptions caused
by two severe snowstorms.
Federal income tax expense attributable to operations increased
due to an increase in pre-tax operating income.
The decreases in nonoperating income for both periods reflect
the effect of the Company's equity share of Yorkshire's loss on its
investment in Ionica, losses on certain energy trades and in the
third quarter the effect of $26 million of tax benefits recognized
in 1997 related to a reduction of the corporate income tax rate in
the U.K. by Yorkshire and the utilization of certain foreign tax
<PAGE>
credits. The energy trades which produced the losses are marked-to-market
and represent non-regulated trading activities outside
the Company's traditional marketing area (see footnote 5).
Although losses were incurred on these non-regulated energy trades,
net revenues from power marketing and trading operations within the
Company's traditional marketing area were significantly larger.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first nine months of 1998 were $652 million.
During the first nine months of 1998, subsidiaries issued $608
million principal amount of long-term obligations at interest rates
ranging from 5.87% to 10.53%; retired $524 million principal amount
of long-term debt with interest rates ranging from 2.85% to 9.15%;
and decreased short-term debt by $20 million.
COOK NUCLEAR PLANT SHUTDOWN
As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1997 Financial Statements and Management's
Discussion and Analysis of Results of Operations and Financial
Condition, both units of the Cook Nuclear Plant were shut down by
Indiana Michigan Power Company (I&M) in September 1997 due to
questions regarding the operability of certain safety systems,
which arose during a Nuclear Regulatory Commission (NRC) architect
engineer design inspection. The NRC issued a Confirmatory Action
Letter in September 1997 requiring I&M to address the issues
identified in the letter. I&M is working with the NRC to resolve
the one remaining issue in the letter.
On April 17, 1998, the NRC notified I&M that it had convened
a Restart Panel for Cook Plant. On July 30, 1998, I&M received a
letter from the NRC providing the NRC's list of required restart
activities. I&M is and will be meeting with the Panel on a regular
basis, until the Cook Plant units are returned to service, to
identify and address the items that need to be addressed in order
to restart the units. When maintenance and other activities
required for restart are complete, I&M will seek concurrence from
the NRC to return the Cook Plant to service.
<PAGE>
<PAGE>
I&M's current restart schedule indicates Unit 1 is expected to
return to service by the end of the first quarter of 1999. The
restart schedule for Unit 2 has not been completed; however,
management anticipates that Unit 2 may return to service 90 days
after Unit 1. If the units are not returned to service, there
could be a material adverse effect on financial condition.
The incremental cost expected to be incurred to restart the
Cook units is approximately $70 million for 1998, of which $34
million has been incurred through September 30, 1998. However,
approximately $20 million of previously budgeted work for 1998 at
the Cook Plant will not be incurred and will partially mitigate the
incremental restart costs. The cost and schedule for the outage
during 1999 could be significantly impacted if additional work is
identified beyond the $35 million planned for the first quarter.
On July 24, 1998, I&M received an "adverse trend letter" from
the NRC indicating that NRC senior managers had determined that
there had been a slow decline in performance at the Cook Plant
during the 18 month period preceding the letter. The letter
indicated that the NRC will closely monitor efforts to address
issues at Cook Plant through additional inspection activities.
In a letter dated October 13, 1998, the NRC issued to I&M a
Notice of Violation and proposed a $500,000 civil penalty for
alleged violations at the Cook Plant discovered during five
inspections conducted between August 4, 1997 and April 15, 1998.
I&M paid the penalty.
The cost of electricity supplied to I&M's retail customers rose
due to the outage of the two units since higher cost coal-fired
generation and purchased power were substituted for low cost
nuclear generation. In the Indiana and Michigan retail
jurisdictions 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 the 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
<PAGE>
future proceeding. When actual fuel costs exceed the estimated
costs reflected in the billing factor as was the case with regard
to the Cook outage, a regulatory asset is recorded and revenues are
accrued.
Due to the unscheduled Cook Plant outage, I&M's actual fuel
costs significantly exceeded the estimated fuel costs reflected in
its fuel cost adjustment factors. A regulatory asset has been
recorded for revenues accrued in anticipation of future
reconciliation and billing of the higher fuel costs to customers.
At September 30, 1998, the regulatory asset was $61 million.
The Indiana Utility Regulatory Commission approved two
agreements authorizing I&M during the billing months of July
through December 1998 to apply a fuel cost adjustment factor less
than that requested by I&M, subject to future reconciliation or
refund. The agreements provide the parties to the proceedings with
the opportunity to conduct discovery regarding certain issues that
were raised in the proceedings, including the appropriateness of
the recovery of replacement energy cost due to the extended Cook
Plant outage, in anticipation of resolving the issues in a future
fuel cost adjustment proceeding. Management believes that it
should be able to recover the Cook replacement energy costs;
however, if recovery of the replacement costs is denied, results of
operations and cash flows would be adversely affected.
The above timetable for the return to service of the Cook Plant
constitute "forward looking statements" as defined in the Private
Securities Litigation Reform Act of 1995. Such statements and
estimates could differ materially from actual results because of
factors referred to specifically in connection with such forward-looking
statements and, in addition, other unforeseen issues
encountered in preparing the Cook Plant for restart and the
unpredictability of the NRC regulatory process.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. Eight northeastern states also
<PAGE>
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located.
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels. On October 30, 1998,
a number of utilities, including the operating companies of the AEP
System, filed a petition in the U.S. Court of Appeals for the
District of Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions. Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources. These reductions are
substantially the same as those required by the final rules and
could be adopted by Federal EPA in the event the states fail to
implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that
compliance costs could result in required capital expenditures by
AEP of approximately $1.2 billion. Compliance costs can not be
estimated with certainty and the actual costs incurred to comply
could be significantly different from this preliminary estimate
depending upon the compliance alternatives selected to achieve
reductions in NOx emissions. Unless such costs are recovered from
customers, they would have a material adverse effect on results of
operations, cash flows and possibly financial condition.
ENERGY MARKETING AND TRADING
During 1998, the Company substantially increased the volume of
its electricity and gas marketing and trading. The purpose of the
marketing and trading business is to utilize the Company's
knowledge of the energy markets in order to improve the
<PAGE>
competitiveness of its generation business and contribute to net
income, thereby enhancing both customer and shareholder value.
The electricity and gas marketing and trading business involves
the marketing of energy under physical forward contracts at fixed
and variable prices and the trading of options, futures, swaps and
other financial derivative contracts at both fixed and variable
prices. Most contracts represent physical forward electricity
marketing contracts for the purchase and sale of electricity in the
Company's traditional marketing area which are recorded as
operating revenues and purchased power expense when the contracts
settle. At September 30, 1998, the Company had open marketing
contracts, not marked-to-market on its balance sheet, in its
traditional marketing area through the year 2004 to sell
electricity with a notional value of approximately $1.1 billion and
to purchase electricity with a notional value of approximately $1.1
billion.
The Company has also purchased and sold electricity and gas
options, futures and swaps, and entered into forward purchase and
sale contracts for the future delivery or receipt of electricity
and gas outside its traditional marketing area. These transactions
represent non-regulated trading activities that are
marked-to-market and recorded in nonoperating income. The
unrealized mark-to-market gains and losses from such trading
activity are reported as assets and liabilities, respectively. At
September 30, 1998, the Company has open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity and gas with a notional value of approximately
$755 million and to purchase electricity and gas with a notional
value of approximately $585 million.
Dependent on future electricity and gas market conditions these
activities could produce material income or losses in future
periods.
TAXES
As discussed in Note 10, "Federal Income Taxes", of the Notes
to Consolidated Financial Statements in the 1997 Financial
Statements and Management's Discussion and Analysis of Results of
Operations and Financial Condition, the Internal Revenue Service
<PAGE>
(IRS) agents auditing the AEP System's consolidated federal income
tax returns requested a ruling from their National Office that
certain interest deductions relating to corporate owned life
insurance (COLI) claimed by the Company should not be allowed. As
a result of a suit filed in United States District Court (discussed
below) this request for ruling has been withdrawn. Adjustments
have been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the COLI
interest deductions through September 30, 1998 would reduce
earnings by approximately $310 million (including interest). The
Company has made no provision for any possible adverse earnings
impact from this matter.
In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio.
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit. In July 1998 the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount. In September 1998 the Company made an
additional payment for the 1997 tax year. The payments were
included on the balance sheet 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. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year
<PAGE>
2000 ready programs.
Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur.
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 Year 2000 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 Year 2000 readiness
program. NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities. In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills. The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources." In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30, 1999 to June 30, 1999.
Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.<PAGE>
<PAGE>
Various state regulatory commissions are also reviewing the
Year 2000 readiness of electric utilities subject to their
jurisdiction.
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,
communications, and the physical generation and delivery of energy;
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 Year 2000 as of September 30, 1998:
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% 11/30/1998 86%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
<PAGE>
<PAGE>
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe 6/30/1999 2%
replacing or retiring 60%
those mission critical and
high priority digital-based
systems with problems Client
processing dates past the Server:
Year 2000. Testing these 1%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
Costs to Address the Company's Year 2000 Issues - Through
September 30, 1998, the Company has spent $15 million on the Year
2000 project and, estimates spending an additional $41 million to
$53 million to achieve Year 2000 readiness. Most Year 2000 costs
are software, IT consultant and salary-related 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 Year 2000 ready 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 Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.
<PAGE>
<PAGE>
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.
In addition, although as discussed 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, Year 2000-related issues may materially adversely
affect AEP.
Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program. The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999. These plans will build upon disaster
recovery, system restoration, and contingency planning that we now
have in place. We have begun the contingency planning process,
including the review of NERC's Contingency Planning Guide. The
Company plans to submit a draft of its contingency plans to NERC as
part of NERC's review of drafts of regional and individual electric
utility contingency plans in 1999.
Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995. Such statements are based on
<PAGE>
management's beliefs as well as assumptions made by, and
information currently available to, management. Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
* Continuing availability of experienced consultants and IT
personnel and related resources
* Ability of third parties to complete their Year 2000
remediations on a timely basis and accuracy of
representations made by such third parties concerning
their Year 2000 readiness
* Ability of the Company to identify and implement
contingency plans.
PROPOSED MERGER AND ACQUISITION
As discussed in the Management's Discussion and Analysis of
Results of Operations and Financial Condition in the 1997 annual
report and the Joint Proxy Statement/Prospectus dated April 16,
1998, the Company and Central and South West Corporation (CSW) have
agreed to merge. At the May 1998 annual meeting, AEP shareholders
approved the issuance of AEP common shares to effect the merger and
approved an increase in the authorized shares of AEP Common Stock
from 300,000,000 to 600,000,000. CSW stockholders approved the
merger at their May 1998 annual meeting. The companies have filed
for necessary approvals to merge with the Federal Energy Regulatory
Commission (FERC), the Securities and Exchange Commission, the NRC
and all of CSW's state regulatory commissions: Arkansas, Louisiana,
Oklahoma and Texas. Filings with the Federal Communications
Commission and the Department of Justice are expected to be made
before the end of 1998. The Company's target consummation date for
the merger is the second quarter of 1999.
In August 1998 the Arkansas Public Service Commission approved
the merger, subject to a number of conditions including the
approval of a regulatory plan for sharing net merger savings. On
November 3, 1998 the Company, CSW and CSW's Arkansas operating
subsidiary, Southwestern Electric Power Company, filed a settlement
<PAGE>
agreement for approval with the Arkansas Public Service Commission
outlining a regulatory plan, agreed to with the Commission staff,
which provides for a sharing of net merger savings through a
reduction of rates for Arkansas retail customers.
In October 1998 the Oklahoma Corporation Commission (OCC)
approved plans by AEP and CSW to submit an amended filing seeking
approval of the proposed merger. The amended application is being
made as a result of an Oklahoma administrative law judge's
recommendation that the merger filing be dismissed without
prejudice for lack of information regarding the potential impact of
the merger on the retail electric market in Oklahoma. Submission
of the amended application will reset Oklahoma's 90-day statutory
time period for OCC action on the merger phase of the application.
The filing of the amended application should not affect the timing
of the merger closing.
In July 1998 the FERC issued an order which confirmed that the
250 megawatt firm contract path with the Ameren System is
available. The contract path is required for AEP and CSW to meet
the requirements of the Public Utility Holding Company Act of 1935
that the two systems operate on an integrated and coordinated
basis. On November 10, 1998, the FERC issued an order establishing
hearing procedures for the merger. A scheduling conference will be
held in November 1998. The 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. The outcome of the FERC
scheduling conference could extend the targeted completion date of
the merger.
A settlement agreement between AEP, CSW and certain key parties
to the Texas merger proceeding has been reached. The staff of the
Public Utility Commission of Texas was not a signatory to the
settlement agreement, which resolves all issues for the signing
parties. The settlement provides for, among other things, the
approval of rate reductions to share net merger savings and settle
existing rate reviews.
<PAGE>
<PAGE>
The application by CSW's operating subsidiary, Central Power
and Light Company, to the NRC requesting permission to transfer
control of the license for the South Texas Project nuclear
generating station to AEP was approved by the NRC.
AEP has a 50% interest in Yorkshire Electricity Group, plc and
CSW has a 100% interest in Seeboard, plc, two U.K. regional
electricity companies (RECs). The proposed merger of CSW into AEP
would result in common ownership of these U.K. entities. As a
result, the common ownership of two U.K. RECs could be referred by
the U.K. Secretary of State for Trade and Industry to the U.K.
Mergers and Monopolies Commission for investigation.
The merger, which is to be accounted for as a pooling of
interests, is conditioned upon, among other things, the approval of
the above state and federal regulatory agencies. The transaction
must satisfy many conditions, including the condition that it must
be a pooling, and some of these conditions may not be waived by the
parties. The Company is unable to predict the outcome or the
timing of the required regulatory proceedings.
In September 1998 the Company and Equitable Resources, Inc.
signed a definitive agreement for the Company to purchase
Equitable's natural gas midstream assets and operations for
approximately $320 million. The purchase includes an intrastate
pipeline system, five natural gas processing plants, one natural
gas storage facility and an energy trading business. The
transaction is expected to close in the fourth quarter of 1998 and
be accounted for as a purchase.
