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 JUNE 30, 1999
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Transition Period from to
<CAPTION>
Commission Registrant; State of Incorporation; I. R. S. Employer
File Number Address; and Telephone Number Identification No.
<S> <C> <C>
1-3525 AMERICAN ELECTRIC POWER COMPANY, INC. 13-4922640
(A New York Corporation)
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
0-18135 AEP GENERATING COMPANY (An Ohio Corporation) 31-1033833
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3457 APPALACHIAN POWER COMPANY (A Virginia Corporation) 54-0124790
40 Franklin Road, Roanoke, Virginia 24011
Telephone (540) 985-2300
1-2680 COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation) 31-4154203
1 Riverside Plaza, Columbus, Ohio 43215
Telephone (614) 223-1000
1-3570 INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation) 35-0410455
One Summit Square
P.O. Box 60, Fort Wayne, Indiana 46801
Telephone (219) 425-2111
1-6858 KENTUCKY POWER COMPANY (A Kentucky Corporation) 61-0247775
1701 Central Avenue, Ashland, Kentucky 41101
Telephone (800) 572-1141
1-6543 OHIO POWER COMPANY (An Ohio Corporation) 31-4271000
301 Cleveland Avenue S.W., Canton, Ohio 44701
Telephone (330) 456-8173
AEP Generating Company, Columbus Southern Power Company and Kentucky Power Company meet
the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are
therefore filing this Form 10-Q with the reduced disclosure format specified in General
Instruction H(2) to Form 10-Q.
Indicate by check mark whether the registrants (1) have filed all reports required to
be filed by Sections 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrants were required to
file such reports), and (2) have been subject to such filing requirements for the past
90 days.
Yes X No
The number of shares outstanding of American Electric Power Company, Inc. Common Stock,
par value $6.50, at July 31, 1999 was 193,389,348.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June 30, 1999
<CAPTION>
INDEX
Page
Part I. FINANCIAL INFORMATION
<S> <C>
American Electric Power Company, Inc. and Subsidiary Companies:
Consolidated Statements of Income and
Statements of Comprehensive Income . . . . . . . . . . . . A-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . A-2 - A-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . A-4
Consolidated Statements of Retained Earnings . . . . . . . . A-5
Notes to Consolidated Financial Statements . . . . . . . . . A-6 - A-18
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . A-19- A-38
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-18
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-9
Management's Narrative Analysis of Results of Operations . . D-10- D-11
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-21
Kentucky Power Company:
Statements of Income and Statements of Retained Earnings . . F-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4
Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-7
Management's Narrative Analysis of Results of Operations . . F-8 - F-9
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended June 30, 1999
<CAPTION>
INDEX
Page
<S> <C>
Ohio Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . G-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . G-2 - G-3
Consolidated Statements of Cash Flows. . . . . . . . . . . G-4
Notes to Consolidated Financial Statements . . . . . . . . G-5 - G-9
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . G-10- G-19
Part II. OTHER INFORMATION
Item 4 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-6
This combined Form 10-Q is separately filed by American Electric Power Company,
Inc., AEP Generating Company, Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company.
Information contained herein relating to any individual registrant is filed by such
registrant on its own behalf. Each registrant makes no representation as to
information relating to the other registrants.
</TABLE>
<PAGE>
<PAGE>
FORWARD-LOOKING INFORMATION
This report made by American Electric Power Company, Inc. (AEP) and certain
of its subsidiaries contains forward-looking statements within the meaning
of Section 21E of the Securities Exchange Act of 1934. Although AEP and
each of its subsidiaries believe that their expectations are based on
reasonable assumptions, any such statements may be influenced by factors
that could cause actual outcomes and results to be materially different from
those projected. Ammong the factors that could cause actual results to
differ materially from those in the forward-looking statements are:
Electric load and customer growth.
Abnormal weather conditions.
Available sources and costs of fuels.
Availability of generating capacity.
The impact of the proposed merger with CSW including any regulatory
conditions imposed on the merger or the inability to consummate the
merger with CSW.
The speed and degree to which competition is introduced to our power
generation business.
The structure and timing of a competitive market and its impact on energy
prices or fixed rates.
The ability to recover stranded costs in connection with
possible/proposed deregulation of generation.
New legislation and government regulations.
The ability of AEP to successfully control its costs.
The success of new business ventures.
International developments affecting AEP's foreign investments.
The economic climate and growth in AEP's service territory.
Unforeseen events affecting AEP's nuclear plant which is on an extended
safety related shutdown.
Problems or failures related to Year 2000 readiness of computer
software and hardware.
Inflationary trends.
Electricity and gas market prices.
Interest rates
Other risks and unforeseen events.
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
<S> <C> <C> <C> <C>
REVENUES:
Domestic Regulated Electric Utilities. . $1,501 $1,561 $3,051 $3,070
Worldwide Non-regulated Electric and
Gas Operations . . . . . . . . . . . . 142 (4) 286 8
TOTAL REVENUES . . . . . . . . . 1,643 1,557 3,337 3,078
EXPENSES:
Fuel and Purchased Power . . . . . . . . 494 554 985 1,039
Maintenance and Other Operation. . . . . 469 437 896 848
Depreciation and Amortization. . . . . . 149 144 297 288
Taxes Other Than Federal Income Taxes. . 119 112 243 234
Worldwide Non-regulated Electric and
Gas Operations . . . . . . . . . . . . 127 16 250 31
TOTAL EXPENSES . . . . . . . . . 1,358 1,263 2,671 2,440
OPERATING INCOME . . . . . . . . . . . . . 285 294 666 638
OTHER INCOME (LOSS), net . . . . . . . . . 2 13 (3) 9
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES . . . . . . . 287 307 663 647
INTEREST AND PREFERRED DIVIDENDS . . . . . 135 109 267 215
INCOME BEFORE INCOME TAXES . . . . . . . . 152 198 396 432
INCOME TAXES . . . . . . . . . . . . . . . 64 80 157 163
NET INCOME . . . . . . . . . . . . . . . . $ 88 $ 118 $ 239 $ 269
AVERAGE NUMBER OF SHARES OUTSTANDING . . . 193 191 192 190
EARNINGS PER SHARE . . . . . . . . . . . . $0.46 $0.62 $1.24 $1.41
CASH DIVIDENDS PAID PER SHARE. . . . . . . $0.60 $0.60 $1.20 $1.20
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
NET INCOME . . . . . . . . . . . . . . . . $ 88 $ 118 $ 239 $ 269
OTHER COMPREHENSIVE INCOME:
Foreign Currency Translation
Adjustments. . . . . . . . . . . . . . 21 - 21 -
COMPREHENSIVE INCOME . . . . . . . . . . . $ 109 $ 118 $ 260 $ 269
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in millions)
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . . . $ 242 $ 173
Accounts Receivable (net). . . . . . . . . . . . . . . . 908 879
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . 322 216
Materials and Supplies . . . . . . . . . . . . . . . . . 306 280
Accrued Utility Revenues . . . . . . . . . . . . . . . . 224 214
Energy Marketing and Trading Contracts . . . . . . . . . 877 372
Prepayments. . . . . . . . . . . . . . . . . . . . . . . 106 84
TOTAL CURRENT ASSETS . . . . . . . . . . . . . . 2,985 2,218
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production . . . . . . . . . . . . . . . . . . . . . . 9,884 9,615
Transmission . . . . . . . . . . . . . . . . . . . . . 3,772 3,692
Distribution . . . . . . . . . . . . . . . . . . . . . 5,320 5,125
Other (including gas and coal mining assets
and nuclear fuel). . . . . . . . . . . . . . . . . . . 2,230 2,118
Construction Work in Progress. . . . . . . . . . . . . . 597 801
Total Property, Plant and Equipment. . . . . . . 21,803 21,351
Accumulated Depreciation and Amortization. . . . . . . . 8,879 8,549
NET PROPERTY, PLANT AND EQUIPMENT. . . . . . . . 12,924 12,802
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . 1,952 1,847
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . . . 2,726 2,616
TOTAL. . . . . . . . . . . . . . . . . . . . . $20,587 $19,483
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts Payable . . . . . . . . . . . . . . . . . . . . $ 560 $ 607
Short-term Debt. . . . . . . . . . . . . . . . . . . . . 989 617
Long-term Debt Due Within One Year . . . . . . . . . . . 957 206
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 279 382
Interest Accrued . . . . . . . . . . . . . . . . . . . . 76 75
Obligations Under Capital Leases . . . . . . . . . . . . 86 82
Energy Marketing and Trading Contracts . . . . . . . . . 860 360
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 491 472
TOTAL CURRENT LIABILITIES. . . . . . . . . . . . 4,298 2,801
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . . . 6,117 6,800
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . 2,618 2,601
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . 340 351
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . . . 217 222
DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . . . 457 263
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . 1,434 1,429
CUMULATIVE PREFERRED STOCKS OF SUBSIDIARIES. . . . . . . . 173 174
CONTINGENCIES (Note 9)
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
1999 1998
Shares Authorized . . . .600,000,000 600,000,000
Shares Issued . . . . . .202,292,368 200,816,469
(8,999,992 shares were held in treasury) . . . . . . . 1,315 1,305
Paid-in Capital. . . . . . . . . . . . . . . . . . . . . 1,906 1,854
Accumulated Other Comprehensive Income:
Foreign Currency Translation Adjustments . . . . . . . 20 (1)
Retained Earnings. . . . . . . . . . . . . . . . . . . . 1,692 1,684
TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . . . 4,933 4,842
TOTAL. . . . . . . . . . . . . . . . . . . . . $20,587 $19,483
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1999 1998
(in millions)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 239 $ 269
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . . . . 348 309
Deferred Federal Income Taxes. . . . . . . . . . . . . . . . . 54 14
Deferred Investment Tax Credits. . . . . . . . . . . . . . . . (11) (12)
Amortization of Deferred Property Taxes. . . . . . . . . . . . 80 78
Cook Restart Expense Deferral. . . . . . . . . . . . . . . . . (60) -
Deferred Costs Under Fuel Clause Mechanisms. . . . . . . . . . (60) (47)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . . . (29) (200)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . . . (132) (31)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . . . (10) (8)
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . . (22) (14)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . . (47) 159
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . . (103) (78)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . . . 35 39
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . . 4 92
Net Cash Flows From Operating Activities . . . . . . . . . 286 570
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . . . (402) (364)
Proceeds from Sale of Property and Other . . . . . . . . . . . . (10) (14)
Net Cash Flows Used For Investing Activities . . . . . . . (412) (378)
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . . . . 62 42
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . . 323 611
Change in Short-term Debt (net). . . . . . . . . . . . . . . . . 372 (49)
Retirement of Long-term Debt . . . . . . . . . . . . . . . . . . (331) (483)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . . (231) (229)
Net Cash Flows From (Used For) Financing Activities. . . . 195 (108)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . . . . 69 84
Cash and Cash Equivalents at Beginning of Period . . . . . . . . . 173 91
Cash and Cash Equivalents at End of Period . . . . . . . . . . . . $ 242 $ 175
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $256 million and $206 million
and for income taxes was $79 million and $117 million in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $43 million and $85 million in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD . . . . . . $1,720 $1,642 $1,684 $1,605
NET INCOME . . . . . . . . . . . . . . . . 88 118 239 269
DEDUCTIONS:
Cash Dividends Declared. . . . . . . . . 116 115 231 229
BALANCE AT END OF PERIOD . . . . . . . . . $1,692 $1,645 $1,692 $1,645
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements should
be read in conjunction with the 1998 Annual Report as incorporated in and
filed with the Form 10-K. Certain prior-period amounts have been
reclassified to conform to current-period presentation. In the opinion of
management, the financial statements reflect all adjustments (consisting of
only normal recurring accruals) which are necessary for a fair
presentation of the results of operations for interim periods.
2. FINANCING AND RELATED ACTIVITIES
During the first six months of 1999, subsidiaries issued
$250 million of senior unsecured notes: $150 million at 6.60%
due in 2009 and $100 million at 6.75% due in 2004. Also $50
million of pollution control revenue bonds at 5.15% due in 2026
were issued and short-term debt borrowings increased by $372
million. In July 1999 an additional $150 million of senior
unsecured notes at 6.875% due in 2004 were issued.
Retirements of debt were: first mortgage bonds totaling
$243 million with interest rates ranging from 6.55% to 8.43%
and due dates ranging from 2003 to 2023, $50 million of
pollution control revenue bonds at 7.40% due 2009 and a $25
million term loan with an interest rate of 6.42%.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the
Financial Accounting Standards Board's Emerging Issues Task
Force Consensus (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities". The
EITF requires that all energy trading contracts be marked-to-market.
The effect on the Consolidated Statements of Income
from marking open trading contracts to market is deferred as
regulatory assets or liabilities for the portion of open
trading transactions that are included in cost of service on
a settlement basis for ratemaking purposes in jurisdictions
other than the Virginia retail jurisdiction. As a result of
a prohibition against establishing new regulatory assets
contained in a Virginia rate settlement agreement, the Virginia
retail jurisdictional share of the mark-to-market adjustment
is included in net income. The adoption of the EITF did not
have a material effect on results of operations, cash flows or
financial condition.
<PAGE>
4. RATE MATTERS
The FERC issued orders 888 and 889 in April 1996 which
required each public utility that owns or controls interstate
transmission facilities to file an open access network and
point-to-point transmission tariff that offers services
comparable to the utility's own uses of its transmission
system. The orders also require utilities to functionally
unbundle their services, by requiring them to use their own
tariffs in making off-system and third-party sales. As part
of the orders, the FERC issued a pro-forma tariff which
reflects the Commission's views on the minimum non-price terms
and conditions for non-discriminatory transmission service.
The orders also allow a utility to seek recovery of certain
prudently-incurred stranded costs that result from unbundled
transmission service.
On July 9, 1996, the AEP System companies filed an Open
Access Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain
pricing issues.
On July 29, 1999, the FERC approved a draft order which
rules on the Company's pending Open Access Transmission Tariff.
This approved order has certain unfavorable pricing issues for
which the Company has 30 days to seek rehearing. If the
Commission's order is ultimately upheld the Company will have
to make refunds including interest. As of June 30, 1999 the
Company has not made any provisions for a refund which is
preliminarily estimated to be approximately $20 million.
5. INVESTMENT IN YORKSHIRE
The Company has a 50% ownership interest in Yorkshire Power
Group Limited (Yorkshire) which is accounted for using the
equity method of accounting. Equity income in Yorkshire is
included in revenues from worldwide non-regulated operations.
The following amounts which are not included in AEP's
consolidated financial statements represent summarized
consolidated financial information of Yorkshire:
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in millions)
Income Statement Data:
Operating Revenues $504.7 $503.9 $1,156.7 $1,167.1
Operating Income 38.5 92.5 152.0 182.2
Net Income (Loss) (4.4) (14.8) 30.2 (7.9)
On August 12, 1999, the Office of Gas and Electricity
Markets (the U.K. regulator of gas and electricity rates)
published draft price proposals for the U.K.'s regional
electric distribution businesses that would be effective for
the five-year period beginning April 1, 2000. The draft price
proposals would require average reductions of 16% to 21%. The
proposed distribution rates for Yorkshire call for a 15% to 20%
reduction in distribution revenues. Yorkshire is in the
process of evaluating the draft price proposals.
6. BUSINESS SEGMENTS
The Company's principal business segment is its cost based
rate regulated Domestic Electric Utility business consisting
of seven regulated utility operating companies providing
residential, commercial, industrial and wholesale electric
services in seven Atlantic and Midwestern states. Also
included in this segment are the Company's electric power
wholesale marketing and trading activities that are conducted
as part of regulated operations and subject to cost of service
rate regulation. Worldwide Non-regulated Electric and Gas
Operations are comprised of a Worldwide Energy Investments
segment and the other segment. The Worldwide Energy
Investments segment represents principally international
investments in energy-related projects and operations. It also
includes the development and management of such projects and
operations. Such investment activities include electric
generation, supply and distribution, and natural gas pipeline,
storage and other natural gas services. Other business
segments include non-regulated electric and gas trading
activities, telecommunication services, and the marketing of
various energy saving products and services. Financial data
for the business segments for the six months ending June 30,
1999 and 1998 is shown in the following table:
<TABLE>
<CAPTION>
Worldwide Non-regulated
Electric and Gas Operations
Regulated
Domestic World
Electric Wide Energy Reconciling AEP
Utilities Investments Other Adjustments Consolidated
(in millions)
<S> <C> <C> <C> <C> <C>
June 30, 1999
Revenues from
external customers $ 3,051 $ 335 $ 57 $(106) $ 3,337
Revenues from
transactions with other
operating segments - 28 78 (106) -
Segment net income (loss) 251 (1) (11) - 239
Total assets 17,766 2,305 516 - 20,587
June 30, 1998
Revenues from
external customers 3,070 9 (1) - 3,078
Revenues from
transactions with other
operating segments - - - - -
Segment net income (loss) 290 (15) (6) - 269
Total assets 16,686 427 100 - 17,213
</TABLE>
7. MERGER
As discussed in Note 5 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the Company and
Central and South West Corporation (CSW) announced plans to
merge in December 1997. In 1998 the appropriate shareholder
proposals for the consummation of the merger were approved.
Approval of the merger has been requested from the Federal
Energy Regulatory Commission (FERC), the Securities and
Exchange Commission (SEC), the Nuclear Regulatory Commission
(NRC) and all of CSW's state regulatory commissions: Arkansas,
Louisiana, Oklahoma and Texas. On July 29, 1999 applications
were made with the Federal Communication Commission to
authorize the transfer of control of licenses of several CSW
entities to the Company. AEP and CSW made a merger filing with
the Department of Justice in July 1999. The NRC and the
Arkansas Public Service Commission approved the merger in 1998.
In 1998 the FERC issued an order which confirmed that a 250
megawatt firm contract path with the Ameren System was
available. The contract path was obtained by the Company and
CSW to meet the requirement of the Public Utility Holding
Company Act of 1935 that the two systems operate on an
integrated and coordinated basis.
FERC
In November, 1998 the FERC issued an order establishing
hearing procedures for the merger. The 1998 FERC order
indicated that the review of the proposed merger will address
the issues of competition, market power and customer
protection. On May 25, 1999 AEP and CSW reached a settlement
with the FERC trial staff resolving competition and rate issues
relating to the merger. On July 13, 1999 AEP and CSW reached
an additional settlement with the FERC trial staff resolving
additional issues. The settlements were submitted to the FERC
for approval. Under the terms of the settlements, AEP filed
with the FERC a regional transmission organization proposal
whereby it will transfer the operation and control of AEP's
bulk transmission facilities. The settlements also cover rates
for transmission services and ancillary service as well as
resolving issues related to system integration agreements and
confirm, subject to FERC guidance on certain elements, that the
proposed generation divestiture of up to 550 megawatts of
capacity will satisfy the staff's market power concerns. The
hearings began on June 29, 1999 and concluded on July 19, 1999.
On June 28, 1999, the Company and CSW filed a motion with
the FERC asking to waive the requirement for a post-hearing
decision by an administrative law judge (ALJ) who presides over
the merger hearing. The motion indicated that the commission
could then decide the matter based on the hearing record and
briefs submitted by all interested parties. On July 28, 1999,
the FERC ordered the ALJ to issue an initial decision as soon
as possible, but no later than November 24, 1999. The
commission concluded that it needed the benefit of the ALJ's
opinion and therefore decided not to grant the request. The
procedural schedule that follows the ALJ's initial decision
should allow the FERC to issue a final order in the first
quarter of 2000.
<PAGE>
Louisiana
On July 29, 1999 the Louisiana Public Service Commission
(LPSC) approved the merger between the Company and CSW subject
to final FERC approval. In granting approval, the LPSC also
approved a stipulated settlement in which the Company and CSW
agreed to share with SWEPCO's Louisiana customers merger
savings created as a result of the merger over the eight years
following its consummation. The merger savings are estimated
to total more than $18 million during that eight-year period.
In addition the settlement also includes:
A cap on base rates for five years after consummation of
the merger;
Sharing of benefits from off-system sales;
Establishment of conditions for affiliate transactions
with other AEP and CSW subsidiaries;
Provisions to ensure continued quality of service; and
Provisions to hold SWEPCO's Louisiana customers harmless
for adverse effects of the merger, if any.
Oklahoma
On May 11, 1999, the Oklahoma Corporation Commission (OCC)
approved the proposed merger between the Company and CSW. The
approval follows an administrative law judge's oral decision
on a partial settlement between certain principal parties to
the Oklahoma merger proceeding which recommended that the OCC
approve the merger. The partial settlement provides for
sharing of net merger savings with Oklahoma customers; no
increase in Oklahoma base rates prior to January 1, 2003;
filing by December 31, 2001 with the FERC an application to
join a regional transmission organization; and implementing
additional quality of service standards for Oklahoma retail
customers. Oklahoma's share (approximately $50 million) of net
merger savings over the first five years after the merger is
consummated will be split between Oklahoma customers and AEP
shareholders. The partial settlement agreement includes a
recommendation by the OCC staff that the OCC file with FERC
indicating that it does not oppose the merger, but reserves the
right to ensure that there are no adverse impacts on the
Oklahoma transmission system. Certain municipal and
cooperative customers have appealed the OCC's merger approval
order.
Texas
On May 4, 1999, AEP and CSW announced that a stipulated
settlement had been reached in Texas. The agreement builds
upon an earlier settlement agreement signed by AEP, CSW and
certain parties to the Texas merger proceeding. In addition
to the parties that were signatories to the earlier agreement,
the staff of the Public Utility Commission of Texas is a
signatory to the new settlement as well as other key parties
to the merger proceeding. The stipulated settlement would
result in rate reductions totaling $221 million over a six-year
period for Texas customers after the merger is completed. The
$221 million rate reduction is composed of $84.4 million of net
merger savings and $136.6 million to resolve existing issues
associated with CSW operating subsidiaries' rate and fuel
reconciliation proceedings in Texas. Under the terms of the
settlement agreement, base rates would not be increased before
January 1, 2003 or three years after the merger, whichever is
later. The settlement also calls for the divestiture of a
total of 1,604 megawatts of existing and proposed generating
capacity within Texas. If it is determined that the
divestiture can proceed immediately after the merger closes
without jeopardizing pooling-of-interests accounting treatment
for the merger, sale of the plants would begin no later than
90 days after the merger closes. Absent that determination,
the divestiture would occur approximately two years after the
merger closes to satisfy the requirements to use pooling-of-interests
accounting treatment. Other provisions in the
settlement agreement provide for, among other things,
accelerated stranded cost recovery, quality-of-service
standards, continuation of programs for disadvantaged customers
and transfer of control of bulk transmission facilities to a
regional transmission organization. The Public Utility
Commission of Texas held hearings on the merger on August 9 and
10, 1999 and a final order is expected in the fourth quarter
of 1999. On August 11, 1999 AEP and CSW announced that
settlement agreements with several Texas wholesale customer
groups had been reached. The agreements, which are subject to
approval by the governing bodies of each of the wholesale
customers, resolve certain issues raised in the merger
proceeding and call for the wholesale customer groups to
withdrawal their opposition to the merger in all regulatory
approval proceedings.
Indiana
The Indiana Utility Regulatory Commission (IURC) approved
a settlement agreement related to the merger on April 26, 1999.
The settlement agreement resulted from an investigation of the
proposed merger initiated by the IURC. The terms of the
settlement agreement provide for, among other things, a sharing
of net merger savings through reductions in customers' bills
of approximately $67 million over eight years after the merger
is completed; a one year extension through January 1, 2005 of
a freeze in base rates; additional annual deposits of $5.5
million to the nuclear decommissioning trust fund for the
Indiana jurisdiction for the years 2001 through 2003; quality-of-service
standards; and participation in a regional
transmission organization. As part of the settlement
agreement, the IURC agreed not to oppose the merger in the FERC
or SEC proceedings.
Kentucky
On April 15, 1999, in compliance with a request from the
staff of the Kentucky Public Service Commission (KPSC) AEP
filed an application seeking KPSC approval for the indirect
change in control of Kentucky Power Company that will occur as
a result of the proposed merger. Although AEP did not believe
that the KPSC has the jurisdictional authority to approve the
merger, AEP reached a merger settlement agreement on May 24,
1999 with key parties in Kentucky which the KPSC approved on
June 14, 1999. Under the terms of the Kentucky settlement, AEP
has agreed to share net merger savings with Kentucky customers;
establish performance standards that will maintain or improve
customer service and system reliability; and to establish rules
to protect consumers and promote fair competition. The
Kentucky customers' share of the net merger savings are
expected to be approximately $28 million. The key parties to
the Kentucky settlement agreed not to oppose the merger during
the FERC or the SEC proceedings.
Other
AEP and CSW have reached settlements with the Missouri
Commission, the International Brotherhood of Electrical Workers
(IBEW), representing employees of AEP and CSW, and the Utility
Worker's Union of America (UWUA) representing AEP employees,
and certain wholesale customers. All have agreed not to oppose
the merger in the FERC or SEC proceedings.
