THE CONSOLIDATED 10-Q FOR AMERICAN ELECTRIC POWER CO., INC, AND
SUBSIDIARIES IS REQUESTED TO BE INCLUDED AS PART OF THE FILING.
<PAGE>
<TABLE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended SEPTEMBER 30, 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 October 31, 1999 was 194,103,349.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 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-21
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . A-22- A-43
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-10
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . C-11- C-22
Columbus Southern Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . D-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . D-2 - D-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . D-4
Notes to Consolidated Financial Statements . . . . . . . . . D-5 - D-10
Management's Narrative Analysis of Results of Operations . . D-11- D-12
Indiana Michigan Power Company and Subsidiaries:
Consolidated Statements of Income and
Consolidated Statements of Retained Earnings . . . . . . . E-1
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . E-2 - E-3
Consolidated Statements of Cash Flows. . . . . . . . . . . . E-4
Notes to Consolidated Financial Statements . . . . . . . . . E-5 - E-11
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . . E-12- E-24
Kentucky Power Company:
Statements of Income and Statements of Retained Earnings . . F-1
Balance Sheets . . . . . . . . . . . . . . . . . . . . . . . F-2 - F-3
Statements of Cash Flows . . . . . . . . . . . . . . . . . . F-4
Notes to Financial Statements. . . . . . . . . . . . . . . . F-5 - F-8
Management's Narrative Analysis of Results of Operations . . F-9 - F-10
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
FORM 10-Q
For The Quarter Ended September 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-12
Management's Discussion and Analysis of Results of
Operations and Financial Condition . . . . . . . . . . . G-13- G-25
Part II. OTHER INFORMATION
Item 5 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-1
Item 6 . . . . . . . . . . . . . . . . . . . . . . . . . . . II-2
SIGNATURE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-3
EXHIBITS INDEX. . . . . . . . . . . . . . . . . . . . . . . . . . . . . II-4
This combined Form 10-Q is separately filed by American Electric Power Company,
Inc., AEP Generating Company, Appalachian Power Company, Columbus Southern Power
Company, Indiana Michigan Power Company, Kentucky Power Company and Ohio Power Company.
Information contained herein relating to any individual registrant is filed by such
registrant on its own behalf. Each registrant makes no representation as to
information relating to the other registrants.
</TABLE>
<PAGE>
<PAGE>
FORWARD-LOOKING INFORMATION
This report made by American Electric Power Company, Inc. (AEP) and certain
of its subsidiaries contains forward-looking statements within the meaning
of Section 21E of the Securities Exchange Act of 1934. Although AEP and
each of its subsidiaries believe that their expectations are based on
reasonable assumptions, any such statements may be influenced by factors
that could cause actual outcomes and results to be materially different
from those projected. Among the factors that could cause actual results to
differ materially from those in the forward-looking statements are:
Electric load and customer growth.
Abnormal weather conditions.
Available sources and costs of fuels.
Availability of generating capacity.
The impact of the proposed merger with CSW including any regulatory
conditions imposed on the merger or the inability to consummate the
merger with CSW.
The speed and degree to which competition is introduced to our power
generation business.
The structure and timing of a competitive market and its impact on energy
prices or fixed rates.
The ability to recover stranded costs in connection with
possible/proposed deregulation of generation.
New legislation and government regulations.
The ability of AEP to successfully control its costs.
The success of new business ventures.
International developments affecting AEP's foreign investments.
The economic climate and growth in AEP's service territory.
Unforeseen events affecting AEP's nuclear plant which is on an extended
safety related shutdown.
Problems or failures related to Year 2000 readiness of computer
software and hardware.
Inflationary trends.
Electricity and gas market prices.
Interest rates
Other risks and unforeseen events.
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF INCOME
(in millions, except per-share amounts)
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
<S> <C> <C> <C> <C>
REVENUES:
Domestic Regulated Electric Utilities. . $1,758 $1,846 $4,809 $4,916
Worldwide Non-regulated Electric and
Gas Operations . . . . . . . . . . . . 156 12 442 20
TOTAL REVENUES . . . . . . . . . 1,914 1,858 5,251 4,936
EXPENSES:
Fuel and Purchased Power . . . . . . . . 631 652 1,616 1,691
Maintenance and Other Operation. . . . . 491 496 1,387 1,344
Depreciation and Amortization. . . . . . 151 146 448 434
Taxes Other Than Federal Income Taxes. . 121 120 364 354
Worldwide Non-regulated Electric and
Gas Operations . . . . . . . . . . . . 144 31 394 62
TOTAL EXPENSES . . . . . . . . . 1,538 1,445 4,209 3,885
OPERATING INCOME . . . . . . . . . . . . . 376 413 1,042 1,051
NONOPERATING INCOME (LOSS) . . . . . . . . 3 (3) - 6
INCOME BEFORE INTEREST, PREFERRED
DIVIDENDS AND INCOME TAXES . . . . . . . 379 410 1,042 1,057
INTEREST AND PREFERRED DIVIDENDS . . . . . 136 110 403 325
INCOME BEFORE INCOME TAXES . . . . . . . . 243 300 639 732
INCOME TAXES . . . . . . . . . . . . . . . 69 105 226 268
NET INCOME . . . . . . . . . . . . . . . . $ 174 $ 195 $ 413 $ 464
AVERAGE NUMBER OF SHARES OUTSTANDING . . . 194 191 193 191
EARNINGS PER SHARE . . . . . . . . . . . . $0.90 $1.02 $2.14 $2.44
CASH DIVIDENDS PAID PER SHARE. . . . . . . $0.60 $0.60 $1.80 $1.80
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
NET INCOME . . . . . . . . . . . . . . . . $174 $195 $413 $464
OTHER COMPREHENSIVE INCOME:
Foreign Currency Translation
Adjustments. . . . . . . . . . . . . . (1) - 20 -
COMPREHENSIVE INCOME . . . . . . . . . . . $173 $195 $433 $464
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1999 1998
(in millions)
ASSETS
<S> <C> <C>
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . $ 274 $ 173
Accounts Receivable (net). . . . . . . . . . . . . . 978 879
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 297 216
Materials and Supplies . . . . . . . . . . . . . . . 307 280
Accrued Utility Revenues . . . . . . . . . . . . . . 213 214
Energy Marketing and Trading Contracts . . . . . . . 666 372
Prepayments and Other. . . . . . . . . . . . . . . . 93 84
TOTAL CURRENT ASSETS . . . . . . . . . . . . 2,828 2,218
PROPERTY, PLANT AND EQUIPMENT:
Electric:
Production . . . . . . . . . . . . . . . . . . . . 9,902 9,615
Transmission . . . . . . . . . . . . . . . . . . . 3,793 3,692
Distribution . . . . . . . . . . . . . . . . . . . 5,349 5,125
Other (including gas and coal mining assets
and nuclear fuel) . . . . . . . . . . . . . . . . . 2,259 2,118
Construction Work in Progress. . . . . . . . . . . . 661 801
Total Property, Plant and Equipment. . . . . 21,964 21,351
Accumulated Depreciation and Amortization. . . . . . 9,043 8,549
NET PROPERTY, PLANT AND EQUIPMENT. . . . . . 12,921 12,802
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 2,049 1,847
OTHER ASSETS . . . . . . . . . . . . . . . . . . . . . 2,640 2,616
TOTAL. . . . . . . . . . . . . . . . . . . $20,438 $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>
September 30, December 31,
1999 1998
(in millions)
LIABILITIES AND SHAREHOLDERS' EQUITY
<S> <C> <C>
CURRENT LIABILITIES:
Accounts Payable . . . . . . . . . . . . . . . . . . $ 647 $ 607
Short-term Debt. . . . . . . . . . . . . . . . . . . 710 617
Long-term Debt Due Within One Year . . . . . . . . . 978 206
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 239 382
Interest Accrued . . . . . . . . . . . . . . . . . . 117 75
Obligations Under Capital Leases . . . . . . . . . . 90 82
Energy Marketing and Trading Contracts . . . . . . . 643 360
Other. . . . . . . . . . . . . . . . . . . . . . . . 483 472
TOTAL CURRENT LIABILITIES. . . . . . . . . . 3,907 2,801
LONG-TERM DEBT . . . . . . . . . . . . . . . . . . . . 6,219 6,800
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 2,647 2,601
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 334 351
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 215 222
DEFERRED CREDITS AND REGULATORY LIABILITIES. . . . . . 424 263
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 1,503 1,429
CUMULATIVE PREFERRED STOCK OF SUBSIDIARIES . . . . . . 169 174
CONTINGENCIES (Note 9)
COMMON SHAREHOLDERS' EQUITY:
Common Stock-Par Value $6.50:
1999 1998
Shares Authorized . . . .600,000,000 600,000,000
Shares Issued . . . . . .203,092,805 200,816,469
(8,999,992 shares were held in treasury) . . . . . 1,320 1,305
Paid-in Capital. . . . . . . . . . . . . . . . . . . 1,931 1,854
Accumulated Other Comprehensive Income -
Foreign Currency Translation Adjustments. . . . . . 19 (1)
Retained Earnings. . . . . . . . . . . . . . . . . . 1,750 1,684
TOTAL COMMON SHAREHOLDERS' EQUITY. . . . . . 5,020 4,842
TOTAL. . . . . . . . . . . . . . . . . . . $20,438 $19,483
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<TABLE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1999 1998
(in millions)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 413 $ 464
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 532 463
Deferred Federal Income Taxes. . . . . . . . . . . . . . 106 34
Deferred Investment Tax Credits. . . . . . . . . . . . . (17) (17)
Amortization of Deferred Property Taxes. . . . . . . . . 138 135
Cook Restart Expense Deferral. . . . . . . . . . . . . . (90) -
Deferred Costs Under Fuel Clause Mechanisms. . . . . . . (103) (59)
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (99) (174)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (108) 14
Accounts Payable . . . . . . . . . . . . . . . . . . . . 40 108
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (143) (81)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 42 30
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . (43) 55
Other Current Assets and Liabilities . . . . . . . . . . 42 124
Payment of Disputed Tax and Interest Related to COLI . . . (19) (303)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 57 52
Net Cash Flows From Operating Activities . . . . . . 748 845
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (598) (557)
Other Investments. . . . . . . . . . . . . . . . . . . . . (15) (10)
Proceeds from Sale of Property . . . . . . . . . . . . . . 5 9
Net Cash Flows Used For Investing Activities . . . . (608) (558)
FINANCING ACTIVITIES:
Issuance of Common Stock . . . . . . . . . . . . . . . . . 91 63
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 545 618
Retirement of Cumulative Preferred Stock . . . . . . . . . (5) -
Retirement of Long-term Debt . . . . . . . . . . . . . . . (416) (548)
Change in Short-term Debt (net). . . . . . . . . . . . . . 93 (20)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (347) (343)
Net Cash Flows Used For Financing Activities . . . . (39) (230)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 101 57
Cash and Cash Equivalents at Beginning of Period . . . . . . 173 91
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 274 $ 148
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $344 million and $279 million
and for income taxes was $63 million and $150 million in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $67 million and $94 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 Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in millions)
<S> <C> <C> <C> <C>
BALANCE AT BEGINNING OF PERIOD . . . . . $1,692 $1,645 $1,684 $1,605
NET INCOME . . . . . . . . . . . . . . . 174 195 413 464
DEDUCTIONS:
Cash Dividends Declared. . . . . . . . 116 114 347 343
BALANCE AT END OF PERIOD . . . . . . . . $1,750 $1,726 $1,750 $1,726
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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 normal recurring accruals and
adjustments which are necessary for a fair presentation of the
results of operations for interim periods.
2. FINANCING AND RELATED ACTIVITIES
During the first nine months of 1999, subsidiaries issued
$475 million of senior unsecured notes: $150 million at 6.60%
due in 2009, $100 million at 6.75% due in 2004, $150 million
at 6.875% due in 2004 and $75 million at 7% 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
$93 million. In October 1999 an additional $50 million of
senior unsecured notes at 7.45% due in 2004 were issued.
Retirements of debt were: first mortgage bonds totaling
$311 million with interest rates ranging from 6.55% to 8.43%
and due dates ranging from 2003 to 2024, $50 million of
pollution control revenue bonds at 7.40% due 2009 and $40
million in term loans with interest rates ranging from 6.42%
to 7.69% due in 1999.
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 those 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.
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 transmission services 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. The 1996 tariff incorporated transmission
rates which were the result of a settlement of a pending rate
case, but which were being collected subject to refund from
certain customers who opposed the settlement and continued to
litigate the reasonableness of AEP's transmission rates. On
July 29, 1999, the FERC issued an order in the litigated rate
case which would reduce AEP's rates for the affected customers
below the settlement rate. AEP and certain of the affected
customers have sought rehearing of the Commission's Order. The
Company made a provision in September 1999 for the refund which
it anticipates would result if the Commission's Order is upheld
including interest.
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 100% of Yorkshire's
summarized consolidated financial information:
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in millions)
Income Statement Data:
Operating Revenues $523.0 $510.2 $1,679.7 $1,677.3
Operating Income 48.5 82.6 200.5 264.8
Net Income 8.3 21.5 38.5 13.6
<PAGE>
In August 1999 the Office of Gas and Electricity Markets
(OFGEM, which is the U.K. regulator of gas and electricity
rates), published draft price proposals for the U.K.'s regional
distribution businesses that would be effective for the five-year period
beginning April 1, 2000. Under the draft price
proposals, the distribution rates for Yorkshire would be
reduced 15% to 20% from current rates. Yorkshire filed
comments on September 17, 1999 with OFGEM expressing various
concerns with the analysis used by OFGEM. Yorkshire also
commented that the methodology used failed to justify the
magnitude of the price cuts proposed and suggested a more
suitable methodology.
On October 8, 1999, OFGEM issued updated draft price
proposals for Yorkshire's electric distribution business. The
updated proposal would require Yorkshire to reduce distribution
rates 15% and transfer 8% of costs to Yorkshire's electricity
supply business, an overall reduction in distribution prices
of 23%.
Also on October 8, 1999, OFGEM issued draft price proposals
for Yorkshire's electric supply business. Under the proposals,
a supply price cap for certain domestic U.K. customers is
retained from April 2000 through March 2002. For Yorkshire,
these proposals would result in a price reduction of
approximately 10.7% on the standard domestic tariff commencing
April 2000 and ending March 2001 and a nominal price freeze for
the year commencing April 2001 and ending March 2002.
OFGEM is expected to publish final proposals on both the
distribution and the supply businesses at the end of November
1999. Yorkshire management intends to take all available
opportunities to increase revenues and reduce costs to mitigate
the impact of the final OFGEM distribution and supply price
reductions. Should Yorkshire be unable to increase revenues
and reduce costs in amounts sufficient to offset the impact of
the OFGEM distribution and supply price reductions, AEP's
equity earnings from its investment in Yorkshire will be
significantly reduced in comparison to its current level of
earnings.
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 other business segments. 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 nine months ending
September 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>
September 30, 1999
Revenues from
external customers $ 4,809 $ 553 $ 79 $(190) $ 5,251
Revenues from
transactions with other
operating segments - 47 143 (190) -
Segment net income (loss) 409 20 (16) - 413
Total assets 17,375 2,333 730 - 20,438
September 30, 1998
Revenues from
external customers 4,916 20 - - 4,936
Revenues from
transactions with other
operating segments - - - - -
Segment net income (loss) 485 (12) (9) - 464
Total assets 16,723 472 281 - 17,476
</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 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.
<PAGE>
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 (RTO)
proposal whereby it will transfer the operation and control of
AEP's bulk transmission facilities to an RTO. 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 asking
the FERC 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 shared 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. On October 13, 1999 this appeal was dismissed by the
Oklahoma Supreme Court and the cooperative customers have since
asked the OCC to dismiss their appeal.
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. Hearings on the merger in
Texas began August 9, 1999 and concluded on August 10, 1999.
As the hearings began, settlements were reached with all but
one of the parties in the case. The settling parties are all
wholesale electric customers of CSW's Texas electric operating
companies. The settlements call for the withdrawal of their
opposition to the merger in all regulatory approval
proceedings. On November 4, 1999 the Texas Commission, in its
open meeting approved the application on the pending merger and
the stipulated settlement announced in May.
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.
Ohio
On October 21, 1999, the Public Utilities Commission of
Ohio (PUCO) issued a decision stating that it will notify the
FERC that it will withdraw its opposition to the Company's
pending merger with CSW and will not seek conditions on the
merger.
American Municipal Power - Ohio (AMP-Ohio) and AEP reached
a settlement addressing outstanding issues. As part of the
settlement AMP-Ohio agreed to withdraw as an intervenor in the
merger process. AMP-Ohio is the nonprofit wholesale power
supplier and service provider for most of Ohio's 84 community-owned
public power systems, two West Virginia public power
systems and four Pennsylvania public power systems.
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 review and
investigation.
Completion of the Merger
As of September 30, 1999, AEP had deferred $37 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 allocable to the regulated
electric operating subsidiaries will be amortized over their
recovery period, generally 5-years, in accordance with state
regulator orders. The remainder of the deferred merger costs
will be expensed upon consummation of the merger.
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 second quarter of 2000, the Company
is unable to predict the outcome or the timing of the required
regulatory proceedings.
8. RESTRUCTURING LEGISLATION
Virginia
In March 1999 a 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 (Virginia SCC) that an effective competitive market
exists, on January 1, 2004.
The law also provides an opportunity for recovery of just
and reasonable net stranded generation 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 depart the
incumbent utility in favor of an alternative supplier prior to
the termination of the rate cap. The law provides for the
establishment of capped rates prior to January 1, 2001 and the
establishment of a wires charge by the fourth quarter of 2001.