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $59,262 $58,136 $167,596 $170,665
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 27,953 26,354 71,718 72,443
Rent - Rockport Plant Unit 2 . . . . . 17,071 17,071 51,212 51,212
Other Operation. . . . . . . . . . . . 2,174 2,518 7,547 8,362
Maintenance. . . . . . . . . . . . . . 2,703 2,372 9,110 10,115
Depreciation . . . . . . . . . . . . . 5,405 5,402 16,229 16,209
Taxes Other Than Federal Income Taxes. 882 1,015 2,759 2,744
Federal Income Taxes . . . . . . . . . 845 922 2,562 2,529
TOTAL OPERATING EXPENSES . . . 57,033 55,654 161,137 163,614
OPERATING INCOME . . . . . . . . . . . . 2,229 2,482 6,459 7,051
NONOPERATING INCOME. . . . . . . . . . . 837 831 2,457 2,631
INCOME BEFORE INTEREST CHARGES . . . . . 3,066 3,313 8,916 9,682
INTEREST CHARGES . . . . . . . . . . . . 903 986 2,494 2,997
NET INCOME . . . . . . . . . . . . . . . $ 2,163 $ 2,327 $ 6,422 $ 6,685
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $2,435 $3,672 $2,528 $1,886
NET INCOME . . . . . . . . . . . . . . . 2,163 2,327 6,422 6,685
CASH DIVIDENDS DECLARED. . . . . . . . . 2,176 3,286 6,528 5,858
BALANCE AT END OF PERIOD . . . . . . . . $2,422 $2,713 $2,422 $2,713
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Financial Statements.<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production. . . . . . . . . . . . . . . . . . . . . . . . $629,055 $627,803
General . . . . . . . . . . . . . . . . . . . . . . . . . 3,151 3,137
Construction Work in Progress . . . . . . . . . . . . . . 2,510 2,510
Total Electric Utility Plant. . . . . . . . . . . 634,716 633,450
Accumulated Depreciation. . . . . . . . . . . . . . . . . 272,198 257,191
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 362,518 376,259
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 142 237
Accounts Receivable . . . . . . . . . . . . . . . . . . . 22,674 20,710
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 12,097 10,107
Materials and Supplies. . . . . . . . . . . . . . . . . . 4,126 4,246
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 152 368
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 39,191 35,668
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 6,044 5,639
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 1,570 1,492
TOTAL . . . . . . . . . . . . . . . . . . . . . $409,323 $419,058
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(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 . . . . . . . . . . . . . . . . . . . . . 36,235 39,235
Retained Earnings . . . . . . . . . . . . . . . . . . . . 2,422 2,528
Total Common Shareholder's Equity . . . . . . . . 39,657 42,763
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . 44,790 69,570
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 84,447 112,333
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 972 1,259
CURRENT LIABILITIES:
Short-term Debt - Notes Payable . . . . . . . . . . . . . 8,175 11,750
Accounts Payable. . . . . . . . . . . . . . . . . . . . . 13,226 9,704
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 4,751 3,420
Interest Accrued. . . . . . . . . . . . . . . . . . . . . 164 461
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 23,427 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 5,311 3,747
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 55,054 34,045
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 134,723 138,901
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . . . 67,494 70,016
Deferred Amounts Due to Customers for Income Tax. . . . . 30,404 31,375
TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 97,898 101,391
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 36,075 31,129
DEFERRED CREDITS. . . . . . . . . . . . . . . . . . . . . . 154 -
TOTAL . . . . . . . . . . . . . . . . . . . . . $409,323 $419,058
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 6,422 $ 6,685
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 16,229 16,209
Deferred Federal Income Taxes. . . . . . . . . . . . . . 3,975 3,564
Deferred Investment Tax Credits. . . . . . . . . . . . . (2,522) (2,526)
Amortization of Deferred Gain on Sale
and Leaseback - Rockport Plant Unit 2. . . . . . . . . (4,178) (4,178)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . . (1,964) (1,804)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (1,870) 7,149
Accounts Payable . . . . . . . . . . . . . . . . . . . . 3,522 (2,655)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 1,331 2,292
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 1,174 (2,044)
Net Cash Flows From Operating Activities . . . . . . 40,583 41,156
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (4,829) (2,042)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,254 -
Net Cash Flows Used For Investing Activities . . . . (2,575) (2,042)
FINANCING ACTIVITIES:
Return of Capital to Parent Company. . . . . . . . . . . . (3,000) (2,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . (3,575) (9,575)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (25,000) (20,010)
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (6,528) (5,858)
Net Cash Flows Used For Financing Activities . . . . (38,103) (37,443)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (95) 1,671
Cash and Cash Equivalents at Beginning of Period . . . . . . 237 139
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 142 $ 1,810
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $2,508,000 and
$2,699,000 and for income taxes was $(1,188,000) and $(1,598,000) in 1998 and 1997,
respectively.
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read
in conjunction with the 1997 Annual Report as incorporated in and
filed with the Form 10-K. In the opinion of management, the
financial statements reflect all adjustments (consisting of only
normal recurring accruals) which are necessary for a fair
presentation of the results of operations and financial condition
for interim periods.
2. FINANCING ACTIVITIES
In March 1998 $12.5 million of the 1995 Series A pollution
control revenue bonds due 2025 and $12.5 million of the 1995 Series
B pollution control revenue bonds due 2025 were redeemed.
3. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in the
first quarter of 1998. SFAS No. 130 established the standards for
reporting and displaying components of "comprehensive income,"
which is the total of net income and all transactions not included
in net income affecting equity except those with shareholders. For
the quarter and year-to-date periods ended September 30, 1998,
there were no material differences between comprehensive income and
net income.
In the first quarter of 1998 the Company adopted the American
Institute of Certified Public Accountants' Statement of Position
(SOP) 98-1, "Accounting for the Costs of Computer Software
Developed or Obtained for Internal Use." The SOP requires the
capitalization and amortization of certain costs of acquiring or
developing internal use computer software. Previously the Company
expensed all software acquisition and development costs. The SOP
must be adopted at the beginning of a fiscal year with no
restatement or retroactive adjustment of prior periods. The
adoption of the SOP effective January 1, 1998 did not have a
material effect on results of operations, cash flows or financial
condition.
<PAGE>
<PAGE>
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
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 costs including a
FERC approved rate of return on common equity and a return on other
capital net of temporary cash investments.
Net income decreased $0.2 million or 7% for the third quarter
and $0.3 million or 4% for the year-to-date period as a result of
capital returned to the parent company in 1997, May 1998 and August
1998.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $ 1.1 2 $(3.1) (2)
Fuel Expense. . . . . . . . 1.6 6 (0.7) (1)
Other Operation Expense . . (0.3) (14) (0.8) (10)
Maintenance Expense . . . . 0.3 14 (1.0) (10)
Interest Charges. . . . . . (0.1) (8) (0.5) (17)
The increase in operating revenues for the third quarter
reflects the recovery through the unit power agreements of higher
operating expenses, primarily fuel expense. In the year-to-date
period, lower operating expenses and a lower return on common
equity reflecting the return of capital are the primary reasons for
the decline in operating revenues.
Fuel expense increased in the third quarter reflecting a 7%
increase in generation. While year-to-date generation increased
5%, a lower average cost of fuel consumed, due to lower coal
prices, produced a reduction in fuel expense.
<PAGE>
<PAGE>
The decline in other operation expense in both the quarter and
year-to-date periods is primarily due to a decline in
administrative and general expenses reflecting a reduction in
allocated wages and employee benefit costs and a reduction in a
FERC assessment.
Maintenance expense increased during the quarter due to a rise
in boiler plant repair expenditures, while for the year-to-date
period the reduction in maintenance expense reflects a longer
duration outage in 1997 compared with 1998's outage.
The decline in interest charges was due to a reduction in
outstanding long-term debt balances reflecting the redemption of
$20 million in June 1997 and $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 Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $1,312,293 $438,510 $2,689,576 $1,228,044
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 113,059 104,514 322,459 288,773
Purchased Power. . . . . . . . . . . . 939,595 100,587 1,654,929 261,595
Other Operation. . . . . . . . . . . . 73,988 60,585 191,297 185,852
Maintenance. . . . . . . . . . . . . . 30,691 27,615 97,519 79,505
Depreciation and Amortization. . . . . 36,059 34,568 107,252 102,817
Taxes Other Than Federal Income Taxes. 29,003 29,544 89,181 89,580
Federal Income Taxes . . . . . . . . . 18,947 16,317 45,547 45,411
TOTAL OPERATING EXPENSES . . . 1,241,342 373,730 2,508,184 1,053,533
OPERATING INCOME . . . . . . . . . . . . 70,951 64,780 181,392 174,511
NONOPERATING INCOME (LOSS) . . . . . . . (5,664) 305 (4,490) 628
INCOME BEFORE INTEREST CHARGES . . . . . 65,287 65,085 176,902 175,139
INTEREST CHARGES . . . . . . . . . . . . 31,841 30,332 95,133 88,524
NET INCOME . . . . . . . . . . . . . . . 33,446 34,753 81,769 86,615
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 675 681 1,822 6,326
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 32,771 $ 34,072 $ 79,947 $ 80,289
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $195,262 $197,471 $207,544 $208,472
NET INCOME . . . . . . . . . . . . . . . 33,446 34,753 81,769 86,615
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 29,729 28,609 89,187 85,827
Cumulative Preferred Stock . . . . . 567 572 1,499 2,649
Capital Stock Expense. . . . . . . . . 108 109 323 3,677
BALANCE AT END OF PERIOD . . . . . . . . $198,304 $202,934 $198,304 $202,934
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,959,309 $1,942,325
Transmission . . . . . . . . . . . . . . . . . . . . 1,117,332 1,079,919
Distribution . . . . . . . . . . . . . . . . . . . . 1,647,232 1,583,161
General. . . . . . . . . . . . . . . . . . . . . . . 228,803 207,380
Construction Work in Progress. . . . . . . . . . . . 77,573 88,261
Total Electric Utility Plant . . . . . . . . 5,030,249 4,901,046
Accumulated Depreciation and Amortization. . . . . . 1,958,654 1,869,057
NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,071,595 3,031,989
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 109,354 34,544
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 8,467 6,947
Accounts Receivable. . . . . . . . . . . . . . . . . 161,074 164,657
Allowance for Uncollectible Accounts . . . . . . . . (1,590) (1,333)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 48,425 47,901
Materials and Supplies . . . . . . . . . . . . . . . 63,860 57,359
Accrued Utility Revenues . . . . . . . . . . . . . . 40,630 51,208
Prepayments and Other. . . . . . . . . . . . . . . . 16,671 6,960
TOTAL CURRENT ASSETS . . . . . . . . . . . . 337,537 333,699
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 434,704 441,223
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 37,346 41,975
TOTAL. . . . . . . . . . . . . . . . . . . $3,990,536 $3,883,430
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(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. . . . . . . . . . . . . . . . . . . 638,510 613,048
Retained Earnings. . . . . . . . . . . . . . . . . . 198,304 207,544
Total Common Shareholder's Equity. . . . . . 1,097,272 1,081,050
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 19,439 19,747
Subject to Mandatory Redemption. . . . . . . . . . 22,310 22,310
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,532,809 1,415,026
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,671,830 2,538,133
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 164,715 137,371
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 19,504 79,509
Short-term Debt. . . . . . . . . . . . . . . . . . . 61,975 130,300
Accounts Payable . . . . . . . . . . . . . . . . . . 80,625 96,816
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 43,772 41,549
Customer Deposits. . . . . . . . . . . . . . . . . . 14,194 13,713
Interest Accrued . . . . . . . . . . . . . . . . . . 29,841 20,949
Revenue Refunds Accrued. . . . . . . . . . . . . . . 42,418 3,311
Other. . . . . . . . . . . . . . . . . . . . . . . . 91,876 68,812
TOTAL CURRENT LIABILITIES. . . . . . . . . . 384,205 454,959
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 649,472 658,655
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 63,948 67,496
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 56,366 26,816
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . . $3,990,536 $3,883,430
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 81,769 $ 86,615
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 108,158 103,796
Deferred Federal Income Taxes. . . . . . . . . . . . . . (1,452) (8,719)
Deferred Investment Tax Credits. . . . . . . . . . . . . (3,548) (3,571)
Provision for Rate Refunds . . . . . . . . . . . . . . . 9,342 3,083
Deferred Power Supply Costs (net). . . . . . . . . . . . 25,137 13,951
Amortization of Deferred Property Taxes. . . . . . . . . 12,940 13,240
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 3,840 13,458
Fuel, Materials and Supplies . . . . . . . . . . . . . . (7,025) (1,763)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 10,578 18,942
Prepayments and Other Current Assets . . . . . . . . . . (9,711) 3,695
Accounts Payable . . . . . . . . . . . . . . . . . . . . (16,191) 13,188
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2,223 1,642
Interest Accrued . . . . . . . . . . . . . . . . . . . . 8,892 12,285
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 39,107 (1,933)
Payment of Disputed Tax and Interest Related to COLI . . . (68,316) -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 22,652 (19,383)
Net Cash Flows From Operating Activities . . . . . . 218,395 248,526
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (138,297) (146,039)
Proceeds from Sale of Property . . . . . . . . . . . . . . 914 4,204
Net Cash Flows Used For Investing Activities . . . . (137,383) (141,835)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . 25,000 20,000
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 193,431 183,257
Change in Short-term Debt (net). . . . . . . . . . . . . . (68,325) 22,825
Retirement of Cumulative Preferred Stock . . . . . . . . . (229) (183,842)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (138,472) (56,378)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (89,187) (85,827)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,710) (5,319)
Net Cash Flows Used For Financing Activities . . . . (79,492) (105,284)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 1,520 1,407
Cash and Cash Equivalents at Beginning of Period . . . . . . 6,947 7,260
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 8,467 $ 8,667
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $83,359,000 and $73,466,000
and for income taxes was $38,378,000 and $46,965,000 in 1998 and 1997, respectively.
Noncash acquisitions under capital leases were $16,909,000 and $14,377,000 in 1998
and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial
statements should be read in conjunction with the 1997 Annual
Report as incorporated in and filed with the Form 10-K. In the
opinion of management, the financial statements reflect all
adjustments (consisting of only normal recurring accruals)
which are necessary for a fair presentation of the results of
operations and financial condition for interim periods.
2. RATE MATTER
In September 1992 the Company implemented, subject to
refund, an $8.7 million annual rate increase to its wholesale
customers pending a final order from the Federal Energy
Regulatory Commission (FERC). On June 29, 1998 the FERC
granted an annual rate increase of $3.4 million and required
a refund including interest of amounts collected in excess of
the $3.4 million annual increase. A rehearing of the FERC's
order has been requested.
At September 30, 1998, the Company had fully provided for
the refund obligation plus interest as a current liability.
3. FINANCING ACTIVITIES
During the first nine months of 1998, the Company issued
two series of senior unsecured notes of $100 million each with
rates of 7.20% and 7.30% due in 2038.
During the first nine months of 1998, the Company
reacquired the following first mortgage bonds for $138 million
including reacquisition premiums:
Principal
Amount
% Rate Due Date Reacquired
(in thousands)
8.75 2022 - February 1 $29,919
8.70 2022 - May 22 35,000
7.95 2002 - March 1 60,000
8.43 2022 - June 1 12,529
In June 1998, the Company received a $25 million cash
capital contribution from its parent which was credited to
paid-in capital.
<PAGE>
<PAGE>
4. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in
the first quarter of 1998. SFAS No. 130 established the
standards for reporting and displaying components of
"comprehensive income," which is the total of net income and
all transactions not included in net income affecting equity
except those with shareholders. For the quarter and year-to-date periods
ended September 30, 1998, there were no material
differences between comprehensive income and net income.
In the first quarter of 1998 the Company adopted the
American Institute of Certified Public Accountants' Statement
of Position (SOP) 98-1, "Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use". The SOP
requires the capitalization and amortization of certain costs
of acquiring or developing internal use computer software.
Previously the Company expensed software acquisition and
development costs with the exception of newly developed
customer service and billing software costs which were
capitalized in accordance with an order of the Virginia State
Corporation Commission. The SOP must be adopted at the
beginning of a fiscal year with no restatement or retroactive
adjustment of prior periods. The adoption of the SOP effective
January 1, 1998 did not have a material effect on results of
operations, cash flows or financial condition.
5. POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation,
as agent for the Company and its affiliates in the AEP System
Power Pool (Power Pool), substantially increased the volume of
its electricity marketing and trading. The purpose of the
power marketing and trading business is to utilize AEP's
knowledge of the energy markets in order to improve the
competitiveness of its generation business and contribute to
net income. Revenues and expenses from these activities are
shared by the Power Pool members based on their relative peak
demands.
The power marketing and trading business involves the
marketing of power under physical forward contracts at fixed
and variable prices and the trading of options, futures, swaps
and other financial derivative contracts at both fixed and
variable prices. Most contracts represent physical forward
electricity marketing contracts for the purchase and sale of
electricity in the Power Pool's traditional marketing area
which are recorded as operating revenues and purchased power
expense when the contracts settle. At September 30, 1998, the
Power Pool had open marketing contracts, not on the balance
sheet, in its traditional marketing area through the year 2004
to sell electricity with a notional value of approximately $1.1
billion and to purchase electricity with a notional value of
approximately $1.1 billion. The Company's share of these
<PAGE>
notional values is approximately $320 million.
The Power Pool has also purchased and sold electricity
options, futures, and swaps, and entered into forward purchase
and sale contracts for the future delivery or receipt of
electricity outside its traditional marketing area. These
transactions represent non-regulated trading activities that
are marked-to-market and recorded in nonoperating income. At
September 30, 1998, the Company's share of the unrealized mark-to-market
gains and losses from such trading contracts are
reported as assets and liabilities, respectively. At September
30, 1998, the Power Pool had open marketing contracts outside
its traditional marketing area through the year 2008 to sell
electricity with a notional value of approximately $230 million
and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these
notional values is approximately $70 million for sales and
approximately $45 million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
6. CONTINGENCIES
Taxes
As discussed in Note 9, "Federal Income Taxes" of the Notes
to Consolidated Financial Statements in the 1997 Annual Report,
the Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a
ruling from their National Office that certain interest
deductions relating to corporate owned life insurance (COLI)
claimed by the Company should not be allowed. As a result of
a suit filed in United States District Court (discussed below)
this request for ruling has been withdrawn. Adjustments have
been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the
COLI interest deduction through September 30, 1998 would reduce
earnings by approximately $77 million (including interest).
The Company has made no provision for any possible adverse
earnings impact from this matter.
In order to resolve this issue without further delay, on
March 24, 1998, the Company filed suit against the United
States in the United States District Court for the Southern
District of Ohio. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit.