The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (UK) regional electricity
companies (RECs), Yorkshire and Seeboard, plc. AEP has a 50%
ownership interest in Yorkshire and CSW has a 100% interest in
Seeboard. Although the merger of CSW into AEP is not subject
to approval by UK regulatory authorities, the common ownership
of two UK RECs could be referred by the UK Secretary of State
for Trade and Industry to the UK Competition Commission
(formerly Monopolies and Mergers Commission) for investigation.
Completion of the Merger
As of June 30, 1999, AEP had deferred $30 million of costs
related to the merger on its consolidated balance sheet, which
will be charged to expense if AEP and CSW are not successful
in completing their proposed merger. If the merger is
consummated the deferred costs will be amortized over their
recovery period, generally 5-years.
The merger is conditioned upon, among other things, the
approval of certain state and federal regulatory agencies. The
transaction must satisfy many conditions, a number of which may
not be waived by the parties, including the condition that the
merger must be accounted for as a pooling of interests. The
merger agreement will terminate on December 31, 1999 unless
extended for six months by either party as provided in the
merger agreement. Although consummation of the merger is
expected to occur in the first quarter of 2000, the Company is
unable to predict the outcome or the timing of the required
regulatory proceedings.
<PAGE>
8. RESTRUCTURING LEGISLATION
Virginia
In March 1999 a new law was enacted in Virginia to
restructure the electric utility industry. Under the
restructuring law a transition to choice of electricity
supplier for retail customers will commence on January 1, 2002
and be completed, subject to a finding by the Virginia State
Corporation Commission that an effective competitive market
exists, on January 1, 2004.
The Virginia restructuring law also provides an opportunity
for recovery of just and reasonable net stranded costs.
Stranded costs are those costs above market including
generation related regulatory assets and impaired tangible
assets that potentially would not be recoverable in a
competitive market. The mechanisms in the Virginia law for
stranded cost recovery are: a capping of rates until as late
as July 1, 2007, and the application of a wires charge upon
customers who may depart the incumbent utility in favor of an
alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior
to January 1, 2001.
Management has concluded that as of June 30, 1999 the
requirements to apply Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain
Types of Regulation," continue to be met. The Company's
Virginia rates for generation will continue to be cost-based
regulated until the establishment of capped rates and the wires
charge as provided in the law. The establishment of capped
rates should enable the Company to determine its ability to
recover stranded costs. When capped rates and the wires charge
are established in Virginia, the application of SFAS 71 would
be discontinued for the Virginia retail jurisdiction portion
of the generating business. At that time the Company will have
to write-off its generation-related regulatory assets to the
extent that they cannot be recovered under provisions of the
restructuring law and record any asset impairments in
accordance with SFAS 121 "Accounting for the Impairment of
Long-lived Assets and for Long-lived Assets to Be Disposed Of."
An impairment loss would be recorded to the extent that the
cost of impaired assets cannot be recovered through the
transition recovery mechanisms provided by the law and future
market prices. Absent the determination in the regulatory
process of capped rates and other pertinent information, it is
not possible at this time to determine if any plants are
impaired in accordance with SFAS 121. The amount of regulatory
assets recorded on the books applicable to the Virginia
generating business at June 30, 1999 is estimated to be $60
million before related tax effects.
Should it not be possible under the Virginia law to recover
all or a portion of the generation related regulatory assets,
it could have a material adverse impact on results of
operations. An estimated determination of whether the Company
will experience any asset impairment loss regarding its
Virginia retail jurisdictional generating assets and any loss
from a possible inability to recover generation related
regulatory assets cannot be made until such time as the
transition capped rates and the wires charge are determined
under the law which is expected to be in the fourth quarter of
2000.
Ohio
On July 6, 1999, the Governor of the State of Ohio signed
The Ohio Electric Restructuring Act of 1999. The Act provides
for customer choice of electricity supplier and a residential
rate reduction of 5% of the unbundled generation rate beginning
on January 1, 2001. The Act also provides for a five-year
transition period to transition from cost based rates to market
pricing for generation services. It authorizes the Public
Utilities Commission of Ohio (PUCO) to address certain major
transition issues including unbundling of rates and the
recovery of regulatory assets and other stranded transition
costs.
Retail electric services that will be competitive are
defined in the Act as electric generation service, aggregation
service, and power marketing and brokering. The PUCO has been
granted broad oversight responsibility under the Act. The Act
requires the PUCO to promulgate rules for competitive retail
electric generation service.
The Act further provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled rates paid by customers who do not switch
generation suppliers and through a wires charges by customers
who switch generation suppliers. Transition costs can include
regulatory assets, impairments of generating assets and other
stranded costs, employee severance and retraining costs and
other costs. Recovery of transition revenues can under certain
circumstances extend beyond the five-year transition period but
cannot continue beyond December 31, 2010. The Company must
file a transition plan with the PUCO by January 3, 2000 and the
PUCO is required to issue a transition order no later than
October 31, 2000.
The Act also provides that the property tax assessment
percentage on electric generation equipment be lowered from
100% to 25% of value effective January 1, 2001. Electric
utilities will also become subject to the Ohio Corporate
Franchise Tax and municipal income taxes on January 1, 2002.
The last year for which electric utilities will pay the excise
tax based on gross receipts is the year ending April 30, 2002.
As of May 1, 2001 electric distribution companies will be
subject to an excise tax based on kilowatt-hours sold to Ohio
customers. These changes should put the Company's generation
operations on an equal level with other competitive businesses
in Ohio regarding state taxation.
As discussed in Note 2, "Effects of Regulation," of the
Notes to Consolidated Financial Statements in the 1998 Annual
Report, the Company defers as regulatory liabilities and assets
certain revenues and expenses consistent with the regulatory
process in accordance with SFAS 71. At June 30, 1999 the
amount of regulatory assets recorded on the books applicable
to the generating business is estimated to be $640 million
before related tax effects. Whether the Company will have any
additional stranded transition costs related to an economic
impairment of its generating assets is dependent on several
factors including the assumed future market price for
electricity. The Company intends to seek recovery in its
transition filing of all regulatory assets and any other
stranded transition costs which may be identified. At this time
management is unable to predict the outcome of the regulatory
process or its impact on results of operations, cash flows or
financial condition. Therefore, the Company will not be
discontinuing application of SFAS 71 until the regulatory
process is completed.
Upon discontinuance of the application of SFAS 71 the
Company will have to write off its generation-related
regulatory assets and record any asset impairments in
accordance with SFAS 121. Absent the determination in the
regulatory process of transition revenues and other pertinent
information, it is not possible at this time to determine if
any plants are impaired in accordance with SFAS 121. Should
the Company be granted recovery of its regulatory assets and/or
any economic asset impairments it can record an offsetting
regulatory asset. Should the PUCO not approve the Company's
request for recovery of its generation-related regulatory
assets and/or other stranded transition costs it would have an
adverse impact on future results of operations and possibly
financial condition. The Company does not expect to be able
to determine the impact of the legislation on its financial
statements until the regulatory process is complete. The PUCO
is required to complete its regulatory process no later than
October 31, 2000.
9. CONTINGENCIES
Litigation
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the
deductibility of certain interest deductions related to AEP's
corporate owned life insurance (COLI) program for taxable years
1991-1996 is under review by the Internal Revenue Service
(IRS). Adjustments have been or will be proposed by the IRS
disallowing COLI interest deductions. A disallowance of COLI
interest deductions through June 30, 1999 would reduce earnings
by approximately $316 million (including interest). The
Company has made no provision for any possible earnings impact
from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1997 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
These payments to the IRS are included on the Consolidated
Balance Sheets in other assets pending the resolution of this
matter. The Company is seeking refunds through litigation of
all amounts paid plus interest.
In order to resolve this issue, the Company filed suit
against the United States (US) in the US District Court for the
Southern District of Ohio in March 1998. Management believes
that it has a meritorious position and will vigorously pursue
this lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations.
Air Quality
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the US
Environmental Protection Agency (Federal EPA) issued final
rules which require reductions in nitrogen oxides (NOx)
emissions in 22 eastern states, including the states in which
the generating plants of the Company and its AEP System
affiliates are located. The final rules were to be implemented
through state implementation plans (SIPs). SIPs are a
procedural method used by each state to comply with Federal EPA
rules. The NOx SIP Call rule requires submission of revised
SIPs by September 30, 1999. A number of utilities, including
the operating companies of the AEP System, filed petitions
seeking a review of the final rule in the U.S. Court of Appeals
for the District of Columbia Circuit (Appeals Court). On May
25, 1999, the Appeals Court ordered an indefinite stay of the
September 30, 1999 deadline for submission of SIP revisions
pending a further order of the court while arguments regarding
the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with
respect to petitions filed by eight northeastern states
pursuant to Section 126 of the Clean Air Act. Federal EPA
approved portions of the states' petitions triggering emission
reductions that are substantially the same as those that would
otherwise have been required by the NOx SIP Call. The
imposition of these NOx reduction requirements on AEP System
generating units would be approximately equivalent to the
reductions contemplated by the stayed SIP Call rule. On May
28, and June 1, 1999, the Utility Air Regulatory Group and the
Midwest Ozone Group, respectively, each filed a petition in the
Appeals Court seeking review of Federal EPA's approval of
portions of the northeastern states' petitions. In the second
quarter of 1999, three additional northeastern states filed
Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could
result in required capital expenditures of approximately $1.5
billion for the Company. Compliance costs cannot 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 through regulated rates and/or reflected in the
future market price of electricity, they will have a material
adverse effect on future results of operations, cash flows and
possibly financial condition.
Cook Nuclear Plant Shutdown
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, both units of
the Cook Plant were shut down in September 1997 due to
questions regarding the operability of certain safety systems
that arose during an NRC architect engineer design inspection.
The NRC issued a Confirmatory Action Letter in September 1997
requiring the Company to address certain issues identified in
the letter. In 1998 the NRC notified the Company that it had
convened a Restart Panel for Cook Plant and provided a list of
required restart activities. In order to identify and resolve
all issues, including those in the letter, necessary to restart
the Cook units, the Company is working with the NRC and will
be meeting with the Panel on a regular basis, until the units
are returned to service.
In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant
as an "agency-focus plant." The NRC senior managers concluded
that continued agency-level oversight was appropriate; however,
the NRC required no additional action to redirect Cook Plant
activities. The letter states that the NRC staff will continue
to monitor Cook Plant performance through the Restart Panel
process and evaluate whether additional action may be
necessary.
On June 24, 1999, the Boards of Directors of the Company
and Indiana Michigan Power Company both approved a plan to
restart the Cook Plant. Unit 2 is scheduled to return to
service in April 2000 and Unit 1 is to return to service in
September 2000. This approval follows a comprehensive systems
readiness review of all operating systems at the Cook Plant.
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.
Management intends to replace the steam generator for Unit
1 before the unit is returned to service. Costs associated
with the steam generator replacement are estimated to be
approximately $165 million, which will be accounted for as a
capital investment unrelated to the restart. At June 30, 1999,
$70 million has been spent on the steam generator replacement.
The cost of electricity supplied to retail customers
increased due to the outage of the two Cook Plant nuclear units
since higher cost coal-fired generation and coal based
purchased power is being substituted for the unavailable low
cost nuclear generation. Actual replacement energy fuel costs
that exceeded the estimated costs reflected in billings have
been recorded as a regulatory asset under the Indiana and
Michigan retail jurisdictional fuel cost recovery mechanisms.
At June 30, 1999, the regulatory asset was $129 million.
On March 30, 1999 the IURC approved a settlement agreement
that resolves all matters related to the recovery of
replacement energy fuel costs and all outage/restart issues
during the extended outage of the Cook Plant. The settlement
agreement provides for, among other things, a credit of $55
million, including interest, to Indiana retail customers'
bills; the deferral of unrecovered fuel revenues accrued
between September 9, 1997 and December 31, 1999, including the
$52.3 million revenue portion of the $55 million billing
credit; the deferral of up to $150 million of incremental
operation and maintenance costs in 1999 for Cook Plant above
the amount included in base rates; the amortization of the
deferred fuel recoveries and non-fuel operation and maintenance
cost deferrals over a five-year period ending December 31,
2003; a freeze in base rates through December 31, 2003; and a
fixed fuel recovery charge through March 1, 2004. The $55
million credit will be applied to customers' bills during the
months of July, August and September 1999.
In June 1999 the Company announced that a settlement
agreement for two open Michigan power supply cost recovery
reconciliation cases had been reached with the staff of the
Michigan Public Service Commission (MPSC). The proposed
settlement agreement would freeze rates and power supply costs
for five years, allow for the amortization of deferred power
supply cost for 1997, 1998 and 1999 over five years, allow for
the deferral and amortization of non-fuel nuclear operation and
maintenance expenses over five years and resolve all issues
related to the Cook Plant extended outage. At a hearing on
June 30, 1999, the MPSC granted a continuance to the one
intervenor who opposed the approval of the settlement
agreement. A hearing has been scheduled for August 13, 1999.
Expenditures for the restart of the Cook units are
estimated to total approximately $574 million and will be
accounted for primarily as current period operation and
maintenance expense in 1999 and 2000. Through June 30, 1999,
$192 million has been spent, of which $108 million was incurred
in the first half of 1999. Pursuant to the Indiana settlement
agreement $60 million of incremental operation and maintenance
costs were deferred through June 30, 1999. The Indiana
jurisdiction deferral is limited to $150 million of incremental
restart costs incurred in 1999. The pending Michigan
settlement limits deferrals to $50 million of non-fuel
operation and maintenance costs.
The costs of the extended outage and restart efforts will
have a material adverse effect on future results of operations,
cash flows, and possibly financial condition through 2003.
Management believes that the Cook units will be successfully
returned to service by April and September 2000, however, if
for some unknown reason the units are not returned to service
or their return is delayed significantly it would have an even
greater adverse effect on future results of operations, cash
flows and financial condition.
<PAGE>
Other
The Company continues to be involved in certain other
matters discussed in the 1998 Annual Report.
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1999 vs. SECOND QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income decreased $30 million or 25% in the second quarter
and $30 million or 11% in the year-to-date period due primarily to
an extended outage of the Company's nuclear plant and mild weather
in the second quarter.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-To-Date
(in millions) % (in millions) %
Revenues:
Domestic Regulated Electric
Utilities. . . . . . . . . . . $(60) (4) $(19) (1)
Worldwide Non-regulated
Operations . . . . . . . . . . 146 N.M. 278 N.M.
Fuel and Purchased Power Expense. (60) (11) (54) (5)
Maintenance and Other
Operation Expense. . . . . . . . 32 7 48 6
Worldwide Non-regulated
Operations Expense . . . . . . . 111 N.M. 219 N.M.
Other Income (Loss), net. . . . . (11) N.M. (12) N.M.
Interest and Preferred Dividends. 26 24 52 24
Income Taxes. . . . . . . . . . . (16) (20) (6) (4)
N.M. = Not Meaningful
Revenues from domestic regulated electric utility operations
decreased in both periods reflecting lower wholesale prices and a
decrease in wholesale energy sales. A decrease in sales to
residential customers reflecting mild weather also contributed to
the decrease in revenues for the second quarter. The decline in
wholesale sales reflects milder springtime temperatures and the
termination of a contract to supply power to several municipal
customers. Lower wholesale prices in 1999 reflect the effect of
reduced demand on prices. Wholesale demand is affected by the
weather and the availability of non-affiliated generating units.
The increase in revenues from worldwide non-regulated
operations was predominantly due to the acquisition in December
1998 of CitiPower, an Australian electric distribution utility, and
Louisiana Intrastate Gas, a midstream natural gas operation in
Louisiana.
The decrease in fuel and purchased power expense was primarily
attributable to a decrease in purchases of power and a reduction in
prices reflecting the effects of mild weather on demand and prices.
Maintenance and other operation expense increased due to the
cost of work to prepare the Company's nuclear generating units for
restart. The units have been on an extended Nuclear Regulatory
Commission monitored outage (see Cook Nuclear Plant Shutdown
below).
Worldwide non-regulated expenses increased as a result of the
expansion of business development activities and expenses from the
December 1998 acquisitions of CitiPower and Louisiana Intrastate
Gas.
The decrease in other income (loss) is primarily due to the
recognition of a provision for loss related to a Public Utilities
Commission of Ohio (PUCO) order which requires the Company to
reprice certain emission allowance transactions which are included
in the electric fuel rate factor of customers' bills. The order
requires the Company to adjust the actual amount paid for
allowances purchased to the weighted average cost of allowances
surrendered to the United States Environmental Protection Agency
(Federal EPA) as a result of exceeding sulfur emission limitations
in order to make wholesale sales.
Additional borrowings to fund the Company's non-regulated
operations, primarily the acquisitions of CitiPower and Louisiana
Intrastate Gas in December 1998, were the primary reason for the
significant increase in interest and preferred dividends.
The decrease in income taxes is primarily attributable to a
decrease in United States federal income taxes which was due to a
decrease in pre-tax income.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first six months were $446 million.
During the first six months of 1999 subsidiaries issued $324
million principal amount of long-term obligations at interest rates
ranging from 5.15% to 6.75%; retired $318 million principal amount
of long-term debt with interest rates ranging from 6.42% to 8.43%;
and increased short-term debt by $372 million from year-end
balances.
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
As discussed in Management's Discussion and Analysis of Results
of Operations and Financial Condition (MDA) in the 1998 Annual
Report, as a result of the Department of Energy's (DOE) failure to
make sufficient progress toward a permanent repository or otherwise
assume responsibility for SNF, the Company along with a number of
unaffiliated utilities and states filed suit in the United States
(US) Court of Appeals for the District of Columbia Circuit
requesting, among other things, that the court order DOE to meet
its obligations under the law. The court ordered the parties to
proceed with contractual remedies but declined to order DOE to
begin accepting SNF for disposal. DOE estimates its planned site
for the nuclear waste will not be ready until 2010. In June 1998,
the Company filed a complaint in the US Court of Federal Claims
seeking damages in excess of $150 million due to the DOE's partial
material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits
have been filed by other utilities. On April 6, 1999, the court
granted DOE's motion to dismiss a lawsuit filed by another utility.
On May 20, 1999, the other utility appealed this decision to the
U.S. Court of Appeals for the Federal Circuit. I&M's case has been
stayed pending final resolution of the other utility's appeal.
Cook Nuclear Plant Shutdown
As discussed in MDA in the 1998 Annual Report, both units of
the Cook Nuclear Plant were shut down by Indiana Michigan Power
Company (I&M) in September 1998 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 certain issues identified in the
letter. In 1998 the NRC notified the Company that it had convened
a Restart Panel for Cook Plant and provided a list of required
restart activities. In order to identify and resolve all issues,
including those in the letter, necessary to restart the Cook units,
the Company is working with the NRC and will be meeting with the
Panel on a regular basis, until the units are returned to service.
In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant as an
"agency-focus plant." The NRC senior managers concluded that
continued agency-level oversight was appropriate; however, the NRC
required no additional action to redirect Cook Plant activities.
The letter states that the NRC staff will continue to monitor Cook
Plant performance through the Restart Panel process and evaluate
whether additional action may be necessary.
On June 24, 1999, the Boards of Directors of the Company and
Indiana Michigan Power Company both approved a plan to restart the
Cook Plant. Unit 2 is scheduled to return to service in April 2000
and Unit 1 is to return to service in September 2000. This
approval follows a comprehensive systems readiness review of all
operating systems at the Cook Plant. 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.
Management intends to replace the steam generator for Unit 1
before the unit is returned to service. Costs associated with the
steam generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart. At June 30, 1999, $70 million has been
spent on the steam generator replacement.
The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal based purchased power is being
substituted for the unavailable low cost nuclear generation.
Actual replacement energy fuel costs that exceeded the estimated
costs reflected in billings have been recorded as a regulatory
asset under the Indiana and Michigan retail jurisdictional fuel
cost recovery mechanisms. At June 30, 1999, the regulatory asset
was $129 million.
On March 30, 1999 the IURC approved a settlement agreement that
resolves all matters related to the recovery of replacement energy
fuel costs and all outage/restart issues during the extended outage
of the Cook Plant. The settlement agreement provides for, among
other things, a credit of $55 million, including interest, to
Indiana retail customers' bills; the deferral of unrecovered fuel
revenues accrued between September 9, 1997 and December 31, 1999,
including the $52.3 million revenue portion of the $55 million
billing credit; the deferral of up to $150 million of incremental
operation and maintenance costs in 1999 for Cook Plant above the
amount included in base rates; the amortization of the deferred
fuel recoveries and non-fuel operation and maintenance cost
deferrals over a five-year period ending December 31, 2003; a
freeze in base rates through December 31, 2003; and a fixed fuel
recovery charge through March 1, 2004. The $55 million credit will
be applied to customers' bills during the months of July, August
and September 1999.
In June 1999 the Company announced that a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases had been reached with the staff of the Michigan Public
Service Commission (MPSC). The proposed settlement agreement would
freeze rates and power supply costs for five years, allow for the
amortization of deferred power supply cost for 1997, 1998 and 1999
over five years, allow for the deferral and amortization of non-fuel nuclear
operation and maintenance expenses over five years and
resolve all issues related to the Cook Plant extended outage. At
a hearing on June 30, 1999, the MPSC granted a continuance to the
one intervenor who opposed the approval of the settlement
agreement. A hearing has been scheduled for August 13, 1999.
Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as current period operation and maintenance expense in
1999 and 2000. Through June 30, 1999, $192 million has been spent,
of which $108 million was incurred in the first half of 1999.
Pursuant to the Indiana settlement agreement $60 million of
incremental operation and maintenance costs were deferred through
June 30, 1999. The Indiana jurisdiction deferral is limited to
$150 million of incremental restart costs incurred in 1999. The
pending Michigan settlement limits deferrals to $50 million of non-fuel
operation and maintenance costs.
<PAGE>
The costs of the extended outage and restart efforts will have
a material adverse effect on future results of operations, cash
flows, and possibly financial condition through 2003. Management
believes that the Cook units will be successfully returned to
service by April and September 2000, however, if for some unknown
reason the units are not returned to service or their return is
delayed significantly it would have an even greater adverse effect
on future results of operations, cash flows and financial
condition.
Merger
As discussed in Note 5 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the Company and Central and
South West Corporation (CSW) announced plans to merge in December
1997. In 1998 the appropriate shareholder proposals for the
consummation of the merger were approved. Approval of the merger
has been requested from the Federal Energy Regulatory Commission
(FERC), the Securities and Exchange Commission (SEC), NRC and all
of CSW's state regulatory commissions: Arkansas, Louisiana,
Oklahoma and Texas. On July 29, 1999 applications were made with
the Federal Communication Commission to authorize the transfer of
control of licenses of several CSW entities to the Company. AEP
and CSW made a merger filing with the Department of Justice in July
1999. The NRC and the Arkansas Public Service Commission approved
the merger in 1998. In 1998 the FERC issued an order which
confirmed that a 250 megawatt firm contract path with the Ameren
System was available. The contract path was obtained by the
Company and CSW to meet the requirement of the Public Utility
Holding Company Act of 1935 that the two systems operate on an
integrated and coordinated basis.
FERC
In November, 1998 the FERC issued an order establishing hearing
procedures for the merger. The 1998 FERC order indicated that the
review of the proposed merger will address the issues of
competition, market power and customer protection. On May 25, 1999
AEP and CSW reached a settlement with the FERC trial staff
resolving competition and rate issues relating to the merger. On
July 13, 1999 AEP and CSW reached an additional settlement with the
FERC trial staff resolving additional issues. The settlements were
submitted to the FERC for approval. Under the terms of the
settlements, AEP filed with the FERC a regional transmission
organization proposal whereby it will transfer the operation and
control of AEP's bulk transmission facilities. The settlements
also cover rates for transmission services and ancillary service as
well as resolving issues related to system integration agreements
and confirm, subject to FERC guidance on certain elements, that the
proposed generation divestiture of up to 550 megawatts of capacity
will satisfy the staff's market power concerns. The hearings began
on June 29, 1999 and concluded on July 19, 1999.
On June 28, 1999, the Company and CSW filed a motion with the
FERC asking to waive the requirement for a post-hearing decision by
an administrative law judge (ALJ) who presides over the merger
hearing. The motion indicated that the commission could then
decide the matter based on the hearing record and briefs submitted
by all interested parties. On July 28, 1999, the FERC ordered the
ALJ to issue an initial decision as soon as possible, but no later
than November 24, 1999. The commission concluded that it needed
the benefit of the ALJ's opinion and therefore decided not to grant
the request. The procedural schedule that follows the ALJ's
initial decision should allow the FERC to issue a final order in
the first quarter of 2000.