Management has concluded that as of September 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 and the wires charge should enable the Company to
determine its ability to recover stranded costs, a requirement
to discontinue application of SFAS 71.
When the capped rates and the wires charge are established
in Virginia, the application of SFAS 71 will be discontinued
for the Virginia retail jurisdiction portion of the Company's
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 capped rates and
wire charges approved by the Virginia SCC under the 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, wires charges and other pertinent
information, it is not possible at this time to determine if
any generation related assets are impaired in accordance with
SFAS 121 and if generation related regulatory assets will be
recovered. The amount of regulatory assets recorded on the
books applicable to the Company's Virginia retail generating
business at September 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
and/or tangible generating assets, it could have a material
adverse impact on results of operations and cash flows. 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 and
other transition costs cannot be made until such time as the
transition capped rates and the wires charge are determined
under the law; which is not expected to occur before the fourth
quarter of 2000.
Ohio
The Ohio Electric Restructuring Act of 1999 became law on
October 4, 1999. The law provides for customer choice of
electricity supplier, a residential rate reduction of 5% and
a freezing of the unbundled generation base rates and a
freezing of fuel rates beginning on January 1, 2001. The law
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 including any unrecovered
deferred fuel costs, stranded plant and mining costs and other
transition costs.
Retail electric services that will be competitive are
defined in the law as electric generation service, aggregation
service, and power marketing and brokering. Under the
legislation the PUCO is granted broad oversight responsibility
and is required by the law to promulgate rules for competitive
retail electric generation service. The law also gives the
PUCO authority to approve a transition plan for each electric
utility company.
The law provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled frozen generation rates paid through December
31, 2005 by customers who do not switch generation suppliers
and through a wires charge for customers who switch generation
suppliers. Transition costs can include regulatory assets,
impairments of generating assets and other stranded costs,
employee severance and retraining costs, consumer education
costs and other costs. Recovery of transition costs can, under
certain circumstances, extend beyond the five-year frozen rate
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 law also provides that the property tax assessment
percentage on electric generation property be lowered from 100%
to 25% of value effective January 1, 2001. Electric utilities
will 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 tax 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. The
gross receipts tax is paid at the beginning of the tax year,
deferred as a prepaid expense and amortized to expense during
the tax year pursuant to the tax laws whereby the payment of
the tax results in the privilege to conduct business in the
year following the payment of the tax. The change in the tax
law to impose an excise tax based on kilowatt-hours sold to
Ohio customers commencing before the expiration of the gross
receipts tax privilege period will result in a 12 month period
when electric utilities are recording as an expense both the
gross receipts tax and the excise tax. Management intends to
seek recovery of the overlap of the gross receipts and excise
taxes in the Ohio transition plan filing.
As discussed in Note 3, "Effects of Regulation and Phase-In
Plans," of the Notes to Consolidated Financial Statements in
the 1998 Annual Report, the Company defers as regulatory assets
and liabilities certain expenses and revenues consistent with
the regulatory process in accordance with SFAS 71. Management
has concluded that as of September 30, 1999 the requirements
to apply SFAS 71 continue to be met since the Company's rates
for generation will continue to be cost-based regulated until
the establishment of unbundled frozen generation rates and a
wires charge as provided in the law. The establishment of
unbundled frozen generation rates and the wires charge should
enable the Company to determine its ability to recover
transition costs including regulatory assets and other stranded
costs, a requirement to discontinue application of SFAS 71.
When unbundled generation rates and the wires charge are
established, the application of SFAS 71 will be discontinued
for the Ohio retail jurisdiction portion of the generation
business. At that time the Company will have to write-off its
Ohio jurisdictional generation-related regulatory assets to the
extent that they cannot be recovered under the unbundled frozen
generation rates and distribution wires charges approved by the
PUCO under the provisions of the restructuring law and record
any asset impairments in accordance with SFAS 121. An
impairment loss would be recorded to the extent that the cost
of generation 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
an unbundled frozen generation rate, the wires charge and other
pertinent information, it is not possible at this time to
determine if any of the Company's generating assets are
impaired in accordance with SFAS 121. The amount of regulatory
assets recorded on the books at September 30, 1999 applicable
to the Ohio retail jurisdictional generating business is $638
million before related tax effects. Due to the planned closing
of affiliated mines including the Meigs mine, and other
anticipated events, generation-related regulatory assets as of
December 31, 2000 allocable to the Ohio retail jurisdiction are
estimated to exceed $800 million, before federal income tax
effects. Recovery of these regulatory assets will be sought
as a part of the Company's Ohio transition plan filing.
An estimated determination of whether the Company will
experience any asset impairment loss regarding its Ohio retail
jurisdictional generating assets and any loss from a possible
inability to recover Ohio generation related regulatory assets
and other transition costs cannot be made until such time as
the unbundled frozen generation rates and the wires charge are
determined through the regulatory process. Management will
seek full recovery of generation-related regulatory assets, any
stranded costs and other transition costs in its transition
plan filing. The PUCO is required to complete its regulatory
process and issue a transition order establishing the
transition rates and wires charges by no later than October 31,
2000. Should the PUCO fail to approve transition rates and
wires charges that are sufficient to recover the Company's
generation-related regulatory assets, any other stranded costs
and transition costs, it could have a material adverse effect
on results of operations, cash flows and financial condition.
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 September 30, 1999 would reduce
earnings by approximately $317 million (including interest).
The Company has made no provision for any possible earnings
impact from this matter.
The Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1998 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. A US Tax Court judge
recently decided in the Winn-Dixie Stores v. Commissioner case
that a corporate taxpayer's COLI interest deductions should be
disallowed. Notwithstanding the decision in Winn-Dixie,
management believes, and has been advised by outside counsel,
that it has a meritorious position and will vigorously pursue
its lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations and cash flows.
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 Company's generating plants are located. A number of
utilities, including the Company, filed petitions seeking a
review of the final rules in the U.S. Court of Appeals for the
District of Columbia Circuit (Appeals Court). The matter is
currently being litigated.
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 that would impose
NOx reduction requirements on AEP System generating units which
are approximately equivalent to the reductions contemplated by
the NOx emission reduction final rules. The AEP System
companies with generating plants, as well as other utility
companies, 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 originally 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. 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 where generation
is being deregulated unbundled generation transition rates,
wires charges and the future market price of electricity, they
will have an adverse effect on future results of operations,
cash flows and possibly financial condition.
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the
request of Federal EPA, filed a complaint in the U.S. District
Court for the Southern District of Ohio that alleges the
Company made modifications to generating units at its Muskingum
River, Mitchell, Philip Sporn, Tanners Creek and Cardinal
plants over the course of the past 25 years to extend unit
operating lives or to increase unit generating capacity without
a preconstruction permit in violation of the Clean Air Act.
Federal EPA also issued a Notice of Violation to the Company
alleging violations of the New Source Review and New Source
Performance Standard provisions of the Clean Air Act at these
same plants as well as Conesville Plant. A number of
unaffiliated utilities also received Notices of Violation,
complaints or administrative orders including a Notice of
Violation issued to The Cincinnati Gas & Electric Company for
Beckjord Plant alleging violations of the New Source Review
provisions of the Clean Air Act. Columbus Southern Power
Company owns a partial interest in Unit 6 of Beckjord Plant.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to
assess compliance with the New Source Review and New Source
Performance Standard provisions of the Clean Air Act. Under
these provisions of the Clean Air Act, if a plant undertakes
a major modification that directly results in an emissions
increase, permitting requirements under the New Source Review
program might be triggered and the plant may be required to
install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each
separately threatened to sue the Company under the Clean Air
Act to compel compliance with the New Source Review and New
Source Performance Standard provisions, alleging that
modifications occurred at certain units at the Company's Philip
Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River
Plant, Gavin Plant, Cardinal Plant, Clinch River Plant, Kanawha
River Plant, Tanners Creek Plant, Amos Plant and Big Sandy
Plant. The State of New York also threatened to sue five
unaffiliated utilities. In addition, the State of New York
indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its
defense of this matter.
The Clean Air Act authorizes civil penalties of up to
$27,500 per day per violation at each generating unit ($25,000
per day prior to January 30, 1997). Civil penalties, if
ultimately imposed by the court, and the cost of any required
new pollution control equipment, if the court accepts all of
Federal EPA's contentions, could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that
may be required as well as any penalties imposed would
adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through regulated rates, and where states are deregulating
generation, approved unbundled transition generation rates,
wires charges and future market prices for energy.
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 a NRC architect engineer design inspection.
The NRC issued a Confirmatory Action Letter in September 1997
requiring the Company to address certain issues identified in
the letter. 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.
The Company's plan to restart the Cook Plant units has Unit
2 scheduled to return to service in April 2000 and Unit 1 to
return to service in September 2000. The restart plan was
developed based upon 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 September 30,
1999, $82 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.
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 billing 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 a $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 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 was applied to retail 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 limit the Company's ability to
increase base rates and freeze 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 restart outage. The pending Michigan
settlement limits deferrals to $50 million of 1999
jurisdictional non-fuel nuclear operation and maintenance
costs. Hearings have been held to give the one intervenor who
opposed the approval of the settlement agreement the
opportunity to voice its objections. The settlement agreement
is pending before the MPSC.
Expenditures for the restart of the Cook units are
estimated to total approximately $574 million and will be
accounted for primarily as a current period operation and
maintenance expense in 1999 and 2000. Through September 30,
1999, $280 million has been spent, of which $196 million was
incurred in 1999. Pursuant to the Indiana settlement agreement
$112.5 million of incremental operation and maintenance costs
were deferred for the nine months ended September 30, 1999.
The Indiana jurisdiction deferral is limited to up to $150
million of incremental restart costs incurred in 1999. The
amortization of such costs through September 30, 1999 was $22.5
million. At September 30, 1999, the unamortized balance of
incremental restart related operation and maintenance costs was
$90 million and was included in regulatory assets. Also
deferred as a regulatory asset at September 30, 1999 was $148
million of replacement energy fuel 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 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
THIRD QUARTER 1999 vs. THIRD QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income decreased by $21 million or 11% for the quarter and
$51 million or 11% for the year-to-date period due predominantly to
a decrease in wholesale energy sales and margins, an increase in
costs to prepare the Cook Plant for restart following an extended
outage in the Company's domestic regulated electric utility
operations and an increase in interest expense to finance
acquisitions in the Company's worldwide non-regulated operations.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Revenues:
Domestic Regulated
Electric Utilities. . . $(88) (5) $(107) (2)
Worldwide Non-regulated
Operations. . . . . . . 144 N.M. 422 N.M.
Fuel and Purchased
Power Expense . . . . . (21) (3) (75) (4)
Maintenance and Other
Operation Expense . . . . (5) (1) 43 3
Worldwide Non-regulated
Operations Expense. . . . 113 N.M. 332 N.M.
Interest and Preferred
Dividends . . . . . . . . 26 24 78 24
Income Taxes . . . . . . . (36) (34) (42) (16)
N.M. = Not Meaningful
Revenues from domestic regulated electric utility operations
decreased in both the third quarter and the year-to-date periods
due predominantly to decreased energy sales to wholesale customers
and a decline in margins on wholesale energy sales. Energy sales
to wholesale customers declined 16% in the quarter and 20% in the
year-to-date period primarily due to weather and its effect on
energy demand. Margins on trading in AEP's marketing area declined
$100 million in the quarter and $90 million for the year-to-date
period reflecting the effect of milder summer weather.
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 decreases in fuel and purchased power expense were
primarily attributable to a decrease in coal-fired generation
reflecting the decline in demand for electricity and an increase in
the deferral of the non-fuel components of the fuel clauses for
recovery in later periods in the domestic regulated electric
utility operations. In the year-to-date period, a decline in
purchased power as a result of the reduced wholesale demand also
contributed to the decrease.
Maintenance and other operation expense increased for the year-to-date
period largely as a result of expenditures to prepare the
Cook Plant units for restart following an extended Nuclear
Regulatory Commission (NRC) monitored outage which began in
September 1997.
Worldwide non-regulated expenses increased as a result of the
expansion of business development activities and expenses of
CitiPower and Louisiana Intrastate Gas which were acquired in
December 1998.
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 and adjustments to prior years tax
returns.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first nine months of 1999 were $665 million.
<PAGE>
During the first nine months of 1999, subsidiaries issued $550
million principal amount of long-term obligations at interest rates
ranging from 5.15% to 10.53%; retired $401 million principal amount
of long-term debt with interest rates ranging from 6.42% to 8.43%;
and increased short-term debt by $93 million.
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 at least 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.
United Kingdom Price Reduction Proposal
In August 1999 the Office of Gas and Electricity Markets
(OFGEM, which is the U.K. regulator of gas and electricity rates),
published draft price proposals for the U.K.'s regional
distribution businesses that would be effective for the five-year
period beginning April 1, 2000. Under the draft price proposals,
the distribution rates for Yorkshire would be reduced 15% to 20%
from current rates. Yorkshire filed comments on September 17, 1999
with OFGEM expressing various concerns with the analysis used by
OFGEM. Yorkshire also commented that the methodology used failed
to justify the magnitude of the price cuts proposed and suggested
a more suitable methodology.
On October 8, 1999, OFGEM issued updated draft price proposals
for Yorkshire's electric distribution business. The updated
proposal would require Yorkshire to reduce distribution rates 15%
and transfer 8% of costs to Yorkshire's electricity supply
business, an overall reduction in distribution prices of 23%.
Also on October 8, 1999, OFGEM issued draft price proposals for
Yorkshire's electric supply business. Under the proposals, a
supply price cap for certain domestic U.K. customers is retained
from April 2000 through March 2002. For Yorkshire, these proposals
would result in a price reduction of approximately 10.7% on the
standard domestic tariff commencing April 2000 and ending March
2001 and a nominal price freeze for the year commencing April 2001
and ending March 2002.
OFGEM is expected to publish final proposals on both the
distribution and the supply businesses at the end of November 1999.
Yorkshire management intends to take all available opportunities to
increase revenues and reduce costs to mitigate the impact of the
final OFGEM distribution and supply price reductions. Should
Yorkshire be unable to increase revenues and reduce costs in
amounts sufficient to offset the impact of the OFGEM distribution
and supply price reductions, AEP's equity earnings from its
investment in Yorkshire will be significantly reduced in comparison
to its current level of earnings.
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 (RTO) proposal whereby it will transfer the operation
and control of AEP's bulk transmission facilities to an RTO. 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 asking the
FERC 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 shared 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. On October 13, 1999 this appeal was dismissed by the
Oklahoma Supreme Court and the cooperative customers have since
asked the OCC to dismiss their appeal.
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. Hearings on the merger in
Texas began August 9, 1999 and concluded on August 10, 1999. As
the hearings began, settlements were reached with all but one of
the parties in the case. The settling parties are all wholesale
electric customers of CSW's Texas electric operating companies.
The settlements call for the withdrawal of their opposition to the
merger in all regulatory approval proceedings. On November 4, 1999
the Texas Commission, in its open meeting approved the application
on the pending merger and the stipulated settlement announced in
May.
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.
Ohio
On October 21, 1999, the Public Utilities Commission of Ohio
(PUCO) issued a decision stating that it will notify the FERC that
it will withdraw its opposition to the Company's pending merger
with CSW and will not seek conditions on the merger.
American Municipal Power - Ohio (AMP-Ohio) and AEP reached a
settlement addressing outstanding issues. As part of the
settlement AMP-Ohio agreed to withdraw as an intervenor in the
merger process. AMP-Ohio is the nonprofit wholesale power supplier
and service provider for most of Ohio's 84 community-owned public
power systems, two West Virginia public power systems and four
Pennsylvania public power systems.
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 review and investigation.
Completion of the Merger
As of September 30, 1999, AEP had deferred $37 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 allocable to the regulated electric operating
subsidiaries will be amortized over their recovery period,
generally 5-years, in accordance with state regulator orders. The
remainder of the deferred merger costs will be expensed upon
consummation of the merger.
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
second quarter of 2000, the Company is unable to predict the
outcome or the timing of the required regulatory proceedings.
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 a NRC
architect engineer design inspection. The NRC issued a
Confirmatory Action Letter in September 1997 requiring the Company
to address certain issues identified in the letter. 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.
The Company's plan to restart the Cook Plant units has Unit 2
scheduled to return to service in April 2000 and Unit 1 to return
to service in September 2000. The restart plan was developed based
upon 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 September 30, 1999, $82 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.
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 billing 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 a $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 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 was applied to retail
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
limit the Company's ability to increase base rates and freeze 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 restart outage. The pending Michigan
settlement limits deferrals to $50 million of 1999 jurisdictional
non-fuel nuclear operation and maintenance costs. Hearings have
been held to give the one intervenor who opposed the approval of
the settlement agreement the opportunity to voice its objections.
The settlement agreement is pending before the MPSC.
Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as a current period operation and maintenance expense in
1999 and 2000. Through September 30, 1999, $280 million has been
spent, of which $196 million was incurred in 1999. Pursuant to the
Indiana settlement agreement $112.5 million of incremental
operation and maintenance costs were deferred for the nine months
ended September 30, 1999. The Indiana jurisdiction deferral is
limited to up to $150 million of incremental restart costs incurred
in 1999. The amortization of such costs through September 30, 1999
was $22.5 million. At September 30, 1999, the unamortized balance
of incremental restart related operation and maintenance costs was
$90 million and was included in regulatory assets. Also deferred
as a regulatory asset at September 30, 1999 was $148 million of
replacement energy fuel 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.
Restructuring Legislation
Virginia
In March 1999 a 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 law also provides an opportunity for recovery of just and
reasonable net stranded generation 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 depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.