In July 1998, the Company made a payment of taxes and interest
attributable to COLI interest deductions for taxable years
1991-96 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
In September 1998 the Company made an additional payment for
the 1997 tax year. The payments were included on the balance
sheet in other property and investments pending the resolution
<PAGE>
of this matter. The Company will seek refund, either
administratively or through litigation, of all amounts paid.
In the event the resolution of this matter is unfavorable, it
will have a material adverse impact on results of operations
and cash flows.
Revised Air Quality Standards
The United States Environmental Protection Agency (Federal
EPA) published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state
implementation plans (SIPs). SIPs are a procedural method used
by each state to comply with Federal EPA rules. Eight
northeastern states also filed petitions in 1997 with Federal
EPA claiming NOx emissions from plants in midwestern states
prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states,
including the states in which the Company's generating plants
are located. The implementation of the final rules would be
achieved through the revision of SIPs by September 1999 that,
by the year 2003, anticipate the imposition of a NOx reduction
on utility sources of approximately 85% below 1990 emission
levels. On October 30, 1998, a number of utilities, including
the Company and its affiliates in the AEP System, filed a
petition in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to
their SIPs within one year of the date of the final rules
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions. Federal EPA
also proposed the approval of portions of the petitions filed
by the eight northeastern states that would result in
imposition of NOx emission reductions on utility and industrial
sources. These reductions are substantially the same as those
required by the final rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance
with the final rules.
Based on initial studies, preliminary estimates indicate
that compliance costs could result in capital expenditures of
approximately $325 million. Compliance costs can not be
estimated with certainty and the actual costs incurred to
comply could be significantly different from the preliminary
estimate depending upon the compliance alternatives selected
to achieve reductions in NOx emissions. Unless such costs are
recovered from customers, they would have a material adverse
effect on results of operations, cash flows and possibly
financial condition.
<PAGE>
<PAGE>
Other
The Company continues to be involved in certain other
matters discussed in its 1997 Annual Report.
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
Despite an increase in revenues net of fuel and purchased power
expenses (net revenues) of $26.3 million for the third quarter and
$34.5 million for the year-to-date period due to an increase in
weather related retail sales and wholesale power marketing and
trading transactions within AEP's traditional marketing area, net
income decreased $1.3 million or 4% for the quarter and $4.8
million or 6% for the year-to-date period. The decline in net
income was primarily due to an increase in operating expenses other
than fuel and purchased power, losses on certain non-regulated
energy trades outside of the Company's marketing area, an increase
in interest charges and the recordation of provisions for revenue
refunds, net of tax.
The significant changes in income statement line items and net
revenues were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $873.8 199 $1,461.5 119
Fuel Expense . . . . . . . 8.5 8 33.7 12
Purchased Power Expense. . 839.0 N.M. 1,393.3 N.M.
Net Revenues . . . . . . 26.3 34.5
Other Operation Expense. . 13.4 22 5.4 3
Maintenance Expense. . . . 3.1 11 18.0 23
Depreciation and
Amortization . . . . . . 1.5 4 4.4 4
Federal Income Taxes . . . 2.6 16 0.1 -
Nonoperating Income. . . . (6.0) N.M. (5.1) N.M.
Interest Charges . . . . . 1.5 5 6.6 7
N.M. = Not Meaningful
Operating revenues increased significantly in both the third
quarter and the year-to-date periods due predominantly to increased
retail and wholesale sales. The increase in retail revenues can be
attributed to increased energy sales to residential and commercial
customers reflecting warmer spring and summer weather in 1998.
<PAGE>
Revenues from wholesale customers increased significantly
reflecting growth in power marketing and trading transactions.
The increases in fuel expense for the quarter and year-to-date
periods were primarily due to increased coal fired generation to
meet the increased demand.
Purchased power expense increased primarily as a result of the
growth in power marketing and trading activities.
The increase in other operation expense was mainly due to
costs related to the increase in sales and employee incentive pay
accruals.
Maintenance expense increased as a result of an increase in
planned expenditures to maintain transmission and distribution
right-of-ways and, for the year-to-date period, costs for repair
and restoration of service caused by two severe snowstorms.
The increase in depreciation and amortization expense is mainly
due to additional investment in depreciable plant reflecting
improvements to the transmission and distribution system.
In the third quarter federal income tax expense attributable
to operations increased primarily due to an increase in pre-tax
operating income.
The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions. These
transactions, which are marked-to-market and described in footnote
5, represent non-regulated trading activities outside the Company's
traditional marketing area. Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
Interest charges for the quarter and year-to-date periods
increased as a result of the accrual of interest on a revenue
refund to wholesale customers under the terms of a final rate order
and an increase in long-term debt outstanding.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first nine months of 1998 were $155 million.
<PAGE>
<PAGE>
During the first nine months of 1998, the Company issued two
series of senior unsecured notes of $100 million each with rates of
7.20% and 7.30% due in 2038 and redeemed $137 million principal
amount of first mortgage bonds with interest rates from 7.95% to
8.75%. Short-term debt decreased by $68 million from year-end
balances. In June 1998, the Company received a $25 million cash
capital contribution from its parent which was credited to paid-in
capital.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. Eight northeastern states also
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located.
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels. On October 30, 1998,
a number of utilities, including the Company and its affiliates in
the AEP System, filed a petition in the U.S. Court of Appeals for
the District of Columbia Circuit seeking a review of the final
rules.
Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions. Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources. These reductions are
substantially the same as those required by the final rules and
could be adopted by Federal EPA in the event the states fail to
<PAGE>
implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that
compliance costs could result in capital expenditures of
approximately $325 million. Compliance costs can not be estimated
with certainty and the actual costs incurred to comply could be
significantly different from the preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year
2000 ready programs.
Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur.
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 Year 2000 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
<PAGE>
Reliability Council (NERC) as part of NERC's Year 2000 readiness
program. NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities. In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills. The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources." In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30, 1999 to June 30, 1999.
Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
Various state regulatory commissions are also reviewing the
Year 2000 readiness of electric utilities subject to their
jurisdiction.
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,
communications, and the physical generation and delivery of energy;
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>
<PAGE>
The following chart shows our progress toward becoming ready
for the Year 2000 as of September 30, 1998:
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% 11/30/1998 86%
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 2%
replacing or retiring 60%
those mission critical and
high priority digital-based
systems with problems Client
processing dates past the Server:
Year 2000. Testing these 1%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
Costs to Address the Company's Year 2000 Issues - Through
September 30, 1998, the Company has spent $4 million on the Year
2000 project and, estimates spending an additional $12 million to
$16 million to achieve Year 2000 readiness. Most Year 2000 costs
are software, IT consultant and salary-related 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 Year 2000 ready is not expected to have a material impact
on the Company's results of operations, cash flows or financial
condition.
<PAGE>
<PAGE>
Risks of the Company's Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.
In addition, although as discussed 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, Year 2000-related issues may materially adversely
affect AEP.
Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program. The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999. These plans will build upon disaster
recovery, system restoration, and contingency planning that we now
<PAGE>
have in place. We have begun the contingency planning process,
including the review of NERC's Contingency Planning Guide. The
Company plans to submit a draft of its contingency plans to NERC as
part of NERC's review of drafts of regional and individual electric
utility contingency plans in 1999.
Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995. Such statements are based on
management's beliefs as well as assumptions made by, and
information currently available to, management. Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
* Continuing availability of experienced consultants and IT
personnel and related resources
* Ability of third parties to complete their Year 2000
remediations on a timely basis and accuracy of
representations made by such third parties concerning
their Year 2000 readiness
* Ability of the Company to identify and implement
contingency plans.
TAXES
As discussed in Note 9, "Federal Income Taxes" of the Notes to
Consolidated Financial Statements in the 1997 Annual Report, the
Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed. As a result of a suit filed in United States
District Court (discussed below) this request for ruling has been
withdrawn. Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions for taxable years 1991-96. A
<PAGE>
disallowance of the COLI interest deduction through September 30,
1998 would reduce earnings by approximately $77 million (including
interest). The Company has made no provision for any possible
adverse earnings impact from this matter.
In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio.
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit. In July 1998, the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount. In September 1998 the Company made an
additional payment for the 1997 tax year. The payments were
included on the balance sheet 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. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation, as
agent for the Company and its affiliates in the AEP System Power
Pool (Power Pool), substantially increased the volume of its
electricity marketing and trading. The purpose of the power
marketing and trading business is to utilize AEP's knowledge of the
energy markets in order to improve the competitiveness of its
generation business and contribute to net income. Revenues and
expenses from these activities are shared by the Power Pool members
based on their relative peak demands.
The power marketing and trading business involves the marketing
of power under physical forward contracts at fixed and variable
prices and the trading of options, futures, swaps and other
financial derivative contracts at both fixed and variable prices.
Most contracts represent physical forward electricity marketing
contracts for the purchase and sale of electricity in the Power
Pool's traditional marketing area which are recorded as operating
<PAGE>
revenues and purchased power expense when the contracts settle.
At September 30, 1998, the Power Pool had open marketing contracts,
not on the balance sheet, in its traditional marketing area through
the year 2004 to sell electricity with a notional value of
approximately $1.1 billion and to purchase electricity with a
notional value of approximately $1.1 billion. The Company's share
of these notional values is approximately $320 million.
The Power Pool has also purchased and sold electricity options,
futures, and swaps, and entered into forward purchase and sale
contracts for the future delivery or receipt of electricity outside
its traditional marketing area. These transactions represent non-regulated
trading activities that are marked-to-market and recorded
in nonoperating income. At September 30, 1998, the Company's share
of the unrealized mark-to-market gains and losses from such trading
contracts are reported as assets and liabilities, respectively. At
September 30, 1998, the Power Pool had open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity with a notional value of approximately $230
million and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these notional
values is approximately $70 million for sales and approximately $45
million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $843,007 $313,024 $1,711,773 $841,294
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 49,693 52,269 143,533 134,198
Purchased Power. . . . . . . . . . . . 561,812 54,444 972,535 138,278
Other Operation. . . . . . . . . . . . 59,478 46,505 150,843 132,256
Maintenance. . . . . . . . . . . . . . 13,932 17,535 43,128 50,602
Depreciation . . . . . . . . . . . . . 22,760 22,784 68,454 67,800
Amortization of Zimmer Plant
Phase-in Costs . . . . . . . . . . . - - - 15,744
Taxes Other Than Federal Income Taxes. 29,295 29,861 86,921 89,484
Federal Income Taxes . . . . . . . . . 31,774 24,731 69,716 57,639
TOTAL OPERATING EXPENSES . . . 768,744 248,129 1,535,130 686,001
OPERATING INCOME . . . . . . . . . . . . 74,263 64,895 176,643 155,293
NONOPERATING INCOME (LOSS) . . . . . . . (2,337) 658 (1,109) 2,018
INCOME BEFORE INTEREST CHARGES . . . . . 71,926 65,553 175,534 157,311
INTEREST CHARGES . . . . . . . . . . . . 19,635 20,065 58,856 59,069
NET INCOME . . . . . . . . . . . . . . . 52,291 45,488 116,678 98,242
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 532 532 1,598 1,909
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 51,759 $ 44,956 $ 115,080 $ 96,333
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $160,171 $111,953 $138,172 $ 99,582
NET INCOME . . . . . . . . . . . . . . . 52,291 45,488 116,678 98,242
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 20,661 19,671 61,983 59,013
Cumulative Preferred Stock . . . . . 437 437 1,312 1,312
Capital Stock Expense. . . . . . . . . 95 95 286 261
BALANCE AT END OF PERIOD . . . . . . . . $191,269 $137,238 $191,269 $137,238
The common stock of the Company is wholly owned by American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,520,079 $1,521,381
Transmission . . . . . . . . . . . . . . . . . . . . 338,743 336,446
Distribution . . . . . . . . . . . . . . . . . . . . 927,225 926,178
General. . . . . . . . . . . . . . . . . . . . . . . 122,532 138,041
Construction Work in Progress. . . . . . . . . . . . 120,161 54,064
Total Electric Utility Plant . . . . . . . . 3,028,740 2,976,110
Accumulated Depreciation . . . . . . . . . . . . . . 1,118,654 1,074,588
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,910,086 1,901,522
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 67,941 33,235
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 6,505 12,626
Accounts Receivable (net). . . . . . . . . . . . . . 129,936 110,969
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 15,856 19,549
Materials and Supplies . . . . . . . . . . . . . . . 30,442 27,628
Accrued Utility Revenues . . . . . . . . . . . . . . 50,537 51,765
Prepayments. . . . . . . . . . . . . . . . . . . . . 34,219 30,397
TOTAL CURRENT ASSETS . . . . . . . . . . . . 267,495 252,934
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 351,571 359,481
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 21,658 66,688
TOTAL. . . . . . . . . . . . . . . . . . . $2,618,751 $2,613,860
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(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. . . . . . . . . . . . . . . . . . . 572,397 572,112
Retained Earnings. . . . . . . . . . . . . . . . . . 191,269 138,172
Total Common Shareholder's Equity. . . . . . 804,692 751,310
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 959,651 887,850
TOTAL CAPITALIZATION . . . . . . . . . . . . 1,789,343 1,664,160
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 46,028 42,271
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . - 81,750
Short-term Debt. . . . . . . . . . . . . . . . . . . 55,350 66,600
Accounts Payable . . . . . . . . . . . . . . . . . . 52,053 71,287
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 95,052 131,107
Interest Accrued . . . . . . . . . . . . . . . . . . 24,227 14,198
Other. . . . . . . . . . . . . . . . . . . . . . . . 42,908 28,972
TOTAL CURRENT LIABILITIES. . . . . . . . . . 269,590 393,914
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 436,168 433,593
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 50,272 52,934
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 27,350 26,988
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $2,618,751 $2,613,860
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 116,678 $ 98,242
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . 68,617 67,978
Deferred Federal Income Taxes. . . . . . . . . . . . . . 12,398 (741)
Deferred Investment Tax Credits. . . . . . . . . . . . . (2,662) (2,705)
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . (10,169) (4,089)
Amortization of Zimmer Plant Operating Expenses and
Carrying Charges . . . . . . . . . . . . . . . . . . . - 15,936
Amortization of Deferred Property Taxes. . . . . . . . . 48,775 48,601
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (18,967) (52,786)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 879 1,364
Accrued Utility Revenues . . . . . . . . . . . . . . . . 1,228 (14,057)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (19,234) 2,008
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (36,055) (50,645)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 10,029 12,707
Other Current Assets and Current Liabilities . . . . . . 10,114 5,350
Payment of Disputed Tax and Interest Related to COLI . . . (37,243) -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 16,799 (9,827)
Net Cash Flows From Operating Activities . . . . . . 161,187 117,336
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (84,178) (82,696)
Proceeds from Sale of Property and Other . . . . . . . . . 2,546 1,586
Net Cash Flows Used For Investing Activities . . . . (81,632) (81,110)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 111,075 38,574
Change in Short-term Debt (net). . . . . . . . . . . . . . (11,250) 42,925
Retirement of Cumulative Preferred Stock . . . . . . . . . - (52,953)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (122,206) -
Dividends Paid on Common Stock . . . . . . . . . . . . . . (61,983) (59,013)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,312) (2,297)
Net Cash Flows Used For Financing Activities . . . . (85,676) (32,764)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (6,121) 3,462
Cash and Cash Equivalents at Beginning of Period . . . . . . 12,626 9,134
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 6,505 $ 12,596
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $46,014,000 and $43,341,000
and for income taxes was $27,254,000 and $50,609,000 in 1998 and 1997, respectively.
Noncash acquisitions under capital leases were $10,029,000 and $6,583,000 in 1998
and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial
statements should be read in conjunction with the 1997 Annual
Report as incorporated in and filed with the Form 10-K. In the
opinion of management, the financial statements reflect all
adjustments (consisting of only normal recurring accruals)
which are necessary for a fair presentation of the results of
operations and financial condition for interim periods.
2. FINANCING ACTIVITIES
During the first nine months of 1998 the Company redeemed
$57 million of 9.15% and $25 million of 7.00% first mortgage
bonds at maturity and $40 million of 7.95% first mortgage bonds
due 2002 and issued $52 million of 6.51% and $60 million of
6.55% senior unsecured notes due in 2008.
3. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in
the first quarter of 1998. SFAS No. 130 established the
standards for reporting and displaying components of
"comprehensive income," which is the total of net income and
all transactions not included in net income affecting equity
except those with shareholders. For the quarter and year-to-date periods
ended September 30, 1998, there were no material
differences between comprehensive income and net income.