Louisiana
On July 29, 1999 the Louisiana Public Service Commission (LPSC)
approved the merger between the Company and CSW subject to final
FERC approval. In granting approval, the LPSC also approved a
stipulated settlement in which the Company and CSW agreed to share
with SWEPCO's Louisiana customers merger savings created as a
result of the merger over the eight years following its
consummation. The merger savings are estimated to total more than
$18 million during that eight-year period. In addition the
settlement also includes:
A cap on base rates for five years after consummation of the
merger;
Sharing of benefits from off-system sales;
Establishment of conditions for affiliate transactions with
other AEP and CSW subsidiaries;
Provisions to ensure continued quality of service; and
Provisions to hold SWEPCO's Louisiana customers harmless for
adverse effects of the merger, if any.
Oklahoma
On May 11, 1999, the Oklahoma Corporation Commission (OCC)
approved the proposed merger between the Company and CSW. The
approval follows an administrative law judge's oral decision on a
partial settlement between certain principal parties to the
Oklahoma merger proceeding which recommended that the OCC approve
the merger. The partial settlement provides for sharing of net
merger savings with Oklahoma customers; no increase in Oklahoma
base rates prior to January 1, 2003; filing by December 31, 2001
with the FERC an application to join a regional transmission
organization; and implementing additional quality of service
standards for Oklahoma retail customers. Oklahoma's share
(approximately $50 million) of net merger savings over the first
five years after the merger is consummated will be split between
Oklahoma customers and AEP shareholders. The partial settlement
agreement includes a recommendation by the OCC staff that the OCC
file with FERC indicating that it does not oppose the merger, but
reserves the right to ensure that there are no adverse impacts on
the Oklahoma transmission system. Certain municipal and
cooperative customers have appealed the OCC's merger approval
order.
Texas
On May 4, 1999, AEP and CSW announced that a stipulated
settlement had been reached in Texas. The agreement builds upon an
earlier settlement agreement signed by AEP, CSW and certain parties
to the Texas merger proceeding. In addition to the parties that
were signatories to the earlier agreement, the staff of the Public
Utility Commission of Texas is a signatory to the new settlement as
well as other key parties to the merger proceeding. The stipulated
settlement would result in rate reductions totaling $221 million
over a six-year period for Texas customers after the merger is
completed. The $221 million rate reduction is composed of $84.4
million of net merger savings and $136.6 million to resolve
existing issues associated with CSW operating subsidiaries' rate
and fuel reconciliation proceedings in Texas. Under the terms of
the settlement agreement, base rates would not be increased before
January 1, 2003 or three years after the merger, whichever is
later. The settlement also calls for the divestiture of a total of
1,604 megawatts of existing and proposed generating capacity within
Texas. If it is determined that the divestiture can proceed
immediately after the merger closes without jeopardizing pooling-of-interests
accounting treatment for the merger, sale of the
plants would begin no later than 90 days after the merger closes.
Absent that determination, the divestiture would occur
approximately two years after the merger closes to satisfy the
requirements to use pooling-of-interests accounting treatment.
Other provisions in the settlement agreement provide for, among
other things, accelerated stranded cost recovery, quality-of-service standards,
continuation of programs for disadvantaged
customers and transfer of control of bulk transmission facilities
to a regional transmission organization. The Public Utility
Commission of Texas held hearings on the merger on August 9 and 10,
1999 and a final order is expected in the fourth quarter of 1999.
On August 11, 1999 AEP and CSW announced that settlement agreements
with several Texas wholesale customer groups had been reached. The
agreements, which are subject to approval by the governing bodies
of each of the wholesale customers, resolve certain issues raised
in the merger proceeding and call for the wholesale customer groups
to withdrawal their opposition to the merger in all regulatory
approval proceedings.
Indiana
The IURC approved a settlement agreement related to the merger
on April 26, 1999. The settlement agreement resulted from an
investigation of the proposed merger initiated by the IURC. The
terms of the settlement agreement provide for, among other things,
a sharing of net merger savings through reductions in customers'
bills of approximately $67 million over eight years after the
merger is completed; a one year extension through January 1, 2005
of a freeze in base rates; additional annual deposits of $5.5
million to the nuclear decommissioning trust fund for the Indiana
jurisdiction for the years 2001 through 2003; quality-of-service
standards; and participation in a regional transmission
organization. As part of the settlement agreement, the IURC agreed
not to oppose the merger in the FERC or SEC proceedings.
Kentucky
On April 15, 1999, in compliance with a request from the staff
of the Kentucky Public Service Commission (KPSC) AEP filed an
application seeking KPSC approval for the indirect change in
control of Kentucky Power Company that will occur as a result of
the proposed merger. Although AEP did not believe that the KPSC
has the jurisdictional authority to approve the merger, AEP reached
a merger settlement agreement on May 24, 1999 with key parties in
Kentucky which the KPSC approved on June 14, 1999. Under the terms
of the Kentucky settlement, AEP has agreed to share net merger
savings with Kentucky customers; establish performance standards
that will maintain or improve customer service and system
reliability; and to establish rules to protect consumers and
promote fair competition. The Kentucky customers' share of the net
merger savings are expected to be approximately $28 million. The
key parties to the Kentucky settlement agreed not to oppose the
merger during the FERC or the SEC proceedings.
Other
AEP and CSW have reached settlements with the Missouri
Commission, the International Brotherhood of Electrical Workers
(IBEW), representing employees of AEP and CSW, and the Utility
Worker's Union of America (UWUA) representing AEP employees, and
certain wholesale customers. All have agreed not to oppose the
merger in the FERC or SEC proceedings.
The proposed merger of CSW into AEP would result in common
ownership of two United Kingdom (UK) regional electricity companies
(RECs), Yorkshire and Seeboard, plc. AEP has a 50% ownership
interest in Yorkshire and CSW has a 100% interest in Seeboard.
Although the merger of CSW into AEP is not subject to approval by
UK regulatory authorities, the common ownership of two UK RECs
could be referred by the UK Secretary of State for Trade and
Industry to the UK Competition Commission (formerly Monopolies and
Mergers Commission) for investigation.
Completion of the Merger
As of June 30, 1999, AEP had deferred $30 million of costs
related to the merger on its consolidated balance sheet, which will
be charged to expense if AEP and CSW are not successful in
completing their proposed merger. If the merger is consummated the
deferred costs will be amortized over their recovery period,
generally 5-years.
The merger is conditioned upon, among other things, the
approval of certain state and federal regulatory agencies. The
transaction must satisfy many conditions, a number of which may not
be waived by the parties, including the condition that the merger
must be accounted for as a pooling of interests. The merger
agreement will terminate on December 31, 1999 unless extended for
six months by either party as provided in the merger agreement.
Although consummation of the merger is expected to occur in the
first quarter of 2000, the Company is unable to predict the outcome
or the timing of the required regulatory proceedings.
Restructuring Legislation
Virginia
In March 1999 a new law was enacted in Virginia to restructure
the electric utility industry. Under the restructuring law a
transition to choice of electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia State Corporation Commission that an
effective competitive market exists, on January 1, 2004.
The Virginia restructuring law also provides an opportunity for
recovery of just and reasonable net stranded costs. Stranded costs
are those costs above market including generation related
regulatory assets and impaired tangible assets that potentially
would not be recoverable in a competitive market. The mechanisms
in the Virginia law for stranded cost recovery are: a capping of
rates until as late as July 1, 2007, and the application of a wires
charge upon customers who may depart the incumbent utility in favor
of an alternative supplier prior to the termination of the rate
cap. The law provides for the establishment of capped rates prior
to January 1, 2001.
Management has concluded that as of June 30, 1999 the
requirements to apply Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation," continue to be met. The Company's Virginia rates for
generation will continue to be cost-based regulated until the
establishment of capped rates and the wires charge as provided in
the law. The establishment of capped rates should enable the
Company to determine its ability to recover stranded costs. When
capped rates and the wires charge are established in Virginia, the
application of SFAS 71 would be discontinued for the Virginia
retail jurisdiction portion of the generating business. At that
time the Company will have to write-off its generation-related
regulatory assets to the extent that they cannot be recovered under
provisions of the restructuring law and record any asset
impairments in accordance with SFAS 121 "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to Be
Disposed Of." An impairment loss would be recorded to the extent
that the cost of impaired assets cannot be recovered through the
transition recovery mechanisms provided by the law and future
market prices. Absent the determination in the regulatory process
of capped rates and other pertinent information, it is not possible
at this time to determine if any plants are impaired in accordance
with SFAS 121. The amount of regulatory assets recorded on the
books applicable to the Virginia generating business at June 30,
1999 is estimated to be $60 million before related tax effects.
Should it not be possible under the Virginia law to recover all
or a portion of the generation related regulatory assets, it could
have a material adverse impact on results of operations. An
estimated determination of whether the Company will experience any
asset impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation related regulatory assets cannot be made until such time
as the transition capped rates and the wires charge are determined
under the law which is expected to be in the fourth quarter of
2000.
Ohio
On July 6, 1999, the Governor of the State of Ohio signed The
Ohio Electric Restructuring Act of 1999. The Act provides for
customer choice of electricity supplier and a residential rate
reduction of 5% of the unbundled generation rate beginning on
January 1, 2001. The Act also provides for a five-year transition
period to transition from cost based rates to market pricing for
generation services. It authorizes the Public Utilities Commission
of Ohio (PUCO) to address certain major transition issues including
unbundling of rates and the recovery of regulatory assets and other
stranded transition costs.
Retail electric services that will be competitive are defined
in the Act as electric generation service, aggregation service, and
power marketing and brokering. The PUCO has been granted broad
oversight responsibility under the Act. The Act requires the PUCO
to promulgate rules for competitive retail electric generation
service.
The Act further provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled rates paid by customers who do not switch
generation suppliers and through a wires charges by customers who
switch generation suppliers. Transition costs can include
regulatory assets, impairments of generating assets and other
stranded costs, employee severance and retraining costs and other
costs. Recovery of transition revenues can under certain
circumstances extend beyond the five-year transition period but
cannot continue beyond December 31, 2010. The Company must file a
transition plan with the PUCO by January 3, 2000 and the PUCO is
required to issue a transition order no later than October 31,
2000.
The Act also provides that the property tax assessment
percentage on electric generation equipment be lowered from 100% to
25% of value effective January 1, 2001. Electric utilities will
also become subject to the Ohio Corporate Franchise Tax and
municipal income taxes on January 1, 2002. The last year for which
electric utilities will pay the excise tax based on gross receipts
is the year ending April 30, 2002. As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kilowatt-hours sold to Ohio customers. These changes should put
the Company's generation operations on an equal level with other
competitive businesses in Ohio regarding state taxation.
As discussed in Note 2, "Effects of Regulation," of the Notes
to Consolidated Financial Statements in the 1998 Annual Report, the
Company defers as regulatory liabilities and assets certain
revenues and expenses consistent with the regulatory process in
accordance with SFAS 71. At June 30, 1999 the amount of regulatory
assets recorded on the books applicable to the generating business
is estimated to be $640 million before related tax effects.
Whether the Company will have any additional stranded transition
costs related to an economic impairment of its generating assets is
dependent on several factors including the assumed future market
price for electricity. The Company intends to seek recovery in its
transition filing of all regulatory assets and any other stranded
transition costs which may be identified. At this time management
is unable to predict the outcome of the regulatory process or its
impact on results of operations, cash flows or financial condition.
Therefore, the Company will not be discontinuing application of
SFAS 71 until the regulatory process is completed.
Upon discontinuance of the application of SFAS 71 the Company
will have to write off its generation-related regulatory assets and
record any asset impairments in accordance with SFAS 121. Absent
the determination in the regulatory process of transition revenues
and other pertinent information, it is not possible at this time to
determine if any plants are impaired in accordance with SFAS 121.
Should the Company be granted recovery of its regulatory assets
and/or any economic asset impairments it can record an offsetting
regulatory asset. Should the PUCO not approve the Company's
request for recovery of its generation-related regulatory assets
and/or other stranded transition costs it would have an adverse
impact on future results of operations and possibly financial
condition. The Company does not expect to be able to determine the
impact of the legislation on its financial statements until the
regulatory process is complete. The PUCO is required to complete
its regulatory process no later than October 31, 2000.
<PAGE>
United Kingdom Price Reduction Proposal
On August 12, 1999, the Office of Gas and Electricity Markets
(the U.K. regulator of gas and electricity rates) published draft
price proposals for the U.K.'s regional electric distribution
businesses that would be effective for the five-year period
beginning April 1, 2000. The draft price proposals would require
average reductions of 16% to 21%. The proposed distribution rates
for Yorkshire call for a 15% to 20% reduction in distribution
revenues. Yorkshire is in the process of evaluating the draft
price proposals.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices, foreign
currency exchange rates and interest rates. The Company's exposure
to market risk from the trading of electricity and natural gas and
related financial derivative instruments has not changed materially
since December 31, 1998. Market risk represents the risk of loss
that may impact the Company due to adverse changes in commodity
market prices, foreign currency exchange rates and interest rates.
There have been no material changes to the Company's exposure
to fluctuations in foreign currency exchange rates related to
foreign ventures and investments since December 31, 1998.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at June 30, 1999 is not
materially different than at December 31, 1998.
Air Quality
As discussed in MDA in the 1998 Annual Report, the US
Environmental Protection Agency (Federal EPA) issued final rules
which require reductions in nitrogen oxides (NOx) emissions in 22
eastern states, including the states in which the generating plants
of the Company and its AEP System affiliates are located. The
final rules were to be implemented through state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. The NOx SIP Call rule requires
submission of revised SIPs by September 30, 1999. A number of
utilities, including the operating companies of the AEP System,
filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals
Court). On May 25, 1999, the Appeals Court ordered an indefinite
stay of the September 30, 1999 deadline for submission of SIP
revisions pending a further order of the court while arguments
regarding the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act. Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP Call. The imposition of these NOx
reduction requirements on AEP System generating units would be
approximately equivalent to the reductions contemplated by the
stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air
Regulatory Group and the Midwest Ozone Group, respectively, each
filed a petition in the Appeals Court seeking review of Federal
EPA's approval of portions of the northeastern states' petitions.
In the second quarter of 1999, three additional northeastern states
filed Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $1.5 billion for
the Company. Compliance costs cannot 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 through
regulated rates and/or reflected in the future market price of
electricity, they will have a material adverse effect on future
results of operations, cash flows and possibly financial condition.
<PAGE>
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date. In
addition, certain systems may fail to detect that the year 2000 is
a leap year. Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company is modifying or
replacing its computer hardware and software programs to minimize
Y2K-related failures and repair such failures if they occur. This
includes both information technology (IT) systems, which are
mainframe and client server applications, and embedded logic
(non-IT) systems, such as process controls for energy production
and delivery. Externally, the problem is being addressed with
entities that interact with the Company, including suppliers,
customers, creditors, financial service organizations and other
parties essential to the Company's operations. In the course of
the external evaluation, the Company has sought written assurances
from third parties regarding their state of Y2K readiness.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
AEP, along with other electric utilities in North America, has
submitted information to the North American Electric Reliability
Council (NERC) as part of NERC's Y2K readiness program. NERC then
publicly reported summary information to the DOE regarding the Y2K
readiness of electric utilities. The fourth and final NERC report,
dated August 3, 1999 and entitled: Preparing the Electric Power
Systems of North America for Transition to the Year 2000 - A Status
Report and Work Plan, Second Quarter 1999 states that: "Mission-critical
component testing indicates that the transition through
critical Y2K dates is expected to have minimal impact on electric
system operations in North America." The report also indicates
that, "the risk of electrical outages caused by Y2K appears to be
no higher than the risks we already experience" from incidents such
as severe wind, ice, floods, equipment failures and power shortages
during an extremely hot or cold period.
AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications. There were no major problems encountered with
relaying information with the use of backup telecommunications
systems. AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.
Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems. Under this effort,
participating utilities, including AEP, are working together to
assess specific vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk. The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
<PAGE>
The following chart shows the Company's progress toward
becoming ready for Y2K as of June 30, 1999:
IT SYSTEMS NON-IT
SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT
DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION
DATE COMPLETE
Launch: Initiation 2/24/1998 100% 5/31/1998
100%
of the Y2K activities
within the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999
100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing:
The process of modifying, 6/30/1999 Mainframe: 6/30/1999
100%
replacing or retiring 100%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 99%*
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
* The Company is upgrading a meteorological reporting system used
at the Donald C. Cook Nuclear Plant, a mission critical IT system,
for Y2K readiness and it is anticipated that the upgrade should be
completed by December 15, 1999.
The above chart does not reflect progress of midstream gas
operations and CitiPower acquired in December 1998. The mission
critical systems for the midstream gas operations are expected to
be ready by August 31, 1999 and the mission critical systems for
CitiPower are expected to be ready by October 1, 1999.
Costs to Address the Company's Y2K Issues - Through June 30,
1999, the Company has spent $35 million on the Y2K project and
estimates spending an additional $13 million to $21 million to
achieve Y2K readiness. Most Y2K costs are for software, IT
consultants and salaries and are expensed; however, in certain
cases the Company has acquired hardware that was capitalized. The
Company intends to fund these expenditures through internal
sources. The cost of becoming Y2K compliant is not expected to
have a material impact on the Company's results of operations, cash
flows or financial condition.
Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
Automated power generation, transmission and distribution
systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for
commercial and industrial customers
Work management and billing systems.
The potential problems related to erroneous processing by, or
failure of, these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restorable in a reasonable
period of time.
CitiPower operates under a legal and regulatory regime which
may expose it to customer claims, that may differ from claims under
the US legal and regulatory regime, for service interruptions
and/or power quality problems resulting from Y2K problems.
<PAGE>
In addition, although the Company is monitoring its
relationships with third parties, such as suppliers, customers and
other electric utilities, these third parties nonetheless represent
a risk that cannot be assessed with precision or controlled with
certainty.
Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others not affiliated with AEP, fail for critical
applications, Y2K-related issues may materially adversely affect
AEP.
Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999. In addition, the Company is
establishing contingency plans for its business units to address
alternatives if Y2K related failures occur. These contingency
plans will be developed by the end of 1999.
AEP's Y2K contingency plans build upon the disaster recovery,
system restoration, and contingency planning that we have had in
place and include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, in order to place
key employees on duty at those locations during the Y2K
transition.
<PAGE>
<PAGE>
<TABLE> AEP GENERATING COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $51,612 $54,282 $104,439 $108,334
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 20,169 21,264 40,427 43,765
Rent - Rockport Plant Unit 2 . . . . . 17,070 17,070 34,141 34,141
Other Operation. . . . . . . . . . . . 2,092 2,724 5,462 5,373
Maintenance. . . . . . . . . . . . . . 4,489 4,229 6,751 6,407
Depreciation . . . . . . . . . . . . . 5,483 5,412 10,923 10,824
Taxes Other Than Federal Income Taxes. 1,253 934 2,492 1,877
Federal Income Taxes . . . . . . . . . 54 755 881 1,717
TOTAL OPERATING EXPENSES . . . 50,610 52,388 101,077 104,104
OPERATING INCOME . . . . . . . . . . . . 1,002 1,894 3,362 4,230
NONOPERATING INCOME. . . . . . . . . . . 889 791 1,745 1,620
INCOME BEFORE INTEREST CHARGES . . . . . 1,891 2,685 5,107 5,850
INTEREST CHARGES . . . . . . . . . . . . 669 806 1,271 1,591
NET INCOME . . . . . . . . . . . . . . . $ 1,222 $ 1,879 $ 3,836 $ 4,259
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $4,311 $1,732 $2,770 $2,528
NET INCOME . . . . . . . . . . . . . . . 1,222 1,879 3,836 4,259
CASH DIVIDENDS DECLARED. . . . . . . . . 1,073 1,176 2,146 4,352
BALANCE AT END OF PERIOD . . . . . . . . $4,460 $2,435 $4,460 $2,435
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production. . . . . . . . . . . . . . . . . . . . . . . . $627,798 $630,260
General . . . . . . . . . . . . . . . . . . . . . . . . . 1,933 2,009
Construction Work in Progress . . . . . . . . . . . . . . 7,017 4,191
Total Electric Utility Plant. . . . . . . . . . . 636,748 636,460
Accumulated Depreciation. . . . . . . . . . . . . . . . . 284,326 277,855
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 352,422 358,605
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 1,561 232
Accounts Receivable . . . . . . . . . . . . . . . . . . . 21,958 22,894
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 26,811 11,308
Materials and Supplies. . . . . . . . . . . . . . . . . . 3,877 3,900
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 31 267
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 54,238 38,601
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 5,864 5,984
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 2,522 702
TOTAL . . . . . . . . . . . . . . . . . . . . . $415,046 $403,892
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
June 30, December 31,
1999 1998
(in thousands)
<CAPTION>
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 . . . . . . . . . . . . . . . . . . . . . 29,235 35,235
Retained Earnings . . . . . . . . . . . . . . . . . . . . 4,460 2,770
Total Common Shareholder's Equity . . . . . . . . 34,695 39,005
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . 44,796 44,792
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 79,491 83,797
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 752 896
CURRENT LIABILITIES:
Short-term Debt - Notes Payable . . . . . . . . . . . . . 39,375 24,450
Accounts Payable:
General . . . . . . . . . . . . . . . . . . . . . . . . 7,902 6,419
Affiliated Companies. . . . . . . . . . . . . . . . . . 11,190 6,177
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 7,704 3,227
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 4,963 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 2,852 6,023
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 73,986 51,259
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 130,545 133,330
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . . . 64,885 66,562
Amounts Due to Customers for Federal Income Tax . . . . . 27,488 28,644
TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 92,373 95,206
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 37,899 39,404
TOTAL . . . . . . . . . . . . . . . . . . . . . $415,046 $403,892
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 3,836 $ 4,259
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 10,923 10,824
Deferred Federal Income Taxes. . . . . . . . . . . . . . (2,661) 2,689
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,677) (1,681)
Amortization of Deferred Gain on Sale
and Leaseback - Rockport Plant Unit 2. . . . . . . . . (2,785) (2,785)
Deferred Property Taxes. . . . . . . . . . . . . . . . . (1,666) (1,572)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . . 936 (1,803)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (15,480) (5,700)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 6,496 8,208
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 4,477 1,330
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (3,413) 517
Net Cash Flows From (Used For) Operating Activities. (1,014) 14,286
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (4,436) (3,769)
FINANCING ACTIVITIES:
Return of Capital to Parent Company. . . . . . . . . . . . (6,000) (2,000)
Retirement of Long-term Debt . . . . . . . . . . . . . . . - (25,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . 14,925 23,200
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (2,146) (4,352)
Net Cash Flows From (Used For) Financing Activities. 6,779 (8,152)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 1,329 2,365
Cash and Cash Equivalents at Beginning of Period . . . . . . 232 237
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,561 $ 2,602
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $1,070,000 and
$1,634,000 and for income taxes was $1,268,000 and $(717,000) in 1999 and 1998,
respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 1998 Annual Report as incorporated in and filed with the
Form 10-K. Certain prior-period amounts have been reclassified to conform to
current-period presentation. In the opinion of management, the financial
statements reflect all adjustments (consisting of only normal recurring
accruals) which are necessary for a fair presentation of the results of
operations for interim periods.
<PAGE>
<PAGE>
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 1999 vs. SECOND QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
Operating revenues are derived from the sale of Rockport Plant energy and
capacity to two affiliated companies and one unaffiliated utility pursuant to
Federal Energy Regulatory Commission (FERC) approved long-term unit power
agreements. The unit power agreements provide for recovery of costs
including a FERC approved rate of return on common equity and a return on
other capital net of temporary cash investments. A monthly power bill for
energy supplied is issued based on estimated expenses for the month and
adjusted to actual amounts in the following month.
Net income declined $0.7 million or 35% in the second quarter and $0.4
million or 10% in the year-to-date period as a result of capital returned to
the Company's parent in 1998 and 1999. Also contributing to the decrease in
net income for the quarter was a reduction to April 1999 billings to reflect
an adjustment to actual of estimated power production expenses included in
March 1999 billings. The adjustment to actual expenses reduced revenues and
net income for the second quarter.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $(2.7) (5) $(3.9) (4)
Fuel Expense . . . . . . . . (1.1) (5) (3.3) (8)
Other Operation Expense. . . (0.6) (23) 0.1 2
Maintenance Expense. . . . . 0.3 6 0.3 5
Taxes Other Than Federal
Income Taxes . . . . . . . 0.3 34 0.6 33
Federal Income Taxes . . . . (0.7) (93) (0.8) (49)
Interest Charges . . . . . . (0.1) (17) (0.3) (20)
The decrease in operating revenues during the second quarter and the
year-to-date period reflects the recovery of lower operating expenses,
primarily fuel, and a reduction in capital cost from the return of capital.
Operating revenues for the second quarter were also reduced by the April 1999
billing adjustment.
Fuel expense decreased reflecting a decrease in generation resulting from
planned maintenance outages of both Rockport units.
The decline in other operation expense in the second quarter is primarily
due to a decrease in administrative and general expenses reflecting a
reduction in allocated employee salary and benefit costs and a reduction in
the FERC annual assessment.
Maintenance expense increased due to the planned maintenance outages.