Management has concluded that as of September 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 and the wires charge
should enable the Company to determine its ability to recover
stranded costs, a requirement to discontinue application of SFAS
71.
When the capped rates and the wires charge are established in
Virginia, the application of SFAS 71 will be discontinued for the
Virginia retail jurisdiction portion of the Company's 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 capped rates and wire charges approved by the
Virginia SCC under the 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, wires charges and other
pertinent information, it is not possible at this time to determine
if any generation related assets are impaired in accordance with
SFAS 121 and if generation related regulatory assets will be
recovered. The amount of regulatory assets recorded on the books
applicable to the Company's Virginia generating business at
September 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 and/or
tangible generating 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 and other transition costs 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 no later than the fourth
quarter of 2000.
Ohio
The Ohio Electric Restructuring Act of 1999 became law on
October 4, 1999. The law provides for customer choice of
electricity supplier, a residential rate reduction of 5% and a
freezing of the unbundled generation base rates and a freezing of
fuel rates beginning on January 1, 2001. The law 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 including any
unrecovered deferred fuel costs, stranded plant and mining costs
and other transition costs.
Retail electric services that will be competitive are defined
in the law as electric generation service, aggregation service, and
power marketing and brokering. Under the legislation the PUCO is
granted broad oversight responsibility and is required by the law
to promulgate rules for competitive retail electric generation
service. The law also gives the PUCO authority to approve a
transition plan for each electric utility company.
The law provides Ohio electric utilities with an opportunity
to recover PUCO approved allowable transition costs through
unbundled frozen generation rates paid through December 31, 2005 by
customers who do not switch generation suppliers and through a
wires charge for customers who switch generation suppliers.
Transition costs can include regulatory assets, impairments of
generating assets and other stranded costs, employee severance and
retraining costs, consumer education costs and other costs.
Recovery of transition costs can, under certain circumstances,
extend beyond the five-year frozen rate 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 law also provides that the property tax assessment
percentage on electric generation property be lowered from 100% to
25% of value effective January 1, 2001. Electric utilities will
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
tax 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. The gross receipts tax is
paid at the beginning of the tax year, deferred as a prepaid
expense and amortized to expense during the tax year pursuant to
the tax laws whereby the payment of the tax results in the
privilege to conduct business in the year following the payment of
the tax. The change in the tax law to impose an excise tax based
on kilowatt-hours sold to Ohio customers commencing before the
expiration of the gross receipts tax privilege period will result
in a 12 month period when electric utilities are recording as an
expense both the gross receipts tax and the excise tax. Management
intends to seek recovery of the overlap of the gross receipts and
excise taxes in the Ohio transition plan filing.
As discussed in Note 3, "Effects of Regulation and Phase-In
Plans," of the Notes to Consolidated Financial Statements in the
1998 Annual Report, the Company defers as regulatory assets and
liabilities certain expenses and revenues consistent with the
regulatory process in accordance with SFAS 71. Management has
concluded that as of September 30, 1999 the requirements to apply
SFAS 71 continue to be met since the Company's rates for generation
will continue to be cost-based regulated until the establishment of
unbundled frozen generation rates and a wires charge as provided in
the law. The establishment of unbundled frozen generation rates
and the wires charge should enable the Company to determine its
ability to recover transition costs including regulatory assets and
other stranded costs, a requirement to discontinue application of
SFAS 71.
When unbundled generation rates and the wires charge are
established, the application of SFAS 71 will be discontinued for
the Ohio retail jurisdiction portion of the generation business.
At that time the Company will have to write-off its Ohio
jurisdictional generation-related regulatory assets to the extent
that they cannot be recovered under the unbundled frozen generation
rates and distribution wires charges approved by the PUCO under the
provisions of the restructuring law and record any asset
impairments in accordance with SFAS 121. An impairment loss would
be recorded to the extent that the cost of generation 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 an unbundled frozen generation rate, the
wires charge and other pertinent information, it is not possible at
this time to determine if any of the Company's generating assets
are impaired in accordance with SFAS 121. The amount of regulatory
assets recorded on the books at September 30, 1999 applicable to
the Ohio retail jurisdictional generating business is $638 million
before related tax effects. Due to the planned closing of
affiliated mines including the Meigs mine, and other anticipated
events, generation-related regulatory assets as of December 31,
2000 allocable to the Ohio retail jurisdiction are estimated to
exceed $800 million, before federal income tax effects. Recovery
of these regulatory assets will be sought as a part of the
Company's Ohio transition plan filing.
An estimated determination of whether the Company will
experience any asset impairment loss regarding its Ohio retail
jurisdictional generating assets and any loss from a possible
inability to recover Ohio generation related regulatory assets and
other transition costs cannot be made until such time as the
unbundled frozen generation rates and the wires charge are
determined through the regulatory process. Management will seek
full recovery of generation-related regulatory assets, any stranded
costs and other transition costs in its transition plan filing.
The PUCO is required to complete its regulatory process and issue
a transition order establishing the transition rates and wires
charges by no later than October 31, 2000. Should the PUCO fail to
approve transition rates and wires charges that are sufficient to
recover the Company's generation-related regulatory assets, any
other stranded costs and transition costs, it could have a material
adverse effect on results of operations, cash flows and financial
condition.
COLI 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
September 30, 1999 would reduce earnings by approximately $317
million (including interest). The Company has made no provision
for any possible earnings impact from this matter.
The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 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. A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
<PAGE>
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 Company's generating plants are
located. A number of utilities, including the Company, filed
petitions seeking a review of the final rules in the U.S. Court of
Appeals for the District of Columbia Circuit (Appeals Court). The
matter is currently being litigated.
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 that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules. The AEP System companies with generating plants, as well as
other utility companies, 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 originally 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.
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 where generation is being deregulated
unbundled generation transition rates, wires charges and the future
market price of electricity, they will have an adverse effect on
future results of operations, cash flows and possibly financial
condition.
<PAGE>
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Muskingum River, Mitchell,
Philip Sporn, Tanners Creek and Cardinal plants over the course of
the past 25 years to extend unit operating lives or to increase
unit generating capacity without a preconstruction permit in
violation of the Clean Air Act. Federal EPA also issued a Notice
of Violation to the Company alleging violations of the New Source
Review and New Source Performance Standard provisions of the Clean
Air Act at these same plants as well as Conesville Plant. A number
of unaffiliated utilities also received Notices of Violation,
complaints or administrative orders including a Notice of Violation
issued to The Cincinnati Gas & Electric Company for Beckjord Plant
alleging violations of the New Source Review provisions of the
Clean Air Act. Columbus Southern Power Company owns a partial
interest in Unit 6 of Beckjord Plant.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act. Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Philip Sporn Plant, Kammer Plant,
Mitchell Plant, Muskingum River Plant, Gavin Plant, Cardinal Plant,
Clinch River Plant, Kanawha River Plant, Tanners Creek Plant, Amos
Plant and Big Sandy Plant. The State of New York also threatened
to sue five unaffiliated utilities. In addition, the State of New
York indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates, and where states are deregulating generation, approved
unbundled transition generation rates, wires charges and future
market prices for energy.
Market Risks
The Company has certain market risks inherent in its business
activities from changes in electricity commodity prices, foreign
currency exchange rates and interest rates. Market risk represents
the risk of loss that may impact the Company due to adverse changes
in commodity market prices, foreign currency exchange rates and
interest rates.
The Company's exposure to market risk from the trading of
electricity, natural gas and related financial derivative
instruments has not changed materially since December 31, 1998.
There have been no material changes to the Company's exposure
to fluctuation 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 September 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 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 and has
been meeting with key vendors in this connection.
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. NERC has classified AEP as
a "Y2K Ready" organization with respect to its electric systems.
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 also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions. The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems. 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.
Except for AEP's Louisiana gas operations and CitiPower, AEP
has completed the process of modifying, replacing or retiring and
testing its mission critical and high priority digital-based
systems with problems processing dates in the Year 2000.
The mission critical systems for the Louisiana gas operations
are expected to be ready by December 10, 1999 and the mission
critical systems for CitiPower are expected to be ready by November
30, 1999.
The Company has upgraded its meteorological reporting system
used at the Donald C. Cook Nuclear Plant, a mission critical IT
system, for Y2K readiness. It was originally anticipated that the
upgrade was to have been completed by December 15, 1999.
Costs to Address the Company's Y2K Issues - Through September
30, 1999, the Company has spent $41 million on the Y2K project and
estimates spending an additional $7 million to $15 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 ready is not expected to have a
material impact on the Company's results of operations, cash flows
or financial condition.
Risks of the Company's 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 system which
may expose it to customer claims for service interruptions and/or
power quality problems resulting from Y2K problems. Such claims
differ from claims under the US legal and regulatory system.
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 could 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 has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities. These contingency plans will be refined 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 Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $57,235 $59,262 $161,674 $167,596
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 28,556 27,953 68,983 71,718
Rent - Rockport Plant Unit 2 . . . . . 17,071 17,071 51,212 51,212
Other Operation. . . . . . . . . . . . 2,447 2,174 7,909 7,547
Maintenance. . . . . . . . . . . . . . 1,457 2,703 8,208 9,110
Depreciation . . . . . . . . . . . . . 5,459 5,405 16,382 16,229
Taxes Other Than Federal Income Taxes. 1,398 882 3,890 2,759
Federal Income Tax Expense (Credit). . (74) 845 807 2,562
TOTAL OPERATING EXPENSES . . . 56,314 57,033 157,391 161,137
OPERATING INCOME . . . . . . . . . . . . 921 2,229 4,283 6,459
NONOPERATING INCOME. . . . . . . . . . . 885 837 2,630 2,457
INCOME BEFORE INTEREST CHARGES . . . . . 1,806 3,066 6,913 8,916
INTEREST CHARGES . . . . . . . . . . . . 848 903 2,119 2,494
NET INCOME . . . . . . . . . . . . . . . $ 958 $ 2,163 $ 4,794 $ 6,422
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $4,460 $2,435 $2,770 $2,528
NET INCOME . . . . . . . . . . . . . . . 958 2,163 4,794 6,422
CASH DIVIDENDS DECLARED. . . . . . . . . 2,073 2,176 4,219 6,528
BALANCE AT END OF PERIOD . . . . . . . . $3,345 $2,422 $3,345 $2,422
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>
September 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production. . . . . . . . . . . . . . . . . . . . . . . . $627,950 $630,260
General . . . . . . . . . . . . . . . . . . . . . . . . . 1,941 2,009
Construction Work in Progress . . . . . . . . . . . . . . 7,524 4,191
Total Electric Utility Plant. . . . . . . . . . . 637,415 636,460
Accumulated Depreciation. . . . . . . . . . . . . . . . . 289,255 277,855
NET ELECTRIC UTILITY PLANT. . . . . . . . . . . . 348,160 358,605
CURRENT ASSETS:
Cash and Cash Equivalents . . . . . . . . . . . . . . . . 1,988 232
Accounts Receivable . . . . . . . . . . . . . . . . . . . 22,122 22,894
Fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . 19,174 11,308
Materials and Supplies. . . . . . . . . . . . . . . . . . 3,920 3,900
Prepayments . . . . . . . . . . . . . . . . . . . . . . . 33 267
TOTAL CURRENT ASSETS. . . . . . . . . . . . . . . 47,237 38,601
REGULATORY ASSETS . . . . . . . . . . . . . . . . . . . . . 5,804 5,984
DEFERRED CHARGES. . . . . . . . . . . . . . . . . . . . . . 1,741 702
TOTAL . . . . . . . . . . . . . . . . . . . . . $402,942 $403,892
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 30, December 31,
1999 1998
(in thousands)
CAPITALIZATION AND LIABILITIES
<S> <C> <C>
CAPITALIZATION:
Common Stock - Par Value $1,000:
Authorized and Outstanding - 1,000 Shares . . . . . . . $ 1,000 $ 1,000
Paid-in Capital . . . . . . . . . . . . . . . . . . . . . 29,235 35,235
Retained Earnings . . . . . . . . . . . . . . . . . . . . 3,345 2,770
Total Common Shareholder's Equity . . . . . . . . 33,580 39,005
Long-term Debt. . . . . . . . . . . . . . . . . . . . . . - 44,792
TOTAL CAPITALIZATION. . . . . . . . . . . . . . . 33,580 83,797
OTHER NONCURRENT LIABILITIES. . . . . . . . . . . . . . . . 653 896
CURRENT LIABILITIES:
Long-term Debt Due Within One Year. . . . . . . . . . . . 44,798 -
Short-term Debt - Notes Payable . . . . . . . . . . . . . 13,825 24,450
Accounts Payable:
General . . . . . . . . . . . . . . . . . . . . . . . . 5,209 6,419
Affiliated Companies. . . . . . . . . . . . . . . . . . 14,277 6,177
Taxes Accrued . . . . . . . . . . . . . . . . . . . . . . 6,146 3,227
Rent Accrued - Rockport Plant Unit 2. . . . . . . . . . . 23,427 4,963
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 3,775 6,023
TOTAL CURRENT LIABILITIES . . . . . . . . . . . . 111,457 51,259
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2 . . . . . . . . . . . . . . . . . . 129,152 133,330
REGULATORY LIABILITIES:
Deferred Investment Tax Credits . . . . . . . . . . . . . 64,046 66,562
Deferred Amounts Due to Customers for Income Tax. . . . . 26,910 28,644
TOTAL REGULATORY LIABILITIES. . . . . . . . . . . 90,956 95,206
DEFERRED INCOME TAXES . . . . . . . . . . . . . . . . . . . 37,144 39,404
TOTAL . . . . . . . . . . . . . . . . . . . . . $402,942 $403,892
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
AEP GENERATING COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 4,794 $ 6,422
Adjustments for Noncash Items:
Depreciation . . . . . . . . . . . . . . . . . . . . . . 16,382 16,229
Deferred Federal Income Taxes. . . . . . . . . . . . . . (3,994) 3,975
Deferred Investment Tax Credits. . . . . . . . . . . . . (2,516) (2,522)
Amortization of Deferred Gain on Sale
and Leaseback - Rockport Plant Unit 2. . . . . . . . . (4,178) (4,178)
Deferred Property Taxes. . . . . . . . . . . . . . . . . (827) (794)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable. . . . . . . . . . . . . . . . . . . 772 (1,964)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (7,886) (1,870)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 6,890 3,522
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . 2,919 1,331
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (2,549) 1,968
Net Cash Flows From Operating Activities . . . . . . 28,271 40,583
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (5,671) (4,829)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . - 2,254
Net Cash Flows Used For Investing Activities . . . . (5,671) (2,575)
FINANCING ACTIVITIES:
Return of Capital to Parent Company. . . . . . . . . . . . (6,000) (3,000)
Retirement of Long-term Debt . . . . . . . . . . . . . . . - (25,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . (10,625) (3,575)
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (4,219) (6,528)
Net Cash Flows Used For Financing Activities . . . . (20,844) (38,103)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 1,756 (95)
Cash and Cash Equivalents at Beginning of Period . . . . . . 232 237
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,988 $ 142
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $1,889,000 and
$2,508,000 and for income taxes was $4,458,000 and $(1,188,000) in 1999 and 1998,
respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
AEP GENERATING COMPANY
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 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 normal recurring accruals and adjustments which are
necessary for a fair presentation of the results of operations for interim
periods.
2. FINANCING ACTIVITIES
Under the terms of installment purchase contracts, the Company is
required to pay the City of Rockport amounts sufficient to enable the payment
of interest and principal on pollution control revenue bonds issued to
finance the construction costs of pollution control facilities at the
Rockport Plant. On the Series 1995 A and B bonds the principal is payable at
maturity (July 1, 2025) or on the demand of the bondholders. The Company has
agreements that provide for brokers to remarket bonds tendered. In the event
the bonds cannot be remarketed, the Company has a standby bond purchase
agreement with a bank that provides for the bank to purchase any bonds not
remarketed. The purchase agreement expires in 2000. Therefore, the
installment purchase contracts have been classified as due within one year.
<PAGE>
<PAGE>
AEP GENERATING COMPANY
MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS
THIRD QUARTER 1999 vs. THIRD 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.
Net income decreased $1.2 million or 56% for the third quarter and $1.6
million or 25% for the year-to-date period as a result of the return of
capital to the parent company in 1998, February 1999 and May 1999 and the
reduction of revenues under the long-term power agreement.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $(2.0) (3) $(5.9) (4)
Fuel Expense. . . . . . . . 0.6 2 (2.7) (4)
Other Operation Expense . . 0.3 13 0.4 5
Maintenance Expense . . . . (1.2) (46) (0.9) (10)
Taxes Other Than Federal
Income Taxes . . . . . . . 0.5 59 1.1 41
Federal Income Taxes. . . . (0.9) (109) (1.8) (69)
Interest Charges. . . . . . (0.1) (6) (0.4) (15)
The decrease in operating revenues for the third quarter results from the
recovery through the unit power agreements of less return on common equity
reflecting the return of capital and less return on other capital reflecting
lower interest charges due to the retirement of debt. In the year-to-date
period, operating revenues declined reflecting the lower returns on common
equity and other capital and a reduction in recoverable operating expenses.
Fuel expense increased in the third quarter due to increases in
generation and average cost of fuel. The increase in generation is
attributable to an increase in the availability of the Rockport Plant units.
The rise in the cost of fuel results from fluctuations in the market price of
coal. In the year-to-date period a 6% reduction in generation, due to
planned maintenance outages in the first and second quarters of 1999 at both
units, reduced fuel expense.
The increase in other operation expense in both the quarter and
year-to-date periods is primarily due to the effect of unfavorable accrual
adjustments for a FERC operating assessment and allocated employee benefits.