In the first quarter of 1998 the Company adopted the
American Institute of Certified Public Accountants' Statement
of Position (SOP) 98-1, "Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use." The SOP
requires the capitalization and amortization of certain costs
of acquiring or developing internal use computer software.
Previously the Company expensed all software acquisition and
development costs. The SOP must be adopted at the beginning
of a fiscal year with no restatement or retroactive adjustment
of prior periods. The adoption of the SOP effective January
1, 1998 did not have a material effect on results of
operations, cash flows or financial condition.
4. POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation,
as agent for the Company and its affiliates in the AEP System
Power Pool (Power Pool), substantially increased the volume of
its electricity marketing and trading. The purpose of the
power marketing and trading business is to utilize AEP's
<PAGE>
knowledge of the energy markets in order to improve the
competitiveness of its generation business and contribute to
net income. Revenues and expenses from these activities are
shared by the Power Pool members based on their relative peak
demands.
The power marketing and trading business involves the
marketing of power under physical forward contracts at fixed
and variable prices and the trading of options, futures, swaps
and other financial derivative contracts at both fixed and
variable prices. Most contracts represent physical forward
electricity marketing contracts for the purchase and sale of
electricity in the Power Pool's traditional marketing area
which are recorded as operating revenues and purchased power
expense when the contracts settle. At September 30, 1998, the
Power Pool had open marketing contracts, not on the balance
sheet, in its traditional marketing area through the year 2004
to sell electricity with a notional value of approximately $1.1
billion and to purchase electricity with a notional value of
approximately $1.1 billion. The Company's share of these
notional values is approximately $190 million.
The Power Pool has also purchased and sold electricity
options, futures, and swaps, and entered into forward purchase
and sale contracts for the future delivery or receipt of
electricity outside the traditional marketing area. These
transactions represent non-regulated trading activities that
are marked-to-market and recorded in nonoperating income. At
September 30, 1998, the Company's share of the unrealized mark-to-market
gains and losses from such trading contracts are
reported as assets and liabilities, respectively. At September
30, 1998, the Power Pool had open marketing contracts outside
its traditional marketing area through the year 2008 to sell
electricity with a notional value of approximately $230 million
and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these
notional values is approximately $40 million for sales and
approximately $25 million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
5. CONTINGENCIES
Taxes
As discussed in Note 8, "Federal Income Taxes" of the Notes
to Consolidated Financial Statements in the 1997 Annual Report,
the Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a
ruling from their National Office that certain interest
deductions relating to corporate owned life insurance (COLI)
claimed by the Company should not be allowed. As a result of
a suit filed in United States District Court (discussed below)
<PAGE>
this request for ruling has been withdrawn. Adjustments have
been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of COLI
interest deductions through September 30, 1998 would reduce
earnings by approximately $42 million (including interest).
The Company has made no provision for any possible adverse
earnings impact from this matter.
In order to resolve this issue without further delay, on
March 24, 1998, the Company filed suit against the United
States in the United States District Court for the Southern
District of Ohio. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit.
In July 1998, the Company made a payment of taxes and interest
attributable to COLI interest deductions for taxable years
1991-96 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
In September 1998, the Company made an additional payment for
the 1997 tax year. The payments were included on the balance
sheet 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.
In the event the resolution of this matter is unfavorable, it
will have a material adverse impact on results of operations
and cash flows.
Revised Air Quality Standards
The United States Environmental Protection Agency (Federal
EPA) published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state
implementation plans (SIPs). SIPs are a procedural method used
by each state to comply with Federal EPA rules. Eight
northeastern states also filed petitions in 1997 with Federal
EPA claiming NOx emissions from plants in midwestern states
prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states,
including the states in which the Company's generating plants
are located. The implementation of the final rules would be
achieved through the revision of SIPs by September 1999 that,
by the year 2003, anticipate the imposition of a NOx reduction
on utility sources of approximately 85% below 1990 emission
levels. On October 30, 1998, a number of utilities, including
the Company and its affiliates in the AEP System, filed a
petition in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to
their SIPs within one year of the date of the final rules
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions. Federal EPA
also proposed the approval of portions of the petitions filed
by the eight northeastern states that would result in
<PAGE>
imposition of NOx emission reductions on utility and industrial
sources. These reductions are substantially the same as those
required by the final rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance
with the final rules.
Based on initial studies, preliminary estimates indicate
that compliance costs could result in capital expenditures of
approximately $140 million. Compliance costs can not be
estimated with certainty and the actual costs incurred to
comply could be significantly different from the preliminary
estimate depending upon the compliance alternatives selected
to achieve reductions in NOx emissions. Unless such costs are
recovered from customers, they would have 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 its 1997 Annual Report.
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
Net income increased $6.8 million or 15% for the third quarter
and $18.4 million or 19% for the year-to-date period primarily due
to increased sales to retail customers reflecting warmer summer
weather and growth in wholesale power marketing and trading
activities.
The significant changes in income statement line items and net
revenues were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $530.0 169 $870.5 103
Fuel Expense. . . . . . . . (2.6) (5) 9.3 7
Purchased Power Expense . . 507.4 N.M. 834.3 N.M.
Net Revenues. . . . . . . 25.2 26.9
Other Operation Expense . . 13.0 28 18.6 14
Maintenance Expense . . . . (3.6) (21) (7.5) (15)
Amortization of Zimmer
Plant Phase-in Costs. . . - - (15.7) N.M.
Federal Income Taxes. . . . 7.0 28 12.1 21
Nonoperating Income . . . . (3.0) N.M. (3.1) (155)
N.M. = Not Meaningful
Operating revenues increased significantly in both the third
quarter and the year-to-date period due predominantly to increased
retail and wholesale sales. The increase in retail revenues
resulted from increased sales to residential customers reflecting
warmer summer weather in 1998. Revenues from wholesale customers
increased reflecting substantial increases in power marketing and
trading transactions.
The increase in fuel expense for the year-to-date period was
due to an increase in generation reflecting the increase in demand
for electricity.
Purchased power expense increased primarily as a result of
increased power marketing and trading activities.
<PAGE>
<PAGE>
Net revenues increased $25.2 million in the third quarter and
$26.9 million in the year-to-date period due to increased retail
sales reflecting warmer summer weather and the successful trading
of wholesale energy in a volatile market.
The increase in other operation expense was mainly due to costs
related to the increase in sales including increased emission
allowance consumption, transmission costs and employee pensions and
benefits expense.
Maintenance expense decreased due to the effect of scheduled
power plant maintenance outages in 1997 and a decline in overhead
line maintenance expenditures in 1998. In 1997 two generating
units underwent a scheduled outage for inspection and repairs while
in 1998 only one unit had a scheduled outage for inspection and
repairs. Expenditures for overhead line maintenance declined in
1998 as a result of lower expenditures for tree trimming and repair
of conductors and pole attachments.
The reduction in the amortization of deferred Zimmer Plant
phase-in costs reflects the completion of the surcharge recovery
plan and the amortization of the original deferral in June 1997.
The cessation of the amortization did not affect net income since
the amortization was being recovered in revenues through a
surcharge which terminated with the completion of the amortization.
Federal income taxes attributable to operations increased
primarily due to an increase in pre-tax operating income.
The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions. These
transactions, which are marked-to-market and described in footnote
4, represent non-regulated trading activities outside the Company's
traditional marketing area. Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $945,474 $362,058 $1,978,907 $1,023,879
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 51,014 62,275 133,768 176,051
Purchased Power. . . . . . . . . . . . 625,294 54,043 1,126,651 124,216
Other Operation. . . . . . . . . . . . 97,985 80,399 257,268 240,310
Maintenance. . . . . . . . . . . . . . 39,107 29,408 99,444 85,103
Depreciation and Amortization. . . . . 36,380 35,271 108,407 105,395
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals. . . . . . . - 2,999 - 10,821
Taxes Other Than Federal Income Taxes. 16,514 15,781 49,011 49,657
Federal Income Taxes . . . . . . . . . 20,541 21,433 52,157 61,843
TOTAL OPERATING EXPENSES . . . 886,835 301,609 1,826,706 853,396
OPERATING INCOME . . . . . . . . . . . . 58,639 60,449 152,201 170,483
NONOPERATING INCOME (LOSS) . . . . . . . (2,404) 499 191 1,464
INCOME BEFORE INTEREST CHARGES . . . . . 56,235 60,948 152,392 171,947
INTEREST CHARGES . . . . . . . . . . . . 17,544 15,857 51,421 48,689
NET INCOME . . . . . . . . . . . . . . . 38,691 45,091 100,971 123,258
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,208 1,219 3,627 4,544
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 37,483 $ 43,872 $ 97,344 $118,714
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $279,943 $285,783 $278,814 $269,071
NET INCOME . . . . . . . . . . . . . . . 38,691 45,091 100,971 123,258
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 29,366 44,066 88,098 102,196
Cumulative Preferred Stock . . . . . 1,183 1,186 3,550 3,573
Capital Stock Expense. . . . . . . . . 25 33 77 971
BALANCE AT END OF PERIOD . . . . . . . . $288,060 $285,589 $288,060 $285,589
The common stock of the Company is wholly owned
by American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,555,893 $2,545,484
Transmission . . . . . . . . . . . . . . . . . . . . 912,155 908,736
Distribution . . . . . . . . . . . . . . . . . . . . 756,348 737,902
General (including nuclear fuel) . . . . . . . . . . 229,589 233,888
Construction Work in Progress. . . . . . . . . . . . 129,122 88,487
Total Electric Utility Plant . . . . . . . . 4,583,107 4,514,497
Accumulated Depreciation and Amortization. . . . . . 2,049,510 1,973,937
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,533,597 2,540,560
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . . . . 627,792 566,390
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 211,848 156,085
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 10,838 5,860
Accounts Receivable. . . . . . . . . . . . . . . . . 171,428 137,310
Allowance For Uncollectible Accounts . . . . . . . . (1,978) (1,188)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 15,985 17,182
Materials and Supplies . . . . . . . . . . . . . . . 80,206 78,701
Accrued Utility Revenues . . . . . . . . . . . . . . 40,378 30,521
Prepayments. . . . . . . . . . . . . . . . . . . . . 7,821 4,828
TOTAL CURRENT ASSETS . . . . . . . . . . . . 324,678 273,214
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 413,799 400,489
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 30,583 31,060
TOTAL. . . . . . . . . . . . . . . . . . . $4,142,297 $3,967,798
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(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. . . . . . . . . . . . . . . . . . . 732,573 732,472
Retained Earnings. . . . . . . . . . . . . . . . . . 288,060 278,814
Total Common Shareholder's Equity. . . . . . 1,077,217 1,067,870
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 9,346 9,435
Subject to Mandatory Redemption. . . . . . . . . . 68,445 68,445
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,124,961 1,014,237
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,279,969 2,159,987
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 440,447 381,016
Other. . . . . . . . . . . . . . . . . . . . . . . . 236,876 232,667
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 677,323 613,683
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . - 35,000
Short-term Debt. . . . . . . . . . . . . . . . . . . 103,500 119,600
Accounts Payable . . . . . . . . . . . . . . . . . . 79,011 68,394
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 43,615 46,850
Interest Accrued . . . . . . . . . . . . . . . . . . 16,081 15,741
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 23,427 4,963
Obligations Under Capital Leases . . . . . . . . . . 32,976 34,033
Other. . . . . . . . . . . . . . . . . . . . . . . . 79,289 58,548
TOTAL CURRENT LIABILITIES. . . . . . . . . . 377,899 383,129
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 559,596 559,708
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 132,318 138,045
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 89,639 92,419
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 25,553 20,827
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $4,142,297 $3,967,798
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 100,971 $ 123,258
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 111,510 111,176
Amortization of Rockport Plant Unit 1
Phase-in Plan Deferrals. . . . . . . . . . . . . . . . - 10,821
Deferral of Incremental Nuclear Refueling
Outage Expenses (net). . . . . . . . . . . . . . . . . 11,368 (2,402)
Deferred Federal Income Taxes. . . . . . . . . . . . . . 11,226 (9,753)
Deferred Investment Tax Credits. . . . . . . . . . . . . (5,727) (5,906)
Under-recovery of Fuel and Purchased Power . . . . . . . (42,676) (9,554)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (33,328) 7,029
Fuel, Materials and Supplies . . . . . . . . . . . . . . (308) 8,705
Accrued Utility Revenues . . . . . . . . . . . . . . . . (9,857) 7,284
Accounts Payable . . . . . . . . . . . . . . . . . . . . 10,617 (36,462)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (3,235) (13,615)
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Payment of Disputed Tax and Interest Related to COLI . . . (53,628) -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 24,237 26,966
Net Cash Flows From Operating Activities . . . . . . 139,634 236,011
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (98,218) (79,066)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 4,154 1,798
Net Cash Flows Used For Investing Activities . . . . (94,064) (77,268)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 122,222 47,728
Retirement of Cumulative Preferred Stock . . . . . . . . . (65) (78,838)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (55,000) (50,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . (16,100) 14,350
Dividends Paid on Common Stock . . . . . . . . . . . . . . (88,098) (87,195)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (3,551) (4,746)
Net Cash Flows Used For Financing Activities . . . . (40,592) (158,701)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 4,978 42
Cash and Cash Equivalents at Beginning of Period . . . . . . 5,860 8,233
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 10,838 $ 8,275
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $49,041,000 and $44,575,000
and for income taxes was $20,224,000 and $83,580,000 in 1998 and 1997, respectively.
Noncash acquisitions under capital leases were $7,050,000 and $80,231,000 in 1998
and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial
statements should be read in conjunction with the 1997 Annual
Report as incorporated in and filed with the Form 10-K. In the
opinion of management, the financial statements reflect all
adjustments (consisting of only normal recurring accruals)
which are necessary for a fair presentation of the results of
operations and financial condition for interim periods.
2. FINANCING ACTIVITIES
In 1998 the Company redeemed $35 million of 7.00% first
mortgage bonds at maturity and $20 million of 7.80% first
mortgage bonds due 2023 at face value. In May 1998 $125
million of 7.60% junior subordinated deferrable interest
debentures due 2038 were issued.
3. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in
the first quarter of 1998. SFAS No. 130 established the
standards for reporting and displaying components of
"comprehensive income," which is the total of net income and
all transactions not included in net income affecting equity
except those with shareholders. For the quarter and year-to-date periods
ended September 30, 1998, there are no material
differences between comprehensive income and net income.
In the first quarter of 1998 the Company adopted the
American Institute of Certified Public Accountants' Statement
of Position (SOP) 98-1, "Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use." The SOP
requires the capitalization and amortization of certain costs
of acquiring or developing internal use computer software.
Previously the Company expensed all software acquisition and
development costs. The SOP must be adopted at the beginning
of a fiscal year with no restatement or retroactive adjustment
of prior periods. The adoption of the SOP effective January
1, 1998 did not have a material effect on results of
operations, cash flows or financial condition.
4. POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation,
as agent for the Company and its affiliates in the AEP System
Power Pool (Power Pool), substantially increased the volume of
its electricity marketing and trading. The purpose of the
power marketing and trading business is to utilize AEP's
<PAGE>
knowledge of the energy markets in order to improve the
competitiveness of its generation business and contribute to
net income. Revenues and expenses from these activities are
shared by the Power Pool members based on their relative peak
demands.
The power marketing and trading business involves the
marketing of power under physical forward contracts at fixed
and variable prices and the trading of options, futures, swaps
and other financial derivative contracts at both fixed and
variable prices. Most contracts represent physical forward
electricity marketing contracts for the purchase and sale of
electricity in the Power Pool's traditional marketing area
which are recorded as operating revenues and purchased power
expense when the contracts settle. At September 30, 1998, the
Power Pool had open marketing contracts, not on the balance
sheet, in its traditional marketing area through the year 2004
to sell electricity with a notional value of approximately $1.1
billion and to purchase electricity with a notional value of
approximately $1.1 billion. The Company's share of these
notional values is approximately $200 million.