Taxes other than federal income taxes increased due to an increase in
state income taxes which resulted from an increase in taxable income due to
the cessation of state tax depreciation for Rockport Plant Unit 1.
Federal income taxes attributable to operations decreased due to a
decrease in pre-tax operating income and the reversal of deferred taxes in
excess of the statutory tax rate.
The decline in interest charges in the second quarter was due to a
reduction in the average outstanding balance of short-term debt. Interest
charges decreased in the year-to-date period primarily due to a reduction in
outstanding long-term debt reflecting a March 1998 redemption of $25 million
of pollution control revenue bonds.
<PAGE>
<PAGE>
<TABLE> APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $373,766 $403,080 $ 801,468 $818,446
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 99,659 101,191 223,232 209,400
Purchased Power. . . . . . . . . . . . 61,048 87,235 111,639 156,497
Other Operation. . . . . . . . . . . . 60,162 62,442 122,911 117,309
Maintenance. . . . . . . . . . . . . . 38,361 31,476 66,872 66,828
Depreciation and Amortization. . . . . 37,224 35,788 73,775 71,193
Taxes Other Than Federal Income Taxes. 30,066 29,934 60,041 60,178
Federal Income Taxes . . . . . . . . . 4,147 8,822 28,292 26,600
TOTAL OPERATING EXPENSES . . . 330,667 356,888 686,762 708,005
OPERATING INCOME . . . . . . . . . . . . 43,099 46,192 114,706 110,441
NONOPERATING INCOME (LOSS) . . . . . . . 315 1,561 (773) 1,174
INCOME BEFORE INTEREST CHARGES . . . . . 43,414 47,753 113,933 111,615
INTEREST CHARGES . . . . . . . . . . . . 32,378 32,629 63,636 63,292
NET INCOME . . . . . . . . . . . . . . . 11,036 15,124 50,297 48,323
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 673 678 1,348 1,147
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 10,363 $ 14,446 $ 48,949 $ 47,176
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $187,699 $210,545 $179,461 $207,544
NET INCOME . . . . . . . . . . . . . . . 11,036 15,124 50,297 48,323
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 30,348 29,729 60,696 59,458
Cumulative Preferred Stock . . . . . 565 570 1,132 932
Capital Stock Expense. . . . . . . . . 108 108 216 215
BALANCE AT END OF PERIOD . . . . . . . . $167,714 $195,262 $167,714 $195,262
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,006,859 $1,979,180
Transmission . . . . . . . . . . . . . . . . . . . . 1,132,344 1,118,726
Distribution . . . . . . . . . . . . . . . . . . . . 1,675,056 1,641,523
General. . . . . . . . . . . . . . . . . . . . . . . 239,257 228,464
Construction Work in Progress. . . . . . . . . . . . 107,941 119,466
Total Electric Utility Plant . . . . . . . . 5,161,457 5,087,359
Accumulated Depreciation and Amortization. . . . . . 2,035,779 1,984,856
NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,125,678 3,102,503
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 140,694 111,020
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 30,081 7,755
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 112,483 122,746
Affiliated Companies . . . . . . . . . . . . . . . 24,797 35,802
Miscellaneous. . . . . . . . . . . . . . . . . . . 11,508 8,572
Allowance for Uncollectible Accounts . . . . . . . (2,883) (2,234)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 64,175 49,826
Materials and Supplies . . . . . . . . . . . . . . . 63,726 60,440
Accrued Utility Revenues . . . . . . . . . . . . . . 38,719 45,985
Energy Marketing and Trading Contracts . . . . . . . 190,857 22,436
Prepayments. . . . . . . . . . . . . . . . . . . . . 7,194 8,151
TOTAL CURRENT ASSETS . . . . . . . . . . . . 540,657 359,479
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 421,647 433,516
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 38,256 40,520
TOTAL. . . . . . . . . . . . . . . . . . . $4,266,932 $4,047,038
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 30,000,000 Shares
Outstanding - 13,499,500 Shares. . . . . . . . . . $ 260,458 $ 260,458
Paid-in Capital. . . . . . . . . . . . . . . . . . . 663,889 663,633
Retained Earnings. . . . . . . . . . . . . . . . . . 167,714 179,461
Total Common Shareholder's Equity. . . . . . 1,092,061 1,103,552
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 19,116 19,359
Subject to Mandatory Redemption. . . . . . . . . . 22,310 22,310
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,449,232 1,472,451
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,582,719 2,617,672
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 131,027 120,281
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 176,005 80,004
Short-term Debt. . . . . . . . . . . . . . . . . . . 115,150 76,400
Accounts Payable . . . . . . . . . . . . . . . . . . 85,718 110,882
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 35,791 35,719
Customer Deposits. . . . . . . . . . . . . . . . . . 13,257 14,123
Interest Accrued . . . . . . . . . . . . . . . . . . 20,017 19,990
Revenue Refunds Accrued. . . . . . . . . . . . . . . 22,237 95,267
Energy Marketing and Trading Contracts . . . . . . . 191,801 24,076
Other. . . . . . . . . . . . . . . . . . . . . . . . 81,663 78,808
TOTAL CURRENT LIABILITIES. . . . . . . . . . 741,639 535,269
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 653,003 643,711
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 59,887 62,231
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 98,657 67,874
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . . $4,266,932 $4,047,038
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . $ 50,297 $ 48,323
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . . 74,302 71,825
Deferred Federal Income Taxes. . . . . . . . . . . . . . . 13,895 2,151
Deferred Investment Tax Credits. . . . . . . . . . . . . . (2,344) (2,366)
Deferred Power Supply Costs (net). . . . . . . . . . . . . 23,208 15,474
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . 18,981 (1,367)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . (17,635) (14,079)
Accrued Utility Revenues . . . . . . . . . . . . . . . . . 7,266 14,726
Accounts Payable . . . . . . . . . . . . . . . . . . . . . (25,164) (20,170)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . . (73,030) 37,862
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . (9,128) 5,342
Net Cash Flows From Operating Activities . . . . . . . 60,648 157,721
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . (86,808) (89,608)
Proceeds from Sale of Property . . . . . . . . . . . . . . . 200 880
Net Cash Flows Used For Investing Activities . . . . . (86,608) (88,728)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . . - 25,000
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . 148,751 193,431
Change in Short-term Debt (net). . . . . . . . . . . . . . . 38,750 (89,300)
Retirement of Cumulative Preferred Stock . . . . . . . . . . (149) (190)
Retirement of Long-term Debt . . . . . . . . . . . . . . . . (77,236) (138,471)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . (60,696) (59,458)
Dividends Paid on Cumulative Preferred Stock . . . . . . . . (1,134) (1,142)
Net Cash Flows From (Used For) Financing Activities. . 48,286 (70,130)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . . 22,326 (1,137)
Cash and Cash Equivalents at Beginning of Period . . . . . . . 7,755 6,947
Cash and Cash Equivalents at End of Period . . . . . . . . . . $ 30,081 $ 5,810
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $61,693,000 and $62,272,000 and
for income taxes was $18,062,000 and $30,981,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $8,845,000 and $11,893,000 in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial
statements should be read in conjunction with the 1998 Annual
Report as incorporated in and filed with the Form 10-K.
Certain prior-period amounts have been reclassified to conform
to current-period presentation. In the opinion of management,
the financial statements reflect all adjustments (consisting
of only normal recurring accruals) which are necessary for a
fair presentation of the results of operations for interim
periods.
2. FINANCING ACTIVITIES
In May 1999 the Company issued $150 million of 6.60% senior
unsecured notes due 2009. During the first six months of 1999,
the Company reacquired the following first mortgage bonds for
$77 million.
Principal
Amount
% Rate Due Date Reacquired
(in thousands)
8.43 June 1, 2022 $37,471
7.80 May 1, 2023 9,763
7.90 June 1, 2023 30,000
3. VIRGINIA RESTRUCTURING
As discussed in Note 2 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, in February
1999 the Virginia legislature passed comprehensive legislation,
which became law upon the Governor's signature in March 1999,
to restructure the electric utility industry. Under the
restructuring law a transition to choice of electricity
supplier for retail customers will commence on January 1, 2002
and be completed, subject to a finding by the Virginia State
Corporation Commission that an effective competitive market
exists, on January 1, 2004.
The Virginia restructuring law also provides an opportunity
for recovery of just and reasonable net stranded costs.
Stranded costs are those costs above market including
generation related regulatory assets and impaired tangible
assets that potentially would not be recoverable in a
competitive market. The mechanisms in the Virginia law for
stranded cost recovery are: a capping of rates until as late
as July 1, 2007, and the application of a wires charge upon
customers who may depart the incumbent utility in favor of an
alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior
to January 1, 2001.
<PAGE>
Management has concluded that as of June 30, 1999 the
requirements to apply Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain
Types of Regulation," continue to be met. The Company's
Virginia rates for generation will continue to be cost-based
regulated until the establishment of capped rates and the wires
charge as provided in the law. The establishment of capped
rates should enable the Company to determine its ability to
recover stranded costs. When capped rates and the wires charge
are established in Virginia, the application of SFAS 71 would
be discontinued for the Virginia retail jurisdiction portion
of the generating business. At that time the Company will have
to write-off its generation-related regulatory assets to the
extent that they cannot be recovered under provisions of the
restructuring law and record any asset impairments in
accordance with SFAS 121 "Accounting for the Impairment of
Long-lived Assets and for Long-lived Assets to Be Disposed Of."
An impairment loss would be recorded to the extent that the
cost of impaired assets cannot be recovered through the
transition recovery mechanisms provided by the law and future
market prices. Absent the determination in the regulatory
process of capped rates and other pertinent information, it is
not possible at this time to determine if any of the Company's
plants are impaired in accordance with SFAS 121. The amount
of regulatory assets recorded on the books applicable to the
Virginia generating business at June 30, 1999 is estimated to
be $60 million before related tax effects.
Should it not be possible under the Virginia law to recover
all or a portion of the generation related regulatory assets,
it could have a material adverse impact on results of
operations. An estimated determination of whether the Company
will experience any asset impairment loss regarding its
Virginia retail jurisdictional generating assets and any loss
from a possible inability to recover generation related
regulatory assets cannot be made until such time as the
transition capped rates and the wires charge are determined
under the law which is expected to be in the fourth quarter of
2000.
4. RATE MATTERS
As discussed in Note 3 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the Company had
requested a rehearing of a June 1998 Federal Energy Regulatory
Commission (FERC) order which granted an annual rate increase
of $3.4 million in response to a request for an $8.7 million
annual rate increase. The FERC had authorized the Company to
implement the $8.7 million annual rate increase subject to
refund in 1992. In April 1999, the FERC denied the rehearing
request. The Company completed the FERC ordered refund to
customers of $46.8 million including interest in July 1999.
A liability for the refunds and interest had previously been
recorded by the Company.
The FERC issued orders 888 and 889 in April 1996 which
required each public utility that owns or controls interstate
transmission facilities to file an open access network and
point-to-point transmission tariff that offers services
comparable to the utility's own uses of its transmission
system. The orders also require utilities to functionally
unbundle their services, by requiring them to use their own
tariffs in making off-system and third-party sales. As part
of the orders, the FERC issued a pro-forma tariff which
reflects the Commission's views on the minimum non-price terms
and conditions for non-discriminatory transmission service.
The orders also allow a utility to seek recovery of certain
prudently-incurred stranded costs that result from unbundled
transmission service.
On July 9, 1996, the AEP System companies filed an Open
Access Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain
pricing issues.
On July 29, 1999, the FERC approved a draft order which
rules on the AEP System's pending Open Access Transmission
Tariff. This approved order has certain unfavorable pricing
issues for which the AEP System has 30 days to seek rehearing.
If the Commission's order is ultimately upheld the Company as
a member of the AEP System will have to make refunds including
interest. As of June 30, 1999 the Company has not made any
provisions for its share of a potential refund which is
preliminarily estimated to be approximately $6 million.
5. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the
Financial Accounting Standards Board's Emerging Issues Task
Force Consensus (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities". The
EITF requires that all energy trading contracts be marked-to-market.
The effect on the Consolidated Statements of Income
of marking open trading contracts to market is deferred as
regulatory assets or liabilities for the portion of open
trading transactions that are included in cost of service on
a settlement basis for ratemaking purposes in the Company's
non-Virginia jurisdictions. The Virginia jurisdiction net
mark-to-market pre-tax gain of $2.3 million for the six months
ended June 30, 1999 is included in net income as a result of
an agreed prohibition against establishing new regulatory
assets in a February 1999 Virginia SCC approved settlement
agreement. The adoption of the EITF did not have a material
effect on results of operations, cash flows or financial
condition.
6. CONTINGENCIES
Litigation
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the
deductibility of certain interest deductions related to
American Electric Power's corporate owned life insurance (COLI)
program for taxable years 1991-1996 is under review by the
Internal Revenue Service (IRS). Adjustments have been or will
be proposed by the IRS disallowing COLI interest deductions.
A disallowance of COLI interest deductions through June 30,
1999 would reduce earnings by approximately $79 million
(including interest). The Company has made no provision for
any possible earnings impact from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1997 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
These payments to the IRS are included on the Consolidated
Balance Sheets in other property and investments pending the
resolution of this matter. The Company is seeking refunds
through litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit
against the United States in the US District Court for the
Southern District of Ohio in March 1998. Management believes
that it has a meritorious position and will vigorously pursue
this lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations.
Air Quality
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the U.S.
Environmental Protection Agency (Federal EPA) issued final
rules which require reductions in nitrogen oxides (NOx)
emissions in 22 eastern states, including the states in which
the generating plants of the Company and its AEP System
affiliates are located. The final rules were to be implemented
through state implementation plans (SIPs). SIPs are a
procedural method used by each state to comply with Federal EPA
rules. The NOx SIP Call rule requires submission of revised
SIPs by September 30, 1999. A number of utilities, including
the Company and its AEP System affiliates, filed petitions
seeking a review of the final rule in the U.S. Court of Appeals
for the District of Columbia Circuit (Appeals Court). On May
25, 1999, the Appeals Court ordered an indefinite stay of the
September 30, 1999 deadline for submission of SIP revisions
pending a further order of the court while arguments regarding
the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with
respect to petitions filed by eight northeastern states
pursuant to Section 126 of the Clean Air Act. Federal EPA
approved portions of the states' petitions triggering emission
reductions that are substantially the same as those that would
otherwise have been required by the NOx SIP Call. The
imposition of these NOx reduction requirements on AEP System
generating units would be approximately equivalent to the
reductions contemplated by the stayed SIP Call rule. On May
28, and June 1, 1999, the Utility Air Regulatory Group and the
Midwest Ozone Group, respectively, each filed a petition in the
Appeals Court seeking review of Federal EPA's approval of
portions of the northeastern states' petitions. In the second
quarter of 1999, three additional northeastern states filed
Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could
result in required capital expenditures of approximately $410
million for the Company. Compliance costs cannot 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 through regulated rates and/or reflected in the
future market price of electricity, they will have a material
adverse effect on future results of operations, cash flows and
possibly financial condition.
Other
The Company continues to be involved in certain other
matters discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1999 vs. SECOND QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income decreased $4.1 million or 27% in the second quarter
due to a decline in residential and wholesale sales. The increase
in net income of $2 million or 4% in the year-to-date period is due
to increased retail sales reflecting colder winter weather.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . $(29.3) (7) $(17.0) (2)
Fuel Expense . . . . . . . . (1.5) (2) 13.8 7
Purchased Power Expense. . . (26.2) (30) (44.9) (29)
Other Operation Expense. . . (2.3) (4) 5.6 5
Maintenance Expense. . . . . 6.9 22 0.0 -
Federal Income Taxes . . . . (4.7) (53) 1.7 6
Operating revenues decreased for both the second quarter and
year-to-date period due predominantly to a decline in wholesale
sales. The reduction in wholesale sales in the year-to-date period
was partly offset by an increase in more profitable retail sales in
the first quarter. Also contributing to the second quarter decline
was a decrease in residential sales of 8% reflecting milder spring
weather. The reduction in wholesale sales is largely attributable
to the termination of a contract with several municipal customers
and mild weather in the second quarter.
The increase in fuel expense in the year-to-date period was due
to an increase in generation to meet the increase in retail demand
during the first quarter. A reduction in the net cost of fuel
consumed reflecting lower prices for coal burned partly offset the
effect of the increased generation.
Purchased power expense decreased in both periods reflecting
a decline in purchases from unaffiliated entities and the American
Electric Power System Power Pool and a lower average price. The
decrease in the average price reflects the reduced demand for
wholesale energy. The need to purchase power decreased due to the
decline in wholesale sales and the increase in generation in the
year-to-date period.
A reduction in employee benefit costs as a result of accrual
adjustments for worker's compensation accounted for the decrease in
other operation expense in the second quarter. For the year-to-date period,
other operation expense increased due to employee
incentive compensation plan accrual adjustments.
Maintenance expense increased in the second quarter as a result
of outages at Amos and Kanawha River plants for boiler repairs.
The decrease in federal income tax expense attributable to
operations in the second quarter was primarily due to a decrease in
pre-tax operating income.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first six months of 1999 were $96 million.
During the first six months of 1999, the Company issued one
series of senior unsecured notes of $150 million with a rate of
6.60% due in 2009 and redeemed $77 million principal amount of
first mortgage bonds with interest rates from 7.8% to 8.43%.
Short-term debt increased by $39 million from year-end balances.
VIRGINIA RESTRUCTURING
As discussed in Note 2 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, in February 1999 the Virginia
legislature passed comprehensive legislation, which became law upon
the Governor's signature in March 1999, to restructure the
electric utility industry. Under the restructuring law a
transition to choice of electricity supplier for retail customers
will commence on January 1, 2002 and be completed, subject to a
finding by the Virginia State Corporation Commission that an
effective competitive market exists, on January 1, 2004.
The Virginia restructuring law also provides an opportunity for
recovery of just and reasonable net stranded costs. Stranded costs
are those costs above market including generation related
regulatory assets and impaired tangible assets that potentially
would not be recoverable in a competitive market. The mechanisms
in the Virginia law for stranded cost recovery are: a capping of
rates until as late as July 1, 2007, and the application of a wires
charge upon customers who may depart the incumbent utility in favor
of an alternative supplier prior to the termination of the rate
cap. The law provides for the establishment of capped rates prior
to January 1, 2001.
Management has concluded that as of June 30, 1999 the
requirements to apply Statement of Financial Accounting Standards
(SFAS) 71, "Accounting for the Effects of Certain Types of
Regulation," continue to be met. The Company's Virginia rates for
generation will continue to be cost-based regulated until the
establishment of capped rates and the wires charge as provided in
the law. The establishment of capped rates should enable the
Company to determine its ability to recover stranded costs. When
capped rates and the wires charge are established in Virginia, the
application of SFAS 71 would be discontinued for the Virginia
retail jurisdiction portion of the generating business. At that
time the Company will have to write-off its generation-related
regulatory assets to the extent that they cannot be recovered under
provisions of the restructuring law and record any asset
impairments in accordance with SFAS 121 "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to Be
Disposed Of." An impairment loss would be recorded to the extent
that the cost of impaired assets cannot be recovered through the
transition recovery mechanisms provided by the law and future
market prices. Absent the determination in the regulatory process
of capped rates and other pertinent information, it is not possible
at this time to determine if any of the Company's plants are
impaired in accordance with SFAS 121. The amount of regulatory
assets recorded on the books applicable to the Virginia generating
business at June 30, 1999 is estimated to be $60 million before
related tax effects.
Should it not be possible under the Virginia law to recover all
or a portion of the generation related regulatory assets, it could
have a material adverse impact on results of operations. An
estimated determination of whether the Company will experience any
asset impairment loss regarding its Virginia retail jurisdictional
generating assets and any loss from a possible inability to recover
generation related regulatory assets cannot be made until such time
as the transition capped rates and the wires charge are determined
under the law which is expected to be in the fourth quarter of
2000.
<PAGE>
Air Quality
As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, Federal EPA issued final
rules which require reductions in nitrogen oxides (NOx) emissions
in 22 eastern states, including the states in which the generating
plants of the Company and its AEP System affiliates are located.
The final rules were to be implemented through state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. The NOx SIP Call rule requires
submission of revised SIPs by September 30, 1999. A number of
utilities, including the Company and its AEP System affiliates,
filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals
Court). On May 25, 1999, the Appeals Court ordered an indefinite
stay of the September 30, 1999 deadline for submission of SIP
revisions pending a further order of the court while arguments
regarding the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act. Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP Call. The imposition of these NOx
reduction requirements on AEP System generating units would be
approximately equivalent to the reductions contemplated by the
stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air
Regulatory Group and the Midwest Ozone Group, respectively, each
filed a petition in the Appeals Court seeking review of Federal
EPA's approval of portions of the northeastern states' petitions.
In the second quarter of 1999, three additional northeastern states
filed Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $410 million for
the Company. Compliance costs cannot 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 through
regulated rates and/or reflected in the future market price of
electricity, they will have a material adverse effect on future
results of operations, cash flows and possibly financial condition.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates. The Company's exposure to market risk from the
trading of electricity and related financial derivative
instruments, which are allocated to the Company through the
American Electric Power System Power Pool, has not changed
materially since December 31, 1998. Market risk represents the
risk of loss that may impact the Company due to adverse changes in
commodity market prices and interest rates.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at June 30, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date. In
addition, certain systems may fail to detect that the year 2000 is
a leap year. Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur. This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery. Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations. In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The Company, along with other electric utilities in North America,
has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities. The fourth and final NERC report, dated August 3, 1999
and entitled: Preparing the Electric Power Systems of North America
for Transition to the Year 2000 - A Status Report and Work Plan,
Second Quarter 1999, states that: "Mission-critical component
testing indicates that the transition through critical Y2K dates is
expected to have minimal impact on electric system operations in
North America." The report also indicates that, "the risk of
electrical outages caused by Y2K appears to be no higher than the
risks we already experience" from incidents such as severe wind,
ice, floods, equipment failures and power shortages during an
extremely hot or cold period.
AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications. There were no major problems encountered with
relaying information with the use of backup telecommunications
systems. AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.
Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk. The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
The following chart shows the Company's progress toward
becoming ready for the Y2K as of June 30, 1999:
IT SYSTEMS NON-IT
SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT
DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION
DATE COMPLETE
Launch: Initiation of 2/24/1998 100% 5/31/1998
100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999
100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe: 6/30/1999
100%
replacing or retiring 100%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 100%
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 June 30,
1999, the Company has spent $11 million on the Y2K project and,
estimates spending an additional $4 million to $6 million to
achieve Y2K readiness. Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized. The Company intends to fund these expenditures
through internal sources. The cost of becoming Y2K compliant is
not expected to have a material impact on the Company's results of
operations, cash flows or financial condition.
Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
Automated power generation, transmission and distribution systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for commercial
and industrial customers and
Work management and billing systems.
The potential problems related to erroneous processing by, or
failure of, these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues may materially adversely affect the Company.
Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council as part
of NERC's review of regional and individual electric utility
contingency plans in 1999. In addition, the Company is
establishing contingency plans for its business units to address
alternatives if Y2K related failures occur. These contingency
plans will be developed by the end of 1999.
The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, in order to place
key employees on duty at those locations during the Y2K
transition.