Maintenance expense decreased due to a decline in maintenance repair and
staff expenditures reflecting the effect of staffing reductions.
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 completion 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 amortization of deferred taxes
in excess of the statutory tax rate.
The decline in interest charges in the year-to-date period was primarily
due to a reduction in outstanding long-term debt balances reflecting the
redemption of $25 million in March 1998 of pollution control revenue bonds.
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $441,435 $474,476 $1,242,903 $1,292,922
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 108,701 113,059 331,933 322,459
Purchased Power. . . . . . . . . . . . 93,041 101,779 204,680 258,275
Other Operation. . . . . . . . . . . . 59,090 73,988 182,001 191,297
Maintenance. . . . . . . . . . . . . . 26,240 30,691 93,112 97,519
Depreciation and Amortization. . . . . 37,700 36,059 111,475 107,252
Taxes Other Than Federal Income Taxes. 29,201 29,003 89,242 89,181
Federal Income Taxes . . . . . . . . . 21,153 18,946 49,445 45,547
TOTAL OPERATING EXPENSES . . . 375,126 403,525 1,061,888 1,111,530
OPERATING INCOME . . . . . . . . . . . . 66,309 70,951 181,015 181,392
NONOPERATING INCOME (LOSS) . . . . . . . 1,925 (5,664) 1,152 (4,490)
INCOME BEFORE INTEREST CHARGES . . . . . 68,234 65,287 182,167 176,902
INTEREST CHARGES . . . . . . . . . . . . 32,573 31,841 96,209 95,133
NET INCOME . . . . . . . . . . . . . . . 35,661 33,446 85,958 81,769
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 667 675 2,015 1,822
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 34,994 $ 32,771 $ 83,943 $ 79,947
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $167,714 $195,262 $179,461 $207,544
NET INCOME . . . . . . . . . . . . . . . 35,661 33,446 85,958 81,769
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 30,348 29,729 91,044 89,187
Cumulative Preferred Stock . . . . . 558 567 1,690 1,499
Capital Stock Expense. . . . . . . . . 109 108 325 323
BALANCE AT END OF PERIOD . . . . . . . . $172,360 $198,304 $172,360 $198,304
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>
September 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,007,970 $1,979,180
Transmission . . . . . . . . . . . . . . . . . . . . 1,139,940 1,118,726
Distribution . . . . . . . . . . . . . . . . . . . . 1,686,801 1,641,523
General. . . . . . . . . . . . . . . . . . . . . . . 240,726 228,464
Construction Work in Progress. . . . . . . . . . . . 123,378 119,466
Total Electric Utility Plant . . . . . . . . 5,198,815 5,087,359
Accumulated Depreciation and Amortization. . . . . . 2,061,813 1,984,856
NET ELECTRIC UTILITY PLANT . . . . . . . . . 3,137,002 3,102,503
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 132,612 111,020
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 30,850 7,755
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 111,847 122,746
Affiliated Companies . . . . . . . . . . . . . . . 20,854 35,802
Miscellaneous. . . . . . . . . . . . . . . . . . . 13,400 8,572
Allowance for Uncollectible Accounts . . . . . . . (2,981) (2,234)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 56,387 49,826
Materials and Supplies . . . . . . . . . . . . . . . 62,256 60,440
Accrued Utility Revenues . . . . . . . . . . . . . . 40,576 45,985
Energy Marketing and Trading Contracts . . . . . . . 95,526 22,436
Prepayments. . . . . . . . . . . . . . . . . . . . . 9,665 8,151
TOTAL CURRENT ASSETS . . . . . . . . . . . . 438,380 359,479
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 417,551 433,516
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 27,805 40,520
TOTAL. . . . . . . . . . . . . . . . . . . $4,153,350 $4,047,038
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 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. . . . . . . . . . . . . . . . . . . 689,099 663,633
Retained Earnings. . . . . . . . . . . . . . . . . . 172,360 179,461
Total Common Shareholder's Equity. . . . . . 1,121,917 1,103,552
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 18,575 19,359
Subject to Mandatory Redemption. . . . . . . . . . 22,310 22,310
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,439,573 1,472,451
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,602,375 2,617,672
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 133,558 120,281
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 176,005 80,004
Short-term Debt. . . . . . . . . . . . . . . . . . . 119,380 76,400
Accounts Payable - General . . . . . . . . . . . . . 48,736 60,569
Accounts Payable - Affiliated Companies. . . . . . . 34,564 50,313
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 33,944 35,719
Customer Deposits. . . . . . . . . . . . . . . . . . 12,831 14,123
Interest Accrued . . . . . . . . . . . . . . . . . . 30,245 19,990
Revenue Refunds Accrued. . . . . . . . . . . . . . . - 95,267
Energy Marketing and Trading Contracts . . . . . . . 91,941 24,076
Other. . . . . . . . . . . . . . . . . . . . . . . . 67,527 78,808
TOTAL CURRENT LIABILITIES. . . . . . . . . . 615,173 535,269
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 648,203 643,711
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 58,715 62,231
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 95,326 67,874
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . . $4,153,350 $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>
Nine Months Ended
September 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 85,958 $ 81,769
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 112,264 108,158
Deferred Federal Income Taxes. . . . . . . . . . . . . . 10,947 (1,452)
Deferred Investment Tax Credits. . . . . . . . . . . . . (3,516) (3,548)
Provision for Rate Refunds . . . . . . . . . . . . . . . 5,139 9,342
Deferred Power Supply Costs (net). . . . . . . . . . . . 27,715 25,137
Amortization of Deferred Property Taxes. . . . . . . . . 13,302 12,940
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 21,766 3,840
Fuel, Materials and Supplies . . . . . . . . . . . . . . (8,377) (7,025)
Accrued Utility Revenues . . . . . . . . . . . . . . . . 5,409 10,578
Accounts Payable . . . . . . . . . . . . . . . . . . . . (27,582) (16,191)
Revenue Refunds Accrued. . . . . . . . . . . . . . . . . (95,267) 39,107
Payment of Disputed Tax and Interest Related to COLI . . . (4,124) (68,316)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (22,882) 24,056
Net Cash Flows From Operating Activities . . . . . . 120,752 218,395
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (134,645) (138,297)
Proceeds from Sale of Property . . . . . . . . . . . . . . 274 914
Net Cash Flows Used For Investing Activities . . . . (134,371) (137,383)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . 25,000 25,000
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 148,751 193,431
Change in Short-term Debt (net). . . . . . . . . . . . . . 42,980 (68,325)
Retirement of Cumulative Preferred Stock . . . . . . . . . (587) (229)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (86,687) (138,472)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (91,044) (89,187)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,699) (1,710)
Net Cash Flows From (Used For) Financing Activities. 36,714 (79,492)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 23,095 1,520
Cash and Cash Equivalents at Beginning of Period . . . . . . 7,755 6,947
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 30,850 $ 8,467
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $83,069,000 and $83,359,000
and for income taxes was $33,996,000 and $38,378,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $12,132,000 and $16,909,000 in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
APPALACHIAN POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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 normal recurring accruals
and adjustments which are necessary for a fair presentation of
the results of operations for interim periods.
2. 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 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 (Virginia
SCC) that an effective competitive market exists, on January
1, 2004.
The law also provides an opportunity for recovery of just
and reasonable net stranded generation 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 depart the
incumbent utility in favor of an alternative supplier prior to
the termination of the rate cap. The law provides for the
establishment of capped rates prior to January 1, 2001 and the
establishment of a wires charge by the fourth quarter of 2001.
Management has concluded that as of September 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 and the wires charge should enable the Company to
determine its ability to recover stranded costs, a requirement
to discontinue application of SFAS 71.
<PAGE>
When the capped rates and the wires charge are established
in Virginia, the application of SFAS 71 will be discontinued
for the Virginia retail jurisdiction portion of the Company's
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 capped rates and
wire charges approved by the Virginia SCC under the 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, wires charges and other pertinent
information, it is not possible at this time to determine if
any generation related assets are impaired in accordance with
SFAS 121 and if generation related regulatory assets will be
recovered. The amount of regulatory assets recorded on the
books applicable to the Company's Virginia retail generating
business at September 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
and/or tangible generating assets, it could have a material
adverse impact on results of operations and cash flows. 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 and
other transition costs cannot be made until such time as the
transition capped rates and the wires charge are determined
under the law; which is not expected to occur before the fourth
quarter of 2000.
3. RATE MATTER
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 transmission service 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
FERC 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. The 1996 tariff incorporated transmission
rates which were the result of a settlement of a pending rate
case, but which were being collected subject to refund from
certain customers who opposed the settlement and continued to
litigate the reasonableness of AEP's transmission rates. On
July 29, 1999, the FERC issued an order in the litigated rate
case which would reduce AEP's rates for the affected customers
below the settlement rate. AEP and certain of the affected
customers have sought rehearing of the Commission's Order. The
Company made a provision in September 1999 for its share of the
refund which it anticipates would result if the Commission's
order is upheld including interest.
4. FINANCING ACTIVITIES
In May 1999 the Company issued $150 million of 6.60% senior
unsecured notes due 2009. During the first nine months of
1999, the Company reacquired the following first mortgage
bonds:
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
7.15 November 1, 2023 10,000
In September 1999, the Company received a $25 million cash
capital contribution from its parent which was credited to
paid-in capital.
In October 1999 the Company issued $50 million of 7.45%
senior unsecured notes due 2004.
During the first nine months of 1999, the Company increased
short-term debt by $43 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 those open
trading transactions within the AEP Power Pool's marketing area
that are included in cost of service on a settlement basis for
ratemaking purposes in the Company's non-Virginia
jurisdictions. A Virginia jurisdiction net mark-to-market pre-tax gain
of $1.4 million as of September 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. Open contracts outside of
AEP Power Pool's marketing area are marked-to-market in non-operating
income. 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 September
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.
The Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1998 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. A US Tax Court judge
recently decided in the Winn-Dixie Stores v. Commissioner case
that a corporate taxpayer's COLI interest deductions should be
disallowed. Notwithstanding the decision in Winn-Dixie,
management believes, and has been advised by outside counsel,
that it has a meritorious position and will vigorously pursue
its lawsuit. In the event the resolutions of this matter is
unfavorable, it will have a material adverse impact on results
of operations and cash flows.
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. 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). The matter
is currently being litigated.
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 that would impose
NOx reduction requirements on AEP System generating units which
are approximately equivalent to the reductions contemplated by
the NOx emission reduction final rules. The AEP System
companies with generating plants, as well as other utility
companies, 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 originally 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. 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 where generation
is being deregulated unbundled generation transition rates,
wires charges and the future market price of electricity, they
will have an adverse effect on future results of operations,
cash flows and possibly financial condition.
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the
request of Federal EPA, filed a complaint in the U.S. District
Court for the Southern District of Ohio that alleges the
Company made modifications to generating units at its Philip
Sporn Plant over the course of the past 25 years to extend unit
operating lives or to increase unit generating capacity without
a preconstruction permit in violation of the Clean Air Act.
Federal EPA also issued a Notice of Violation to the Company
alleging violations of the New Source Review and New Source
Performance Standard provisions of the Clean Air Act at this
plant. A number of unaffiliated utilities also received
Notices of Violation, complaints or administrative orders.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to
assess compliance with the New Source Review and New Source
Performance Standard provisions of the Clean Air Act. Under
these provisions of the Clean Air Act, if a plant undertakes
a major modification that directly results in an emissions
increase, permitting requirements under the New Source Review
program might be triggered and the plant may be required to
install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each
separately threatened to sue the Company under the Clean Air
Act to compel compliance with the New Source Review and New
Source Performance Standard provisions, alleging that
modifications occurred at certain units at the Company's Clinch
River Plant, Kanawha River Plant and Amos Plant. The State of
New York also threatened to sue five unaffiliated utilities.
In addition, the State of New York indicated that it may seek
to recover, under state law, compensation for alleged
environmental damage caused by excess emissions of sulfur
dioxide and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its
defense of this matter.
The Clean Air Act authorizes civil penalties of up to
$27,500 per day per violation at each generating unit ($25,000
per day prior to January 30, 1997). Civil penalties, if
ultimately imposed by the court, and the cost of any required
new pollution control equipment, if the court accepts all of
Federal EPA's contentions, could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that
may be required as well as any penalties imposed would
adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through regulated rates, and where generation is being
deregulated, approved unbundled transition generation rates,
wires charges and future market prices for energy.
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
THIRD QUARTER 1999 vs. THIRD QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income increased $2.2 million or 7% for the quarter and
$4.2 million or 5% for the year-to-date period primarily due to an
increase in sales to retail customers, a decline in operating
expenses and an increase in nonoperating income.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $(33.0) (7) $(50.0) (4)
Fuel Expense . . . . . . . (4.4) (4) 9.5 3
Purchased Power Expense. . (8.7) (9) (53.6) (21)
Other Operation Expense. . (14.9) (20) (9.3) (5)
Maintenance Expense. . . . (4.5) (15) (4.4) (5)
Federal Income Taxes . . . 2.2 12 3.9 9
Nonoperating Income (Loss) 7.6 134 5.6 126
Operating revenues decreased in both the third quarter and the
year-to-date periods due predominantly to a decline in wholesale
power sales margins and a revenue refund provision for wholesale
transmission service. Also contributing to the year-to-date
decrease in wholesale revenues was the termination of a contract
with several municipal customers effective July 1, 1998. These
decreases in wholesale power revenues and sales were partially
offset by increases in retail revenues from increased energy sales
to residential and commercial customers reflecting changes in the
weather. Colder winter weather and warmer summer temperatures led
to increased energy usage by residential and commercial customers.
The decrease in fuel expense for the quarter was due to a lower
average cost of fuel consumed and a reduction in the over recovery
of power supply costs in the West Virginia retail jurisdiction
through the operation of the West Virginia power supply cost
recovery mechanism, partially offset by increased fuel consumed for
additional generation. A decline in the market price of coal
accounted for the decrease in the average cost of fuel consumed.
Pursuant to the West Virginia retail jurisdictional power supply
cost recovery mechanism, over collections of power supply costs are
deferred for future refund to customers through a charge to fuel
expense. The over recovery of West Virginia non-fuel power supply
costs declined in the third quarter primarily due to the decreased
wholesale energy sales and margins on off-system sales included in
the West Virginia power supply cost recovery mechanism. Also in
the third quarter, fuel expense rose due to increased coal fired
generation to meet the increased retail demand resulting from the
warmer summer weather. In the year-to-date period, fuel expense
rose primarily due to increased coal fired generation to meet the
increased retail demand resulting from the first quarter's colder
winter weather and the warmer summer weather.
Purchased power expense decreased primarily as a result of
decreased purchases from the American Electric Power (AEP) System
Power Pool (AEP Power Pool), reflecting increased generation, and
a decline in capacity charges paid to 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 Company pays net capacity charges to the
AEP Power Pool because its peak demand is greater than its internal
generating capacity. The decrease in capacity charges was
attributed to a decrease in the Company's prior twelve month peak
demand relative to the total peak demand of all AEP Power Pool
members.
The reduction in other operation expense was mainly due to
cost savings from staff reductions and reduced accruals and
adjustments for incentive compensation and liability insurance.
Maintenance expense decreased in the third quarter mainly as
a result of an adjustment to the cost of materials used for power
plant repairs. In the year-to-date period, the decline in
maintenance expense was due to significant costs incurred in 1998
for repair and restoration of distribution service caused by two
severe snowstorms.
Federal income tax expense attributable to operations increased
primarily due to changes in certain book/tax differences accounted
for on a flow-through basis for rate-making purposes which were
partially offset in the quarter by a decrease in pre-tax operating
income.
The increase in nonoperating income is primarily due to the
effect of losses in 1998 on certain power marketing and trading
transactions. These transactions, which are marked-to-market,
represent non-regulated trading activities outside the Company's
traditional marketing area.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first nine months of 1999 were $147 million.
During the first nine 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 $87 million principal amount of
first mortgage bonds with interest rates from 7.15% to 8.43%.
Short-term debt increased by $43 million from year-end balances.
In September 1999, the Company received a $25 million cash capital
contribution from its parent which was credited to paid-in capital.
In October 1999 the Company issued $50 million of 7.45% senior
unsecured notes due 2004.
OTHER MATTERS
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 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 (Virginia SCC) that an effective competitive
market exists, on January 1, 2004.
The law also provides an opportunity for recovery of just and
reasonable net stranded generation 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 depart the incumbent utility in favor of
an alternative supplier prior to the termination of the rate cap.
The law provides for the establishment of capped rates prior to
January 1, 2001 and the establishment of a wires charge by the
fourth quarter of 2001.
Management has concluded that as of September 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 and the wires charge
should enable the Company to determine its ability to recover
stranded costs, a requirement to discontinue application of SFAS
71.
When the capped rates and the wires charge are established in
Virginia, the application of SFAS 71 will be discontinued for the
Virginia retail jurisdiction portion of the Company's 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 capped rates and wires charges approved by the
Virginia SCC under the 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, wires charges and other
pertinent information, it is not possible at this time to determine
if any generation related assets are impaired in accordance with
SFAS 121 and if generation related regulatory assets will be
recovered. The amount of regulatory assets recorded on the books
applicable to the Company's Virginia retail generating business at
September 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 and/or
tangible generating assets, it could have a material adverse impact
on results of operations and cash flows. 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 and other transition costs
cannot be made until such time as the transition capped rates and
the wires charge are determined under the law; which is not
expected to occur before the fourth quarter of 2000.
COLI 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
September 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.
The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 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. A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit. In the event the
resolutions of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
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. 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). The
matter is currently being litigated.