The Power Pool has also purchased and sold electricity
options, futures, and swaps, and entered into forward purchase
and sale contracts for the future delivery or receipt of
electricity outside its traditional marketing area. These
transactions represent non-regulated trading activities that
are marked-to-market and recorded in nonoperating income. At
September 30, 1998 the Company's share of the unrealized mark-to-market
gains and losses of such trading contracts are
reported as assets and liabilities, respectively. At September
30, 1998, the Power Pool had open marketing contracts outside
its traditional marketing area through the year 2008 to sell
electricity with a notional value of approximately $230 million
and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these
notional values is approximately $45 million for sales and
approximately $30 million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
5. CONTINGENCIES
Taxes
As discussed in Note 7, "Federal Income Taxes" of the Notes
to Consolidated Financial Statements in the 1997 Annual Report,
the Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a
ruling from their National Office that certain interest
deductions relating to corporate owned life insurance (COLI)
claimed by the Company should not be allowed. As a result of
a suit filed in United States District Court (discussed below)
<PAGE>
this request for ruling has been withdrawn. Adjustments have
been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the
COLI interest deduction through September 30, 1998 would reduce
earnings by approximately $64 million (including interest).
The Company has made no provision for any possible adverse
earnings impact from this matter.
In order to resolve this issue without further delay, on
March 24, 1998, the Company filed suit against the United
States in the United States District Court for the Southern
District of Ohio. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit.
In July 1998, the Company made a payment of taxes and interest
attributable to COLI interest deductions for taxable years
1991-96 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
In September 1998 the Company made an additional payment for
the 1997 tax year. The payments were included on the balance
sheet 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.
In the event the resolution of this matter is unfavorable, it
will have a material adverse impact on results of operations
and cash flows.
Cook Nuclear Plant Shutdown
As discussed in Note 3 of the Notes to Consolidated
Financial Statements in the 1997 Annual Report, both units of
the Cook Nuclear Plant were shut down by the Company in
September 1997 due to questions regarding the operability of
certain safety systems, which 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 the issues identified in the letter.
The Company is working with the NRC to resolve a remaining
issue in the letter.
On April 17, 1998, the NRC notified the Company that it had
convened a Restart Panel for the Cook Plant. On July 30, 1998,
the Company received a letter from the NRC providing the NRC's
list of required restart activities. The Company is and will
be meeting with the Panel on a regular basis, until the Cook
Plant units are returned to service, to identify and address
the issues necessary for the restart of the units. 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.
<PAGE>
<PAGE>
The current restart schedule indicates Unit 1 is expected
to return to service by the end of the first quarter of 1999.
The restart schedule for Unit 2 has not been completed;
however, management anticipates that Unit 2 may return to
service 90 days after Unit 1. If the units are not returned
to service, there could be a material adverse effect on
financial condition.
The incremental cost expected to be incurred to restart the
Cook units is approximately $70 million for 1998, of which $34
million has been incurred through September 30, 1998. However,
approximately $20 million of previously budgeted work for 1998
at the Cook Plant will not be incurred and will partially
mitigate the incremental restart costs. The cost and schedule
for the outage during 1999 could be significantly impacted if
additional work is identified beyond the $35 million planned
for the first quarter.
On July 24, 1998, the Company received an "adverse trend
letter" from the NRC indicating that NRC senior managers had
determined that there had been a slow decline in performance
at the Cook Plant during the 18 month period preceding the
letter. The letter indicated that the NRC will closely monitor
efforts to address issues at Cook Plant through additional
inspection activities.
In a letter dated October 13, 1998, the NRC issued to the
Company a Notice of Violation and proposed $500,000 civil
penalty for alleged violations at the Cook Plant discovered
during five inspections conducted between August 4, 1997 and
April 15, 1998. The Company paid the penalty.
The cost of electricity supplied to retail customers rose
due to the outage of the two units since higher cost coal-fired
generation and purchased power were substituted for low cost
nuclear generation. In the Indiana and Michigan retail
jurisdictions 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 the 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 as was the case with regard to Cook, a
regulatory asset is recorded and revenues are accrued.
<PAGE>
<PAGE>
Due to the unscheduled Cook Plant outage, the Company's
actual fuel costs significantly exceeded the estimated fuel
costs reflected in its fuel cost adjustment factors. A
regulatory asset has been recorded for revenues accrued in
anticipation of future reconciliation and billing of the higher
fuel costs to customers. At September 30, 1998, the regulatory
asset was $61 million.
The Indiana Utility Regulatory Commission approved two
agreements authorizing the Company during the billing months
of July through December 1998 to apply a fuel cost adjustment
factor less than that requested by the Company, subject to
future reconciliation or refund. The agreements provide the
parties to the proceedings with the opportunity to conduct
discovery regarding certain issues that were raised in the
proceedings, including the recovery of replacement energy cost
due to the extended Cook Plant outage, in anticipation of
resolving the issues in a future fuel cost adjustment
proceeding. Management believes that the Company should be
able to recover the Cook replacement energy costs; however, if
recovery of the replacement costs is denied, results of
operations and cash flows would be adversely affected.
Revised Air Quality Standards
The United States Environmental Protection Agency (Federal
EPA) published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state
implementation plans (SIPs). SIPs are a procedural method used
by each state to comply with Federal EPA rules. Eight
northeastern states also filed petitions in 1997 with Federal
EPA claiming NOx emissions from plants in midwestern states
prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states,
including the states in which the Company's generating plants
are located. The implementation of the final rules would be
achieved through the revision of SIPs by September 1999 that,
by the year 2003, anticipate the imposition of a NOx reduction
on utility sources of approximately 85% below 1990 emission
levels. On October 30, 1998, a number of utilities, including
the Company and its affiliates in the AEP System, filed a
petition in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to
their SIPs within one year of the date of the final rules
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions. Federal EPA
also proposed the approval of portions of the petitions filed
by the eight northeastern states that would result in
imposition of NOx emission reductions on utility and industrial
sources. These reductions are substantially the same as those
required by the final rules and could be adopted by Federal EPA
<PAGE>
in the event the states fail to implement SIPs in accordance
with the final rules.
Based on initial studies, preliminary estimates indicate
that compliance costs could result in capital expenditures of
approximately $169 million. Compliance costs can not be
estimated with certainty and the actual costs incurred to
comply could be significantly different from the preliminary
estimate depending upon the compliance alternatives selected
to achieve reductions in NOx emissions. Unless such costs are
recovered from customers, they would have 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 its 1997 Annual Report.<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
Despite substantial increases in operating revenues due to
increased retail sales and power marketing and trading activities,
net income decreased $6.4 million or 14% for the quarter and $22.3
million or 18% for the year-to-date period. The decreases in net
income are due primarily to increased costs related to an extended
Cook Nuclear Plant outage, increased purchased power costs, losses
on certain energy trades outside AEP's traditional market area and
a decrease in capacity credits from the AEP System Power Pool
(Power Pool). Under the terms of the Power Pool, capacity credits
and charges are designed to allocate the cost of the AEP System's
capacity among the Power Pool members based on their relative peak
demands and generating reserves. The reduction in capacity credits
received can be attributed to an increase in the Company's prior
twelve month peak demand relative to the total peak demand of all
Power Pool members.
As discussed in Note 5 of the Notes to Consolidated Financial
Statements, the Cook Nuclear Plant was shut down in September 1997.
The shutdown has had a significant impact on the operations of the
Company as reflected in the variations of certain income statement
line items discussed below.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $583.4 161 $ 955.0 93
Fuel Expense . . . . . . . (11.3) (18) (42.3) (24)
Purchased Power Expense. . 571.3 N.M. 1,002.4 N.M.
Other Operation Expense. . 17.6 22 17.0 7
Maintenance Expense. . . . 9.7 33 14.3 17
Amortization of Rockport
Plant Unit 1 Phase-in
Plan Deferrals. . . . . . (3.0) N.M. (10.8) N.M.
Federal Income Taxes . . . (0.9) (4) (9.7) (16)
Nonoperating Income. . . . (2.9) N.M. (1.3) (87)
N.M. = Not Meaningful<PAGE>
<PAGE>
Operating revenues increased significantly in both periods due
predominantly to an increase in sales to retail and wholesale
customers. The increase in retail revenues can be attributed to
increased energy sales to all retail customer classes reflecting
warmer summer weather and increased industrial customer usage.
Fuel and power supply cost recovery accruals also contributed to
the increase in retail revenues. Under the fuel cost recovery
mechanism, revenues are accrued to match increased fuel expense in
both of the Company's retail jurisdictions and for replacement
power costs in the Michigan jurisdiction. The fuel and purchased
power costs incurred are subsequently reviewed by the commissions
and, if acceptable, approved for recovery through billings. During
the extended outage of both nuclear units, retail revenues
increased from the accrual of revenues to match the increased fuel
costs and purchase power expense incurred to replace the
unavailable lower cost nuclear power.
Revenues from wholesale customers increased reflecting growth
in power marketing and trading activities.
Fuel expense decreased significantly in both periods due to a
decline in nuclear generation reflecting the outages of both
nuclear units in 1998.
The significant increase in purchased power expense for both
periods was the result of purchases for the power marketing and
trading business and additional energy purchases from the Power
Pool due to the unavailability of the nuclear units.
Other operation expense increased for both periods as a result
of costs associated with the extended Cook Plant outage and
increased incentive pay accruals.
The increase in maintenance expense for both periods was the
result of additional expenditures to prepare the nuclear units for
restart.
The recovery periods for Rockport Plant Unit 1 costs deferred
under a rate phase-in plan in the Indiana and FERC jurisdictions
ended in the fall of 1997 causing the decrease in amortization of
phase-in plan deferrals. The deferred costs were amortized over a
10-year period commensurate with their collection from customers
pursuant to commission orders. The Company has increased its
<PAGE>
decommissioning expense accruals (approximately $12 million through
September 30, 1998), pending approval from the Indiana Utility
Regulatory Commission (IURC), in an amount equal to the continuing
phase-in plan revenues. On November 12, 1998 the IURC issued an
order that denied the Company's request to increase its
decommissioning accruals and requires the Company to submit revised
quarterly net operating income calculations for each quarter
subsequent to August 1997. The Company will be making the revised
calculations and under the worst case scenario there would be no
favorable impact on results of operations.
Federal income taxes attributable to operations decreased for
the year-to-date period as a result of a decrease in pre-tax
operating income.
The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions. These
transactions, which are marked-to-market and described in footnote
4, represent non-regulated trading activities outside the Company's
traditional marketing area. Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the year-to-date period were $106 million. During the first nine
months of 1998 short-term debt outstanding decreased by $16
million.
During the first nine months of 1998 the Company redeemed two
series of first mortgage bonds; $35 million at 7.00% at maturity
and $20 million at 7.80% due 2023, and issued $125 million of 7.60%
junior subordinated deferrable interest debentures due 2038.
COOK NUCLEAR PLANT SHUTDOWN
As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1997 Annual Report, both units of the Cook
Nuclear Plant were shut down by the Company in September 1997 due
to questions regarding the operability of certain safety systems,
which arose during a Nuclear Regulatory Commission (NRC) architect
engineer design inspection. The NRC issued a Confirmatory Action
<PAGE>
Letter in September 1997 requiring the Company to address the
issues identified in the letter. The Company is working with the
NRC to resolve a remaining issue in the letter.
On April 17, 1998, the NRC notified the Company that it had
convened a Restart Panel for the Cook Plant. On July 30, 1998, the
Company received a letter from the NRC providing the NRC's list of
required restart activities. The Company is and will be meeting
with the Panel on a regular basis, until the Cook Plant units are
returned to service, to identify and address the issues necessary
for the restart of the units. 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.
The current restart schedule indicates Unit 1 is expected to
return to service by the end of the first quarter of 1999. The
restart schedule for Unit 2 has not been completed; however,
management anticipates that Unit 2 may return to service 90 days
after Unit 1. If the units are not returned to service, there
could be a material adverse effect on financial condition.
The incremental cost expected to be incurred to restart the
Cook units is approximately $70 million for 1998, of which $34
million has been incurred through September 30, 1998. However,
approximately $20 million of previously budgeted work for 1998 at
the Cook Plant will not be incurred and will partially mitigate the
incremental restart costs. The cost and schedule for the outage
during 1999 could be significantly impacted if additional work is
identified beyond the $35 million planned for the first quarter.
On July 24, 1998, the Company received an "adverse trend
letter" from the NRC indicating that NRC senior managers had
determined that there had been a slow decline in performance at the
Cook Plant during the 18 month period preceding the letter. The
letter indicated that the NRC will closely monitor efforts to
address issues at Cook Plant through additional inspection
activities.
<PAGE>
<PAGE>
In a letter dated October 13, 1998, the NRC issued to the
Company a Notice of Violation and proposed $500,000 civil penalty
for alleged violations at the Cook Plant discovered during five
inspections conducted between August 4, 1997 and April 15, 1998.
The Company paid the penalty.
As a result of the extended outage, the cost of electricity
supplied to retail customers increased since higher cost coal-fired
generation and purchased power were substituted for low cost
nuclear generation. In the Indiana and Michigan retail
jurisdictions 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 the 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.
Due to the unscheduled Cook Plant outage, the Company's actual
fuel costs significantly exceeded the estimated fuel costs
reflected in its fuel cost adjustment factors. A regulatory asset
has been recorded for revenues accrued in anticipation of future
reconciliation and billing of the higher fuel costs to customers.
At September 30, 1998, the regulatory asset was $61 million.
The IURC approved two agreements authorizing the Company during
the billing months of July through December 1998 to apply a fuel
cost adjustment factor less than that requested by the Company,
subject to future reconciliation or refund. The agreements provide
the parties to the proceedings with the opportunity to conduct
discovery regarding certain issues that were raised in the
proceedings, including the recovery of replacement energy cost due
to the Cook Plant outage, in anticipation of resolving the issues
in a future fuel cost adjustment proceeding. Management believes
that the Company should be able to recover the Cook replacement
costs; however, if recovery of the replacement costs is denied, <PAGE>
<PAGE>
results of operations and cash flows would be adversely affected.
The timetable for the return to service of the Cook Plant
constitute "forward looking statements" as defined in the Private
Securities Litigation Reform Act of 1995. Such statements and
estimates could differ materially from actual results because of
factors referred to specifically in connection with such forward-looking
statements and, in addition, other unforeseen issues
encountered in preparing the Cook Plant for restart and the
unpredictability of the NRC regulatory process.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. Eight northeastern states also
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located.
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels. On October 30, 1998,
a number of utilities, including the Company and its affiliates in
the AEP System, filed a petition in the U.S. Court of Appeals for
the District of Columbia Circuit seeking a review of the final
rules.
Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions. Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources. These reductions are
substantially the same as those required by the final rules and <PAGE>
<PAGE>
could be adopted by Federal EPA in the event the states fail to
implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that
compliance costs could result in capital expenditures of
approximately $169 million. Compliance costs can not be estimated
with certainty and the actual costs incurred to comply could be
significantly different from the preliminary estimate depending
upon the compliance alternatives selected to achieve reductions in
NOx emissions. Unless such costs are recovered from customers,
they would have a material adverse effect on results of operations,
cash flows and possibly financial condition.
POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation, as
agent for the Company and its affiliates in the Power Pool,
substantially increased the volume of its electricity marketing and
trading. The purpose of the power marketing and trading business
is to utilize AEP's knowledge of the energy markets in order to
improve the competitiveness of its generation business and
contribute to net income. Revenues and expenses from these
activities are shared by the Power Pool members based on their
relative peak demands.
The power marketing and trading business involves the marketing
of power under physical forward contracts at fixed and variable
prices and the trading of options, futures, swaps and other
financial derivative contracts at both fixed and variable prices.
Most contracts represent physical forward electricity marketing
contracts for the purchase and sale of electricity in the Power
Pool's traditional marketing area which are recorded as operating
revenues and purchased power expense when the contracts settle.
At September 30, 1998, the Power Pool had open marketing contracts,
not on the balance sheet, in its traditional marketing area through
the year 2004 to sell electricity with a notional value of
approximately $1.1 billion and to purchase electricity with a
notional value of approximately $1.1 billion. The Company's share
of these notional values is approximately $200 million.
<PAGE>
<PAGE>
The Power Pool has also purchased and sold electricity options,
futures, and swaps, and entered into forward purchase and sale
contracts for the future delivery or receipt of electricity outside
its traditional marketing area. These transactions represent non-regulated
trading activities that are marked-to-market and recorded
in nonoperating income. At September 30, 1998 the Company's share
of the unrealized mark-to-market gains and losses of such trading
contracts are reported as assets and liabilities, respectively. At
September 30, 1998, the Power Pool had open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity with a notional value of approximately $230
million and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these notional
values is approximately $45 million for sales and approximately $30
million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
TAXES
As discussed in Note 7, "Federal Income Taxes" of the Notes to
Consolidated Financial Statements in the 1997 Annual Report, the
Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed. As a result of a suit filed in United States
District Court (discussed below) this request for ruling has been
withdrawn. Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions for taxable years 1991-96. A
disallowance of the COLI interest deduction through September 30,
1998 would reduce earnings by approximately $64 million (including
interest). The Company has made no provision for any possible
adverse earnings impact from this matter.