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $301,419 $298,263 $580,486 $564,662
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 49,144 46,860 95,000 93,840
Purchased Power. . . . . . . . . . . . 59,255 58,782 114,446 106,619
Other Operation. . . . . . . . . . . . 46,514 46,783 92,483 91,365
Maintenance. . . . . . . . . . . . . . 18,374 14,889 32,320 29,196
Depreciation . . . . . . . . . . . . . 23,522 22,844 46,706 45,694
Taxes Other Than Federal Income Taxes. 30,051 27,690 61,129 57,626
Federal Income Taxes . . . . . . . . . 20,086 23,264 37,882 37,942
TOTAL OPERATING EXPENSES . . . 246,946 241,112 479,966 462,282
OPERATING INCOME . . . . . . . . . . . . 54,473 57,151 100,520 102,380
NONOPERATING INCOME (LOSS) . . . . . . . (478) 1,256 (117) 1,228
INCOME BEFORE INTEREST CHARGES . . . . . 53,995 58,407 100,403 103,608
INTEREST CHARGES . . . . . . . . . . . . 19,436 19,665 38,426 39,221
NET INCOME . . . . . . . . . . . . . . . 34,559 38,742 61,977 64,387
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 532 532 1,065 1,065
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,027 $ 38,210 $ 60,912 $ 63,322
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $191,327 $142,623 $186,441 $138,172
NET INCOME . . . . . . . . . . . . . . . 34,559 38,742 61,977 64,387
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 21,999 20,661 43,998 41,322
Cumulative Preferred Stock . . . . . 438 438 875 875
Capital Stock Expense. . . . . . . . . 95 95 191 191
BALANCE AT END OF PERIOD . . . . . . . . $203,354 $160,171 $203,354 $160,171
The common stock of the Company is wholly owned by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,535,336 $1,526,869
Transmission . . . . . . . . . . . . . . . . . . . . 346,714 339,934
Distribution . . . . . . . . . . . . . . . . . . . . 971,086 938,283
General. . . . . . . . . . . . . . . . . . . . . . . 134,273 130,002
Construction Work in Progress. . . . . . . . . . . . 103,598 118,477
Total Electric Utility Plant . . . . . . . . 3,091,007 3,053,565
Accumulated Depreciation . . . . . . . . . . . . . . 1,171,875 1,134,348
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,919,132 1,919,217
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 95,506 73,088
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 7,850 7,206
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 81,118 89,522
Affiliated Companies . . . . . . . . . . . . . . . 33,808 17,966
Miscellaneous. . . . . . . . . . . . . . . . . . . 5,847 11,989
Allowance for Uncollectible Accounts . . . . . . . (3,093) (2,598)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 19,753 22,140
Materials and Supplies . . . . . . . . . . . . . . . 37,836 33,263
Accrued Utility Revenues . . . . . . . . . . . . . . 53,625 40,127
Energy Marketing and Trading Contracts . . . . . . . 111,655 12,670
Prepayments. . . . . . . . . . . . . . . . . . . . . 37,801 29,084
TOTAL CURRENT ASSETS . . . . . . . . . . . . 386,200 261,369
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 339,480 353,369
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 38,129 74,647
TOTAL. . . . . . . . . . . . . . . . . . . $2,778,447 $2,681,690
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 24,000,000 Shares
Outstanding - 16,410,426 Shares. . . . . . . . . . $ 41,026 $ 41,026
Paid-in Capital. . . . . . . . . . . . . . . . . . . 572,682 572,492
Retained Earnings. . . . . . . . . . . . . . . . . . 203,354 186,441
Total Common Shareholder's Equity. . . . . . 817,062 799,959
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 946,058 959,786
TOTAL CAPITALIZATION . . . . . . . . . . . . 1,788,120 1,784,745
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 44,697 42,176
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 14,000 -
Short-term Debt. . . . . . . . . . . . . . . . . . . 70,400 52,500
Accounts Payable - General . . . . . . . . . . . . . 30,259 34,631
Accounts Payable - Affiliated Companies. . . . . . . 34,819 37,132
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 109,453 141,831
Interest Accrued . . . . . . . . . . . . . . . . . . 14,387 14,355
Energy Marketing and Trading Contracts . . . . . . . 112,206 13,682
Other. . . . . . . . . . . . . . . . . . . . . . . . 27,114 37,197
TOTAL CURRENT LIABILITIES. . . . . . . . . . 412,638 331,328
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 438,152 442,100
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 46,973 48,710
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 47,867 32,631
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . . $2,778,447 $2,681,690
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 61,977 $ 64,387
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 46,837 45,808
Deferred Federal Income Taxes. . . . . . . . . . . . . . 2,697 3,959
Deferred Investment Tax Credits. . . . . . . . . . . . . (1,737) (1,775)
Deferred Collection of Fuel Costs (net). . . . . . . . . 4,252 (5,753)
Amortization of Deferred Property Taxes. . . . . . . . . 34,406 32,514
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (801) 1,709
Fuel, Materials and Supplies . . . . . . . . . . . . . . (2,186) (33)
Accrued Utility Revenues . . . . . . . . . . . . . . . . (13,498) (13,677)
Prepayments. . . . . . . . . . . . . . . . . . . . . . . (8,717) (7,909)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (6,685) 544
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (32,378) (51,022)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (10,806) 8,491
Net Cash Flows From Operating Activities . . . . . . 73,361 77,243
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (46,005) (57,626)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 261 2,287
Net Cash Flows Used For Investing Activities . . . . (45,744) (55,339)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 111,075
Change in Short-term Debt (net). . . . . . . . . . . . . . 17,900 (14,075)
Retirement of Long-term Debt . . . . . . . . . . . . . . . - (81,750)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (43,998) (41,322)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (875) (437)
Net Cash Flows Used For Financing Activities . . . . (26,973) (26,509)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 644 (4,605)
Cash and Cash Equivalents at Beginning of Period . . . . . . 7,206 12,626
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 7,850 $ 8,021
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $36,491,000 and $37,667,000
and for income taxes was $14,207,000 and $20,886,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $4,043,000 and $6,060,000 in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial statements should
be read in conjunction with the 1998 Annual Report as incorporated in and
filed with the Form 10-K. Certain prior-period amounts have been
reclassified to conform to current-period presentation. In the opinion
of management, the financial statements reflect all adjustments
(consisting of only normal recurring accruals) which are necessary for
a fair presentation of the results of operations for interim periods.
2. FINANCING ACTIVITIES
The short-term debt limitation of the Company was increased from $300
million to $350 million with approval of the Securities and Exchange
Commission.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus (EITF)
98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities". The EITF requires that all energy trading
contracts be marked-to-market. The effect on the Consolidated Statements
of Income of marking open trading contracts to market is deferred as
regulatory assets or liabilities for those open trading transactions that
are included in cost of service on a settlement basis for ratemaking
purposes. The adoption of the EITF did not have a material effect on
results of operations, cash flows or financial condition.
4. RATE MATTERS
The Federal Energy Regulatory Commission (FERC) issued orders 888 and
889 in April 1996 which required each public utility that owns or
controls interstate transmission facilities to file an open access
network and point-to-point transmission tariff that offers services
comparable to the utility's own uses of its transmission system. The
orders also require utilities to functionally unbundle their services,
by requiring them to use their own tariffs in making off-system and
third-party sales. As part of the orders, the FERC issued a pro-forma
tariff which reflects the Commission's views on the minimum non-price
terms and conditions for non-discriminatory transmission service. The
orders also allow a utility to seek recovery of certain prudently-incurred
stranded costs that result from unbundled transmission service.
On July 9, 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma transmission
tariff, subject to the resolution of certain pricing issues.
<PAGE>
On July 29, 1999, the FERC approved a draft order which rules on the
AEP System's pending Open Access Transmission Tariff. This approved
order has certain unfavorable pricing issues for which the AEP System has
30 days to seek rehearing. If the Commission's order is ultimately
upheld the Company as a member of the AEP System will have to make
refunds including interest. As of June 30, 1999 the Company has not made
any provisions for its share of a potential refund which is preliminarily
estimated to be approximately $3 million.
5. OHIO RESTRUCTURING LEGISLATION
On July 6, 1999, the Governor of the State of Ohio signed The Ohio
Electric Restructuring Act of 1999. The Act provides for customer choice
of electricity supplier and a residential rate reduction of 5% of the
unbundled generation rate beginning on January 1, 2001. The Act also
provides for a five-year transition period to transition from cost based
rates to market pricing for generation services. It authorizes the
Public Utilities Commission of Ohio (PUCO) to address certain major
transition issues including unbundling of rates and the recovery of
regulatory assets and other stranded transition costs.
Retail electric services that will be competitive are defined in the
Act as electric generation service, aggregation service, and power
marketing and brokering. The PUCO has been granted broad oversight
responsibility under the Act. The Act requires the PUCO to promulgate
rules for competitive retail electric generation service.
The Act further provides Ohio electric utilities with an opportunity
to recover PUCO approved allowable transition costs through unbundled
rates paid by customers who do not switch generation suppliers and
through a wires charges by customers who switch generation suppliers.
Transition costs can include regulatory assets, impairments of generating
assets and other stranded costs, employee severance and retraining costs
and other costs. Recovery of transition revenues can under certain
circumstances extend beyond the five-year transition period but cannot
continue beyond December 31, 2010. The Company must file a transition
plan with the PUCO by January 3, 2000 and the PUCO is required to issue
a transition order no later than October 31, 2000.
The Act also provides that the property tax assessment percentage on
electric generation equipment be lowered from 100% to 25% of value
effective January 1, 2001. Electric utilities will also become subject
to the Ohio Corporate Franchise Tax and municipal income taxes on January
1, 2002. The last year for which electric utilities will pay the excise
tax based on gross receipts is the year ending April 30, 2002. As of May
1, 2001 electric distribution companies will be subject to an excise tax
based on kilowatt-hours sold to Ohio customers. These changes should put
the Company's generation operations on an equal level with other
competitive businesses in Ohio regarding state taxation.
As discussed in Note 2, "Effects of Regulation and the Zimmer Phase-in
Plan," of the Notes to Consolidated Financial Statements in the 1998
Annual Report, the Company defers as regulatory liabilities and assets
certain revenues and expenses consistent with the regulatory process in
accordance with Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation." At June 30,
1999, the amount of regulatory assets recorded on the books applicable
to the generating business is estimated to be $275 million before related
tax effects. Whether the Company will have any additional stranded
transition costs related to an economic impairment of its generating
assets is dependent on several factors including the assumed future
market price for electricity. The Company intends to seek recovery in
its transition filing of all regulatory assets and any other stranded
transition costs which may be identified. At this time management is
unable to predict the outcome of the regulatory process or its impact on
results of operations, cash flows or financial condition. Therefore, the
Company will not be discontinuing application of SFAS 71 until the
regulatory process is completed.
Upon discontinuance of the application of SFAS 71 the Company will
have to write off its generation-related regulatory assets and record any
asset impairments in accordance with SFAS 121 "Accounting for the
Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed
Of." Absent the determination in the regulatory process of transition
revenues and other pertinent information, it is not possible at this time
to determine if any of the Company's plants are impaired in accordance
with SFAS 121. Should the Company be granted recovery of its regulatory
assets and/or any economic asset impairments it can record an offsetting
regulatory asset. Should the PUCO not approve the Company's request for
recovery of its generation-related regulatory assets and/or other
stranded transition costs it would have an adverse impact on future
results of operations and possibly financial condition. The Company does
not expect to be able to determine the impact of the legislation on its
financial statements until the regulatory process is complete. The PUCO
is required to complete its regulatory process no later than October 31,
2000.
6. CONTINGENCIES
Litigation
As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the deductibility of certain
interest deductions related to American Electric Power's corporate owned
life insurance (COLI) program for taxable years 1991-1996 is under review
by the Internal Revenue Service (IRS). Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions. A disallowance
of COLI interest deductions through June 30, 1999 would reduce earnings
by approximately $43 million (including interest). The Company has made
no provision for any possible earnings impact from this matter.
In 1998 the Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1997 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. These payments to the IRS are included
on the Consolidated Balance Sheets in other property and investments
pending the resolution of this matter. The Company is seeking refunds
through litigation of all amounts paid plus interest.
<PAGE>
In order to resolve this issue, the Company filed suit against the
United States in the United States (U.S.) District Court for the Southern
District of Ohio in March 1998. Management believes that it has a
meritorious position and will vigorously pursue this lawsuit. In the
event the resolution of this matter is unfavorable, it will have a
material adverse impact on results of operations.
Air Quality
As discussed in Note 3 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, the U.S. Environmental Protection
Agency (Federal EPA) issued final rules which require reductions in
nitrogen oxides (NOx) emissions in 22 eastern states, including the
states in which the generating plants of the Company and its AEP System
affiliates are located. The final rules were to be implemented through
state implementation plans (SIPs). SIPs are a procedural method used by
each state to comply with Federal EPA rules. The NOx SIP Call rule
requires submission of revised SIPs by September 30, 1999. A number of
utilities, including the Company and its AEP System affiliates, filed
petitions seeking a review of the final rule in the U.S. Court of Appeals
for the District of Columbia Circuit (Appeals Court). On May 25, 1999,
the Appeals Court ordered an indefinite stay of the September 30, 1999
deadline for submission of SIP revisions pending a further order of the
court while arguments regarding the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with respect to
petitions filed by eight northeastern states pursuant to Section 126 of
the Clean Air Act. Federal EPA approved portions of the states'
petitions triggering emission reductions that are substantially the same
as those that would otherwise have been required by the NOx SIP Call.
The imposition of these NOx reduction requirements on AEP System
generating units would be approximately equivalent to the reductions
contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999,
the Utility Air Regulatory Group and the Midwest Ozone Group,
respectively, each filed a petition in the Appeals Court seeking review
of Federal EPA's approval of portions of the northeastern states'
petitions. In the second quarter of 1999, three additional northeastern
states filed Section 126 petitions with Federal EPA similar to those
filed by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could result in
required capital expenditures of approximately $175 million for the
Company. Compliance costs cannot 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 or reflected in the future market price of
electricity, they will have a material adverse effect on future results
of operations, cash flows and possibly financial condition.
Other
The Company continues to be involved in certain other matters
discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 1999 vs. SECOND QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
Net income decreased $4.2 million or 11% in the second quarter and $2.4
million or 4% in the year-to-date period primarily due to increased operating
expenses.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $ 3.2 1 $15.8 3
Fuel Expense. . . . . . . . 2.3 5 1.2 1
Purchased Power Expense . . 0.5 1 7.8 7
Maintenance Expense . . . . 3.5 23 3.1 11
Taxes Other Than Federal
Income Taxes . . . . . . . 2.4 9 3.5 6
Federal Income Taxes. . . . (3.2) (14) (0.1) -
Operating revenues increased in both the second quarter and the year-to-date
period due predominantly to increased retail sales. Retail revenues and
sales increased 4% and 3%, respectively, in the second quarter and 5% in the
year-to-date period due to customer growth and the effect of colder winter
weather on residential and commercial usage in the year-to-date period.
Fuel expense increased in the second quarter due to the operation of the
fuel clause adjustment mechanism as prior period deferrals of underrecovered
fuel costs were amortized to expense in the current period concurrent with
rate recovery.
The increase in purchased power expense in the year-to-date period is
primarily due to increased capacity charges from the American Electric Power
(AEP) System Power Pool (AEP Power Pool). Under the terms of the AEP Power
Pool, capacity credits and charges are designed to allocate the cost of the
AEP System's capacity among the AEP Power Pool members based on their
relative peak demands and generating reserves. The increase in capacity
charges can be attributed to an increase in the Company's prior twelve month
peak demand relative to the total peak demand of all AEP Power Pool members.
<PAGE>
Maintenance expense increased primarily due to scheduled power plant
maintenance outages of the Zimmer Plant and one unit of the Conesville Plant
in 1999.
The increase in taxes other than federal income taxes was primarily due
to higher property tax rates in 1999 and the effect of a favorable property
tax accrual adjustment recorded in May 1998.
Federal income taxes attributable to operations decreased in the second
quarter primarily as a result of a decrease in pre-tax operating income.
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $336,553 $348,271 $ 670,666 $676,739
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 42,123 37,875 83,923 82,754
Purchased Power. . . . . . . . . . . . 67,510 86,504 129,825 144,663
Other Operation. . . . . . . . . . . . 115,258 82,850 206,833 159,283
Maintenance. . . . . . . . . . . . . . 24,621 33,259 55,823 60,337
Depreciation and Amortization. . . . . 37,495 36,234 74,480 72,027
Taxes Other Than Federal Income Taxes. 17,256 16,105 36,285 32,497
Federal Income Taxes . . . . . . . . . 5,324 13,250 17,693 31,616
TOTAL OPERATING EXPENSES . . . 309,587 306,077 604,862 583,177
OPERATING INCOME . . . . . . . . . . . . 26,966 42,194 65,804 93,562
NONOPERATING INCOME. . . . . . . . . . . 1,556 3,585 3,291 2,595
INCOME BEFORE INTEREST CHARGES . . . . . 28,522 45,779 69,095 96,157
INTEREST CHARGES . . . . . . . . . . . . 18,777 17,243 39,280 33,877
NET INCOME . . . . . . . . . . . . . . . 9,745 28,536 29,815 62,280
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,215 1,202 2,429 2,419
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 8,530 $ 27,334 $ 27,386 $ 59,861
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $243,346 $281,975 $253,154 $278,814
NET INCOME . . . . . . . . . . . . . . . 9,745 28,536 29,815 62,280
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 28,664 29,366 57,328 58,732
Cumulative Preferred Stock . . . . . 1,182 1,183 2,364 2,367
Capital Stock Expense. . . . . . . . . 33 19 65 52
BALANCE AT END OF PERIOD . . . . . . . . $223,212 $279,943 $223,212 $279,943
The common stock of the Company is wholly owned
by American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,583,294 $2,565,041
Transmission . . . . . . . . . . . . . . . . . . . . 919,595 913,495
Distribution . . . . . . . . . . . . . . . . . . . . 785,634 768,888
General (including nuclear fuel) . . . . . . . . . . 232,486 228,013
Construction Work in Progress. . . . . . . . . . . . 167,441 156,411
Total Electric Utility Plant . . . . . . . . 4,688,450 4,631,848
Accumulated Depreciation and Amortization. . . . . . 2,143,088 2,081,355
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,545,362 2,550,493
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR
FUEL DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . 688,793 648,307
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 214,515 197,368
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 20,839 12,465
Accounts Receivable (net). . . . . . . . . . . . . . 141,220 130,746
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 36,466 20,857
Materials and Supplies . . . . . . . . . . . . . . . 85,941 78,009
Accrued Utility Revenues . . . . . . . . . . . . . . 31,354 37,277
Energy Marketing and Trading Contracts . . . . . . . 121,939 14,105
Prepayments. . . . . . . . . . . . . . . . . . . . . 5,880 4,848
TOTAL CURRENT ASSETS . . . . . . . . . . . . 443,639 298,307
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 525,631 421,475
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 31,064 32,573
TOTAL. . . . . . . . . . . . . . . . . . . $4,449,004 $4,148,523
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 2,500,000 Shares
Outstanding - 1,400,000 Shares . . . . . . . . . . $ 56,584 $ 56,584
Paid-in Capital. . . . . . . . . . . . . . . . . . . 732,672 732,605
Retained Earnings. . . . . . . . . . . . . . . . . . 223,212 253,154
Total Common Shareholder's Equity. . . . . . 1,012,468 1,042,343
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 9,266 9,273
Subject to Mandatory Redemption. . . . . . . . . . 68,445 68,445
Long-term Debt . . . . . . . . . . . . . . . . . . . 982,604 1,140,789
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,072,783 2,260,850
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 480,938 445,934
Other. . . . . . . . . . . . . . . . . . . . . . . . 247,389 240,320
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 728,327 686,254
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 133,000 35,000
Short-term Debt. . . . . . . . . . . . . . . . . . . 269,180 108,700
Accounts Payable - General . . . . . . . . . . . . . 54,488 53,187
Accounts Payable - Affiliated Companies. . . . . . . 29,114 37,647
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 11,299 35,161
Interest Accrued . . . . . . . . . . . . . . . . . . 14,355 15,279
Revenue Refunds Accrued. . . . . . . . . . . . . . . 55,000 -
Obligations Under Capital Leases . . . . . . . . . . 10,744 9,667
Energy Marketing and Trading Contracts . . . . . . . 122,541 15,228
Dividends Declared . . . . . . . . . . . . . . . . . 29,846 1,183
Other. . . . . . . . . . . . . . . . . . . . . . . . 76,093 70,882
TOTAL CURRENT LIABILITIES. . . . . . . . . . 805,660 381,934
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 573,752 559,288
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 125,983 129,779
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 86,859 88,712
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 55,640 41,706
COMMITMENTS AND CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $4,449,004 $4,148,523
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 29,815 $ 62,280
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 76,431 74,126
Amortization of Incremental Nuclear
Refueling Outage Expenses (net). . . . . . . . . . . . 4,695 8,518
Unrecovered Fuel and Purchased Power . . . . . . . . . . (63,922) (34,369)
Deferred Nuclear Outage Costs (net). . . . . . . . . . . (60,000) -
Deferred Federal Income Taxes. . . . . . . . . . . . . . 23,448 7,839
Deferred Investment Tax Credits. . . . . . . . . . . . . (3,796) (3,818)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (10,474) (61,320)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (23,541) (10,343)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 5,923 (11,384)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (7,232) 57,979
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (23,862) (12,041)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . 55,000 -
Dividends Declared . . . . . . . . . . . . . . . . . . . 28,663 -
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (25,103) (8,581)
Net Cash Flows From Operating Activities . . . . . . 6,045 68,886
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (63,316) (61,203)
Proceeds from Sale of Property . . . . . . . . . . . . . . 1,198 1,391
Net Cash Flows Used for Investing Activities . . . . (62,118) (59,812)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 122,222
Retirement of Long-term Debt . . . . . . . . . . . . . . . (65,000) (35,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . 160,480 (8,800)
Retirement of Cumulative Preferred Stock . . . . . . . . . (5) (39)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (28,664) (58,732)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (2,364) (2,368)
Net Cash Flows From Financing Activities . . . . . . 64,447 17,283
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 8,374 26,357
Cash and Cash Equivalents at Beginning of Period . . . . . . 12,465 5,860
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 20,839 $ 32,217
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $38,775,000 and $32,651,000
and for income taxes was $19,217,000 and $15,054,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $6,901,000 and $18,801,000 in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments should be
read in conjunction with the 1998 Annual Report as incorporated in and
filed with the Form 10-K. Certain prior-period amounts have been
reclassified to conform to current-period presentation. In the opinion of
management, the financial statements reflect all adjustments (consisting
of only normal recurring accruals) which are necessary for a fair
presentation of the results of operations for interim periods.
2. FINANCING ACTIVITIES
During the first six months of 1999, the Company reacquired
the following first mortgage bonds for $65 million:
Principal
Amount
% Rate Due Date Reacquired
(in thousands)
6.80 July 1, 2003 $20,000
6.55 October 1, 2003 20,000
6.55 March 1, 2004 25,000
In July 1999 the Company issued $150 million of 6-7/8%
senior unsecured notes due 2004.
The short-term debt limitation of the Company was increased
from $300 million to $500 million with approval of the
Securities and Exchange Commission.
During the first six months of 1999, the Company issued
$160 million of short-term debt.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the
Financial Accounting Standards Board's Emerging Issues Task
Force Consensus (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities". The
EITF requires that all energy trading contracts be marked-to-market.
The effect on the Consolidated Statements of Income
of marking open trading contracts to market is deferred as
regulatory assets or liabilities for those open trading
transactions that are included in cost of service on a
settlement basis for ratemaking purposes. The adoption of the
EITF did not have a material effect on results of operations,
cash flows or financial condition.
<PAGE>
4. RATE MATTERS
The Federal Energy Regulatory Commission (FERC) issued
orders 888 and 889 in April 1996 which required each public
utility that owns or controls interstate transmission
facilities to file an open access network and point-to-point
transmission tariff that offers services comparable to the
utility's own uses of its transmission system. The orders also
require utilities to functionally unbundle their services, by
requiring them to use their own tariffs in making off-system
and third-party sales. As part of the orders, the FERC issued
a pro-forma tariff which reflects the Commission's views on the
minimum non-price terms and conditions for non-discriminatory
transmission service. The orders also allow a utility to seek
recovery of certain prudently-incurred stranded costs that
result from unbundled transmission service.
On July 9, 1996, the AEP System companies filed an Open
Access Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain
pricing issues.
On July 29, 1999, the FERC approved a draft order which
rules on the AEP System's pending Open Access Transmission
Tariff. This approved order has certain unfavorable pricing
issues for which the AEP System has 30 days to seek rehearing.
If the Commission's order is ultimately upheld the Company as
a member of the AEP System will have to make refunds including
interest. As of June 30, 1999 the Company has not made any
provisions for its share of a potential refund which is
preliminarily estimated to be approximately $4 million.
5. CONTINGENCIES
Litigation
As discussed in Note 3 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the
deductibility of certain interest deductions related to
American Electric Power's corporate owned life insurance (COLI)
program for taxable years 1991-1996 is under review by the
Internal Revenue Service (IRS). Adjustments have been or will
be proposed by the IRS disallowing COLI interest deductions.
A disallowance of COLI interest deductions through June 30,
1999 would reduce earnings by approximately $66 million
(including interest). The Company has made no provision for
any possible earnings impact from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1997 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
These payments to the IRS are included on the Consolidated
Balance Sheets in other property and investments pending the
resolution of this matter. The Company is seeking refunds
through litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit
against the United States in the U.S. District Court for the
Southern District of Ohio in March 1998. Management believes
that it has a meritorious position and will vigorously pursue
this lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations.
Air Quality
As discussed in Note 3 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the U.S.