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 that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules. The AEP System companies with generating plants, as well as
other utility companies, 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 originally 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.
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 where generation is being deregulated
unbundled generation transition rates, wires charges and the future
market price of electricity, they will have an adverse effect on
future results of operations, cash flows and possibly financial
condition.
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Philip Sporn Plant over
the course of the past 25 years to extend unit operating lives or
to increase unit generating capacity without a preconstruction
permit in violation of the Clean Air Act. Federal EPA also issued
a Notice of Violation to the Company alleging violations of the New
Source Review and New Source Performance Standard provisions of the
Clean Air Act at this plant. A number of unaffiliated utilities
also received Notices of Violation, complaints or administrative
orders.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act. Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Clinch River Plant, Kanawha River
Plant and Amos Plant. The State of New York also threatened to sue
five unaffiliated utilities. In addition, the State of New York
indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates, and where generation is being deregulated, approved
unbundled transition generation rates, wires charges and future
market prices for energy.
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 September 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 and has been meeting with key vendors in this connection.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The AEP System, 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. NERC has classified the AEP System
as a "Y2K Ready" organization with respect to its electric systems.
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 also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions. The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems. 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 AEP System has completed the
process of modifying,
replacing, retiring and testing those mission critical and high
priority digital-based systems with problems processing dates in
the Year 2000.
Costs to Address the Company's Year 2000 Issues - Through September
30, 1999, the Company has spent $12 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 Company has benefited from the
sharing of costs with its affiliates in the AEP System. The cost
of becoming Y2K ready is not expected to have a material impact on
the Company's results of operations, cash flows or financial
condition.
Risks of the Company's 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 could 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 (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999. In addition, the Company has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities. These contingency plans will be refined 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 Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $368,946 $361,405 $949,432 $926,067
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 44,416 49,693 139,416 143,533
Purchased Power. . . . . . . . . . . . 90,272 80,210 204,718 186,829
Other Operation. . . . . . . . . . . . 46,829 59,478 139,312 150,843
Maintenance. . . . . . . . . . . . . . 16,693 13,932 49,013 43,128
Depreciation . . . . . . . . . . . . . 23,723 22,760 70,429 68,454
Taxes Other Than Federal Income Taxes. 31,558 29,295 92,687 86,921
Federal Income Taxes . . . . . . . . . 31,977 31,774 69,859 69,716
TOTAL OPERATING EXPENSES . . . 285,468 287,142 765,434 749,424
OPERATING INCOME . . . . . . . . . . . . 83,478 74,263 183,998 176,643
NONOPERATING LOSS. . . . . . . . . . . . (1,076) (2,337) (1,193) (1,109)
INCOME BEFORE INTEREST CHARGES . . . . . 82,402 71,926 182,805 175,534
INTEREST CHARGES . . . . . . . . . . . . 18,683 19,635 57,109 58,856
NET INCOME . . . . . . . . . . . . . . . 63,719 52,291 125,696 116,678
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 533 532 1,598 1,598
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 63,186 $ 51,759 $124,098 $115,080
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $203,354 $160,171 $186,441 $138,172
NET INCOME . . . . . . . . . . . . . . . 63,719 52,291 125,696 116,678
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 21,999 20,661 65,997 61,983
Cumulative Preferred Stock . . . . . 437 437 1,312 1,312
Capital Stock Expense. . . . . . . . . 95 95 286 286
BALANCE AT END OF PERIOD . . . . . . . . $244,542 $191,269 $244,542 $191,269
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>
September 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $1,537,121 $1,526,869
Transmission . . . . . . . . . . . . . . . . . . . . 349,376 339,934
Distribution . . . . . . . . . . . . . . . . . . . . 987,274 938,283
General. . . . . . . . . . . . . . . . . . . . . . . 139,565 130,002
Construction Work in Progress. . . . . . . . . . . . 106,534 118,477
Total Electric Utility Plant . . . . . . . . 3,119,870 3,053,565
Accumulated Depreciation . . . . . . . . . . . . . . 1,194,857 1,134,348
NET ELECTRIC UTILITY PLANT . . . . . . . . . 1,925,013 1,919,217
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 92,441 73,088
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 8,735 7,206
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 88,401 89,522
Affiliated Companies . . . . . . . . . . . . . . . 29,312 17,966
Miscellaneous. . . . . . . . . . . . . . . . . . . 8,732 11,989
Allowance for Uncollectible Accounts . . . . . . . (3,900) (2,598)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 21,762 22,140
Materials and Supplies . . . . . . . . . . . . . . . 39,918 33,263
Accrued Utility Revenues . . . . . . . . . . . . . . 45,203 40,127
Energy Marketing and Trading Contracts . . . . . . . 59,865 12,670
Prepayments and Other Current Assets . . . . . . . . 29,641 29,084
TOTAL CURRENT ASSETS . . . . . . . . . . . . 327,669 261,369
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 342,000 353,369
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 15,989 74,647
TOTAL. . . . . . . . . . . . . . . . . . . $2,703,112 $2,681,690
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
COLUMBUS SOUTHERN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 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. . . . . . . . . . . . . . . . . . . 572,777 572,492
Retained Earnings. . . . . . . . . . . . . . . . . . 244,542 186,441
Total Common Shareholder's Equity. . . . . . 858,345 799,959
Cumulative Preferred Stock - Subject to
Mandatory Redemption . . . . . . . . . . . . . . . 25,000 25,000
Long-term Debt . . . . . . . . . . . . . . . . . . . 924,412 959,786
TOTAL CAPITALIZATION . . . . . . . . . . . . 1,807,757 1,784,745
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 44,670 42,176
CURRENT LIABILITIES:
Short-term Debt. . . . . . . . . . . . . . . . . . . 28,200 52,500
Accounts Payable - General . . . . . . . . . . . . . 32,603 34,631
Accounts Payable - Affiliated Companies. . . . . . . 44,054 37,132
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 99,297 141,831
Interest Accrued . . . . . . . . . . . . . . . . . . 23,139 14,355
Energy Marketing and Trading Contracts . . . . . . . 57,608 13,682
Other. . . . . . . . . . . . . . . . . . . . . . . . 33,485 37,197
TOTAL CURRENT LIABILITIES. . . . . . . . . . 318,386 331,328
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 442,198 442,100
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 46,105 48,710
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 43,996 32,631
CONTINGENCIES (Note 6)
TOTAL. . . . . . . . . . . . . . . . . . . $2,703,112 $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>
Nine Months Ended
September 30,
1999 1998
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 125,696 $ 116,678
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . 70,727 68,617
Deferred Federal Income Taxes. . . . . . . . . . . . . . 7,854 12,398
Deferred Investment Tax Credits. . . . . . . . . . . . . (2,605) (2,662)
Deferred Fuel Costs (net). . . . . . . . . . . . . . . . 3,765 (10,169)
Amortization of Deferred Property Taxes. . . . . . . . . 51,680 48,775
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (5,666) (18,967)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (6,277) 879
Accrued Utility Revenues . . . . . . . . . . . . . . . . (5,076) 1,228
Accounts Payable . . . . . . . . . . . . . . . . . . . . 4,894 (19,234)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (42,534) (36,055)
Interest Accrued . . . . . . . . . . . . . . . . . . . . 8,784 10,029
Other Current Assets and Current Liabilities . . . . . . (7,538) 10,114
Payment of Disputed Tax and Interest Related to COLI . . . (2,239) (37,243)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 2,634 16,799
Net Cash Flows From Operating Activities . . . . . . 204,099 161,187
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (75,933) (84,178)
Proceeds from Sale of Property and Other . . . . . . . . . 495 2,546
Net Cash Flows Used For Investing Activities . . . . (75,438) (81,632)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . - 111,075
Change in Short-term Debt (net). . . . . . . . . . . . . . (24,300) (11,250)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (35,523) (122,206)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (65,997) (61,983)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,312) (1,312)
Net Cash Flows Used For Financing Activities . . . . (127,132) (85,676)
Net Increase (Decrease) in Cash and Cash Equivalents . . . . 1,529 (6,121)
Cash and Cash Equivalents at Beginning of Period . . . . . . 7,206 12,626
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 8,735 $ 6,505
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $45,659,000 and $46,014,000
and for income taxes was $41,866,000 and $27,254,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $5,573,000 and $10,029,000 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
SEPTEMBER 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 normal recurring
accruals and adjustments which are necessary for a fair presentation of
the results of operations for interim periods.
2. FINANCING ACTIVITIES
During the first nine months of 1999 the Company redeemed $20 million
of 7.45% first mortgage bonds due in 2024, $9 million of 7.60% first
mortgage bonds due in 2024 and $7 million of 7.75% first mortgage bonds
due 2023.
During the first nine months of 1999, the Company decreased
short-term debt by $24.3 million.
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
within the AEP Power Pool's marketing area that are included in cost of
service on a settlement basis for ratemaking purposes. Open contracts
outside of AEP Power Pool's marketing area are marked-to-market in
non-operating income. 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 transmission service 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 FERC 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. The 1996
tariff incorporated transmission rates which were the result of a
settlement of a pending rate case, but which were being collected subject
to refund from certain customers who opposed the settlement and continued
to litigate the reasonableness of AEP's transmission rates. On July 29,
1999, the FERC issued an order in the litigated rate case which would
reduce AEP's rates for the affected customers below the settlement rate.
AEP and certain of the affected customers have sought rehearing of the
Commission's Order. The Company made a provision in September 1999 for
its share of the refund which it anticipates would result if the
Commission's order is upheld including interest.
5. OHIO RESTRUCTURING LEGISLATION
The Ohio Electric Restructuring Act of 1999 became law on October 4,
1999. The law provides for customer choice of electricity supplier and
a residential rate reduction of 5% and a freezing of the unbundled
generation base rates and a freezing of fuel rates beginning on January
1, 2001. The law 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, stranded plant costs and other
transition costs.
Retail electric services that will be competitive are defined in the
law as electric generation service, aggregation service, and power
marketing and brokering. Under the legislation the PUCO is granted broad
oversight responsibility and is required by the law to promulgate rules
for competitive retail electric generation service. The law also gives
the PUCO authority to approve a transition plan for each electric utility
company.
The law provides Ohio electric utilities with an opportunity to
recover PUCO approved allowable transition costs through unbundled frozen
generation rates paid through December 31, 2005 by customers who do not
switch generation suppliers and through a wires charge for customers who
switch generation suppliers. Transition costs can include regulatory
assets, impairments of generating assets and other stranded costs,
employee severance and retraining costs, consumer education costs and
other costs. Recovery of transition costs can, under certain
circumstances, extend beyond the five-year frozen rate 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 law also provides that the property tax assessment percentage on
electric generation property be lowered from 100% to 25% of value
effective January 1, 2001. Electric utilities will 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 tax 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. The gross receipts tax
is paid at the beginning of the tax year, deferred as a prepaid expense
and amortized to expense during the tax year pursuant to the tax laws
whereby the payment of the tax results in the privilege to conduct
business in the year following the payment of the tax. The change in the
tax law to impose an excise tax based on kilowatt-hours sold to Ohio
customers commencing before the expiration of the gross receipts tax
privilege period will result in a 12 month period when electric utilities
are recording as an expense both the gross receipts tax and the excise
tax. Management intends to seek recovery of the overlap of the gross
receipts and excise taxes in the Ohio transition plan filing.
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 assets and
liabilities certain expenses and revenues consistent with the
regulatory process in
accordance with Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation." Management
has concluded that as of September 30, 1999 the requirements to apply
SFAS 71 continue to be met since the Company's rates for generation will
continue to be cost-based regulated until the establishment of unbundled
frozen generation rates and a wires charge as provided in the law. The
establishment of unbundled frozen generation rates and the wires charge
should enable the Company to determine its ability to recover transition
costs including regulatory assets and other stranded costs, a requirement
to discontinue application of SFAS 71.
When unbundled generation rates and the wires charge are established,
the application of SFAS 71 will be discontinued for the Ohio retail
jurisdiction portion of the generation business. At that time the
Company will have to write-off its Ohio jurisdictional generation-related
regulatory assets to the extent that they cannot be recovered under the
unbundled frozen generation rates and distribution wires charges approved
by the PUCO under the 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 generation 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 an unbundled frozen generation
rate, the wires charge and other pertinent information, it is not
possible at this time to determine if any of the Company's generating
assets are impaired in accordance with SFAS 121. The amount of
regulatory assets recorded on the books at September 30, 1999 applicable
to the Ohio retail jurisdictional generating business is $311 million
before related tax effects. Recovery of these regulatory assets will be
sought as a part of the Company's Ohio transition plan filing.
An estimated determination of whether the Company will experience any
asset impairment loss regarding its Ohio retail jurisdictional generating
assets and any loss from a possible inability to recover Ohio generation
related regulatory assets and other transition costs cannot be made until
such time as the unbundled frozen generation rates and the wires charge
are determined through the regulatory process. Management will seek full
recovery of generation-related regulatory assets, any stranded costs and
other transition costs in its transition plan filing. The PUCO is
required to complete its regulatory process and issue a transition order
establishing the transition rates and wires charges by no later than
October 31, 2000. Should the PUCO fail to approve transition rates and
wires charges that are sufficient to recover the Company's
generation-related regulatory assets, any other stranded costs and
transition costs, it could have a material adverse effect on results
of operations, cash flows and financial condition.
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 September 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.
The Company made payments of taxes and interest attributable to COLI
interest deductions for taxable years 1991-1998 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 United States (U.S.) District Court for the Southern
District of Ohio in March 1998. A US Tax Court judge recently decided
in the Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's
COLI interest deductions should be disallowed. Notwithstanding the
decision in Winn-Dixie, management believes, and has been advised by
outside counsel, that it has a meritorious position and will vigorously
pursue its lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results of
operations and cash flows.
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. 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). The matter is currently being litigated.
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 that would impose NOx reduction requirements on AEP System
generating units which are approximately equivalent to the reductions
contemplated by the NOx emission reduction final rules. The AEP System
companies with generating plants, as well as other utility companies,
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 originally 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. 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 PUCO approved unbundled generation
transition rates, wire charges and the future market price of
electricity, they will have an adverse effect on future results of
operations, cash flows and possibly financial condition.
Federal EPA Notice of Violation
On November 3, 1999, Federal EPA issued a Notice of Violation to the
Company alleging violations of the New Source Review and New Source
Performance Standard provisions of the Clean Air Act at its Conesville
Plant. A number of unaffiliated utilities also received Notices of
Violation or administrative orders including a Notice of Violation issued
to The Cincinnati Gas & Electric Company for Beckjord Plant alleging
violations of the New Source Review provisions of the Clean Air Act. The
Company owns a partial interest in Unit 6 at Beckjord Plant.
Federal EPA's Notice of Violation is based on an investigation by
Federal EPA to assess compliance with the New Source Review and New
Source Performance Standard provisions of the Clean Air Act. Under these
provisions of the Clean Air Act, if a plant undertakes a major
modification that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered and
the plant may be required to install additional pollution control
technology. This requirement does not apply to activities such as
routine maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and efficient
operation of the plant.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were exempted
from the New Source Review and New Source Performance Standard
requirements, and intends to vigorously pursue its defense of this
matter.
The Clean Air Act authorizes civil penalties of up to $27,500 per day
per violation at each generating unit ($25,000 per day prior to January
30, 1997). Civil penalties, if ultimately imposed, and the cost of any
required new pollution control equipment, if all of Federal EPA's
contentions are upheld, could be substantial.
In the event the Company does not prevail, any capital and operating
costs of additional pollution control equipment that may be required as
well as any penalties imposed would adversely affect future results of
operations, cash flows and possibly financial condition unless such costs
can be recovered through PUCO approved unbundled generation transition
rates, wires charges and the future market price for electricity.
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
THIRD QUARTER 1999 vs. THIRD QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
Net income increased $11.4 million or 22% for the third quarter and $9
million or 8% for the year-to-date period primarily due to increased sales to
retail customers reflecting customer growth and in the year-to-date period
colder winter weather.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $ 7.5 2 $ 23.4 3
Fuel Expense. . . . . . . . (5.3) (11) (4.1) (3)
Purchased Power Expense . . 10.1 13 17.9 10
Other Operation Expense . . (12.6) (21) (11.5) (8)
Maintenance Expense . . . . 2.8 20 5.9 14
Operating revenues increased in both the third quarter and the
year-to-date period due predominantly to increased retail sales.
The increase in retail revenues resulted from increased sales to
residential and commercial
customers reflecting growth in the number of customers and in the
year-to-date period colder winter weather. Revenues from wholesale customers
declined, due to a decline in wholesale margins, partially offsetting the
retail revenue gains.
The decrease in fuel expense was due to a decline in generation
reflecting a decrease in availability of certain generating units in 1999 due
to power plant maintenance outages.
The increase in purchased power expense in the third quarter was
primarily the result of increased purchases of electricity from the American
Electric Power (AEP) System Power Pool (AEP Power Pool) and unaffiliated
companies to replace unavailable generation and to meet the increase in
demand from retail customers. In the year-to-date period, increased capacity
charges from the AEP Power Pool were the primary reason for the increase in
purchased power expense. 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 Company pays net capacity charges to
the AEP Power Pool because its peak demand is greater than its internal
generating capacity. The increase in capacity charge was 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.
The reduction in other operation expense was mainly due to cost savings
from staffing reductions, a reduction in bad debt expense, reduced accruals
and adjustments for incentive compensation and liability insurance, and a
gain on the sale of excess emission allowances.
Maintenance expense increased due to tree trimming for overhead
distribution lines and scheduled power plant maintenance outages in 1999.