<PAGE>
<PAGE>
In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio.
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit. In July 1998, the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount. In September 1998 the Company made an
additional payment for the 1997 tax year. The payments were
included on the balance sheet 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. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year
2000 ready programs.
Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur.
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 <PAGE>
<PAGE>
the external evaluation, the Company has sought written assurances
from third parties regarding their state of Year 2000 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 Year 2000 readiness
program. NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities. In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills. The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources." In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30, 1999 to June 30, 1999.
Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
Various state regulatory commissions are also reviewing the
Year 2000 readiness of electric utilities subject to their
jurisdiction.
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,
communications, and the physical generation and delivery of energy;
followed by back office activities such as customer
service/billing, regulatory reporting, internal reporting and
administrative activities (e.g. payroll, procurement, accounts <PAGE>
<PAGE>
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 Year 2000 as of September 30, 1998:
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% 11/30/1998 86%
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 2%
replacing or retiring 60%
those mission critical and
high priority digital-based
systems with problems Client
processing dates past the Server:
Year 2000. Testing these 1%
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
Costs to Address the Company's Year 2000 Issues - Through
September 30, 1998, the Company has spent $3 million on the Year
2000 project and, estimates spending an additional $7 million to
$10 million to achieve Year 2000 readiness. Most Year 2000 costs
are software, IT consultant and salary-related 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 Year 2000 ready is not expected to have a material impact
on the Company's results of operations, cash flows or financial <PAGE>
<PAGE>
condition.
Risks of the Company's Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.
In addition, although as discussed 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, Year 2000-related issues may materially adversely
affect AEP.
Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program. The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999. These plans will build upon disaster <PAGE>
<PAGE>
recovery, system restoration, and contingency planning that we now
have in place. We have begun the contingency planning process,
including the review of NERC's Contingency Planning Guide. The
Company plans to submit a draft of its contingency plans to NERC as
part of NERC's review of drafts of regional and individual electric
utility contingency plans in 1999.
Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995. Such statements are based on
management's beliefs as well as assumptions made by, and
information currently available to, management. Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
* Continuing availability of experienced consultants and IT
personnel and related resources
* Ability of third parties to complete their Year 2000
remediations on a timely basis and accuracy of
representations made by such third parties concerning
their Year 2000 readiness
* Ability of the Company to identify and implement
contingency plans.
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $282,319 $89,791 $571,743 $256,472
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 21,478 20,020 61,963 58,647
Purchased Power. . . . . . . . . . . . . 208,945 28,632 375,333 73,775
Other Operation. . . . . . . . . . . . . 13,647 13,241 36,633 37,130
Maintenance. . . . . . . . . . . . . . . 7,335 6,148 23,759 16,826
Depreciation and Amortization. . . . . . 7,068 6,649 20,956 19,708
Taxes Other Than Federal Income Taxes. . 2,668 2,427 7,420 7,266
Federal Income Taxes . . . . . . . . . . 4,627 1,837 7,406 7,614
TOTAL OPERATING EXPENSES. . . . . 265,768 78,954 533,470 220,966
OPERATING INCOME . . . . . . . . . . . . . 16,551 10,837 38,273 35,506
NONOPERATING LOSS. . . . . . . . . . . . . (902) (62) (1,066) (351)
INCOME BEFORE INTEREST CHARGES . . . . . . 15,649 10,775 37,207 35,155
INTEREST CHARGES . . . . . . . . . . . . . 7,207 6,323 21,335 18,431
NET INCOME . . . . . . . . . . . . . . . . $ 8,442 $ 4,452 $ 15,872 $ 16,724
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $71,356 $82,982 $78,076 $84,090
NET INCOME . . . . . . . . . . . . . . . . 8,442 4,452 15,872 16,724
CASH DIVIDENDS DECLARED. . . . . . . . . . 7,075 6,690 21,225 20,070
BALANCE AT END OF PERIOD . . . . . . . . . $72,723 $80,744 $72,723 $80,744
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Financial Statements.<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $ 259,980 $ 249,184
Transmission . . . . . . . . . . . . . . . . . . . . 325,854 303,456
Distribution . . . . . . . . . . . . . . . . . . . . 347,834 350,793
General. . . . . . . . . . . . . . . . . . . . . . . 74,670 71,462
Construction Work in Progress. . . . . . . . . . . . 24,167 32,060
Total Electric Utility Plant . . . . . . . . 1,032,505 1,006,955
Accumulated Depreciation and Amortization. . . . . . 310,083 296,318
NET ELECTRIC UTILITY PLANT . . . . . . . . . 722,422 710,637
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 12,031 6,414
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 955 1,381
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 18,122 24,127
Affiliated Companies . . . . . . . . . . . . . . . 11,469 1,722
Miscellaneous. . . . . . . . . . . . . . . . . . . 4,221 3,276
Allowance for Uncollectible Accounts . . . . . . . (698) (525)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 9,300 10,685
Materials and Supplies . . . . . . . . . . . . . . . 14,212 14,054
Accrued Utility Revenues . . . . . . . . . . . . . . 11,587 12,981
Other. . . . . . . . . . . . . . . . . . . . . . . . 3,568 1,715
TOTAL CURRENT ASSETS . . . . . . . . . . . . 72,736 69,416
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 91,502 90,045
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 6,788 10,159
TOTAL. . . . . . . . . . . . . . . . . . . $ 905,479 $ 886,671
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares . . . . . . . . . . $ 50,450 $ 50,450
Paid-in Capital. . . . . . . . . . . . . . . . . . . 138,750 128,750
Retained Earnings. . . . . . . . . . . . . . . . . . 72,723 78,076
Total Common Shareholder's Equity. . . . . . 261,923 257,276
Long-term Debt . . . . . . . . . . . . . . . . . . . 313,979 341,051
TOTAL CAPITALIZATION . . . . . . . . . . . . 575,902 598,327
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 28,124 26,544
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 25,000 -
Short-term Debt. . . . . . . . . . . . . . . . . . . 49,350 36,500
Accounts Payable . . . . . . . . . . . . . . . . . . 20,817 24,574
Customer Deposits. . . . . . . . . . . . . . . . . . 3,999 3,660
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 4,937 6,130
Interest Accrued . . . . . . . . . . . . . . . . . . 8,097 6,015
Other. . . . . . . . . . . . . . . . . . . . . . . . 18,069 15,084
TOTAL CURRENT LIABILITIES. . . . . . . . . . 130,269 91,963
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 155,655 153,945
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 14,700 15,615
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 829 277
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $905,479 $886,671
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 15,872 $ 16,724
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 20,966 19,718
Deferred Federal Income Taxes. . . . . . . . . . . . . . 1,173 163
Deferred Investment Tax Credits. . . . . . . . . . . . . (915) (924)
Amortization of Deferred Property Taxes. . . . . . . . . 3,840 3,690
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (4,514) (305)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 1,227 (113)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 1,394 1,712
Accounts Payable . . . . . . . . . . . . . . . . . . . . (3,757) (9,040)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (1,193) (1,237)
Payment of Disputed Taxes and Interest Related to COLI . . (5,376) -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 1,952 5,301
Net Cash Flows From Operating Activities . . . . . . 30,669 35,689
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (30,517) (45,023)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . 10,000 10,000
Change in Short-term Debt (net). . . . . . . . . . . . . . 12,850 19,775
Retirement of Long-term Debt . . . . . . . . . . . . . . . (2,203) -
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (21,225) (20,070)
Net Cash Flows From (Used For) Financing Activities. (578) 9,705
Net Increase (Decrease) in Cash and Cash Equivalents . . . . (426) 371
Cash and Cash Equivalents at Beginning of Period . . . . . . 1,381 1,106
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 955 $ 1,477
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $18,950,000 and $16,950,000
and for income taxes was $5,812,000 and $8,115,000 in 1998 and 1997, respectively.
Noncash acquisitions under capital leases were $4,448,000 and $3,571,000 in 1998
and 1997, respectively.
</TABLE>
See Notes to Financial Statements.
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be
read in conjunction with the 1997 Annual Report as incorporated
in and filed with the Form 10-K. In the opinion of management,
the financial statements reflect all adjustments (consisting
of only normal recurring accruals) which are necessary for a
fair presentation of the results of operations and financial
condition for interim periods.
2. FINANCING ACTIVITIES
The Company received from its parent a cash capital
contribution of $10 million in June 1998 which was credited to
paid-in capital.
3. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in
the first quarter of 1998. SFAS No. 130 established the
standards for reporting and displaying components of
"comprehensive income," which is the total of net income and
all transactions not included in net income affecting equity
except those with shareholders. For the quarter and year-to-date periods
ended September 30, 1998, there were no material
differences between comprehensive income and net income.
In the first quarter of 1998 the Company adopted the
American Institute of Certified Public Accountants' Statement
of Position (SOP) 98-1, "Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use". The SOP
requires the capitalization and amortization of certain costs
of acquiring or developing internal use computer software.
Previously the Company expensed all software acquisition and
development costs. The SOP must be adopted at the beginning
of a fiscal year with no restatement or retroactive adjustment
of prior periods. The adoption of the SOP effective January
1, 1998 did not have a material effect on results of
operations, cash flows or financial condition.
4. POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation,
as agent for the Company and its affiliates in the AEP System
Power Pool (Power Pool), substantially increased the volume of
its electricity marketing and trading. The purpose of the
power marketing and trading business is to utilize AEP's
knowledge of the energy markets in order to improve the
competitiveness of its generation business and contribute to
net income. Revenues and expenses from these activities are <PAGE>
<PAGE>
shared by the Power Pool members based on their relative peak
demands.
The power marketing and trading business involves the
marketing of power under physical forward contracts at fixed
and variable prices and the trading of options, futures, swaps
and other financial derivative contracts at both fixed and
variable prices. Most contracts represent physical forward
electricity marketing contracts for the purchase and sale of
electricity in the Power Pool's traditional marketing area
which are recorded as operating revenues and purchased power
expense when the contracts settle. At September 30, 1998, the
Power Pool had open marketing contracts, not on the balance
sheet, in its traditional marketing area through the year 2004
to sell electricity with a notional value of approximately $1.1
billion and to purchase electricity with a notional value of
approximately $1.1 billion. The Company's share of these
notional values is approximately $70 million.
The Power Pool has also purchased and sold electricity
options, futures, and swaps, and entered into forward purchase
and sale contracts for the future delivery or receipt of
electricity outside its traditional marketing area. These
transactions represent non-regulated trading activities that
are marked-to-market and recorded in nonoperating loss. At
September 30, 1998, the Company's share of the unrealized mark-to-market
gains and losses from such trading contracts are
reported as assets and liabilities, respectively. At September
30, 1998, the Power Pool had open marketing contracts outside
its traditional marketing area through the year 2008 to sell
electricity with a notional value of approximately $230 million
and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these
notional values is approximately $15 million for sales and
approximately $10 million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
5. CONTINGENCIES
Taxes
As discussed in Note 8, "Federal Income Taxes" of the Notes
to Financial Statements in the 1997 Annual Report, the Internal
Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating
to corporate owned life insurance (COLI) claimed by the Company
should not be allowed. As a result of a suit filed in United
States District Court (discussed below) this request for ruling
has been withdrawn. Adjustments have been or will be proposed
by the IRS disallowing COLI interest deductions for taxable
years 1992-96. A disallowance of COLI interest deductions<PAGE>
<PAGE>
through September 30, 1998 would reduce earnings by
approximately $7 million (including interest). The Company has
made no provision for any possible adverse earnings impact from
this matter.
In order to resolve this issue without further delay, on
March 24, 1998, the Company filed suit against the United
States in the United States District Court for the Southern
District of Ohio. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit.
In July 1998, the Company made a payment of taxes and interest
attributable to COLI interest deductions for taxable years
1992-96 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
In September 1998 the Company made an additional payment for
the 1997 tax year. The payments were included on the balance
sheet 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.
In the event the resolution of this matter is unfavorable, it
will have a material adverse impact on results of operations
and cash flows.
Revised Air Quality Standards
The United States Environmental Protection Agency (Federal
EPA) published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state
implementation plans (SIPs). SIPs are a procedural method used
by each state to comply with Federal EPA rules. Eight
northeastern states also filed petitions in 1997 with Federal
EPA claiming NOx emissions from plants in midwestern states
prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states,
including the states in which the Company's generating plants
are located. The implementation of the final rules would be
achieved through the revision of SIPs by September 1999 that,
by the year 2003, anticipate the imposition of a NOx reduction
on utility sources of approximately 85% below 1990 emission
levels. On October 30, 1998, a number of utilities, including
the Company and its affiliates in the AEP System, filed a
petition in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to
their SIPs within one year of the date of the final rules
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions. Federal EPA
also proposed the approval of portions of the petitions filed
by the eight northeastern states that would result in
imposition of NOx emission reductions on utility and industrial
sources. These reductions are substantially the same as those
required by the final rules and could be adopted by Federal EPA
<PAGE>
<PAGE>
in the event the states fail to implement SIPs in accordance
with the final rules.
Based on initial studies, preliminary estimates indicate
that compliance costs could result in capital expenditures of
approximately $105 million. Compliance costs can not be
estimated with certainty and the actual costs incurred to
comply could be significantly different from the preliminary
estimate depending upon the compliance alternatives selected
to achieve reductions in NOx emissions. Unless such costs are
recovered from customers, they would have 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 its 1997 Annual Report.
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
Net income increased $4 million or 90% for the quarter and
decreased $0.9 million or 5% for the year-to-date period. The
increase in net income for the quarter is attributable to an
increase in retail and wholesale revenues reflecting increased
sales. The decline in year-to-date net income is due to increased
maintenance and interest costs.
The significant changes in income statement line items and net
revenues were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $192.5 214 $315.3 123
Fuel Expense. . . . . . . . 1.5 7 3.3 6
Purchased Power Expense . . 180.3 N.M. 301.6 409
Net Revenues 10.7 10.4
Maintenance Expense . . . . 1.2 19 6.9 41
Depreciation and
Amortization. . . . . . . 0.4 6 1.2 6
Federal Income Taxes. . . . 2.8 152 (0.2) (3)
Nonoperating Loss . . . . . (0.8) N.M. (0.7) N.M.
Interest Charges. . . . . . 0.9 14 2.9 16
N.M. = Not Meaningful
The substantial increases in operating revenues for the third
quarter and year-to-date periods were due primarily to increased
sales volume. Retail revenues increased 4% in the third quarter
and 2% year-to-date reflecting the impact of warmer summer weather
on retail usage. Wholesale revenues increased in both periods due
to growth in the power marketing and trading business which
contributed substantially to an increase in wholesale sales.
Fuel expense increased due to additional generation to meet the
increase in demand and an increase in the cost of coal.
The significant increase in purchased power expense resulted
from the growth of the power marketing and trading business.
<PAGE>
<PAGE>
Net revenues increased $10.7 million in the third quarter and
$10.4 million in the year-to-date period due to increased retail
sales reflecting the impact of warmer summer weather and the
successful trading of wholesale energy in a volatile market.
The increase in maintenance expense in both periods reflects
the effects of scheduled steam plant maintenance work in 1998 at
the Company's Big Sandy Plant and, for the year-to-date period,
expenditures for repair and restoration of distribution service
caused by two severe snowstorms.
Depreciation and amortization expense increased due to
additional investment in depreciable plant reflecting improvements
to the transmission and distribution systems completed during 1997.
The increase in federal income taxes for the third quarter
resulted from an increase in pre-tax operating income.
Nonoperating income declined due to losses on certain power
marketing and trading transactions. These transactions, which are
marked-to-market and described in footnote 4, represent non-regulated
trading activities outside the Company's traditional
marketing area. Although losses were incurred on these non-regulated energy
trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
The increase in interest charges reflects an increase in
outstanding long-term debt due to the issuance of Senior Unsecured
Notes in October 1997.