Environmental Protection Agency (Federal EPA) issued final
rules which require reductions in nitrogen oxides (NOx)
emissions in 22 eastern states, including the states in which
the generating plants of the Company and its AEP System
affiliates are located. The final rules were to be implemented
through state implementation plans (SIPs). SIPs are a
procedural method used by each state to comply with Federal EPA
rules. The NOx SIP Call rule requires submission of revised
SIPs by September 30, 1999. A number of utilities, including
the Company and its AEP System affiliates, filed petitions
seeking a review of the final rule in the U.S. Court of Appeals
for the District of Columbia Circuit (Appeals Court). On May
25, 1999, the Appeals Court ordered an indefinite stay of the
September 30, 1999 deadline for submission of SIP revisions
pending a further order of the court while arguments regarding
the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with
respect to petitions filed by eight northeastern states
pursuant to Section 126 of the Clean Air Act. Federal EPA
approved portions of the states' petitions triggering emission
reductions that are substantially the same as those that would
otherwise have been required by the NOx SIP Call. The
imposition of these NOx reduction requirements on AEP System
generating units would be approximately equivalent to the
reductions contemplated by the stayed SIP Call rule. On May
28, and June 1, 1999, the Utility Air Regulatory Group and the
Midwest Ozone Group, respectively, each filed a petition in the
Appeals Court seeking review of Federal EPA's approval of
portions of the northeastern states' petitions. In the second
quarter of 1999, three additional northeastern states filed
Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could
result in required capital expenditures of approximately $215
million for the Company. Compliance costs cannot 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 through regulated rates and/or reflected in the
future market price of electricity if generation is
deregulated, they will have a material adverse effect on future
results of operations, cash flows and possibly financial
condition.
Cook Plant Shutdown
As discussed in Note 3 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, both units of
the Cook Plant were shut down in September 1997 due to
questions regarding the operability of certain safety systems
that arose during a Nuclear Regulatory Commission (NRC)
architect engineer design inspection. The NRC issued a
Confirmatory Action Letter in September 1997 requiring the
Company to address certain issues identified in the letter.
In 1998 the NRC notified the Company that it had convened a
Restart Panel for Cook Plant and provided a list of required
restart activities. In order to identify and resolve all
issues, including those in the letter, necessary to restart the
Cook units, the Company is working with the NRC and will be
meeting with the Panel on a regular basis, until the units are
returned to service.
In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant
as an "agency-focus plant." The NRC senior managers concluded
that continued agency-level oversight was appropriate; however,
the NRC required no additional action to redirect Cook Plant
activities. The letter states that the NRC staff will continue
to monitor Cook Plant performance through the Restart Panel
process and evaluate whether additional action may be
necessary.
On June 24, 1999, the Boards of Directors of American
Electric Power Company, Inc. and the Company both approved a
plan to restart the Cook Plant. Unit 2 is scheduled to return
to service in April 2000 and Unit 1 is to return to service in
September 2000. This approval follows a comprehensive systems
readiness review of all operating systems at the Cook Plant.
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.
Management intends to replace the steam generator for Unit
1 before the unit is returned to service. Costs associated
with the steam generator replacement are estimated to be
approximately $165 million, which will be accounted for as a
capital investment unrelated to the restart. At June 30, 1999,
$70 million has been spent on the steam generator replacement.
The cost of electricity supplied to retail customers
increased due to the outage of the two Cook Plant nuclear units
since higher cost coal-fired generation and coal based
purchased power is being substituted for the unavailable low
cost nuclear generation. Actual replacement energy fuel costs
that exceeded the costs reflected in billings have been
recorded as a regulatory asset under the Indiana and Michigan
retail jurisdictional fuel cost recovery mechanisms. At June
30, 1999, the regulatory asset was $129 million.
On March 30, 1999 the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolves all
matters related to the recovery of replacement energy fuel
costs and all outage/restart issues during the extended outage
of the Cook Plant. The settlement agreement provides for,
among other things, a credit of $55 million, including
interest, to Indiana retail customers' bills; the deferral of
unrecovered fuel revenues accrued between September 9, 1997 and
December 31, 1999, including the $52.3 million revenue portion
of the $55 million billing credit; the deferral of up to $150
million of incremental operation and maintenance costs in 1999
for Cook Plant above the amount included in base rates; the
amortization of the deferred fuel recoveries and non-fuel
operation and maintenance cost deferrals over a five-year
period ending December 31, 2003; a freeze in base rates through
December 31, 2003; and a fixed fuel recovery charge through
March 1, 2004. The $55 million credit will be applied to
customers' bills during the months of July, August and
September 1999.
In June 1999 the Company announced that a settlement
agreement for two open Michigan power supply cost recovery
reconciliation cases had been reached with the staff of the
Michigan Public Service Commission (MPSC). The proposed
settlement agreement would freeze rates and power supply costs
for five years, allow for the amortization of deferred power
supply cost for 1997, 1998 and 1999 over five years, allow for
the deferral and amortization of non-fuel nuclear operation and
maintenance expenses over five years and resolve all issues
related to the Cook Plant extended outage. At a hearing on
June 30, 1999, the MPSC granted a continuance to the one
intervenor who opposed the approval of the settlement
agreement. A hearing has been scheduled for August 13, 1999.
Expenditures for the restart of the Cook units are
estimated to total approximately $574 million and will be
accounted for primarily as current period operation and
maintenance expense in 1999 and 2000. Through June 30, 1999,
$192 million has been spent, of which $108 million was incurred
in the first half of 1999. Pursuant to the Indiana settlement
agreement $60 million of incremental operation and maintenance
costs were deferred through June 30, 1999. The Indiana
jurisdiction deferral is limited to up to $150 million of
incremental restart costs incurred in 1999. The pending
Michigan settlement limits deferrals to $50 million of non-fuel
operation and maintenance costs.
The costs of the extended outage and restart efforts will
have a material adverse effect on future results of operations,
cash flows, and possibly financial condition through 2003.
Management believes that the Cook units will be successfully
returned to service by April and September 2000, however, if
for some unknown reason the units are not returned to service
or their return is delayed significantly it would have an even
greater adverse effect on future results of operations, cash
flows and financial condition.
Other
The Company continues to be involved in other matters
discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1999 vs. SECOND QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income decreased $18.8 million or 66% in the second quarter
and $32.5 million or 52% for the year-to-date period due primarily
to increased operation expense related to an extended outage of the
Cook Nuclear Plant which was shut down in September 1997.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . $(11.7) (3) $ (6.1) (1)
Fuel Expense. . . . . . . 4.2 11 1.2 1
Purchased Power Expense . (19.0) (22) (14.8) (10)
Other Operation Expense . 32.4 39 47.6 30
Maintenance Expense . . . (8.6) (26) (4.5) (7)
Taxes Other Than
Federal Income Taxes . . 1.2 7 3.8 12
Federal Income Taxes. . . (7.9) (60) (13.9) (44)
Interest Charges. . . . . 1.5 9 5.4 16
Operating revenues decreased in both the second quarter and the
year-to-date period due primarily to a decrease in retail revenues
reflecting the effect of an Indiana settlement agreement on fuel
recovery billings in the Company's Indiana retail jurisdiction.
Under the terms of the settlement agreement, approved by the
Indiana commission in March 1999, the fuel recovery rate was
reduced and fixed through March 1, 2004. The unrecovered Cook
replacement power and restart costs were deferred for future
amortization.
Fuel expense increased in the second quarter due to an increase
in generation reflecting increased availability of the Company's
coal fired generating units in 1999.
The decrease in purchased power expense resulted from decreased
purchases reflecting the increased generating plant availability.
Other operation expense increased due to increased nuclear
engineering and contract employee costs during the extended Cook
shutdown and restart efforts.
<PAGE>
The deferral in 1999 of maintenance costs
during the extended shutdown of the Cook Plant under the terms of the Indiana
settlement agreement accounted for the decrease in maintenance
expense.
Increases in real and personal property, gross receipts and
single business taxes accounted for the increases in taxes other
than federal income taxes.
Federal income taxes attributable to operations decreased in
both periods as a result of a decrease in pre-tax operating income.
Interest expense increased in the second quarter due to an
increase in short-term borrowing to fund the expenditures for the
Cook Plant restart effort. In the year-to-date period interest
expense increased due to increased long-term debt interest expense
reflecting higher outstanding balances, the accrual of interest for
revenue refunds ordered by the Indiana commission as part of the
settlement agreement and the increase in short-term borrowings.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the year-to-date period were $71 million.
During the first six months of 1999 the Company redeemed $65
million principal amount of first mortgage bonds with interest
rates from 6.55% to 6.80%. Short-term debt outstanding increased
by $160 million from year-end balances.
In July 1999 the Company issued $150 million of 6-7/8% senior
unsecured notes due 2004.
The short-term debt limitation of the Company was increased
from $300 million to $500 million with the approval of the
Securities and Exchange Commission.
OTHER MATTERS
Spent Nuclear Fuel (SNF) Litigation
As discussed in Management's Discussion and Analysis of Results
of Operations and Financial Condition (MDA) in the 1998 Annual
Report, as a result of the Department of Energy's (DOE) failure to
make sufficient progress toward a permanent repository or otherwise
assume responsibility for SNF, the Company along with a number of
unaffiliated utilities and states filed suit in the United States
(U.S.) Court of Appeals for the District of Columbia Circuit
requesting, among other things, that the court order DOE to meet
its obligations under the law. The court ordered the parties to
proceed with contractual remedies but declined to order DOE to
begin accepting SNF for disposal. DOE estimates its planned site
for the nuclear waste will not be ready until 2010. In June 1998,
the Company filed a complaint in the U.S. Court of Federal Claims
seeking damages in excess of $150 million due to the DOE's partial
material breach of its unconditional contractual deadline to begin
disposing of SNF generated by the Cook Plant. Similar lawsuits
have been filed by other utilities. On April 6, 1999, the court
granted DOE's motion to dismiss a lawsuit filed by another utility.
On May 20, 1999, the other utility appealed this decision to the
U.S. Court of Appeals for the Federal Circuit. I&M's case has been
stayed pending final resolution of the other utility's appeal.
Cook Nuclear Plant Shutdown
As discussed in MDA in the 1998 Annual Report, both units of
the Cook Plant were shut down in September 1997 due to questions
regarding the operability of certain safety systems that arose
during a Nuclear Regulatory Commission (NRC) architect engineer
design inspection. The NRC issued a Confirmatory Action Letter in
September 1997 requiring the Company to address certain issues
identified in the letter. In 1998 the NRC notified the Company
that it had convened a Restart Panel for Cook Plant and provided a
list of required restart activities. In order to identify and
resolve all issues, including those in the letter, necessary to
restart the Cook units, the Company is working with the NRC and
will be meeting with the Panel on a regular basis, until the units
are returned to service.
In May 1999 the Company received a letter from the NRC
indicating that NRC senior managers had identified Cook Plant as an
"agency-focus plant." The NRC senior managers concluded that
continued agency-level oversight was appropriate; however, the NRC
required no additional action to redirect Cook Plant activities.
The letter states that the NRC staff will continue to monitor Cook
Plant performance through the Restart Panel process and evaluate
whether additional action may be necessary.
On June 24, 1999, the Boards of Directors of American Electric
Power Company, Inc. and the Company both approved a plan to restart
the Cook Plant. Unit 2 is scheduled to return to service in April
2000 and Unit 1 is to return to service in September 2000. This
approval follows a comprehensive systems readiness review of all
operating systems at the Cook Plant. 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.
Management intends to replace the steam generator for Unit 1
before the unit is returned to service. Costs associated with the
steam generator replacement are estimated to be approximately $165
million, which will be accounted for as a capital investment
unrelated to the restart. At June 30, 1999, $70 million has been
spent on the steam generator replacement.
The cost of electricity supplied to retail customers increased
due to the outage of the two Cook Plant nuclear units since higher
cost coal-fired generation and coal based purchased power is being
substituted for the unavailable low cost nuclear generation.
Actual replacement energy fuel costs that exceeded the estimated
costs reflected in billings have been recorded as a regulatory
asset under the Indiana and Michigan retail jurisdictional fuel
cost recovery mechanisms. At June 30, 1999, the regulatory asset
was $129 million.
On March 30, 1999 the Indiana Utility Regulatory Commission
(IURC) approved a settlement agreement that resolves all matters
related to the recovery of replacement energy fuel costs and all
outage/restart issues during the extended outage of the Cook Plant.
The settlement agreement provides for, among other things, a credit
of $55 million, including interest, to Indiana retail customers'
bills; the deferral of any unrecovered fuel revenues accrued
between September 9, 1997 and December 31, 1999, including the
$52.3 million revenue portion of the $55 million billing credit;
the deferral of up to $150 million of incremental operation and
maintenance costs in 1999 for Cook Plant above the amount included
in base rates; the amortization of the deferred fuel recoveries and
non-fuel operation and maintenance cost deferrals over a five-year
period ending December 31, 2003; a freeze in base rates through
December 31, 2003; and a fixed fuel recovery charge through March
1, 2004. The $55 million credit will be applied to customers'
bills during the months of July, August and September 1999.
<PAGE>
In June 1999 the Company announced that a settlement agreement
for two open Michigan power supply cost recovery reconciliation
cases had been reached with the staff of the Michigan Public
Service Commission (MPSC). The proposed settlement agreement would
freeze rates and power supply costs for five years, allow for the
amortization of deferred power supply cost for 1997, 1998 and 1999
over five years, allow for the deferral and amortization of non-fuel nuclear
operation and maintenance expenses over five years and
resolve all issues related to the Cook Plant extended outage. At
a hearing on June 30, 1999, the MPSC granted a continuance to the
one intervenor who opposed the approval of the settlement
agreement. A hearing has been scheduled for August 13, 1999.
Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as current period operation and maintenance expense in
1999 and 2000. Through June 30, 1999, $192 million has been spent,
of which $108 million was incurred in the first half of 1999.
Pursuant to the Indiana settlement agreement $60 million of
incremental operation and maintenance costs were deferred through
June 30, 1999. The Indiana jurisdiction deferral is limited to up
to $150 million of incremental restart costs incurred in 1999. The
pending Michigan settlement limits deferrals to $50 million of non-fuel
operation and maintenance costs.
The costs of the extended outage and restart efforts will have
a material adverse effect on results of operations, cash flows, and
possibly financial condition through 2003. Management believes
that the Cook units will be successfully returned to service by
April and September 2000, however, if for some unknown reason the
units are not returned to service or their return is delayed
significantly it would have an even greater adverse effect on
results of operations, cash flows and financial condition.
Air Quality
As discussed in MDA in the 1998 Annual Report, the U.S.
Environmental Protection Agency (Federal EPA) issued final rules
which require reductions in nitrogen oxides (NOx) emissions in 22
eastern states, including the states in which the generating plants
of the Company and its AEP System affiliates are located. The
final rules were to be implemented through state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. The NOx SIP Call rule requires
submission of revised SIPs by September 30, 1999. A number of
utilities, including the Company and its AEP System affiliates,
filed petitions seeking a review of the final rule in the U.S.
Court of Appeals for the District of Columbia Circuit (Appeals
Court). On May 25, 1999, the Appeals Court ordered an indefinite
stay of the September 30, 1999 deadline for submission of SIP
revisions pending a further order of the court while arguments
regarding the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act. Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP Call. The imposition of these NOx
reduction requirements on AEP System generating units would be
approximately equivalent to the reductions contemplated by the
stayed SIP Call rule. On May 28, and June 1, 1999, the Utility Air
Regulatory Group and the Midwest Ozone Group, respectively, each
filed a petition in the Appeals Court seeking review of Federal
EPA's approval of portions of the northeastern states' petitions.
In the second quarter of 1999, three additional northeastern states
filed Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $215 million for
the Company. Compliance costs cannot 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 through
regulated rates and/or reflected in the future market price of
electricity if generation is deregulated, they will have a material
adverse effect on future results of operations, cash flows and
possibly financial condition.
<PAGE>
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates. The Company's exposure to market risk from the
trading of electricity and related financial derivative
instruments, which are allocated to the Company through the AEP
Power Pool, has not changed materially since December 31, 1998.
Market risk represents the risk of loss that may impact the Company
due to adverse changes in commodity market prices and interest
rates.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at June 30, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date. In
addition, certain systems may fail to detect that the year 2000 is
a leap year. Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur. This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery. Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations. In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The Company, along with other electric utilities in North America,
has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the US DOE
regarding the Y2K readiness of electric utilities. The fourth and
final NERC report, dated August 3, 1999 and entitled: Preparing the
Electric Power Systems of North America for Transition to the Year
2000 - A Status Report and Work Plan, Second Quarter 1999, states
that: "Mission-critical component testing indicates that the
transition through critical Y2K dates is expected to have minimal
impact on electric system operations in North America." The report
also indicates that, "the risk of electrical outages caused by Y2K
appears to be no higher than the risks we already experience" from
incidents such as severe wind, ice, floods, equipment failures and
power shortages during an extremely hot or cold period.
AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications. There were no major problems encountered with
relaying information with the use of backup telecommunications
systems. AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.
Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk. The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
The following chart shows the Company's progress toward
becoming ready for the Y2K as of June 30, 1999:
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
Launch: Initiation 2/24/1998 100% 5/31/1998 100%
of the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999 100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing:
The process of modifying, 6/30/1999 Mainframe: 6/30/1999 100%
replacing or retiring 100%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 99%*
systems to ensure that after
modifications have been
implemented correct date
processing occurs and full
functionality has been maintained.
*The Company is upgrading a meteorological reporting system used at the Cook
Plant, a mission critical IT system, for Y2K readiness and it is anticipated
that the upgrade should be completed by December 15, 1999.
Costs to Address the Company's Year 2000 Issues - Through June 30,
1999, the Company has spent $6 million on the Y2K project and,
estimates spending an additional $2 million to $4 million to
achieve Y2K readiness. Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized. The Company intends to fund these expenditures
through internal sources. The cost of becoming Y2K compliant is
not expected to have a material impact on the Company's results of
operations, cash flows or financial condition.
<PAGE>
Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
Automated power generation, transmission and distribution systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for commercial
and industrial customers and
Work management and billing systems.
The potential problems related to erroneous processing by, or
failure of, these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues may materially adversely affect the Company.
Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council as part
of NERC's review of regional and individual electric utility
contingency plans in 1999. In addition, the Company is
establishing contingency plans for its business units to address
alternatives if Y2K related failures occur. These contingency
plans will be developed by the end of 1999.
The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, in order to place
key employees on duty at those locations during the Y2K
transition.
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $86,231 $84,021 $176,972 $171,366
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 22,284 18,184 41,975 40,485
Purchased Power. . . . . . . . . . . . . 25,920 27,119 50,347 48,330
Other Operation. . . . . . . . . . . . . 11,768 11,992 24,119 22,986
Maintenance. . . . . . . . . . . . . . . 5,047 7,258 9,838 16,424
Depreciation and Amortization. . . . . . 7,287 6,978 14,477 13,888
Taxes Other Than Federal Income Taxes. . 2,682 2,260 5,216 4,752
Federal Income Taxes . . . . . . . . . . 1,010 599 5,407 2,779
TOTAL OPERATING EXPENSES. . . . . 75,998 74,390 151,379 149,644
OPERATING INCOME . . . . . . . . . . . . . 10,233 9,631 25,593 21,722
NONOPERATING LOSS. . . . . . . . . . . . . (41) (93) (155) (164)
INCOME BEFORE INTEREST CHARGES . . . . . . 10,192 9,538 25,438 21,558
INTEREST CHARGES . . . . . . . . . . . . . 7,197 7,125 14,234 14,128
NET INCOME . . . . . . . . . . . . . . . . $ 2,995 $ 2,413 $ 11,204 $ 7,430
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $72,218 $76,018 $71,452 $78,076
NET INCOME . . . . . . . . . . . . . . . . 2,995 2,413 11,204 7,430
CASH DIVIDENDS DECLARED. . . . . . . . . . 7,443 7,075 14,886 14,150
BALANCE AT END OF PERIOD . . . . . . . . . $67,770 $71,356 $67,770 $71,356
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $ 267,658 $ 267,201
Transmission . . . . . . . . . . . . . . . . . . . . 340,617 326,989
Distribution . . . . . . . . . . . . . . . . . . . . 358,349 351,407
General. . . . . . . . . . . . . . . . . . . . . . . 66,452 68,038
Construction Work in Progress. . . . . . . . . . . . 22,083 30,076
Total Electric Utility Plant . . . . . . . . 1,055,159 1,043,711
Accumulated Depreciation and Amortization. . . . . . 326,751 315,546
NET ELECTRIC UTILITY PLANT . . . . . . . . . 728,408 728,165
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 18,376 12,078
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 2,436 1,935
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 18,560 23,295
Affiliated Companies . . . . . . . . . . . . . . . 14,087 8,797
Miscellaneous. . . . . . . . . . . . . . . . . . . 3,268 4,019
Allowance for Uncollectible Accounts . . . . . . . (1,094) (848)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 9,358 7,888
Materials and Supplies . . . . . . . . . . . . . . . 16,570 13,652
Accrued Utility Revenues . . . . . . . . . . . . . . 13,052 13,560
Energy Marketing and Trading Contracts . . . . . . . 45,027 4,726
Prepayments. . . . . . . . . . . . . . . . . . . . . 1,954 1,657
TOTAL CURRENT ASSETS . . . . . . . . . . . . 123,218 78,681
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 92,327 92,447
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 8,560 10,476
TOTAL. . . . . . . . . . . . . . . . . . . $ 970,889 $ 921,847
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - $50 Par Value:
Authorized - 2,000,000 Shares
Outstanding - 1,009,000 Shares . . . . . . . . . . $ 50,450 $ 50,450
Paid-in Capital. . . . . . . . . . . . . . . . . . . 158,750 148,750
Retained Earnings. . . . . . . . . . . . . . . . . . 67,770 71,452
Total Common Shareholder's Equity. . . . . . 276,970 270,652
Long-term Debt . . . . . . . . . . . . . . . . . . . 271,228 308,838
TOTAL CAPITALIZATION . . . . . . . . . . . . 548,198 579,490
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 24,745 26,827
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 60,000 60,000
Short-term Debt. . . . . . . . . . . . . . . . . . . 56,350 20,350
Accounts Payable - General . . . . . . . . . . . . . 9,363 12,917
Accounts Payable - Affiliated Companies. . . . . . . 14,166 11,814
Customer Deposits. . . . . . . . . . . . . . . . . . 4,006 4,038
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 9,244 7,256
Interest Accrued . . . . . . . . . . . . . . . . . . 5,522 6,241
Energy Marketing and Trading Contracts . . . . . . . 45,245 5,089
Other. . . . . . . . . . . . . . . . . . . . . . . . 13,476 13,612
TOTAL CURRENT LIABILITIES. . . . . . . . . . 217,372 141,317
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 159,541 158,706
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 13,599 14,200
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 7,434 1,307
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $970,889 $921,847
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 11,204 $ 7,430
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 14,480 13,894
Deferred Federal Income Taxes. . . . . . . . . . . . . . 912 368
Deferred Investment Tax Credits. . . . . . . . . . . . . (601) (610)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 442 (2,792)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (4,388) (1,234)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 508 2,409
Accounts Payable . . . . . . . . . . . . . . . . . . . . (1,202) (2,281)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 1,988 (902)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 1,258 811
Net Cash Flows From Operating Activities . . . . . . 24,601 17,093
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (17,402) (17,705)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . 10,000 10,000
Change in Short-term Debt (net). . . . . . . . . . . . . . 36,000 6,600
Retirement of Long-term Debt . . . . . . . . . . . . . . . (37,812) (2,203)
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (14,886) (14,150)
Net Cash Flows From (Used For) Financing Activities. (6,698) 247
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 501 (365)
Cash and Cash Equivalents at Beginning of Period . . . . . . 1,935 1,381
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 2,436 $ 1,016
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $14,748,000 and $13,982,000
and for income taxes was $3,631,000 and $4,538,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $1,150,000 and $2,960,000 in 1999
and 1998, respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited financial statements should be read in
conjunction with the 1998 Annual Report as incorporated in and filed with
the Form 10-K. Certain prior-period amounts have been reclassified to
conform to current-period presentation. In the opinion of management,
the financial statements reflect all adjustments (consisting of only
normal recurring accruals) which are necessary for a fair presentation
of the results of operations for interim periods.
2. FINANCING ACTIVITIES
In April 1999 the Company redeemed a $25 million term loan note with
a rate of 6.42% and in May 1999 the Company redeemed the principal amount
of $12,797,000 of the 7.90% Series First Mortgage Bonds.
In June 1999 the Company received a $10 million cash capital
contribution from its parent which was credited to paid-in capital.
During the first six months of 1999, the Company issued $36 million
of short-term debt.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the Financial
Accounting Standards Board's Emerging Issues Task Force Consensus (EITF)
98-10, "Accounting for Contracts Involved in Energy Trading and Risk
Management Activities". The EITF requires that all energy trading
contracts be marked-to-market. The effect on the Statements of Income
of marking open trading contracts to market is deferred as regulatory
assets or liabilities for those open trading transactions that are
included in cost of service on a settlement basis for ratemaking
purposes. The adoption of the EITF did not have a material effect on
results of operations, cash flows or financial condition.
4. RATE MATTERS
The Federal Energy Regulatory Commission (FERC) issued orders 888 and
889 in April 1996 which required each public utility that owns or
controls interstate transmission facilities to file an open access
network and point-to-point transmission tariff that offers services
comparable to the utility's own uses of its transmission system. The
orders also require utilities to functionally unbundle their services,
by requiring them to use their own tariffs in making off-system and
third-party sales. As part of the orders, the FERC issued a pro-forma
tariff which reflects the Commission's views on the minimum non-price
terms and conditions for non-discriminatory transmission service. The
orders also allow a utility to seek recovery of certain prudently-incurred
stranded costs that result from unbundled transmission service.