The cost of plant maintenance outages was mitigated by cost savings from
planned staffing reductions.
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $411,248 $412,908 $1,081,914 $1,089,647
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 51,908 51,014 135,831 133,768
Purchased Power. . . . . . . . . . . . 93,683 92,728 223,508 237,391
Other Operation. . . . . . . . . . . . 139,997 97,985 346,830 257,268
Maintenance. . . . . . . . . . . . . . 43,526 39,107 99,349 99,444
Depreciation and Amortization. . . . . 37,626 36,380 112,106 108,407
Taxes Other Than Federal Income Taxes. 12,356 16,514 48,641 49,011
Federal Income Taxes . . . . . . . . . 6,067 20,541 23,760 52,157
TOTAL OPERATING EXPENSES . . . 385,163 354,269 990,025 937,446
OPERATING INCOME . . . . . . . . . . . . 26,085 58,639 91,889 152,201
NONOPERATING INCOME (LOSS) . . . . . . . 2,407 (2,404) 5,698 191
INCOME BEFORE INTEREST CHARGES . . . . . 28,492 56,235 97,587 152,392
INTEREST CHARGES . . . . . . . . . . . . 20,408 17,544 59,688 51,421
NET INCOME . . . . . . . . . . . . . . . 8,084 38,691 37,899 100,971
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 1,218 1,208 3,647 3,627
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 6,866 $ 37,483 $ 34,252 $ 97,344
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $223,212 $279,943 $253,154 $278,814
NET INCOME . . . . . . . . . . . . . . . 8,084 38,691 37,899 100,971
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 28,664 29,366 85,992 88,098
Cumulative Preferred Stock . . . . . 1,182 1,183 3,546 3,550
Capital Stock Expense. . . . . . . . . 65 25 130 77
BALANCE AT END OF PERIOD . . . . . . . . $201,385 $288,060 $201,385 $288,060
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>
September 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,586,427 $2,565,041
Transmission . . . . . . . . . . . . . . . . . . . . 924,028 913,495
Distribution . . . . . . . . . . . . . . . . . . . . 791,768 768,888
General (including nuclear fuel) . . . . . . . . . . 233,394 228,013
Construction Work in Progress. . . . . . . . . . . . 183,358 156,411
Total Electric Utility Plant . . . . . . . . 4,718,975 4,631,848
Accumulated Depreciation and Amortization. . . . . . 2,175,163 2,081,355
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,543,812 2,550,493
NUCLEAR DECOMMISSIONING AND SPENT NUCLEAR FUEL
DISPOSAL TRUST FUNDS. . . . . . . . . . . . . . . . . 693,532 648,307
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 207,141 197,368
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 19,784 12,465
Accounts Receivable (net). . . . . . . . . . . . . . 131,878 130,746
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 25,551 20,857
Materials and Supplies . . . . . . . . . . . . . . . 83,515 78,009
Accrued Utility Revenues . . . . . . . . . . . . . . 43,045 37,277
Energy Marketing and Trading Contracts . . . . . . . 65,076 14,105
Prepayments. . . . . . . . . . . . . . . . . . . . . 6,403 4,848
TOTAL CURRENT ASSETS . . . . . . . . . . . . 375,252 298,307
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 566,226 421,475
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 17,602 32,573
TOTAL. . . . . . . . . . . . . . . . . . . $4,403,565 $4,148,523
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 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. . . . . . . . . . . . . . . . . . . 732,711 732,605
Retained Earnings. . . . . . . . . . . . . . . . . . 201,385 253,154
Total Common Shareholder's Equity. . . . . . 990,680 1,042,343
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 9,255 9,273
Subject to Mandatory Redemption. . . . . . . . . . 67,445 68,445
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,123,841 1,140,789
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,191,221 2,260,850
OTHER NONCURRENT LIABILITIES:
Nuclear Decommissioning. . . . . . . . . . . . . . . 488,931 445,934
Other. . . . . . . . . . . . . . . . . . . . . . . . 247,620 240,320
TOTAL OTHER NONCURRENT LIABILITIES . . . . . 736,551 686,254
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 133,000 35,000
Short-term Debt. . . . . . . . . . . . . . . . . . . 190,850 108,700
Accounts Payable - General . . . . . . . . . . . . . 50,019 53,187
Accounts Payable - Affiliated Companies. . . . . . . 10,808 37,647
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 30,510 35,161
Interest Accrued . . . . . . . . . . . . . . . . . . 17,808 15,279
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . 23,427 4,963
Obligations Under Capital Leases . . . . . . . . . . 11,047 9,667
Energy Marketing and Trading Contracts . . . . . . . 62,624 15,228
Other. . . . . . . . . . . . . . . . . . . . . . . . 88,700 67,102
TOTAL CURRENT LIABILITIES. . . . . . . . . . 618,793 381,934
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 603,133 559,288
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 124,085 129,779
DEFERRED GAIN ON SALE AND LEASEBACK -
ROCKPORT PLANT UNIT 2. . . . . . . . . . . . . . . . 85,932 88,712
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 43,850 41,706
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $4,403,565 $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>
Nine Months Ended
September 30,
1999 1998
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 37,899 $ 100,971
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 115,014 111,510
Amortization of Incremental Nuclear Refueling
Outage Expenses (net). . . . . . . . . . . . . . . . . 6,413 11,368
Under-recovery of Fuel and Purchased Power . . . . . . . (82,213) (42,676)
Deferred Nuclear Outage Costs (net). . . . . . . . . . . (90,000) -
Deferred Federal Income Taxes. . . . . . . . . . . . . . 57,254 11,226
Deferred Investment Tax Credits. . . . . . . . . . . . . (5,694) (5,727)
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (1,132) (33,328)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (10,200) (308)
Accrued Utility Revenues . . . . . . . . . . . . . . . . (5,768) (9,857)
Accounts Payable . . . . . . . . . . . . . . . . . . . . (30,007) 10,617
Rent Accrued - Rockport Plant Unit 2 . . . . . . . . . . 18,464 18,464
Payment of Disputed Taxes and Interest Related to COLI . . (3,228) (53,628)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 30,208 21,002
Net Cash Flows From Operating Activities . . . . . . 37,010 139,634
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (97,044) (98,218)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,904 4,154
Net Cash Flows Used For Investing Activities . . . . (95,140) (94,064)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 148,379 122,222
Retirement of Cumulative Preferred Stock . . . . . . . . . (1,042) (65)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (74,500) (55,000)
Change in Short-term Debt (net). . . . . . . . . . . . . . 82,150 (16,100)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (85,992) (88,098)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (3,546) (3,551)
Net Cash Flows From (Used For) Financing Activities. 65,449 (40,592)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 7,319 4,978
Cash and Cash Equivalents at Beginning of Period . . . . . . 12,465 5,860
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 19,784 $ 10,838
Supplemental Disclosure:
Cash paid (received) for interest net of capitalized amounts was $54,928,000 and
$49,041,000 and for income taxes was $(29,106,000) and $20,224,000 in 1999 and 1998,
respectively. Noncash acquisitions under capital leases were $9,005,000 and
$7,050,000 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
SEPTEMBER 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 normal recurring accruals
and adjustments which are necessary for a fair presentation of
the results of operations for interim periods.
2. FINANCING ACTIVITIES
In July 1999 the Company issued $150 million of 6.875%
senior unsecured notes due 2004. During the first nine months
of 1999, the Company reacquired the following first mortgage
bonds:
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
7.20 February 1, 2024 10,000
During the first nine months of 1999, the Company increased
short-term debt by $82 million.
The short-term debt limitation of the Company was increased
from $300 million to $500 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 within the American Electric Power (AEP) System
Power Pool's marketing area that are included in cost of
service on a settlement basis for ratemaking purposes. Open
contracts outside of AEP System Power Pool's marketing area are
marked-to-market in nonoperating income. 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 transmission services 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
FERC 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. The 1996 tariff incorporated transmission
rates which were the result of a settlement of a pending rate
case, but which were being collected subject to refund from
certain customers who opposed the settlement and continued to
litigate the reasonableness of AEP's transmission rates. On
July 29, 1999, the FERC issued an order in the litigated rate
case which would reduce AEP's rates for the affected customers
below the settlement rate. AEP and certain of the affected
customers have sought rehearing of the Commission's Order. The
Company made a provision in September 1999 for its share of the
refund which it anticipates would result if the Commission's
order is upheld including interest.
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 September
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.
<PAGE>
The Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1998 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. A US Tax Court judge
recently decided in the Winn-Dixie Stores v. Commissioner case
that a corporate taxpayer's COLI interest deductions should be
disallowed. Notwithstanding the decision in Winn-Dixie,
management believes, and has been advised by outside counsel,
that it has a meritorious position and will vigorously pursue
its lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations and cash flows.
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. 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). The matter
is currently being litigated.
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 that would impose
NOx reduction requirements on AEP System generating units which
are approximately equivalent to the reductions contemplated by
the NOx emission reduction final rules. The AEP System
companies with generating plants, as well as other utility
companies, 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 originally 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. 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 an adverse effect on future results
of operations, cash flows and possibly financial condition.
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the
request of Federal EPA, filed a complaint in the U.S. District
Court for the Southern District of Ohio that alleges the
Company made modifications to generating units at its Tanners
Creek Plant over the course of the past 25 years to extend unit
operating lives or to increase unit generating capacity without
a preconstruction permit in violation of the Clean Air Act.
Federal EPA also issued a Notice of Violation to the Company
alleging violations of the New Source Review and New Source
Performance Standard provisions of the Clean Air Act at this
plant. A number of unaffiliated utilities also received
Notices of Violation, complaints or administrative orders.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to
assess compliance with the New Source Review and New Source
Performance Standard provisions of the Clean Air Act. Under
these provisions of the Clean Air Act, if a plant undertakes
a major modification that directly results in an emissions
increase, permitting requirements under the New Source Review
program might be triggered and the plant may be required to
install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each
separately threatened to sue the Company under the Clean Air
Act to compel compliance with the New Source Review and New
Source Performance Standard provisions, alleging that
modifications occurred at certain units at the Company's
Tanners Creek Plant. The State of New York also threatened to
sue five unaffiliated utilities. In addition, the State of New
York indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its
defense of this matter.
The Clean Air Act authorizes civil penalties of up to
$27,500 per day per violation at each generating unit ($25,000
per day prior to January 30, 1997). Civil penalties, if
ultimately imposed by the court, and the cost of any required
new pollution control equipment, if the court accepts all of
Federal EPA's contentions, could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that
may be required as well as any penalties imposed would
adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through regulated rates and/or reflected in the future market
prices of electricity if generation is deregulated.
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.
The Company's plan to restart the Cook Plant units has Unit
2 scheduled to return to service in April 2000 and Unit 1 to
return to service in September 2000. The restart plan was
developed based upon 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 September 30,
1999, $82 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.
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 billing 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 a $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 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 was applied to retail 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 limit the Company's ability to
increase base rates and freeze 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 restart outage. The pending Michigan
settlement limits deferrals to $50 million of 1999
jurisdictional non-fuel nuclear operation and maintenance
costs. Hearings have been held to give the one intervenor who
opposed the approval of the settlement agreement the
opportunity to voice its objections. The settlement agreement
is pending before the MPSC.
Expenditures for the restart of the Cook units are
estimated to total approximately $574 million and will be
accounted for primarily as a current period operation and
maintenance expense in 1999 and 2000. Through September 30,
1999, $280 million has been spent, of which $196 million was
incurred in 1999. Pursuant to the Indiana settlement agreement
$112.5 million of incremental operation and maintenance costs
were deferred for the nine months ended September 30, 1999.
The Indiana jurisdiction deferral is limited to up to $150
million of incremental restart costs incurred in 1999. The
amortization of such costs through September 30, 1999 was $22.5
million. At September 30, 1999, the unamortized balance of
incremental restart related operation and maintenance costs was
$90 million and was included in regulatory assets. Also
deferred as a regulatory asset at September 30, 1999 was $148
million of replacement energy fuel 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 certain 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
THIRD QUARTER 1999 vs. THIRD QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income decreased $30.6 million or 79% for the quarter and
$63.1 million or 62% for the year-to-date period due primarily to
an increase in the cost of the extended Cook Nuclear Plant restart
outage.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues . . . . $ (1.6) - $ (7.7) (1)
Purchased Power Expense. . 1.0 1 (13.9) (6)
Other Operation Expense. . 41.9 43 89.6 35
Maintenance Expense. . . . 4.4 11 (0.1) -
Taxes Other Than Federal
Income Taxes. . . . . . . (4.2) (25) (0.4) -
Federal Income Taxes . . . (14.5) (70) (28.4) (54)
Nonoperating Income. . . . 4.8 200 5.5 N.M.
Interest Charges . . . . . 2.9 16 8.3 16
N.M. = Not Meaningful
Operating revenues declined as a decrease in wholesale revenues
was largely offset by an increase in retail revenues. The decrease
in wholesale revenues resulted from a decline in wholesale power
sales margins. Retail revenues rose due to increased sales of 7%
in the quarter and 5% in the year-to-date period. The retail sales
increase can be attributed to increased energy usage by residential
and commercial customers due to colder winter weather and warmer
summer temperatures. In the year-to-date period, the rise in
retail revenues from increased sales was mostly offset by the
effect of an Indiana settlement agreement that allowed amortization
of unrecovered fuel cost revenues over five years. 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.
<PAGE>
The decrease in purchased power expense in the year-to-date
period was due to a reduction in the average price of purchased
power as the Company was able to substitute lower cost purchases
from affiliates for more expensive power bought from unaffiliated
utilities.
Other operation and maintenance expense increased primarily as
a result of costs associated with the extended Cook Plant restart
outage including nuclear engineering and contract employee costs.
The decrease in taxes other than federal income taxes in the
third quarter is due primarily to a favorable accrual adjustment
for Indiana supplemental income tax to reflect a revised taxable
income estimate.
Federal income taxes attributable to operations decreased
significantly in both periods as a result of a decrease in pre-tax
operating income.
The increase in nonoperating income is primarily due to losses
on certain power marketing and trading transactions in 1998. These
transactions, which are marked-to-market, represent non-regulated
trading activities outside the AEP System Power Pool's traditional
marketing area.
Interest charges increased due to increased long-term and
short-term borrowing to fund the expenditures for the Cook Plant
restart effort.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the year-to-date period were $106 million.
During the first nine months of 1999 short-term debt
outstanding increased by $82 million. 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 nine months of 1999 the Company redeemed $75
million principal amount of first mortgage bonds with interest
rates from 6.55% to 7.20% and issued $150 million of 6.875% senior
unsecured notes due 2004.
<PAGE>
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 at least 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 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.
The Company's plan to restart the Cook Plant units has Unit 2
scheduled to return to service in April 2000 and Unit 1 to return
to service in September 2000. The restart plan was developed based
upon 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 September 30, 1999, $82 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.
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
billing 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
a $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 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 was applied to retail 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
limit the Company's ability to increase base rates and freeze 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 restart outage. The pending Michigan
settlement limits deferrals to $50 million of 1999 jurisdictional
non-fuel nuclear operation and maintenance costs. Hearings have
been held to give the one intervenor who opposed the approval of
the settlement agreement the opportunity to voice its objections.
The settlement agreement is pending before the MPSC.
Expenditures for the restart of the Cook units are estimated
to total approximately $574 million and will be accounted for
primarily as a current period operation and maintenance expense in
1999 and 2000. Through September 30, 1999, $280 million has been
spent, of which $196 million was incurred in 1999. Pursuant to the
Indiana settlement agreement $112.5 million of incremental
operation and maintenance costs were deferred for the nine months
ended September 30, 1999. The Indiana jurisdiction deferral is
limited to up to $150 million of incremental restart costs incurred
in 1999. The amortization of such costs through September 30, 1999
was $22.5 million. At September 30, 1999, the unamortized balance
of incremental restart related operation and maintenance costs was
$90 million and was included in regulatory assets. Also deferred
as a regulatory asset at September 30, 1999 was $148 million of
replacement energy fuel 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.
COLI 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
September 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.
The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 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. A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
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. 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). The
matter is currently being litigated.
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 that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules. The AEP System companies with generating plants, as well as
other utility companies, 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 originally 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.
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 an adverse
effect on future results of operations, cash flows and possibly
financial condition.
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Tanners Creek Plant over
the course of the past 25 years to extend unit operating lives or
to increase unit generating capacity without a preconstruction
permit in violation of the Clean Air Act. Federal EPA also issued
a Notice of Violation to the Company alleging violations of the New
Source Review and New Source Performance Standard provisions of the
Clean Air Act at this plant. A number of unaffiliated utilities
also received Notices of Violation, complaints or administrative
orders.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act. Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Tanners Creek Plant. The State of
New York also threatened to sue five unaffiliated utilities. In
addition, the State of New York indicated that it may seek to
recover, under state law, compensation for alleged environmental
damage caused by excess emissions of sulfur dioxide and nitrogen
oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through regulated
rates and/or reflected in the future market prices of electricity
if generation is deregulated.
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
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 September 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 and has been meeting with key vendors in this connection.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The AEP System, 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. NERC has classified the AEP System
as a "Y2K Ready" organization with respect to its electric systems.
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 also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions. The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems. 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 AEP System has completed the process of modifying,
replacing, retiring and testing those mission critical and high
priority digital-based systems with problems processing dates in
the Year 2000.
The Company has upgraded its meteorological reporting system
used at the Donald C. Cook Nuclear Plant, a mission critical IT
system, for Y2K readiness. It was originally anticipated that the
upgrade was to have been completed by December 15, 1999.