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $1,361,336 $486,398 $2,901,072 $1,417,845
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 199,934 156,482 574,156 462,720
Purchased Power. . . . . . . . . . . . 824,021 37,270 1,392,404 69,738
Other Operation. . . . . . . . . . . . 96,254 78,623 260,097 240,182
Maintenance. . . . . . . . . . . . . . 34,900 39,443 98,651 102,292
Depreciation and Amortization. . . . . 36,236 35,323 108,097 105,351
Taxes Other Than Federal Income Taxes. 42,931 42,938 127,451 126,801
Federal Income Taxes . . . . . . . . . 38,222 27,203 102,444 92,022
TOTAL OPERATING EXPENSES . . . 1,272,498 417,282 2,663,300 1,199,106
OPERATING INCOME . . . . . . . . . . . . 88,838 69,116 237,772 218,739
NONOPERATING INCOME (LOSS) . . . . . . . (2,665) 2,273 2,022 9,803
INCOME BEFORE INTEREST CHARGES . . . . . 86,173 71,389 239,794 228,542
INTEREST CHARGES . . . . . . . . . . . . 20,212 20,718 60,338 61,961
NET INCOME . . . . . . . . . . . . . . . 65,961 50,671 179,456 166,581
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 369 370 1,107 2,278
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 65,592 $ 50,301 $ 178,349 $ 164,303
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1998 1997 1998 1997
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $597,357 $573,236 $590,151 $584,015
NET INCOME . . . . . . . . . . . . . . . 65,961 50,671 179,456 166,581
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 52,775 37,562 158,325 161,771
Cumulative Preferred Stock . . . . . 369 370 1,108 2,829
Capital Stock Expense. . . . . . . . . - - - 21
BALANCE AT END OF PERIOD . . . . . . . . $610,174 $585,975 $610,174 $585,975
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
</TABLE>
See Notes to Consolidated Financial Statements.<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,636,368 $2,606,981
Transmission . . . . . . . . . . . . . . . . . . . . 841,410 837,953
Distribution . . . . . . . . . . . . . . . . . . . . 938,470 927,239
General (including mining assets). . . . . . . . . . 686,593 709,475
Construction Work in Progress. . . . . . . . . . . . 103,453 74,149
Total Electric Utility Plant . . . . . . . . 5,206,294 5,155,797
Accumulated Depreciation and Amortization. . . . . . 2,425,511 2,349,995
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,780,783 2,805,802
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 219,677 113,279
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 95,620 44,203
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 329,254 196,982
Affiliated Companies . . . . . . . . . . . . . . . 73,956 55,597
Miscellaneous. . . . . . . . . . . . . . . . . . . 20,884 43,594
Allowance for Uncollectible Accounts . . . . . . . (1,838) (2,501)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 87,763 119,543
Materials and Supplies . . . . . . . . . . . . . . . 84,433 80,853
Accrued Utility Revenues . . . . . . . . . . . . . . 43,900 37,586
Prepayments. . . . . . . . . . . . . . . . . . . . . 37,905 37,257
TOTAL CURRENT ASSETS . . . . . . . . . . . . 771,877 613,114
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 528,068 523,891
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 46,127 107,116
TOTAL. . . . . . . . . . . . . . . . . . . $4,346,532 $4,163,202
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1998 1997
(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. . . . . . . . . . . . . . . . . . . 462,314 462,296
Retained Earnings. . . . . . . . . . . . . . . . . . 610,174 590,151
Total Common Shareholder's Equity. . . . . . 1,393,689 1,373,648
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 17,471 17,542
Subject to Mandatory Redemption. . . . . . . . . . 11,850 11,850
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,027,587 1,012,031
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,450,597 2,415,071
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 315,114 295,375
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 16,289 83,195
Short-term Debt. . . . . . . . . . . . . . . . . . . 98,808 78,700
Accounts Payable - General . . . . . . . . . . . . . 286,042 146,824
Accounts Payable - Affiliated Companies. . . . . . . 44,392 37,923
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 114,435 160,055
Interest Accrued . . . . . . . . . . . . . . . . . . 22,165 16,255
Obligations Under Capital Leases . . . . . . . . . . 27,994 30,307
Other. . . . . . . . . . . . . . . . . . . . . . . . 114,733 94,829
TOTAL CURRENT LIABILITIES. . . . . . . . . . 724,858 648,088
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 723,718 723,172
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 40,293 42,821
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 91,952 38,675
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $4,346,532 $4,163,202
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1998 1997
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 179,456 $ 166,581
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . 129,366 129,597
Deferred Federal Income Taxes. . . . . . . . . . . . . . 12,504 85
Amortization of Deferred Property Taxes. . . . . . . . . 58,664 57,646
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (128,584) (9,892)
Fuel, Materials and Supplies . . . . . . . . . . . . . . 28,200 (5,112)
Accrued Utility Revenues . . . . . . . . . . . . . . . . (6,314) 10,044
Accounts Payable . . . . . . . . . . . . . . . . . . . . 145,687 34,712
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (45,620) (80,111)
Other Current Assets and Current Liabilities . . . . . . 22,853 31,267
Payment of Disputed Tax and Interest Related to COLI . . . (104,222) -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 68,381 (24,047)
Net Cash Flows From Operating Activities . . . . . . 360,371 310,770
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (121,310) (102,469)
Proceeds from Sale of Property and Other . . . . . . . . . 4,348 8,553
Net Cash Flows Used For Investing Activities . . . . (116,962) (93,916)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 137,566 146,589
Change in Short-term Debt (net). . . . . . . . . . . . . . 20,108 53,123
Retirement of Cumulative Preferred Stock . . . . . . . . . (52) (117,601)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (190,181) (119,542)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (158,325) (161,771)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,108) (2,829)
Net Cash Flows Used For Financing Activities . . . . (191,992) (202,031)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 51,417 14,823
Cash and Cash Equivalents at Beginning of Period . . . . . . 44,203 24,003
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 95,620 $ 38,826
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $52,523,000 and $54,010,000
and for income taxes was $55,898,000 and $98,341,000 in 1998 and 1997, respectively.
Noncash acquisitions under capital leases were $24,740,000 and $41,677,000 in 1998
and 1997, respectively.
</TABLE>
See Notes to Consolidated Financial Statements.
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements
should be read in conjunction with the 1997 Annual Report
as incorporated in and filed with the Form 10-K. In the
opinion of management, the financial statements reflect all
adjustments (consisting of only normal recurring accruals)
which are necessary for a fair presentation of the results of
operations and financial condition for interim periods.
2. FINANCING ACTIVITY
In April 1998 the Company issued $140 million of 7-3/8%
senior unsecured notes due 2038. During the first nine months
of 1998 the Company and a subsidiary retired $183 million of
long-term debt: $56 million of 6-3/4% first mortgage bonds and
$17 million of 6.85% notes payable at maturity and two series
of $50 million first mortgage bonds due in 2002 with interest
rates of 8.10% and 8.25% and $10 million of variable rate notes
payable due in 1999.
As a result of the redemption of the 6-3/4% series first
mortgage bonds due in 1998, the restriction on the use of
retained earnings for the payment of common stock dividends was
eliminated.
3. NEW ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130
"Reporting Comprehensive Income" was adopted by the Company in
the first quarter of 1998. SFAS No. 130 established the
standards for reporting and displaying components of
"comprehensive income," which is the total of net income and
all transactions not included in net income affecting equity
except those with shareholders. For the quarter and year-to-date periods
ended September 30, 1998, there are no material
differences between comprehensive income and net income.
In the first quarter of 1998 the Company adopted the
American Institute of Certified Public Accountants' Statement
of Position (SOP) 98-1, "Accounting for the Costs of Computer
Software Developed or Obtained for Internal Use." The SOP
requires the capitalization and amortization of certain costs
of acquiring or developing internal use computer software.
Previously the Company expensed all software acquisition and
development costs. The SOP must be adopted at the beginning
of a fiscal year with no restatement or retroactive adjustment
of prior periods. The adoption of the SOP effective January
1, 1998 did not have a material effect on results of
operations, cash flows or financial condition.
<PAGE>
<PAGE>
4. POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation,
as agent for the Company and its affiliates in the AEP System
Power Pool (Power Pool), substantially increased the volume of
its electricity marketing and trading. The purpose of the
power marketing and trading business is to utilize AEP's
knowledge of the energy markets in order to improve the
competitiveness of its generation business and contribute to
net income. Revenues and expenses from these activities are
shared by the Power Pool members based on their relative peak
demands.
The power marketing and trading business involves the
marketing of power under physical forward contracts at fixed
and variable prices and the trading of options, futures, swaps
and other financial derivative contracts at both fixed and
variable prices. Most contracts represent physical forward
electricity marketing contracts for the purchase and sale of
electricity in the Power Pool's traditional marketing area
which are recorded as operating revenues and purchased power
expense when the contracts settle. At September 30, 1998, the
Power Pool had open marketing contracts, not on the balance
sheet, in its traditional marketing area through the year 2004
to sell electricity with a notional value of approximately $1.1
billion and to purchase electricity with a notional value of
approximately $1.1 billion. The Company's share of these
notional values is approximately $290 million.
The Power Pool has also purchased and sold electricity
options, futures, and swaps, and entered into forward purchase
and sale contracts for the future delivery or receipt of
electricity outside the traditional marketing area. These
transactions represent non-regulated trading activities that
are marked-to-market and recorded in nonoperating income. At
September 30, 1998, the Company's share of the unrealized mark-to-market
gains and losses from such trading contracts are
reported as assets and liabilities, respectively. At
September 30, 1998, the Power Pool had open marketing contracts
outside its traditional marketing area through the year 2008
to sell electricity with a notional value of approximately $230
million and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these
notional values is approximately $65 million for sales and
approximately $40 million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
<PAGE>
<PAGE>
5. CONTINGENCIES
Taxes
As discussed in Note 8, "Federal Income Taxes" of the Notes
to Consolidated Financial Statements in the 1997 Annual Report,
the Internal Revenue Service (IRS) agents auditing the AEP
System's consolidated federal income tax returns requested a
ruling from their National Office that certain interest
deductions relating to corporate owned life insurance (COLI)
claimed by the Company should not be allowed. As a result of
a suit filed in United States District Court (discussed below)
this request for ruling has been withdrawn. Adjustments have
been or will be proposed by the IRS disallowing COLI interest
deductions for taxable years 1991-96. A disallowance of the
COLI interest deduction through September 30, 1998 would reduce
earnings by approximately $115 million (including interest).
The Company has made no provision for any possible adverse
earnings impact from this matter.
In order to resolve this issue without further delay, on
March 24, 1998, the Company filed suit against the United
States in the United States District Court for the Southern
District of Ohio. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit.
In July 1998 the Company made a payment of taxes and interest
attributable to COLI interest deductions for taxable years
1991-96 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
In September 1998 the Company made an additional payment for
the 1997 tax year. The payments were included on the balance
sheet 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.
In the event the resolution of this matter is unfavorable, it
will have a material adverse impact on results of operations
and cash flows.
Revised Air Quality Standards
The United States Environmental Protection Agency (Federal
EPA) published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state
implementation plans (SIPs). SIPs are a procedural method used
by each state to comply with Federal EPA rules. Eight
northeastern states also filed petitions in 1997 with Federal
EPA claiming NOx emissions from plants in midwestern states
prevent them from complying with air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states,
including the states in which the Company's generating plants
are located. The implementation of the final rules would be
achieved through the revision of SIPs by September 1999 that,
by the year 2003, anticipate the imposition of a NOx reduction
on utility sources of approximately 85% below 1990 emission <PAGE>
<PAGE>
levels. On October 30, 1998, a number of utilities, including
the Company and its affiliates in the AEP System, filed a
petition in the U.S. Court of Appeals for the District of
Columbia Circuit seeking a review of the final rules.
Should the states fail to adopt the required revisions to
their SIPs within one year of the date of the final rules
(September 24, 1999), Federal EPA has proposed to implement a
federal plan to accomplish the NOx reductions. Federal EPA
also proposed the approval of portions of the petitions filed
by the eight northeastern states that would result in
imposition of NOx emission reductions on utility and industrial
sources. These reductions are substantially the same as those
required by the final rules and could be adopted by Federal EPA
in the event the states fail to implement SIPs in accordance
with the final rules.
Based on initial studies, preliminary estimates indicate
that compliance costs could result in required capital
expenditures by the Company of approximately $452 million.
Compliance costs can not be estimated with certainty and the
actual costs incurred to comply could be significantly
different from the preliminary estimate depending upon the
compliance alternatives selected to achieve reductions in NOx
emissions. Unless such costs are recovered from customers,
they would have 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 1997 Annual Report.
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
THIRD QUARTER 1998 vs. THIRD QUARTER 1997
AND
YEAR-TO-DATE 1998 vs. YEAR-TO-DATE 1997
RESULTS OF OPERATIONS
Net income increased $15.3 million or 30% for the quarter and
$12.9 million or 8% for the year-to-date period primarily due to
increased energy sales to retail customers, reflecting warmer
summer weather and increased industrial energy consumption, and
growth in wholesale power marketing and trading activities.
The significant changes in income statement line items and net
revenues were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . $874.9 180 $1,483.2 105
Fuel Expense. . . . . . . 43.5 28 111.4 24
Purchased Power . . . . . 786.8 N.M. 1,322.7 N.M.
Net Revenues. . . . . . 44.6 49.1
Other Operation Expense . 17.6 22 19.9 8
Maintenance Expense . . . (4.5) (12) (3.6) (4)
Federal Income Taxes. . . 11.0 41 10.4 11
Nonoperating Income . . . (4.9) (217) (7.8) (79)
N.M. = Not Meaningful
Operating revenues increased significantly in both the third
quarter and year-to-date periods due predominantly to increased
retail and wholesale sales. Retail sales increased 6% in the third
quarter and 4% year-to-date reflecting warmer summer weather in
1998 and the resumption of operations by a major industrial
customer following an extended labor strike. Operating revenues
from wholesale sales increased significantly as a result of growth
in power marketing and trading activities and increased sales to
the AEP System Power Pool (Power Pool) to replace power previously
generated at an affiliate's nuclear plant which was out of service.
<PAGE>
<PAGE>
The increases in fuel expense for the third quarter and year-to-date
periods were mainly due to an increase in generation,
reflecting the rise in demand and the replacement of energy
previously supplied to the Power Pool by an affiliate's out-of-service
nuclear plant, and an increase in the cost of fuel
consumed.
Purchased power expense increased substantial for both periods
primarily due to the growth of power marketing and trading
activities.
The increase in net revenues of $45 million in the third
quarter and $49 million in the year-to-date period reflects the
impact of warmer summer weather and increased industrial usage on
retail sales and the successful trading of wholesale energy in a
volatile market.
Other operation expense increased in both periods primarily due
to costs related to the increase in energy sales, employer pension
and benefit expense, a reduction in gains on emission allowance
sales and increased costs under the AEP System transmission
equalization agreement. The transmission equalization agreement
combines certain AEP System companies' investment in transmission
facilities and shares the costs of ownership of those facilities in
proportion to each AEP System company's peak demand relative to the
peak demands of all AEP System companies utilizing the AEP System
transmission system. The charges paid by the Company under the
agreement increased due to an increase in the Company's prior
twelve month peak demand relative to the total peak demand of all
transmission agreement members.
The decreases in maintenance expense for both periods were
mainly due to decreased boiler plant maintenance reflecting a
reduction in planned maintenance work on the Company's generating
units.
Federal income taxes attributable to operations increased due
to an increase in pre-tax operating income.
<PAGE>
<PAGE>
The decrease in nonoperating income is primarily due to losses
on certain power marketing and trading transactions. These
transactions, which are marked-to-market and described in footnote
4, represent non-regulated trading activities outside the Company's
traditional marketing area. Although losses were incurred on these
non-regulated energy trades, net revenues from power marketing and
trading operations within the Company's traditional marketing area
were significantly larger.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first nine months of 1998 were $146 million.
During the first nine months of 1998, the Company and a
subsidiary retired $183 million principal amount of long-term debt
with interest rates ranging from 6.11% to 8.25%, issued $140
million of senior unsecured notes at an interest rate of 7-3/8% and
increased short-term debt by $20 million.
As a result of the redemption of the 6-3/4% series first
mortgage bonds due in 1998, the restriction on the use of retained
earnings for the payment of common stock dividends was eliminated.
REVISED AIR QUALITY STANDARDS
The United States Environmental Protection Agency (Federal EPA)
published in October 1997 a proposed nitrogen oxides (NOx)
emissions reduction rule which called for new state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. Eight northeastern states also
filed petitions in 1997 with Federal EPA claiming NOx emissions
from plants in midwestern states prevent them from complying with
air quality standards.