<PAGE>
On July 9, 1996, the AEP System companies filed an Open Access
Transmission Tariff conforming with the FERC's pro-forma transmission
tariff, subject to the resolution of certain pricing issues.
On July 29, 1999, the FERC approved a draft order which rules on the
AEP System's pending Open Access Transmission Tariff. This approved
order has certain unfavorable pricing issues for which the AEP System has
30 days to seek rehearing. If the Commission's order is ultimately
upheld the Company as a member of the AEP System will have to make
refunds including interest. As of June 30, 1999 the Company has not made
any provisions for its share of a potential refund which is preliminarily
estimated to be approximately $1 million.
5. CONTINGENCIES
Litigation
As discussed in Note 3, of the Notes to Financial Statements in the
1998 Annual Report, the deductibility of certain interest deductions
related to American Electric Power's corporate owned life insurance
(COLI) program for taxable years 1992-1996 is under review by the
Internal Revenue Service (IRS). Adjustments have been or will be
proposed by the IRS disallowing COLI interest deductions. A disallowance
of COLI interest deductions through June 30, 1999 would reduce earnings
by approximately $8 million (including interest). The Company has made
no provision for any possible earnings impact from this matter.
In 1998 the Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1992-1997 to avoid the
potential assessment by the IRS of any additional above market rate
interest on the contested amount. These payments to the IRS are included
on the Balance Sheets in other property and investments pending the
resolution of this matter. The Company is seeking refunds through
litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit against the
United States in the U.S. District Court for the Southern District of
Ohio in March 1998. Management believes that it has a meritorious
position and will vigorously pursue this lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material adverse
impact on results of operations.
Air Quality
As discussed in Note 3 of the Notes to Financial Statements in the
1998 Annual Report, the U.S. Environmental Protection Agency (Federal
EPA) issued final rules which require reductions in nitrogen oxides (NOx)
emissions in 22 eastern states, including the states in which the
generating plants of the Company and its AEP System affiliates are
located. The final rules were to be implemented through state
implementation plans (SIPs). SIPs are a procedural method used by each
state to comply with Federal EPA rules. The NOx SIP Call rule requires
submission of revised SIPs by September 30, 1999. A number of utilities,
including the Company and its AEP System affiliates, filed petitions
seeking a review of the final rule in the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court). On May 25, 1999, the
Appeals Court ordered an indefinite stay of the September 30, 1999
deadline for submission of SIP revisions pending a further order of the
court while arguments regarding the SIP Call rule are considered.
On April 30, 1999, Federal EPA took final action with respect to
petitions filed by eight northeastern states pursuant to Section 126 of
the Clean Air Act. Federal EPA approved portions of the states'
petitions triggering emission reductions that are substantially the same
as those that would otherwise have been required by the NOx SIP Call.
The imposition of these NOx reduction requirements on AEP System
generating units would be approximately equivalent to the reductions
contemplated by the stayed SIP Call rule. On May 28, and June 1, 1999,
the Utility Air Regulatory Group and the Midwest Ozone Group,
respectively, each filed a petition in the Appeals Court seeking review
of Federal EPA's approval of portions of the northeastern states'
petitions. In the second quarter of 1999, three additional northeastern
states filed Section 126 petitions with Federal EPA similar to those
filed by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could result in
required capital expenditures of approximately $130 million for the
Company. Compliance costs cannot 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 through regulated rates and/or reflected in the
future market price of electricity if generation is deregulated, they
will have a material adverse effect on future results of operations, cash
flows and possibly financial condition.
Other
The Company continues to be involved in certain other matters
discussed in its 1998 Annual Report.
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
SECOND QUARTER 1999 vs. SECOND QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
Net income increased $0.6 million or 24% for the quarter and $3.8 million
or 51% for the year-to-date period. The increases in net income were mainly
attributable to increased operating revenues and a decline in maintenance
costs.
Income statement line items which changed significantly were:
Increase(Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . . . $ 2.2 3 $ 5.6 3
Fuel Expense . . . . . . . . . 4.1 23 1.5 4
Purchased Power Expense. . . . (1.2) (4) 2.0 4
Other Operation Expense. . . . (0.2) (2) 1.1 5
Maintenance Expense. . . . . . (2.2) (30) (6.6) (40)
Taxes Other Than Federal
Income Taxes . . . . . . . . 0.4 19 0.5 10
Federal Income Taxes . . . . . 0.4 69 2.6 95
Operating revenues increased in the second quarter due to increased
wholesale sales primarily to the American Electric Power System Power Pool
(AEP Power Pool) while retail sales declined slightly. Wholesale sales rose
as a result of increased availability of the Company's generation plant. In
the second quarter of 1998 one of the two units at the Company's Big Sandy
Plant was on an extended maintenance outage. The increase in operating
revenues in the year-to-date period was due to increased retail sales
reflecting colder winter weather.
Fuel expense increased in the second quarter and the year-to-date period
primarily due to increased generation and a rise in the average cost of fuel
consumed. The increase in generation reflects the absence of an extended
maintenance outage in 1999. The rise in fuel costs was due to an increase in
the price of coal burned to produce electricity and included in fuel expense
concurrent with recovery through fuel clause revenues. Changes in the cost
of fuel are deferred until reflected in fuel clause billings to customers.
The decrease in purchased power expense in the second quarter resulted
from reduced purchases of power from unaffiliated entities and lower average
purchase prices. The reductions resulted from a decreased need for purchased
energy since the availability of Big Sandy Plant increased and a decline in
demand by unaffiliated wholesale customers mainly due to mild weather.
Purchased power expense increased in the year-to-date period primarily due to
increased capacity charges from the AEP Power Pool. Under the terms of the
AEP Power Pool, capacity credits and charges are designed to allocate the
cost of the AEP System's capacity among the AEP Power Pool members based on
their relative peak demands and generating reserves. The increase in
capacity charges can be attributed to an increase in the Company's prior
twelve month peak demand relative to the total peak demand of all AEP Power
Pool members.
Other operation expense increased in the year-to-date period due to
accrual adjustments for employee pensions and benefits recorded in the first
quarter of 1999 and 1998. The 1999 adjustment was unfavorable while the 1998
adjustment was favorable.
The decline in maintenance expense is primarily attributable to decreased
overhead distribution line and generating plant maintenance expenditures. In
the first quarter of 1998 the repair and restoration of customers'
distribution service after winter storm damage and a lengthy scheduled outage
in the second quarter of 1998 for maintenance and repairs of the 260 mw Big
Sandy Plant Unit 1 increased maintenance expense.
Taxes other than federal income taxes increased in both periods primarily
due to increased state income tax expense reflecting a rise in taxable
income.
The increase in federal income tax expense attributable to operations in
both periods was primarily due to an increase in pre-tax operating income.
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $498,587 $523,671 $1,016,808 $1,039,343
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 169,055 180,947 358,218 374,222
Purchased Power. . . . . . . . . . . . . 35,699 48,400 56,972 67,990
Other Operation. . . . . . . . . . . . . 82,829 82,942 167,890 163,843
Maintenance. . . . . . . . . . . . . . . 28,501 33,158 53,991 63,751
Depreciation and Amortization. . . . . . 37,397 35,998 74,182 71,861
Taxes Other Than Federal Income Taxes. . 41,952 41,862 85,805 84,520
Federal Income Taxes . . . . . . . . . . 29,826 30,499 67,466 64,222
TOTAL OPERATING EXPENSES . . . . 425,259 453,806 864,524 890,409
OPERATING INCOME . . . . . . . . . . . . . 73,328 69,865 152,284 148,934
NONOPERATING INCOME (LOSS) . . . . . . . . (492) 3,449 1,508 4,687
INCOME BEFORE INTEREST CHARGES . . . . . . 72,836 73,314 153,792 153,621
INTEREST CHARGES . . . . . . . . . . . . . 20,971 20,255 41,106 40,126
NET INCOME . . . . . . . . . . . . . . . . 51,865 53,059 112,686 113,495
PREFERRED STOCK DIVIDEND REQUIREMENTS. . . 367 368 734 738
EARNINGS APPLICABLE TO COMMON STOCK. . . . $ 51,498 $ 52,691 $ 111,952 $ 112,757
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Six Months Ended
June 30, June 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $590,251 $597,442 $587,500 $590,151
NET INCOME . . . . . . . . . . . . . . . . 51,865 53,059 112,686 113,495
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . . 57,703 52,775 115,406 105,550
Cumulative Preferred Stock . . . . . . 368 369 735 739
BALANCE AT END OF PERIOD . . . . . . . . . $584,045 $597,357 $584,045 $597,357
The common stock of the Company is wholly owned by
American Electric Power Company, Inc.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . . . . $2,676,712 $2,646,597
Transmission . . . . . . . . . . . . . . . . . . . . . . . 851,679 842,318
Distribution . . . . . . . . . . . . . . . . . . . . . . . 969,875 949,224
General (including mining assets). . . . . . . . . . . . . 718,745 689,815
Construction Work in Progress. . . . . . . . . . . . . . . 100,865 129,887
Total Electric Utility Plant . . . . . . . . . . . 5,317,876 5,257,841
Accumulated Depreciation and Amortization. . . . . . . . . 2,547,315 2,461,376
NET ELECTRIC UTILITY PLANT . . . . . . . . . . . . 2,770,561 2,796,465
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . . . . 246,654 218,311
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . . . . 101,648 89,652
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . . . . 288,445 215,665
Affiliated Companies . . . . . . . . . . . . . . . . . . 82,055 63,922
Miscellaneous. . . . . . . . . . . . . . . . . . . . . . 22,528 28,139
Allowance for Uncollectible Accounts . . . . . . . . . . (2,583) (1,678)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . . . . 143,844 94,914
Materials and Supplies . . . . . . . . . . . . . . . . . . 92,977 86,870
Accrued Utility Revenues . . . . . . . . . . . . . . . . . 48,911 43,501
Energy Marketing and Trading Contracts . . . . . . . . . . 175,702 19,790
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . 41,404 34,523
TOTAL CURRENT ASSETS . . . . . . . . . . . . . . . 994,931 675,298
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . . . . 572,025 551,776
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . . . . 82,570 102,830
TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,666,741 $4,344,680
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
June 30, December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - No Par Value:
Authorized - 40,000,000 Shares
Outstanding - 27,952,473 Shares. . . . . . . . . . . . . $ 321,201 $ 321,201
Paid-in Capital. . . . . . . . . . . . . . . . . . . . . . 462,366 462,335
Retained Earnings. . . . . . . . . . . . . . . . . . . . . 584,045 587,500
Total Common Shareholder's Equity. . . . . . . . . 1,367,612 1,371,036
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . . . . 17,211 17,370
Subject to Mandatory Redemption. . . . . . . . . . . . . 11,850 11,850
Long-term Debt . . . . . . . . . . . . . . . . . . . . . . 1,072,702 1,073,456
TOTAL CAPITALIZATION . . . . . . . . . . . . . . . 2,469,375 2,473,712
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . . . . 367,663 360,330
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . . . . 11,283 11,472
Short-term Debt. . . . . . . . . . . . . . . . . . . . . . 194,090 123,005
Accounts Payable . . . . . . . . . . . . . . . . . . . . . 261,265 235,787
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . 162,576 161,406
Interest Accrued . . . . . . . . . . . . . . . . . . . . . 13,367 14,187
Obligations Under Capital Leases . . . . . . . . . . . . . 29,234 28,310
Energy Marketing and Trading Contracts . . . . . . . . . . 176,569 22,480
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 92,750 97,916
TOTAL CURRENT LIABILITIES. . . . . . . . . . . . . 941,134 694,563
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . . . . 702,342 711,913
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . . . . 37,637 39,296
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . . . . 148,590 64,866
CONTINGENCIES (Note 7)
TOTAL. . . . . . . . . . . . . . . . . . . . . . $4,666,741 $4,344,680
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Six Months Ended
June 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . . . $ 112,686 $ 113,495
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . . . 93,008 87,091
Deferred Federal Income Taxes. . . . . . . . . . . . . . . . 1,603 2,480
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . . . (23,695) (22,968)
Amortization of Deferred Property Taxes. . . . . . . . . . . 39,464 38,294
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . . . (84,397) (134,357)
Fuel, Materials and Supplies . . . . . . . . . . . . . . . . (55,037) 3,906
Accrued Utility Revenues . . . . . . . . . . . . . . . . . . (5,410) (2,807)
Prepayments. . . . . . . . . . . . . . . . . . . . . . . . . (6,881) (6,055)
Accounts Payable . . . . . . . . . . . . . . . . . . . . . . 25,478 114,553
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . . . 1,170 (19,733)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . . . 44,808 81,078
Net Cash Flows From Operating Activities . . . . . . . . 142,797 254,977
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . . . (83,279) (71,323)
Proceeds from Sale of Property and Other . . . . . . . . . . . 670 3,600
Net Cash Flows Used For Investing Activities . . . . . . (82,609) (67,723)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . . . 148,215 137,566
Change in Short-term Debt (net). . . . . . . . . . . . . . . . 71,085 31,400
Retirement of Cumulative Preferred Stock . . . . . . . . . . . (128) (47)
Retirement of Long-term Debt . . . . . . . . . . . . . . . . . (151,223) (185,809)
Dividends Paid on Common Stock . . . . . . . . . . . . . . . . (115,406) (105,550)
Dividends Paid on Cumulative Preferred Stock . . . . . . . . . (735) (739)
Net Cash Flows Used For Financing Activities . . . . . . (48,192) (123,179)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . . . 11,996 64,075
Cash and Cash Equivalents at Beginning of Period . . . . . . . . 89,652 44,203
Cash and Cash Equivalents at End of Period . . . . . . . . . . . $ 101,648 $ 108,278
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $40,816,000 and $41,125,000 and
for income taxes was $24,645,000 and $43,019,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $11,849,000 and $18,913,000 in 1999 and
1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
JUNE 30, 1999
(UNAUDITED)
1. GENERAL
The accompanying unaudited consolidated financial state-ments should be
read in conjunction with the 1998 Annual Report
as incorporated in and filed with the Form 10-K. Certain
prior-period amounts have been reclassified to conform to
current-period presentation. In the opinion of management, the
financial statements reflect all adjustments (consisting of
only normal recurring accruals) which are necessary for a fair
presentation of the results of operations for interim periods.
2. FINANCING ACTIVITY
In May 1999 the Company issued $50 million of 5.15% Ohio
Air Quality Series C pollution control revenue bonds due 2026
and in June 1999 the Company issued $100 million of 6.75%
senior unsecured notes due 2004.
During the first six months of 1999, the Company reacquired
the following first mortgage bonds for $88 million.
Principal
Amount
% Rate Due Date Reacquired
(in thousands)
6.875 June 1, 2003 $40,000
6.55 October 1, 2003 7,865
7.85 June 1, 2023 40,000
In May 1999 the Company reacquired $50 million of 7.40%
Ohio Air Quality Series B pollution control revenue bonds due
2009.
The short-term debt limitation of the Company was increased
from $400 million to $450 million with approval of the
Securities and Exchange Commission.
3. NEW ACCOUNTING STANDARDS
In the first quarter of 1999 the Company adopted the
Financial Accounting Standards Board's Emerging Issues Task
Force Consensus (EITF) 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management Activities". The
EITF requires that all energy trading contracts be marked-to-market.
The effect on the Consolidated Statements of Income
of marking open trading contracts to market is deferred as
regulatory assets or liabilities for those open trading
transactions that are included in cost of service on a
settlement basis for ratemaking purposes. The adoption of the
EITF did not have a material effect on results of operations,
cash flows or financial condition.
4. OHIO RESTRUCTURING LEGISLATION
On July 6, 1999, the Governor of the State of Ohio signed
The Ohio Electric Restructuring Act of 1999. The Act provides
for customer choice of electricity supplier and a residential
rate reduction of 5% of the unbundled generation rate beginning
on January 1, 2001. The Act also provides for a five-year
transition period to transition from cost based rates to market
pricing for generation services. It authorizes the Public
Utilities Commission of Ohio (PUCO) to address certain major
transition issues including unbundling of rates and the
recovery of regulatory assets and other stranded transition
costs.
Retail electric services that will be competitive are
defined in the Act as electric generation service, aggregation
service, and power marketing and brokering. The PUCO has been
granted broad oversight responsibility under the Act. The Act
requires the PUCO to promulgate rules for competitive retail
electric generation service.
The Act further provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled rates paid by customers who do not switch
generation suppliers and through a wires charges by customers
who switch generation suppliers. Transition costs can include
regulatory assets, impairments of generating assets and other
stranded costs, employee severance and retraining costs and
other costs. Recovery of transition revenues can under certain
circumstances extend beyond the five-year transition period but
cannot continue beyond December 31, 2010. The Company must
file a transition plan with the PUCO by January 3, 2000 and the
PUCO is required to issue a transition order no later than
October 31, 2000.
The Act also provides that the property tax assessment
percentage on electric generation equipment be lowered from
100% to 25% of value effective January 1, 2001. Electric
utilities will also become subject to the Ohio Corporate
Franchise Tax and municipal income taxes on January 1, 2002.
The last year for which electric utilities will pay the excise
tax based on gross receipts is the year ending April 30, 2002.
As of May 1, 2001 electric distribution companies will be
subject to an excise tax based on kilowatt-hours sold to Ohio
customers. These changes should put the Company's generation
operations on an equal level with other competitive businesses
in Ohio regarding state taxation.
As discussed in Note 2, "Effects of Regulation," of the
Notes to Consolidated Financial Statements in the 1998 Annual
Report, the Company defers as regulatory liabilities and assets
certain revenues and expenses consistent with the regulatory
process in accordance with Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain
Types of Regulation." At June 30, 1999 the amount of
regulatory assets recorded on the books applicable to the
generating business is estimated to be $363 million before
related tax effects. Whether the Company will have any
additional stranded transition costs related to an economic
impairment of its generating assets is dependent on several
factors including the assumed future market price for
electricity. The Company intends to seek recovery in its
transition filing of all regulatory assets and any other
stranded transition costs which may be identified. At this time
management is unable to predict the outcome of the regulatory
process or its impact on results of operations, cash flows or
financial condition. Therefore, the Company will not be
discontinuing application of SFAS 71 until the regulatory
process is completed.
Upon discontinuance of the application of SFAS 71 the
Company will have to write off its Ohio generation-related
regulatory assets and record any asset impairments in
accordance with SFAS 121 "Accounting for the Impairment of
Long-lived Assets and for Long-lived Assets to Be Disposed Of."
Absent the determination in the regulatory process of
transition revenues and other pertinent information, it is not
possible at this time to determine if any of the Company's
plants are impaired in accordance with SFAS 121. Should the
Company be granted recovery of its regulatory assets and/or any
economic asset impairments it can record an offsetting
regulatory asset. Should the PUCO not approve the Company's
request for recovery of its generation-related regulatory
assets and/or other stranded transition costs it would have an
adverse impact on future results of operations and possibly
financial condition. The Company does not expect to be able
to determine the impact of the legislation on its financial
statements until the regulatory process is complete. The PUCO
is required to complete its regulatory process no later than
October 31, 2000.
5. WINDSOR MINE CLOSING
In July 1999 the Company announced that the scheduled
closing of the affiliated Windsor coal mine was being
accelerated from December 31, 2000 to April 30, 2000. The
liability for closing the mine is estimated to be $48.4 million
including reclamation costs. As discussed in Note 3, "Rate
Matters" of the Notes to Consolidated Financial Statements in
the 1998 Annual Report, management believes the Ohio
jurisdictional portion of the cost of the mine shutdown can be
deferred for future recovery under the terms of the Ohio fuel
clause predetermined price agreement. Management intends to
continue to recover from non-Ohio jurisdictional ratepayers the
non-Ohio jurisdictional portion of the investment in and the
liabilities and closing costs of the Windsor mine. Unless the
cost of the remaining coal production and mine shutdown are
recovered, results of operations and cash flows would be
adversely affected.
<PAGE>
6. RATE MATTERS
The Federal Energy Regulatory Commission (FERC) issued
orders 888 and 889 in April 1996 which required each public
utility that owns or controls interstate transmission
facilities to file an open access network and point-to-point
transmission tariff that offers services comparable to the
utility's own uses of its transmission system. The orders also
require utilities to functionally unbundle their services, by
requiring them to use their own tariffs in making off-system
and third-party sales. As part of the orders, the FERC issued
a pro-forma tariff which reflects the Commission's views on the
minimum non-price terms and conditions for non-discriminatory
transmission service. The orders also allow a utility to seek
recovery of certain prudently-incurred stranded costs that
result from unbundled transmission service.
On July 9, 1996, the AEP System companies filed an Open
Access Transmission Tariff conforming with the FERC's pro-forma
transmission tariff, subject to the resolution of certain
pricing issues.
On July 29, 1999, the FERC approved a draft order which
rules on the AEP System's pending Open Access Transmission
Tariff. This approved order has certain unfavorable pricing
issues for which the AEP System has 30 days to seek rehearing.
If the Commission's order is ultimately upheld the Company as
a member of the AEP System will have to make refunds including
interest. As of June 30, 1999 the Company has not made any
provisions for its share of a potential refund which is
preliminarily estimated to be approximately $5 million.
7. CONTINGENCIES
Litigation
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the
deductibility of certain interest deductions related to
American Electric Power's corporate owned life insurance (COLI)
program for taxable years 1991-1996 is under review by the
Internal Revenue Service (IRS). Adjustments have been or will
be proposed by the IRS disallowing COLI interest deductions.
A disallowance of COLI interest deductions through June 30,
1999 would reduce earnings by approximately $117 million
(including interest). The Company has made no provision for
any possible earnings impact from this matter.
In 1998 the Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1997 to avoid the potential assessment by the IRS of any
additional above market rate interest on the contested amount.
These payments to the IRS are included on the Consolidated
Balance Sheets in other property and investments pending the
resolution of this matter. The Company is seeking refunds
through litigation of all amounts paid plus interest.
In order to resolve this issue, the Company filed suit
against the United States in the US District Court for the
Southern District of Ohio in March 1998. Management believes
that it has a meritorious position and will vigorously pursue
this lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations.
Air Quality
As discussed in Note 4 of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, the U.S.
Environmental Protection Agency (Federal EPA) issued final
rules which require reductions in nitrogen oxides (NOx)
emissions in 22 eastern states, including the states in which
the generating plants of the Company and its AEP System
affiliates are located. The final rules were to be implemented
through state implementation plans (SIPs). SIPs are a
procedural method used by each state to comply with Federal EPA
rules. The rules require submission of revised SIPs by
September 30, 1999. A number of utilities, including the
Company and its AEP System affiliates, filed petitions seeking
a review of the final rules in the U.S. Court of Appeals for
the District of Columbia Circuit (Appeals Court). On May 25,
1999, the Appeals Court ordered an indefinite stay of the
September 30, 1999 deadline for submission of SIP revisions
pending a further order of the court while arguments regarding
the SIP call rule are considered.
On April 30, 1999, Federal EPA took final action with
respect to petitions filed by eight northeastern states
pursuant to Section 126 of the Clean Air Act. Federal EPA
approved portions of the states' petitions triggering emission
reductions that are substantially the same as those that would
otherwise have been required by the NOx SIP call. On May 28,
and June 1, 1999, the Utility Air Regulatory Group and the
Midwest Ozone Group, respectively, each filed a petition in the
Appeals Court seeking review of Federal EPA's approval of
portions of the northeastern states' petitions. In the second
quarter of 1999, three additional northeastern states filed
Section 126 petitions with Federal EPA similar to those filed
by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could
result in required capital expenditures of approximately $570
million for the Company. Compliance costs cannot 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 or reflected in the future market price of
electricity, they will have a material adverse effect on future
results of operations, cash flows and possibly financial
condition.
<PAGE>
Other
The Company continues to be involved in certain other
matters discussed in the 1998 Annual Report.
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
MANAGEMENT'S DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS
AND FINANCIAL CONDITION
SECOND QUARTER 1999 vs. SECOND QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income decreased $1.2 million or 2% in the second quarter
and $0.8 million or 1% in the year-to-date period. The decline in
both periods is mainly due to a reduction in operating revenues and
nonoperating income.
Income statement line items which changed significantly were:
Increase (Decrease)
Second Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $(25.1) (5) $(22.5) (2)
Fuel Expense . . . . . . . (11.9) (7) (16.0) (4)
Purchased Power Expense. . (12.7) (26) (11.0) (16)
Maintenance Expense. . . . (4.7) (14) (9.8) (15)
Nonoperating Income. . . . (3.9) (114) (3.2) (68)
Operating revenues decreased for both periods due to a decline
in wholesale energy sales to unaffiliated utilities and the
American Electric Power System Power Pool reflecting the effect of
milder spring weather on demand.
The decrease in fuel expense in both periods was mainly due to
a decrease in generation resulting from the decreased demand for
energy.