Costs to Address the Company's Year 2000 Issues - Through September
30, 1999, the Company has spent $7 million on the Y2K project and,
estimates spending an additional $1 million to $3 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 Company has benefited from the
sharing of costs with its affiliates in the AEP System. The cost
of becoming Y2K ready is not expected to have a material impact on
the Company's results of operations, cash flows or financial
condition.
Risks of the Company's 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 could 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 (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999. In addition, the Company has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities. These contingency plans will be refined 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 Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . . $94,939 $104,922 $271,911 $276,288
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . . 18,258 21,478 60,233 61,963
Purchased Power. . . . . . . . . . . . . 32,177 31,548 82,524 79,878
Other Operation. . . . . . . . . . . . . 10,607 13,647 34,726 36,633
Maintenance. . . . . . . . . . . . . . . 5,522 7,335 15,360 23,759
Depreciation and Amortization. . . . . . 7,356 7,068 21,833 20,956
Taxes Other Than Federal Income Taxes. . 2,967 2,668 8,183 7,420
Federal Income Taxes . . . . . . . . . . 3,808 4,627 9,215 7,406
TOTAL OPERATING EXPENSES. . . . . 80,695 88,371 232,074 238,015
OPERATING INCOME . . . . . . . . . . . . . 14,244 16,551 39,837 38,273
NONOPERATING INCOME (LOSS) . . . . . . . . 111 (902) (44) (1,066)
INCOME BEFORE INTEREST CHARGES . . . . . . 14,355 15,649 39,793 37,207
INTEREST CHARGES . . . . . . . . . . . . . 7,158 7,207 21,392 21,335
NET INCOME . . . . . . . . . . . . . . . . $ 7,197 $ 8,442 $ 18,401 $ 15,872
STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . . $67,770 $71,356 $71,452 $78,076
NET INCOME . . . . . . . . . . . . . . . . 7,197 8,442 18,401 15,872
CASH DIVIDENDS DECLARED. . . . . . . . . . 7,443 7,075 22,329 21,225
BALANCE AT END OF PERIOD . . . . . . . . . $67,524 $72,723 $67,524 $72,723
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>
September 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $ 267,680 $ 267,201
Transmission . . . . . . . . . . . . . . . . . . . . 342,366 326,989
Distribution . . . . . . . . . . . . . . . . . . . . 360,289 351,407
General. . . . . . . . . . . . . . . . . . . . . . . 66,934 68,038
Construction Work in Progress. . . . . . . . . . . . 28,194 30,076
Total Electric Utility Plant . . . . . . . . 1,065,463 1,043,711
Accumulated Depreciation and Amortization. . . . . . 334,057 315,546
NET ELECTRIC UTILITY PLANT . . . . . . . . . 731,406 728,165
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 17,048 12,078
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 1,065 1,935
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 17,702 23,295
Affiliated Companies . . . . . . . . . . . . . . . 8,945 8,797
Miscellaneous. . . . . . . . . . . . . . . . . . . 4,716 4,019
Allowance for Uncollectible Accounts . . . . . . . (769) (848)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 12,386 7,888
Materials and Supplies . . . . . . . . . . . . . . . 16,916 13,652
Accrued Utility Revenues . . . . . . . . . . . . . . 9,226 13,560
Energy Marketing and Trading Contracts . . . . . . . 22,536 4,726
Prepayments. . . . . . . . . . . . . . . . . . . . . 1,714 1,657
TOTAL CURRENT ASSETS . . . . . . . . . . . . 94,437 78,681
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 94,321 92,447
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 6,231 10,476
TOTAL. . . . . . . . . . . . . . . . . . . $ 943,443 $ 921,847
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 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. . . . . . . . . . . . . . . . . . 67,524 71,452
Total Common Shareholder's Equity. . . . . . 276,724 270,652
Long-term Debt . . . . . . . . . . . . . . . . . . . 260,838 308,838
TOTAL CAPITALIZATION . . . . . . . . . . . . 537,562 579,490
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 24,402 26,827
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 60,000 60,000
Short-term Debt. . . . . . . . . . . . . . . . . . . 65,965 20,350
Accounts Payable - General . . . . . . . . . . . . . 10,671 12,917
Accounts Payable - Affiliated Companies. . . . . . . 11,448 11,814
Customer Deposits. . . . . . . . . . . . . . . . . . 4,068 4,038
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 6,894 7,256
Interest Accrued . . . . . . . . . . . . . . . . . . 7,913 6,241
Energy Marketing and Trading Contracts . . . . . . . 21,685 5,089
Other. . . . . . . . . . . . . . . . . . . . . . . . 13,268 13,612
TOTAL CURRENT LIABILITIES. . . . . . . . . . 201,912 141,317
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 160,954 158,706
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 13,298 14,200
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 5,315 1,307
CONTINGENCIES (Note 5)
TOTAL. . . . . . . . . . . . . . . . . . . $943,443 $921,847
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
KENTUCKY POWER COMPANY
STATEMENTS OF CASH FLOWS
(UNAUDITED)
<CAPTION>
Nine Months Ended
September 30,
1999 1998
(in thousands)
<S> <C> <C>
OPERATING ACTIVITIES:
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 18,401 $ 15,872
Adjustments for Noncash Items:
Depreciation and Amortization. . . . . . . . . . . . . . 21,838 20,966
Deferred Federal Income Taxes. . . . . . . . . . . . . . 2,361 1,173
Deferred Investment Tax Credits. . . . . . . . . . . . . (902) (915)
Amortization of Deferred Property Taxes. . . . . . . . . 4,035 3,840
Changes in Certain Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . 4,669 (4,514)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (7,762) 1,227
Accrued Utility Revenues . . . . . . . . . . . . . . . . 4,334 1,394
Accounts Payable . . . . . . . . . . . . . . . . . . . . (2,612) (3,757)
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (362) (1,193)
Payment of Disputed Taxes and Interest Related to COLI . . (567) (5,376)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . (1,138) 1,952
Net Cash Flows From Operating Activities . . . . . . 42,295 30,669
INVESTING ACTIVITIES - Construction Expenditures . . . . . . (28,144) (30,517)
FINANCING ACTIVITIES:
Capital Contributions from Parent Company. . . . . . . . . 10,000 10,000
Change in Short-term Debt (net). . . . . . . . . . . . . . 45,615 12,850
Retirement of Long-term Debt . . . . . . . . . . . . . . . (48,307) (2,203)
Dividends Paid . . . . . . . . . . . . . . . . . . . . . . (22,329) (21,225)
Net Cash Flows Used For Financing Activities . . . . (15,021) (578)
Net Decrease in Cash and Cash Equivalents. . . . . . . . . . (870) (426)
Cash and Cash Equivalents at Beginning of Period . . . . . . 1,935 1,381
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 1,065 $ 955
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $19,420,000 and $18,950,000
and for income taxes was $7,271,000 and $5,812,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $1,889,000 and $4,448,000 in 1999
and 1998, respectively.
See Notes to Financial Statements.
</TABLE>
<PAGE>
<PAGE>
KENTUCKY POWER COMPANY
NOTES TO FINANCIAL STATEMENTS
SEPTEMBER 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 normal recurring accruals and
adjustments which are necessary for a fair presentation of the results
of operations for interim periods.
2. FINANCING ACTIVITIES
In 1999 the following amounts of long-term debt were redeemed: a $25
million term loan note with a rate of 6.42% in April; $12.8 million
principal amount of the 7.90% Series First Mortgage Bonds in May; and
$10.5 million principal amount of the remaining 7.90% Series First
Mortgage Bonds in August.
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 nine months of 1999, the Company increased
short-term debt by $45.6 million.
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 within the AEP
Power Pool's marketing area that are included in cost of service on a
settlement basis for ratemaking purposes. Open contracts outside of AEP
Power Pool's marketing area are marked-to-market in non-operating income.
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 transmission service 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 FERC 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. The 1996
tariff incorporated transmission rates which were the result of a
settlement of a pending rate case, but which were being collected subject
to refund from certain customers who opposed the settlement and continued
to litigate the reasonableness of AEP's transmission rates. On July 29,
1999, the FERC issued an order in the litigated rate case which would
reduce AEP's rates for the affected customers below the settlement rate.
AEP and certain of the affected customers have sought rehearing of the
Commission's Order. The Company made a provision in September 1999 for
its share of the refund which it anticipates would result if the
Commission's order is upheld including interest.
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 September 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.
The Company made payments of taxes and interest attributable to COLI
interest deductions for taxable years 1992-1998 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. A US Tax Court judge recently decided in the
Winn-Dixie Stores v. Commissioner case that a corporate taxpayer's COLI
interest deductions should be disallowed. Notwithstanding the decision
in Winn-Dixie, management believes, and has been advised by outside
counsel, that it has a meritorious position and will vigorously pursue
its lawsuit. In the event the resolutions of this matter is unfavorable,
it will have a material adverse impact on results of operations and cash
flows.
<PAGE>
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. 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). The matter is currently being litigated.
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 that would impose NOx reduction requirements on AEP System
generating units which are approximately equivalent to the reductions
contemplated by the NOx emission reduction final rules. The AEP System
companies with generating plants, as well as other utility companies,
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 originally 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. 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 an adverse effect on future results of operations, cash flows
and possibly financial condition.
Clean Air Act Threatened Litigation
In the fall of 1999 the State of New York, various environmental
groups and the State of Connecticut each separately threatened to sue the
Company under the Clean Air Act to compel compliance with the New Source
Review and New Source Performance Standard provisions, alleging that
modifications occurred at certain units at the Company's Big Sandy Plant.
Under these provisions of the Clean Air Act, if a plant undertakes a
major modification that directly results in an emissions increase,
permitting requirements under the New Source Review program might be
triggered and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities such
as routine maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and efficient
operation of the plant. The State of New York also threatened to sue
five unaffiliated utilities. In addition, the State of New York
indicated that it may seek to recover, under state law, compensation for
alleged environmental damage caused by excess emissions of sulfur dioxide
and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were exempted
from the New Source Review and New Source Performance Standard
requirements, and intends to vigorously pursue its defense of this
matter.
In the event the Company does not prevail in any litigation
ultimately filed, any capital and operating costs of additional pollution
control equipment that may be required as well as any penalties imposed
would adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered through
regulated rates and/or reflected in the future market price of
electricity if generation is deregulated.
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
THIRD QUARTER 1999 vs. THIRD QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
Net income decreased $1.2 million or 15% for the quarter and increased
$2.5 million or 16% for the year-to-date period. The decrease in net income
for the quarter is attributable to lower wholesale power sales margins and a
refund provision for transmission revenues. The effect on net income of
decreases in revenues in both periods were offset by reductions in operating
expenses. The increase in year-to-date net income is due predominantly to
such decreases.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . . $(10.0) (10) $(4.4) (2)
Fuel Expense. . . . . . . . (3.2) (15) (1.7) (3)
Purchased Power Expense . . 0.6 2 2.6 3
Other Operation Expense . . (3.0) (22) (1.9) (5)
Maintenance Expense . . . . (1.8) (25) (8.4) (35)
Federal Income Taxes. . . . (0.8) (18) 1.8 24
Nonoperating Income . . . . 1.0 112 1.0 96
The decreases in operating revenues for the third quarter and
year-to-date periods were due primarily to a reduction in wholesale power sales
margins and a revenue refund provision for wholesale transmission service.
In the year-to-date period, the decline in wholesale power and transmission
revenues were partially offset by a 3% increase in retail revenues as a
result of colder winter weather.
Fuel expense decreased in the third quarter due to a decline in
generation reflecting a planned maintenance outage at Big Sandy Plant Unit 2
which began in mid-September 1999. In the year-to-date period, fuel expense
decreased mainly due to the deferral of fuel cost for later recovery under a
fuel cost recovery mechanism. Changes in the cost of fuel are deferred until
reflected in fuel clause billings to customers.
The increase in purchased power expense in the year-to-date period
resulted from increased capacity charges from the American Electric Power
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 Company pays net capacity charges
to the AEP Power Pool because its peak demand is greater than its internal
generating capacity. 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 decreased due to reduced accruals for incentive
compensation and uncollectible accounts.
The decrease in maintenance expense in the third quarter reflects the
effect of staff reductions. The decline in maintenance expense in the
year-to-date period is primarily attributable to decreased overhead
distribution line and generating plant maintenance expenditures
and the staff reductions savings. In the first quarter of 1998 the repair
and restoration of 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 1998 maintenance expense.
Federal income tax attributable to operations decreased in the quarter
due to a decline in pre-tax operating income partially offset by changes in
certain book/tax timing differences accounted for on a flow-through basis for
rate-making and financial reporting purposes. The increase in federal income
taxes for the year-to-date period resulted from an increase in pre-tax
operating income and changes in certain book/tax timing differences accounted
for on a flow-through basis for rate-making and financial reporting purposes.
Nonoperating income increased due to the effect of losses recorded in
1998 on certain power marketing and trading transactions. These
transactions, which are marked-to-market, represent non-regulated trading
activities outside the Company's traditional marketing area.
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
<CAPTION>
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
<S> <C> <C> <C> <C>
OPERATING REVENUES . . . . . . . . . . . $544,451 $597,812 $1,561,259 $1,637,155
OPERATING EXPENSES:
Fuel . . . . . . . . . . . . . . . . . 173,857 199,934 532,075 574,156
Purchased Power. . . . . . . . . . . . 68,836 60,497 125,808 128,487
Other Operation. . . . . . . . . . . . 81,113 96,254 249,003 260,097
Maintenance. . . . . . . . . . . . . . 27,434 34,900 81,425 98,651
Depreciation and Amortization. . . . . 37,509 36,236 111,691 108,097
Taxes Other Than Federal Income Taxes. 42,941 42,931 128,746 127,451
Federal Income Taxes . . . . . . . . . 39,903 38,222 107,369 102,444
TOTAL OPERATING EXPENSES . . . 471,593 508,974 1,336,117 1,399,383
OPERATING INCOME . . . . . . . . . . . . 72,858 88,838 225,142 237,772
NONOPERATING INCOME (LOSS) . . . . . . . 4,856 (2,665) 6,364 2,022
INCOME BEFORE INTEREST CHARGES . . . . . 77,714 86,173 231,506 239,794
INTEREST CHARGES . . . . . . . . . . . . 21,481 20,212 62,587 60,338
NET INCOME . . . . . . . . . . . . . . . 56,233 65,961 168,919 179,456
PREFERRED STOCK DIVIDEND REQUIREMENTS. . 364 369 1,098 1,107
EARNINGS APPLICABLE TO COMMON STOCK. . . $ 55,869 $ 65,592 $ 167,821 $ 178,349
CONSOLIDATED STATEMENTS OF RETAINED EARNINGS
(UNAUDITED)
Three Months Ended Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
(in thousands)
BALANCE AT BEGINNING OF PERIOD . . . . . $584,045 $597,357 $587,500 $590,151
NET INCOME . . . . . . . . . . . . . . . 56,233 65,961 168,919 179,456
DEDUCTIONS:
Cash Dividends Declared:
Common Stock . . . . . . . . . . . . 57,704 52,775 173,110 158,325
Cumulative Preferred Stock . . . . . 366 369 1,101 1,108
BALANCE AT END OF PERIOD . . . . . . . . $582,208 $610,174 $582,208 $610,174
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>
September 30, December 31,
1999 1998
(in thousands)
ASSETS
<S> <C> <C>
ELECTRIC UTILITY PLANT:
Production . . . . . . . . . . . . . . . . . . . . . $2,688,839 $2,646,597
Transmission . . . . . . . . . . . . . . . . . . . . 852,726 842,318
Distribution . . . . . . . . . . . . . . . . . . . . 975,947 949,224
General (including mining assets). . . . . . . . . . 728,744 689,815
Construction Work in Progress. . . . . . . . . . . . 118,395 129,887
Total Electric Utility Plant . . . . . . . . 5,364,651 5,257,841
Accumulated Depreciation and Amortization. . . . . . 2,600,110 2,461,376
NET ELECTRIC UTILITY PLANT . . . . . . . . . 2,764,541 2,796,465
OTHER PROPERTY AND INVESTMENTS . . . . . . . . . . . . 240,305 218,311
CURRENT ASSETS:
Cash and Cash Equivalents. . . . . . . . . . . . . . 136,765 89,652
Accounts Receivable:
Customers. . . . . . . . . . . . . . . . . . . . . 303,690 215,665
Affiliated Companies . . . . . . . . . . . . . . . 91,718 63,922
Miscellaneous. . . . . . . . . . . . . . . . . . . 23,473 28,139
Allowance for Uncollectible Accounts . . . . . . . (3,175) (1,678)
Fuel . . . . . . . . . . . . . . . . . . . . . . . . 139,431 94,914
Materials and Supplies . . . . . . . . . . . . . . . 93,539 86,870
Accrued Utility Revenues . . . . . . . . . . . . . . 38,146 43,501
Energy Marketing and Trading Contracts . . . . . . . 89,217 19,790
Prepayments and Other Current Assets . . . . . . . . 34,474 34,523
TOTAL CURRENT ASSETS . . . . . . . . . . . . 947,278 675,298
REGULATORY ASSETS. . . . . . . . . . . . . . . . . . . 627,432 551,776
DEFERRED CHARGES . . . . . . . . . . . . . . . . . . . 45,219 102,830
TOTAL. . . . . . . . . . . . . . . . . . . $4,624,775 $4,344,680
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
<TABLE>
OHIO POWER COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(UNAUDITED)
<CAPTION>
September 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. . . . . . . . . . . . . . . . . . . 462,317 462,335
Retained Earnings. . . . . . . . . . . . . . . . . . 582,208 587,500
Total Common Shareholder's Equity. . . . . . 1,365,726 1,371,036
Cumulative Preferred Stock:
Not Subject to Mandatory Redemption. . . . . . . . 17,121 17,370
Subject to Mandatory Redemption. . . . . . . . . . 8,850 11,850
Long-term Debt . . . . . . . . . . . . . . . . . . . 1,142,610 1,073,456
TOTAL CAPITALIZATION . . . . . . . . . . . . 2,534,307 2,473,712
OTHER NONCURRENT LIABILITIES . . . . . . . . . . . . . 419,733 360,330
CURRENT LIABILITIES:
Long-term Debt Due Within One Year . . . . . . . . . 11,480 11,472
Short-term Debt. . . . . . . . . . . . . . . . . . . 97,605 123,005
Accounts Payable - General . . . . . . . . . . . . . 252,513 173,369
Accounts Payable - Associated Companies. . . . . . . 97,837 62,418
Taxes Accrued. . . . . . . . . . . . . . . . . . . . 88,276 161,406
Interest Accrued . . . . . . . . . . . . . . . . . . 22,646 14,187
Obligations Under Capital Leases . . . . . . . . . . 33,068 28,310
Energy Marketing and Trading Contracts . . . . . . . 86,406 22,480
Other. . . . . . . . . . . . . . . . . . . . . . . . 109,317 97,916
TOTAL CURRENT LIABILITIES. . . . . . . . . . 799,148 694,563
DEFERRED INCOME TAXES. . . . . . . . . . . . . . . . . 700,803 711,913
DEFERRED INVESTMENT TAX CREDITS. . . . . . . . . . . . 36,817 39,296
DEFERRED CREDITS . . . . . . . . . . . . . . . . . . . 133,967 64,866
CONTINGENCIES (Note 7)
TOTAL. . . . . . . . . . . . . . . . . . . $4,624,775 $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>
Nine Months Ended
September 30,
1999 1998
(in thousands)
OPERATING ACTIVITIES:
<S> <C> <C>
Net Income . . . . . . . . . . . . . . . . . . . . . . . . $ 168,919 $ 179,456
Adjustments for Noncash Items:
Depreciation, Depletion and Amortization . . . . . . . . 146,388 129,366
Deferred Federal Income Taxes. . . . . . . . . . . . . . 7,529 12,504
Amortization of Deferred Property Taxes. . . . . . . . . 59,567 58,664
Changes in Current Assets and Liabilities:
Accounts Receivable (net). . . . . . . . . . . . . . . . (109,658) (128,584)
Fuel, Materials and Supplies . . . . . . . . . . . . . . (51,186) 28,200
Accrued Utility Revenues . . . . . . . . . . . . . . . . 5,355 (6,314)
Accounts Payable . . . . . . . . . . . . . . . . . . . . 114,563 145,687
Taxes Accrued. . . . . . . . . . . . . . . . . . . . . . (73,130) (45,620)
Other Current Assets and Current Liabilities . . . . . . 19,166 22,853
Payment of Disputed Tax and Interest Related to COLI . . . (6,272) (104,222)
Other (net). . . . . . . . . . . . . . . . . . . . . . . . 26,829 68,381
Net Cash Flows From Operating Activities . . . . . . 308,070 360,371
INVESTING ACTIVITIES:
Construction Expenditures. . . . . . . . . . . . . . . . . (126,524) (121,310)
Proceeds from Sale of Property and Other . . . . . . . . . 2,003 4,348
Net Cash Flows Used For Investing Activities . . . . (124,521) (116,962)
FINANCING ACTIVITIES:
Issuance of Long-term Debt . . . . . . . . . . . . . . . . 222,308 137,566
Change in Short-term Debt (net). . . . . . . . . . . . . . (25,400) 20,108
Retirement of Cumulative Preferred Stock . . . . . . . . . (3,267) (52)
Retirement of Long-term Debt . . . . . . . . . . . . . . . (155,866) (190,181)
Dividends Paid on Common Stock . . . . . . . . . . . . . . (173,110) (158,325)
Dividends Paid on Cumulative Preferred Stock . . . . . . . (1,101) (1,108)
Net Cash Flows Used For Financing Activities . . . . (136,436) (191,992)
Net Increase in Cash and Cash Equivalents. . . . . . . . . . 47,113 51,417
Cash and Cash Equivalents at Beginning of Period . . . . . . 89,652 44,203
Cash and Cash Equivalents at End of Period . . . . . . . . . $ 136,765 $ 95,620
Supplemental Disclosure:
Cash paid for interest net of capitalized amounts was $52,526,000 and $52,523,000
and for income taxes was $48,052,000 and $55,898,000 in 1999 and 1998, respectively.