On September 24, 1998, Federal EPA issued final rules which
require reductions in NOx emissions in 22 eastern states, including
the states in which the Company's generating plants are located.
The implementation of the final rules would be achieved through the
revision of SIPs by September 1999 that, by the year 2003,
anticipate the imposition of a NOx reduction on utility sources of
approximately 85% below 1990 emission levels. On October 30, 1998,
a number of utilities, including the Company and its affiliates in
the AEP System, filed a petition in the U.S. Court of Appeals for <PAGE>
<PAGE>
the District of Columbia Circuit seeking a review of the final
rules.
Should the states fail to adopt the required revisions to their
SIPs within one year of the date of the final rules (September 24,
1999), Federal EPA has proposed to implement a federal plan to
accomplish the NOx reductions. Federal EPA also proposed the
approval of portions of the petitions filed by the eight
northeastern states that would result in imposition of NOx emission
reductions on utility and industrial sources. These reductions are
substantially the same as those required by the final rules and
could be adopted by Federal EPA in the event the states fail to
implement SIPs in accordance with the final rules.
Based on initial studies, preliminary estimates indicate that
compliance costs could result in required capital expenditures by
the Company of approximately $452 million. Compliance costs can
not be estimated with certainty and the actual costs incurred to
comply could be significantly different from the preliminary
estimate depending upon the compliance alternatives selected to
achieve reductions in NOx emissions. Unless such costs are
recovered from customers, they would have a material adverse effect
on results of operations, cash flows and possibly financial
condition.
COMPUTER ISSUE - YEAR 2000
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems were 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-Year
2000 ready programs.
<PAGE>
<PAGE>
Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Year 2000-related failures and repair such failures if they occur.
This includes both information technology systems (IT), which are
mainframe and client server applications, and embedded logic
systems (non-IT), 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 Year 2000 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 Year 2000 readiness
program. NERC then publicly reports summary information to the
U.S. Department of Energy regarding the Year 2000 readiness of
electric utilities. In 1999 AEP plans to participate in two
NERC-sponsored coordinated electric industry Year 2000 readiness
drills.
The first NERC report, dated September 17, 1998 and titled
Preparing the Electric Power Systems of North America for
Transition to the Year 2000-A Status Report and Work Plan, states
that: "Mission critical systems and components are to be made Y2K
Ready by June 30, 1999." In addition, the report indicates that:
"While many organizations are on track to meet these targets, many
others need to accelerate project plans and resources." In
response to the report, the Company has accelerated its Year 2000
readiness date for mission critical and high priority systems and
components from September 30 to June 30, 1999.
Through the Electric Power Research Institute, an electric
industry-wide effort has been established to deal with Year 2000
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.<PAGE>
<PAGE>
Various state commissions are also reviewing the Year 2000
readiness of electric utilities subject to their jurisdiction.
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,
communications, and the physical generation and delivery of energy;
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 Year 2000 as of September 30, 1998:
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% 11/30/1998 86%
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 2%
replacing or retiring 60%
those mission critical and
high priority digital-based Client
systems with problems Server:
processing dates past the 1%
Year 2000. Testing these
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
<PAGE>
<PAGE>
Costs to Address the Company's Year 2000 Issues - Through
September 30, 1998, the Company has spent $5 million on the Year
2000 project and, estimates spending an additional $12 million to
$16 million to achieve Year 2000 readiness. Most Year 2000 costs
are software- and salary-related and are expensed; however, in
certain cases the Company has acquired hardware that is
capitalized. The Company intends to fund these expenditures
through internal sources. Although significant, the cost of
becoming Year 2000 ready 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 Year 2000 Issues - The applications
posing the greatest business risk to the Company's operations
should they experience Year 2000 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.
In addition, although as discussed 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.
<PAGE>
<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 not affiliated with AEP, fail for critical
applications, Year 2000-related issues may materially adversely
affect AEP.
Company's Contingency Plans - The Company intends to establish
contingency plans on a case-by-case basis to address alternatives
if Year 2000 failures of automatic systems and equipment occur as
part of its Year 2000 readiness program. The contingency plans
will be based upon a risk analysis process and will be developed by
the fourth quarter of 1999. These plans will build upon disaster
recovery, system restoration, and contingency planning that we now
have in place. We have begun the contingency planning process,
including the review of NERC's contingency planning and
preparations guide. The Company plans to submit a draft of its
contingency plans to NERC as part of NERC's review of drafts of
regional and individual electric utility contingency plans in 1999.
Forward-Looking Statements - This description of Year 2000
problems, the consequences of Year 2000 failures and the estimated
costs of, and timetable for, becoming Year 2000 ready constitute
"forward looking statements" as defined in the Private Securities
Litigation Reform Act of 1995. Such statements are based on
management's beliefs as well as assumptions made by, and
information currently available to, management. Investors are
cautioned that such statements and estimates could differ
materially from actual results because of factors referred to
specifically in connection with such forward-looking statements
and, in addition, the following other factors, among others:
<PAGE>
<PAGE>
* Continuing availability of experienced consultants and IT
personnel and related resources
* Ability of third parties to complete their Year 2000
remediations on a timely basis and accuracy of
representations made by such third parties concerning
their Year 2000 readiness
* Ability of the Company to identify and implement
contingency plans.
TAXES
As discussed in Note 8, "Federal Income Taxes" of the Notes to
Consolidated Financial Statements in the 1997 Annual Report, the
Internal Revenue Service (IRS) agents auditing the AEP System's
consolidated federal income tax returns requested a ruling from
their National Office that certain interest deductions relating to
corporate owned life insurance (COLI) claimed by the Company should
not be allowed. As a result of a suit filed in United States
District Court (discussed below) this request for ruling has been
withdrawn. Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions for taxable years 1991-96. A
disallowance of the COLI interest deduction through September 30,
1998 would reduce earnings by approximately $115 million (including
interest). The Company has made no provision for any possible
adverse earnings impact from this matter.
In order to resolve this issue without further delay, on March
24, 1998, the Company filed suit against the United States in the
United States District Court for the Southern District of Ohio.
Management believes that it has a meritorious position and will
vigorously pursue this lawsuit. In July 1998 the Company made a
payment of taxes and interest attributable to COLI interest
deductions for taxable years 1991-96 to avoid the potential
assessment by the IRS of any additional above market rate interest
on the contested amount. In September 1998 the Company made an
additional payment for the 1997 tax year. The payments were
included on the balance sheet 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. In the event the resolution of this matter is <PAGE>
<PAGE>
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
POWER MARKETING AND TRADING
During 1998, American Electric Power Service Corporation, as
agent for the Company and its affiliates in the AEP System Power
Pool (Power Pool), substantially increased the volume of its
electricity marketing and trading. The purpose of the power
marketing and trading business is to utilize AEP's knowledge of the
energy markets in order to improve the competitiveness of its
generation business and contribute to net income. Revenues and
expenses from these activities are shared by the Power Pool members
based on their relative peak demands.
The power marketing and trading business involves the marketing
of power under physical forward contracts at fixed and variable
prices and the trading of options, futures, swaps and other
financial derivative contracts at both fixed and variable prices.
Most contracts represent physical forward electricity marketing
contracts for the purchase and sale of electricity in the Power
Pool's traditional marketing area which are recorded as operating
revenues and purchased power expense when the contracts settle.
At September 30, 1998, the Power Pool had open marketing contracts,
not on the balance sheet, in its traditional marketing area through
the year 2004 to sell electricity with a notional value of
approximately $1.1 billion and to purchase electricity with a
notional value of approximately $1.1 billion. The Company's share
of these notional values is approximately $290 million.
The Power Pool has also purchased and sold electricity options,
futures, and swaps, and entered into forward purchase and sale
contracts for the future delivery or receipt of electricity outside
the traditional marketing area. These transactions represent non-regulated
trading activities that are marked-to-market and recorded
in nonoperating income. At September 30, 1998, the Company's share
of the unrealized mark-to-market gains and losses from such trading
contracts are reported as assets and liabilities, respectively. At
September 30, 1998, the Power Pool had open marketing contracts
outside its traditional marketing area through the year 2008 to
sell electricity with a notional value of approximately $230 <PAGE>
<PAGE>
million and to purchase electricity with a notional value of
approximately $145 million. The Company's share of these notional
values is approximately $65 million for sales and approximately $40
million for purchases.
Dependent on future electricity market conditions these
activities could produce material income or losses in future
periods.
<PAGE>
PART II. OTHER INFORMATION
Item 5. Other Information.
American Electric Power Company, Inc. ("AEP")
The deadline for submission of shareholder proposals pursuant
to Rule 14a-8 under the Securities Exchange Act of 1934, as
amended, ("Rule 14a-8"), for inclusion in AEP's proxy statement for
its 1999 Annual Meeting of Shareholders was November 10, 1998.
After February 1, 1999, notice to AEP of a shareholder proposal
submitted otherwise than pursuant to Rule 14a-8 will be considered
untimely, and the persons named in proxies solicited by AEP's Board
of Directors for its 1999 Annual Meeting of Shareholders may
exercise discretionary voting power with respect to any such
proposal as to which AEP does not receive timely notice.
AEP and Appalachian Power Company ("APCo")
Reference is made to page 10 of the Annual Report on Form 10-K
for the year ended December 31, 1997 ("1997 10-K") and page II-1 of
the Quarterly Report on Form 10-Q for the quarter ended March 31,
1998, for a discussion of retail competition in Virginia. Pursuant
to an order of the Virginia State Corporation Commission ("Virginia
SCC"), APCo filed its Customer Choice Pilot Program with the
Virginia SCC on November 2, 1998. The Virginia SCC must approve
the program before it becomes effective. The proposed two-year
program would give approximately 3,200 APCo retail customers in
Virginia--residential, commercial and industrial--an opportunity to
choose an Energy Service Provider ("ESP") of generation service
other than APCo. ESPs include marketers, brokers and aggregators
who provide generation service at unregulated prices. If a
participating customer were to pick an ESP for generation service,
APCo would continue to provide distribution and transmission
service. Participation would be open to 2% or 50 megawatts of
APCo's Virginia load.
Reference is made to pages 12 and 13 of the 1997 10-K and page
II-3 of the Quarterly Report on Form 10-Q for the quarter ended
June 30, 1998, for a discussion of APCo's proposed transmission
facilities. By Hearing Examiner's Ruling of June 9, 1998, the
procedural schedule for the certificate in Virginia was suspended
for 90 days to allow APCo to conduct additional studies. On August
21, 1998, APCo filed a report stating that a two-phased alternative
project could provide electrical transmission reinforcement
comparable to the Wyoming-Cloverdale line.
II-1<PAGE>
By Hearing Examiner's Ruling of September 22, 1998, the
proceeding was continued and APCo was directed to study the first
phase of the alternative project, involving a line running from
Wyoming Station in West Virginia to APCo's existing Jacksons Ferry
Station in Virginia or any point on the Jacksons Ferry-Cloverdale
765kV transmission line. APCo estimates that the Wyoming-Jacksons
Ferry line would be between 82-100 miles in length, including 32
miles in West Virginia previously certified. APCo must file its
study by June 1, 1999. The Hearing Examiner also ordered APCo and
the Virginia SCC Staff to provide at the evidentiary hearing
information on generation alternatives, specifically natural gas
generation, to APCo's proposed transmission line.
Management estimates that the earliest APCo could complete
either the Wyoming-Cloverdale or Wyoming-Jacksons Ferry project is
the winter of 2003/2004.
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 page 22 of the 1997 10-K for a discussion
of proposed revisions to the new source performance standard for
nitrogen oxides emissions from new utility and large industrial
boilers. On September 3, 1998, the U.S. Environmental Protection
Agency issued final revisions to this standard. The revised rule
specifies the emission limit for new sources in terms of output
rather than emission rate. The emission limit is set at a level
which cannot currently be achieved by combustion controls and will
require the use of post combustion control equipment. Imposition
of this standard to existing sources which might become subject to
the rule based on an administrative finding that an existing source
had been modified or reconstructed could result in substantial
capital and operating expenditures.
AEP and OPCo
Reference is made to page 31 of the 1997 10-K for a discussion
of litigation with Ormet Corporation involving the ownership of
sulfur dioxide allowances. In a letter dated August 27, 1998, the
U.S. District Court, Northern District of West Virginia, advised
the parties to the litigation that the court would issue an order
granting the motion for summary judgment filed by OPCo and the AEP
Service Corporation.
II-2
<PAGE>
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
AEP, APCo and OPCo
Exhibit 10 - AEP System Survivor Benefit Plan,
effective January 27, 1998.
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
September 30, 1998.
II-3<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: November 12, 1998
II-4
<TABLE>
EXHIBIT 12
COLUMBUS SOUTHERN POWER COMPANY
Computation of Consolidated Ratios of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Twelve
Months
Year Ended December 31, Ended
1993 1994 1995 1996 1997 9/30/98
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . $74,119 $68,471 $66,811 $59,711 $55,156 $49,855
Interest on Other Long-term Debt. . . . . . . . 10,436 10,221 8,829 12,125 15,525 21,755
Interest on Short-term Debt . . . . . . . . . . 1,305 817 1,328 2,400 5,104 3,804
Miscellaneous Interest Charges. . . . . . . . . 4,036 4,566 4,657 4,374 4,729 4,439
Estimated Interest Element in Lease Rentals . . 3,700 3,700 4,100 4,600 4,100 4,100
Total Fixed Charges. . . . . . . . . . . . $93,596 $87,775 $85,725 $83,210 $84,614 $83,953
Earnings:
Net Income (Loss) . . . . . . . . . . . . . . .$(55,898) $109,845 $110,616 $107,108 $119,379 $137,815
Plus Federal Income Taxes . . . . . . . . . . . 34,154 49,838 58,648 60,302 69,760 80,346
Plus State Income Taxes . . . . . . . . . . . . - 1 7 11 6 6
Plus Fixed Charges (as above) . . . . . . . . . 93,596 87,775 85,725 83,210 84,614 83,953
Total Earnings . . . . . . . . . . . . . .$ 71,852 $247,459 $254,996 $250,631 $273,759 $302,120
Ratio of Earnings to Fixed Charges. . . . . . . . 0.76(a) 2.81 2.97 3.01 3.23 3.59
(a) Ratio includes the effect of the Loss from Zimmer Plant Disallowance of $144,533,000 (net of applicable
income taxes of $14,534,000). As a result, earnings for the twelve months ended December 31, 1993 were
inadequate to cover fixed charges by $21,744,000. If the effect of the Loss from Zimmer Plant Disallowance
were excluded, the ratio would be 2.46 for the twelve months ended December 31, 1993.
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000022198
<NAME> COLUMBUS SOUTHERN POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> SEP-30-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,910,086
<OTHER-PROPERTY-AND-INVEST> 67,941
<TOTAL-CURRENT-ASSETS> 267,495
<TOTAL-DEFERRED-CHARGES> 21,658
<OTHER-ASSETS> 351,571
<TOTAL-ASSETS> 2,618,751
<COMMON> 41,026
<CAPITAL-SURPLUS-PAID-IN> 572,397
<RETAINED-EARNINGS> 191,269
<TOTAL-COMMON-STOCKHOLDERS-EQ> 804,692
25,000
0
<LONG-TERM-DEBT-NET> 959,651
<SHORT-TERM-NOTES> 30,950
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 24,400
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 36,620
<LEASES-CURRENT> 6,801
<OTHER-ITEMS-CAPITAL-AND-LIAB> 730,637
<TOT-CAPITALIZATION-AND-LIAB> 2,618,751
<GROSS-OPERATING-REVENUE> 1,711,773
<INCOME-TAX-EXPENSE> 69,721
<OTHER-OPERATING-EXPENSES> 1,465,409
<TOTAL-OPERATING-EXPENSES> 1,535,130
<OPERATING-INCOME-LOSS> 176,643
<OTHER-INCOME-NET> (1,109)
<INCOME-BEFORE-INTEREST-EXPEN> 175,534
<TOTAL-INTEREST-EXPENSE> 58,856
<NET-INCOME> 116,678
1,598
<EARNINGS-AVAILABLE-FOR-COMM> 115,080
<COMMON-STOCK-DIVIDENDS> 61,983
<TOTAL-INTEREST-ON-BONDS> 36,238
<CASH-FLOW-OPERATIONS> 161,187
<EPS-PRIMARY> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