Purchased power expense decreased in the second quarter
primarily due to the decline in demand for electricity. In the
year-to-date period a lower average price for purchases from
unaffiliated companies accounted for the decrease in purchased
power expense. The decrease in the average price reflected the
reduced demand for energy.
The decline in maintenance expense was primarily due to a
reduction in scheduled generating plant maintenance in 1999.
Nonoperating income decreased due to the recognition of a
provision for loss related to a Public Utilities Commission of Ohio
(PUCO) order which requires the Company to reprice certain emission
allowance transactions which are included in the electric fuel rate
factor of customers' bills. The order requires the Company to
adjust the actual amount paid for allowances purchased to the
weighted average cost of allowances surrendered to the United
States Environmental Protection Agency (Federal EPA) as a result of
exceeding sulfur emission limitations in order to make wholesale
sales.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first six months of 1999 were $95 million.
During the first six months of 1999, the Company retired $138
million principal amount of long-term debt with interest rates
ranging from 6.55% to 7.85%, issued $100 million of senior
unsecured notes at a rate of 6.75% due 2004, issued $50 million of
pollution control revenues bonds at a rate of 5.15% due 2026 and
increased short-term debt by $71 million from year-end balances.
The short-term debt limitation of the Company was increased from
$400 million to $450 million with the approval of the Securities
and Exchange Commission.
OTHER MATTERS
Ohio Restructuring Legislation
On July 6, 1999, the Governor of the State of Ohio signed The
Ohio Electric Restructuring Act of 1999. The Act provides for
customer choice of electricity supplier and a residential rate
reduction of 5% of the unbundled generation rate beginning on
January 1, 2001. The Act also provides for a five-year transition
period to transition from cost based rates to market pricing for
generation services. It authorizes the PUCO to address certain
major transition issues including unbundling of rates and the
recovery of regulatory assets and other stranded transition costs.
Retail electric services that will be competitive are defined
in the Act as electric generation service, aggregation service, and
power marketing and brokering. The PUCO has been granted broad
oversight responsibility under the Act. The Act requires the PUCO
to promulgate rules for competitive retail electric generation
service.
The Act further provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled rates paid by customers who do not switch
generation suppliers and through a wires charges by customers who
switch generation suppliers. Transition costs can include
regulatory assets, impairments of generating assets and other
stranded costs, employee severance and retraining costs and other
costs. Recovery of transition revenues can under certain
circumstances extend beyond the five-year transition period but
cannot continue beyond December 31, 2010. The Company must file a
transition plan with the PUCO by January 3, 2000 and the PUCO is
required to issue a transition order no later than October 31,
2000.
The Act also provides that the property tax assessment
percentage on electric generation equipment be lowered from 100% to
25% of value effective January 1, 2001. Electric utilities will
also become subject to the Ohio Corporate Franchise Tax and
municipal income taxes on January 1, 2002. The last year for which
electric utilities will pay the excise tax based on gross receipts
is the year ending April 30, 2002. As of May 1, 2001 electric
distribution companies will be subject to an excise tax based on
kilowatt-hours sold to Ohio customers. These changes should put
the Company's generation operations on an equal level with other
competitive businesses in Ohio regarding state taxation.
As discussed in Note 2, "Effects of Regulation," of the Notes
to Consolidated Financial Statements in the 1998 Annual Report, the
Company defers as regulatory liabilities and assets certain
revenues and expenses consistent with the regulatory process in
accordance with Statement of Financial Accounting Standards (SFAS)
71, "Accounting for the Effects of Certain Types of Regulation."
At June 30, 1999 the amount of regulatory assets recorded on the
books applicable to the generating business is estimated to be $363
million before related tax effects. Whether the Company will have
any additional stranded transition costs related to an economic
impairment of its generating assets is dependent on several factors
including the assumed future market price for electricity. The
Company intends to seek recovery in its transition filing of all
regulatory assets and any other stranded transition costs which may
be identified. At this time management is unable to predict the
outcome of the regulatory process or its impact on results of
operations, cash flows or financial condition. Therefore, the
Company will not be discontinuing application of SFAS 71 until the
regulatory process is completed.
Upon discontinuance of the application of SFAS 71 the Company
will have to write off its Ohio generation-related regulatory
assets and record any asset impairments in accordance with SFAS 121
"Accounting for the Impairment of Long-lived Assets and for Long-lived Assets
to Be Disposed Of." Absent the determination in the
regulatory process of transition revenues and other pertinent
information, it is not possible at this time to determine if any of
the Company's plants are impaired in accordance with SFAS 121.
Should the Company be granted recovery of its generation-related
regulatory assets and/or any economic asset impairments it can
record an offsetting regulatory asset. Should the PUCO not approve
the Company's request for recovery of its regulatory assets and/or
other stranded transition costs it would have an adverse impact on
future results of operations and possibly financial condition. The
Company does not expect to be able to determine the impact of the
legislation on its financial statements until the regulatory
process is complete. The PUCO is required to complete its
regulatory process no later than October 31, 2000.
Windsor Mine Closing
In July 1999 the Company announced that the scheduled closing
of the affiliated Windsor coal mine was being accelerated from
December 31, 2000 to April 30, 2000. The liability for closing the
mine is estimated to be $48.4 million including reclamation costs.
As discussed in Note 3, "Rate Matters" of the Notes to Consolidated
Financial Statements in the 1998 Annual Report, management believes
the Ohio jurisdictional portion of the cost of the mine shutdown
can be deferred for future recovery under terms of the Ohio fuel
clause predetermined price agreement. Management intends to
continue to recover from non-Ohio jurisdictional ratepayers the
non-Ohio jurisdictional portion of the investment in and the
liabilities and closing costs of the Windsor mine. Unless the cost
of the remaining coal production and mine shutdown are recovered,
results of operations and cash flows would be adversely affected.
Air Quality
As discussed in Note 4 of the Notes to Consolidated Financial
Statements in the 1998 Annual Report, Federal EPA issued final
rules which require reductions in nitrogen oxides (NOx) emissions
in 22 eastern states, including the states in which the generating
plants of the Company and its AEP System affiliates are located.
The final rules were to be implemented through state implementation
plans (SIPs). SIPs are a procedural method used by each state to
comply with Federal EPA rules. The rules require submission of
revised SIPs by September 30, 1999. A number of utilities,
including the Company and its AEP System affiliates, filed
petitions seeking a review of the final rules in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court). On
May 25, 1999, the Appeals Court ordered an indefinite stay of the
September 30, 1999 deadline for submission of SIP revisions pending
a further order of the court while arguments regarding the SIP call
rule are considered.
On April 30, 1999, Federal EPA took final action with respect
to petitions filed by eight northeastern states pursuant to Section
126 of the Clean Air Act. Federal EPA approved portions of the
states' petitions triggering emission reductions that are
substantially the same as those that would otherwise have been
required by the NOx SIP call. On May 28, and June 1, 1999, the
Utility Air Regulatory Group and the Midwest Ozone Group,
respectively, each filed a petition in the Appeals Court seeking
review of Federal EPA's approval of portions of the northeastern
states' petitions. In the second quarter of 1999, three additional
northeastern states filed Section 126 petitions with Federal EPA
similar to those filed by the eight northeastern states.
Preliminary estimates indicate that NOx compliance could result
in required capital expenditures of approximately $570 million for
the Company. Compliance costs cannot 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 or
reflected in the future market price of electricity, they will have
a material adverse effect on future results of operations, cash
flows and possibly financial condition.
<PAGE>
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices and
interest rates. The Company's exposure to market risk from the
trading of electricity and related financial derivative
instruments, which are allocated to the Company through the
American Electric Power System Power Pool, has not changed
materially since December 31, 1998. Market risk represents the
risk of loss that may impact the Company due to adverse changes in
commodity market prices and interest rates.
The exposure to changes in interest rates from the Company's
short-term and long-term borrowings at June 30, 1999 is not
materially different than at December 31, 1998.
Year 2000 (Y2K) Readiness Disclosure
On or about midnight on December 31, 1999, digital computing
systems may begin to produce erroneous results or fail, unless
these systems are modified or replaced, because such systems may be
programmed incorrectly and interpret the date of January 1, 2000 as
being January 1st of the year 1900 or another incorrect date. In
addition, certain systems may fail to detect that the year 2000 is
a leap year. Problems can also arise earlier than January 1, 2000,
as dates in the next millennium are entered into non-Y2K ready
programs.
Readiness Program - Internally, the Company, through the AEP
System, is modifying or replacing its computer hardware and
software programs to minimize Y2K-related failures and repair such
failures if they occur. This includes both information technology
(IT) systems, which are mainframe and client server applications,
and embedded logic (non-IT) systems, such as process controls for
energy production and delivery. Externally, the problem is being
addressed with entities that interact with the Company, including
suppliers, customers, creditors, financial service organizations
and other parties essential to the Company's operations. In the
course of the external evaluation, the Company has sought written
assurances from third parties regarding their state of Y2K
readiness.
<PAGE>
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The Company, along with other electric utilities in North America,
has submitted information to the North American Electric
Reliability Council (NERC) as part of NERC's Y2K readiness program.
NERC then publicly reported summary information to the U.S.
Department of Energy (DOE) regarding the Y2K readiness of electric
utilities. The fourth and final NERC report, dated August 3, 1999
and entitled: Preparing the Electric Power Systems of North America
for Transition to the Year 2000 - A Status Report and Work Plan,
Second Quarter 1999, states that: "Mission-critical component
testing indicates that the transition through critical Y2K dates is
expected to have minimal impact on electric system operations in
North America." The report also indicates that, "the risk of
electrical outages caused by Y2K appears to be no higher than the
risks we already experience" from incidents such as severe wind,
ice, floods, equipment failures and power shortages during an
extremely hot or cold period.
AEP participated in an industry-wide NERC-sponsored drill on
April 9, 1999 simulating the partial loss of voice and data
communications. There were no major problems encountered with
relaying information with the use of backup telecommunications
systems. AEP and other utilities plan to participate in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions.
Through the Electric Power Research Institute, an electric
utility industry-wide effort has been established to deal with Y2K
problems affecting embedded systems. Under this effort,
participating utilities are working together to assess specific
vendors' system problems and test plans.
The state regulatory commissions in the Company's service
territory are also reviewing the Y2K readiness of the Company.
Company's State of Readiness - Work has been prioritized in
accordance with business risk. The highest priority has been
assigned to activities that potentially affect safety, the physical
generation and delivery of energy, and communications; followed by
back office activities such as customer service/billing, regulatory
reporting, internal reporting and administrative activities (e.g.,
payroll, procurement, accounts payable); and finally, those
activities that would cause inconvenience or productivity loss in
normal business operations.
The following chart shows the Company's progress toward
becoming ready for the Y2K as of June 30, 1999:
IT SYSTEMS NON-IT SYSTEMS
COMPLETION COMPLETION
DATE/ESTIMATED PERCENT DATE/ESTIMATED PERCENT
YEAR 2000 PROJECT PHASES COMPLETION DATE COMPLETE COMPLETION DATE COMPLETE
Launch: Initiation of 2/24/1998 100% 5/31/1998 100%
the Year 2000
activities within
the organization.
Establishment of
organizational structure,
personnel assignments
and budget for the
workgroup. Continuous
management update and
awareness program.
Inventory and Assessment:
Identifying all Company 7/31/1998 100% 2/15/1999 100%
computer systems that
could be affected by the
millennium change.
Prioritize repair efforts
based upon criticality to
maintaining ongoing operations.
Remediation/Testing: The
process of modifying, 6/30/1999 Mainframe: 6/30/1999 100%
replacing or retiring 100%
those mission critical and
high priority digital-based
systems with problems Client
processing dates in the Server:
Year 2000. Testing these 100%
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 June 30,
1999, the Company has spent $11 million on the Y2K project and,
estimates spending an additional $4 million to $6 million to
achieve Y2K readiness. Most Y2K costs are for software
modifications, IT consultants and salaries and are expensed;
however, in certain cases the Company has acquired hardware that
was capitalized. The Company intends to fund these expenditures
through internal sources. Although significant, the cost of
becoming Y2K compliant is not expected to have a material impact on
the Company's results of operations, cash flows or financial
condition.
Risks of the Company's Y2K Issues - The applications posing the
greatest business risk to the Company's operations should they
experience Y2K problems are:
Automated power generation, transmission and distribution systems
Telecommunications systems
Energy trading systems
Time-in-use, demand and remote metering systems for commercial
and industrial customers and
Work management and billing systems.
The potential problems related to erroneous processing by, or
failure of, these systems are:
Power service interruptions to customers
Interrupted revenue data gathering and collection
Poor customer relations resulting from delayed billing and
settlement.
Although it is difficult to hypothesize a most reasonably
likely worst case Y2K scenario with any degree of certainty,
management believes that such a scenario would be small, localized
interruptions of service, which would be restored.
In addition, although relationships with third parties, such
as suppliers, customers and other electric utilities, are being
monitored, these third parties nonetheless represent a risk that
cannot be assessed with precision or controlled with certainty.
Due to the complexity of the problem and the interdependent
nature of computer systems, if our corrective actions, and/or the
actions of others who impact the AEP System's operations but are
not affiliated with the AEP System, fail for critical applications,
Y2K-related issues may materially adversely affect the Company.
Company's Contingency Plans - To address possible failures of
electric generation and delivery of electrical energy due to Y2K
related failures, we have established a Y2K contingency plan and
submitted it to the East Central Area Reliability Council as part
of NERC's review of regional and individual electric utility
contingency plans in 1999. In addition, the Company is
establishing contingency plans for its business units to address
alternatives if Y2K related failures occur. These contingency
plans will be developed by the end of 1999.
The Company's plans build upon the disaster recovery, system
restoration, and contingency planning that we have had in place and
include:
Availability of additional power generation reserves.
Coal inventory of approximately 45 days of normal usage.
Identifying critical operational locations, in order to place
key employees on duty at those locations during the Y2K
transition.
<PAGE>
<PAGE>
PART II. OTHER INFORMATION
Item 4. Submission of Matters to a Vote of Security Holders.
American Electric Power Company, Inc. ("AEP")
The annual meeting of shareholders was held in Charleston, West
Virginia on April 28, 1999. The holders of shares entitled to vote
at the meeting or their proxies cast votes at the meeting with
respect to the following two matters, as indicated below:
1. Election of 10 directors to hold office until the next
annual meeting and until their successors are duly
elected. Each nominee for director received the votes of
shareholders as follows:
Number of Shares Number of
Nominee Voted For Votes With-
held
John P. DesBarres 152,429,069 1,587,655
E. Linn Draper, Jr. 152,409,489 1,607,235
Robert M. Duncan 152,228,331 1,788,393
Robert W. Fri 152,374,521 1,642,203
Lester A. Hudson, Jr. 152,399,000 1,617,724
Leonard J. Kujawa 152,337,815 1,678,909
Donald G. Smith 152,425,646 1,571,078
Linda Gillespie Stuntz 152,373,335 1,643,389
Kathryn D. Sullivan 152,227,130 1,789,594
Morris Tanenbaum 152,274,788 1,741,936
Ronald Marsico 55,033
2. Approve the appointment by the Board of Directors of
Deloitte & Touche LLP as independent auditors of AEP for
the year 1999. The proposal was approved by a vote of the
shareholders as follows:
Votes FOR 152,631,080
Votes AGAINST 430,714
Votes ABSTAINED 954,930
Broker NON-VOTES* 0
<PAGE>
<PAGE>
*A non-vote occurs when a nominee holding shares for a
beneficial owner votes on one proposal, but does not vote
on another proposal because the nominee does not have
discretionary voting power and has not received
instructions from the beneficial owner.
Appalachian Power Company ("APCo")
The annual meeting of stockholders was held on April 27, 1999
at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 13,499,500
votes were cast FOR each of the following six persons for election
as directors and there were no votes withheld and such persons were
elected directors to hold office for one year or until their
successors are elected and qualify:
E. Linn Draper, Jr. James J. Markowsky
Henry W. Fayne Armando A. Pena
William J. Lhota Joseph H. Vipperman
No other business was transacted at the meeting.
Indiana Michigan Power Company ("I&M")
The annual meeting of stockholders was held on April 27, 1999
at 1 Riverside Plaza, Columbus, Ohio. At the meeting, 1,400,000
votes were cast FOR each of the following thirteen persons for
election as directors and there were no votes withheld and such
persons were elected directors to hold office for one year or until
their successors are elected and qualify:
Karl G. Boyd James J. Markowsky C. R. Boyle, III
Armando A. Pena G. A. Clark David B. Synowiec
E. Linn Draper, Jr. Joseph H. Vipperman
Henry W. Fayne William E. Walters
James Kobyra Earl H. Wittkamper
William J. Lhota
No other business was transacted at the meeting.
<PAGE>
<PAGE>
Ohio Power Company ("OPCo")
The annual meeting of shareholders was held on May 4, 1999 at
1 Riverside Plaza, Columbus, Ohio. At the meeting, 27,952,473
votes were cast FOR each of the following six persons for election
as directors and there were no votes withheld and such persons were
elected directors to hold office for one year or until their
successors are elected and qualify:
E. Linn Draper, Jr. James J. Markowsky
Henry W. Fayne Armando A. Pena
William J. Lhota Joseph H. Vipperman
No other business was transacted at the meeting.
Item 5. Other Information.
AEP, AEP Generating Company ("AEGCo"), APCo, Columbus Southern
Power Company ("CSPCo"), I&M, Kentucky Power Company ("KEPCo") and
OPCo
Reference is made to page 29 of the Annual Report on Form 10-K
for the year ended December 31, 1998 ("1998 10-K") for a discussion
of ambient air quality standards attainment. On May 14, 1999, the
U.S. Court of Appeals for the District of Columbia Circuit issued
its decision vacating the ambient air quality standard for
particulate matter less than 10 microns in diameter and remanding
the 8-hour air quality standards for ozone and fine particulate
matter (less than 2.5 microns in diameter). The ruling, in effect,
suspends the ozone and fine particulate matter standards pending
the corrective steps mandated by the court. The U.S. Environmental
Protection Agency ("Federal EPA") filed a motion for rehearing with
the court on June 28, 1999.
<PAGE>
<PAGE>
Reference is made to pages 32 and 33 of the 1998 10-K for a
discussion of Federal EPA's proposed regional haze rule. On July
1, 1999, Federal EPA issued a final rule which requires each state
to develop and implement measures to control emissions from sources
within the state which are reasonably anticipated to contribute to
regional haze within a Class I area (essentially national parks or
wilderness areas). Deadlines for the states to implement such
measures vary between 2002 and 2008 depending on the particulate
matter attainment status for the areas within each state. The rule
requires each state to identify sources constructed between 1962
and 1977 which may be eligible for application of Best Available
Retrofit Technology. AEP is unable to predict when or to what
extent controls may be required for AEP System generating units to
comply with this rule or the extent of costs which may be incurred.
Reference is made to page 33 of the 1998 10-K and pages II-1
and II-2 of the Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999, for a discussion of requests issued to AEP under
Section 114 of the Clean Air Act focused on assessing compliance
with the New Source Review and New Source Performance Standard
provisions. In July 1999, Federal EPA, Region V, issued an
additional request seeking documents and information regarding
capital and maintenance expenditures at Tanners Creek Plant and, in
August 1999, made a site visit to Cardinal Plant. Federal EPA
staff has advised AEP that it is their preliminary view that there
has been widespread noncompliance at coal fired generating units
within the utility industry (including at several AEP plants) over
the past 20 years with regard to New Source Review requirements.
AEP management does not agree with this view. An adverse
determination by Federal EPA could result in substantial additional
capital costs and significant penalties for any affected company.
AEP is unable to predict what, if any, further action may be taken
by Federal EPA in respect of this matter or the effect that any
action taken by Federal EPA may have on the financial condition or
the results of operation of AEP.
<PAGE>
<PAGE>
AEP and OPCo
Reference is made to page 32 of the 1998 10-K for a discussion
of the SO2 limitation applicable to the Kammer Plant. On July 22,
1999, the West Virginia Division of Environmental Protection,
Office of Air Quality, conducted a public meeting to consider
revised SO2 emission limits for the Kammer Plant and other emission
sources within Marshall County. The emission limit proposed for
Kammer is 2.7 pounds of SO2 per million Btu. The limit, if
approved, would conform to the current federally approved emission
limit for Kammer contained in the West Virginia State
Implementation Plan.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
APCo, CSPCo, I&M, KEPCo and OPCo
Exhibit 12 - Statement re: Computation of Ratios.
AEP, AEGCo, APCo, CSPCo, I&M, KEPCo and OPCo
Exhibit 27 - Financial Data Schedule.
(b) Reports on Form 8-K:
Company
Reporting Date of Report Item Reported
AEP and I&M June 24, 1999 Item 5. Other Events
AEGCo, APCo, CSPCo, KEPCo and OPCo
No reports on Form 8-K were filed during the quarter ended
June 30, 1999.
<PAGE>
<PAGE>
Signature
Pursuant to the requirements of the Securities Exchange Act of
1934, each registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized. The
signature for each undersigned company shall be deemed to relate
only to matters having reference to such company and any
subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ Armando A. Pena By: /s/ Leonard V. Assante
Armando A. Pena Leonard V. Assante
Treasurer Controller and
Chief Accounting Officer
(Duly Authorized Officer) (Chief Accounting Officer)
AEP GENERATING COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
By: /s/ Armando A. Pena By: /s/ Leonard V. Assante
Armando A. Pena Leonard V. Assante
Vice President, Treasurer, Controller and
and Chief Financial Officer Chief Accounting Officer
(Duly Authorized Officer) (Chief Accounting Officer)
Date: August 12, 1999
<TABLE>
EXHIBIT 12
OHIO POWER COMPANY
Computation of Consolidated Ratio of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Twelve
Months
Year Ended December 31, Ended
1994 1995 1996 1997 1998 6/30/99
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds. . . . . . . . $ 63,805 $ 61,836 $ 52,147 $ 45,540 $ 33,663 $ 28,767
Interest on Other Long-term Debt. . . . . . . . 21,453 23,193 27,045 29,620 38,520 43,435
Interest on Short-term Debt . . . . . . . . . . 992 2,658 4,006 4,519 5,821 7,711
Miscellaneous Interest Charges. . . . . . . . . 5,140 7,126 3,705 4,464 4,617 4,645
Estimated Interest Element in Lease Rentals . . 13,900 50,700 53,200 52,900 59,300 59,300
Total Fixed Charges. . . . . . . . . . . . $105,290 $145,513 $140,103 $137,043 $141,921 $143,858
Earnings:
Net Income. . . . . . . . . . . . . . . . . . . $162,626 $189,447 $217,655 $208,689 $209,925 $209,116
Plus Federal Income Taxes . . . . . . . . . . . 74,822 93,699 117,243 121,559 112,087 115,649
Plus State Income Taxes . . . . . . . . . . . . 3,375 1,618 2,252 2,655 2,742 2,889
Plus Fixed Charges (as above) . . . . . . . . . 105,290 145,513 140,103 137,043 141,921 143,858
Total Earnings . . . . . . . . . . . . . . $346,113 $430,277 $477,253 $469,946 $466,675 $471,512
Ratio of Earnings to Fixed Charges. . . . . . . . 3.28 2.95 3.40 3.42 3.28 3.27
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000073986
<NAME> OHIO POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,770,561
<OTHER-PROPERTY-AND-INVEST> 246,654
<TOTAL-CURRENT-ASSETS> 994,931
<TOTAL-DEFERRED-CHARGES> 82,570
<OTHER-ASSETS> 572,025
<TOTAL-ASSETS> 4,666,741
<COMMON> 321,201
<CAPITAL-SURPLUS-PAID-IN> 462,366
<RETAINED-EARNINGS> 584,045
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,367,612
11,850
17,211
<LONG-TERM-DEBT-NET> 1,072,702
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 194,090
<LONG-TERM-DEBT-CURRENT-PORT> 11,283
0
<CAPITAL-LEASE-OBLIGATIONS> 107,424
<LEASES-CURRENT> 29,235
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,855,334
<TOT-CAPITALIZATION-AND-LIAB> 4,666,741
<GROSS-OPERATING-REVENUE> 1,016,808
<INCOME-TAX-EXPENSE> 68,955
<OTHER-OPERATING-EXPENSES> 795,569
<TOTAL-OPERATING-EXPENSES> 864,524
<OPERATING-INCOME-LOSS> 152,284
<OTHER-INCOME-NET> 1,508
<INCOME-BEFORE-INTEREST-EXPEN> 153,792
<TOTAL-INTEREST-EXPENSE> 41,106
<NET-INCOME> 112,686
734
<EARNINGS-AVAILABLE-FOR-COMM> 111,952
<COMMON-STOCK-DIVIDENDS> 115,406
<TOTAL-INTEREST-ON-BONDS> 13,849
<CASH-FLOW-OPERATIONS> 142,797
<EPS-BASIC> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