Noncash acquisitions under capital leases were $23,955,000 and $24,740,000 in 1999
and 1998, respectively.
See Notes to Consolidated Financial Statements.
</TABLE>
<PAGE>
<PAGE>
OHIO POWER COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 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 normal recurring accruals and
adjustments 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% Air
Quality Series C pollution control revenue bonds due 2026. In
June 1999 the Company issued $100 million of 6.75% senior
unsecured notes due 2004 and in September 1999 the Company
issued $75 million of 7% senior unsecured notes also due in
2004.
During the first nine months of 1999, the Company
reacquired the following first mortgage bonds:
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
7.10 November 1, 2023 2,000
In May 1999 the Company reacquired $50 million of 7.40%
Ohio Air Quality Series B pollution control revenue bonds due
2009.
During the first nine months of 1999 the Company decreased
short-term debt by $25.4 million.
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 within the AEP System Power Pool's marketing area
that are included in cost of service on a settlement basis for
ratemaking purposes. Open contracts outside of the AEP Power
Pool's marketing area are marked-to-market in nonoperating
income. The adoption of the EITF did not have a material
effect on results of operations, cash flows or financial
condition.
4. OHIO RESTRUCTURING LEGISLATION
The Ohio Electric Restructuring Act of 1999 became law on
October 4, 1999. The law provides for customer choice of
electricity supplier, a residential rate reduction of 5% and
a freezing of the unbundled generation base rates and a
freezing of fuel rates beginning on January 1, 2001. The law
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 including any unrecovered deferred fuel costs, stranded
plant and mining costs and other transition costs.
Retail electric services that will be competitive are
defined in the law as electric generation service, aggregation
service, and power marketing and brokering. Under the
legislation the PUCO is granted broad oversight responsibility
and is required by the law to promulgate rules for competitive
retail electric generation service. The law also gives the
PUCO authority to approve a transition plan for each electric
utility company.
The law provides Ohio electric utilities with an
opportunity to recover PUCO approved allowable transition costs
through unbundled frozen generation rates paid through December
31, 2005 by customers who do not switch generation suppliers
and through a wires charge for customers who switch generation
suppliers. Transition costs can include regulatory assets,
impairments of generating assets and other stranded costs,
employee severance and retraining costs, consumer education
costs and other costs. Recovery of transition costs can, under
certain circumstances, extend beyond the five-year frozen rate
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 law also provides that the property tax assessment
percentage on electric generation property be lowered from 100%
to 25% of value effective January 1, 2001. Electric utilities
will 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 tax 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. The
gross receipts tax is paid at the beginning of the tax year,
deferred as a prepaid expense and amortized to expense during
the tax year pursuant to the tax laws whereby the payment of
the tax results in the privilege to conduct business in the
year following the payment of the tax. The change in the tax
law to impose an excise tax based on kilowatt-hours sold to
Ohio customers commencing before the expiration of the gross
receipts tax privilege period will result in a 12 month period
when electric utilities are recording as an expense both the
gross receipts tax and the excise tax. Management intends to
seek recovery of the overlap of the gross receipts and excise
taxes in the Ohio transition plan filing.
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 assets and liabilities
certain expenses and revenues consistent with the regulatory
process in accordance with Statement of Financial Accounting
Standards (SFAS) 71, "Accounting for the Effects of Certain
Types of Regulation." Management has concluded that as of
September 30, 1999 the requirements to apply SFAS 71 continue
to be met since the Company's rates for generation will
continue to be cost-based regulated until the establishment of
unbundled frozen generation rates and a wires charge as
provided in the law. The establishment of unbundled frozen
generation rates and the wires charge should enable the Company
to determine its ability to recover transition costs including
regulatory assets and other stranded costs, a requirement to
discontinue application of SFAS 71.
When unbundled generation rates and the wires charge are
established, the application of SFAS 71 will be discontinued
for the Ohio retail jurisdiction portion of the generation
business. At that time the Company will have to write-off its
Ohio jurisdictional generation-related regulatory assets to the
extent that they cannot be recovered under the unbundled frozen
generation rates and distribution wires charges approved by the
PUCO under the 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 generation 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 an unbundled frozen
generation rate, the wires charge and other pertinent
information, it is not possible at this time to determine if
any of the Company's generating assets are impaired in
accordance with SFAS 121. The amount of regulatory assets
recorded on the books at September 30, 1999 applicable to the
Ohio retail jurisdictional generating business is $327 million
before related tax effects. Due to the planned closing of
affiliated mines including the Meigs mine, and other
anticipated events, generation-related regulatory assets as of
December 31, 2000 allocable to the Ohio retail jurisdiction are
estimated to exceed $500 million, before federal income tax
effects. Recovery of these regulatory assets will be sought
as a part of the Company's Ohio transition plan filing.
An estimated determination of whether the Company will
experience any asset impairment loss regarding its Ohio retail
jurisdictional generating assets and any loss from a possible
inability to recover Ohio generation related regulatory assets
and other transition costs cannot be made until such time as
the unbundled frozen generation rates and the wires charge are
determined through the regulatory process. Management will
seek full recovery of generation-related regulatory assets, any
stranded costs and other transition costs in its transition
plan filing. The PUCO is required to complete its regulatory
process and issue a transition order establishing the
transition rates and wires charges by no later than October 31,
2000. Should the PUCO fail to approve transition rates and
wires charges that are sufficient to recover the Company's
generation-related regulatory assets, any other stranded costs
and transition costs, it could have a material adverse effect
on results of operations, cash flows and financial condition.
5. MUSKINGUM AND 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 Windsor mine is estimated to be $48.4
million. In October 1999 the Company closed the Muskingum coal
mine.
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 shutdowns can be deferred for future recovery
through the Ohio fuel clause mechanism under terms of the Ohio
fuel clause predetermined price agreement. At September 30,
1999 the Company has deferred $158 million 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
Muskingum and Windsor mines. Unless the cost of the remaining
coal production and deferred mine shutdowns are recovered
through the remaining Ohio fuel clause rates and Ohio
restructuring transition rates and/or a wires charge, results
of operations and cash flows would be adversely affected.
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 transmission service 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
FERC 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. The 1996 tariff incorporated transmission
rates which were the result of a settlement of a pending rate
case, but which were being collected subject to refund from
certain customers who opposed the settlement and continued to
litigate the reasonableness of AEP's transmission rates. On
July 29, 1999, the FERC issued an order in the litigated rate
case which would reduce AEP's rates for the affected customers
below the settlement rate. AEP and certain of the affected
customers have sought rehearing of the Commission's Order. The
Company made a provision in September 1999 for its share of the
refund which it anticipates would result if the Commission's
order is upheld including interest.
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 September
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.
The Company made payments of taxes and interest
attributable to COLI interest deductions for taxable years
1991-1998 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. A US Tax Court judge
recently decided in the Winn-Dixie Stores v. Commissioner case
that a corporate taxpayer's COLI interest deductions should be
disallowed. Notwithstanding the decision in Winn-Dixie,
management believes, and has been advised by outside counsel,
that it has a meritorious position and will vigorously pursue
its lawsuit. In the event the resolution of this matter is
unfavorable, it will have a material adverse impact on results
of operations and cash flows.
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. 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). The matter
is currently being litigated.
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 that would impose
NOx reduction requirements on AEP System generating units which
are approximately equivalent to the reductions contemplated by
the NOx emission reduction final rules. The AEP System
companies with generating plants, as well as other utility
companies, 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 originally 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. 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 PUCO approved unbundled generation
transition rates, wires charges and the future market price of
electricity, they will have an adverse effect on future results
of operations, cash flows and possibly financial condition.
<PAGE>
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the
request of Federal EPA, filed a complaint in the U.S. District
Court for the Southern District of Ohio that alleges the
Company made modifications to generating units at its Muskingum
River, Mitchell, Philip Sporn and Cardinal plants over the
course of the past 25 years to extend unit operating lives or
to increase unit generating capacity without a preconstruction
permit in violation of the Clean Air Act. Federal EPA also
issued a Notice of Violation to the Company alleging violations
of the New Source Review and New Source Performance Standard
provisions of the Clean Air Act at these same plants. A number
of unaffiliated utilities also received Notices of Violation,
complaints or administrative orders.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to
assess compliance with the New Source Review and New Source
Performance Standard provisions of the Clean Air Act. Under
these provisions of the Clean Air Act, if a plant undertakes
a major modification that directly results in an emissions
increase, permitting requirements under the New Source Review
program might be triggered and the plant may be required to
install additional pollution control technology. This
requirement does not apply to activities such as routine
maintenance, replacement of degraded equipment or failed
components, or other repairs needed for the reliable, safe and
efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each
separately threatened to sue the Company under the Clean Air
Act to compel compliance with the New Source Review and New
Source Performance Standard provisions, alleging that
modifications occurred at certain units at the Company's Philip
Sporn Plant, Kammer Plant, Mitchell Plant, Muskingum River
Plant, Gavin Plant and Cardinal Plant. The State of New York
also threatened to sue five unaffiliated utilities. In
addition, the State of New York indicated that it may seek to
recover, under state law, compensation for alleged
environmental damage caused by excess emissions of sulfur
dioxide and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its
defense of this matter.
The Clean Air Act authorizes civil penalties of up to
$27,500 per day per violation at each generating unit ($25,000
per day prior to January 30, 1997). Civil penalties, if
ultimately imposed by the court, and the cost of any required
new pollution control equipment, if the court accepts all of
Federal EPA's contentions, could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that
may be required as well as any penalties imposed would
adversely affect future results of operations, cash flows and
possibly financial condition unless such costs can be recovered
through PUCO approved unbundled generation transition rates,
wires charges and the future market price for electricity.
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
THIRD QUARTER 1999 vs. THIRD QUARTER 1998
AND
YEAR-TO-DATE 1999 vs. YEAR-TO-DATE 1998
RESULTS OF OPERATIONS
Net income decreased $9.7 million or 15% for the quarter and
$10.5 million or 6% for the year-to-date period primarily due to a
decline in energy sales to wholesale customers and a decline in
wholesale margins.
Income statement line items which changed significantly were:
Increase (Decrease)
Third Quarter Year-to-Date
(in millions) % (in millions) %
Operating Revenues. . . . $(53.4) (9) $(75.9) (5)
Fuel Expense. . . . . . . (26.1) (13) (42.1) (7)
Purchased Power . . . . . 8.3 14 (2.7) (2)
Other Operation Expense . (15.1) (16) (11.1) (4)
Maintenance Expense . . . (7.5) (21) (17.2) (17)
Nonoperating Income . . . 7.5 N.M. 4.3 215
N.M. = Not Meaningful
Operating revenues decreased significantly in both the third
quarter and year-to-date periods due predominantly to declines in
wholesale sales and margins and a revenue refund provision for
wholesale transmission service. Operating revenues from wholesale
sales declined significantly as a result of decreased sales to the
American Electric Power System Power Pool (AEP Power Pool) and
unaffiliated entities reflecting the effect of mild weather on
demand. Wholesale margins declined due to the effects of mild
weather especially during August.
The decreases in fuel expense for the third quarter and year-to-date
periods were mainly due to a decrease in generation,
reflecting the decline in demand and an increase in the deferral of
fuel cost to be recovered in future periods under the Ohio fuel
clause mechanism.
<PAGE>
Purchased power expense increased in the third quarter
primarily due to increased purchases from unaffiliated companies at
premium prices during periods of extremely high demand in July
1999.
Other operation expense decreased in both periods primarily due
to reduced accruals for incentive compensation, cost savings from
staffing reductions and an increase in gains on emission allowance
sales.
The decreases in maintenance expense in both periods were
mainly due to decreased boiler plant maintenance reflecting a
reduction in planned maintenance work on the Company's generating
units and costs savings from staff reductions at the Company's
generating plants.
The increase in nonoperating income is primarily due to the
effect of losses in 1998 on certain non-regulated power marketing
and trading transactions outside the AEP Power Pool's traditional
marketing area.
FINANCIAL CONDITION
Total plant and property additions including capital leases for
the first nine months of 1999 were $150 million.
During the first nine months of 1999, the Company reacquired
$90 million principal amount of first mortgage bonds with interest
rates ranging from 6.55% to 7.85% and issued two series of senior
unsecured notes of $100 million and $75 million with rates of 6.75%
and 7%, respectively, both due in 2004. The Company retired $50
million of 7.40% pollution control revenue bonds and issued $50
million of pollution control revenue bonds at 5.15% due 2026.
During the first nine months of 1999 the Company reduced short-term
debt by $25.4 million.
The short-term debt limitation of the Company was increased
from $400 million to $450 million with approval of the Securities
and Exchange Commission.
OTHER MATTERS
Ohio Restructuring Legislation
The Ohio Electric Restructuring Act of 1999 became law on
October 4, 1999. The law provides for customer choice of
electricity supplier, a residential rate reduction of 5% and a
freezing of the unbundled generation base rates and a freezing of
fuel rates beginning on January 1, 2001. The law 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 including any unrecovered deferred fuel costs,
stranded plant and mining costs and other transition costs.
Retail electric services that will be competitive are defined
in the law as electric generation service, aggregation service, and
power marketing and brokering. Under the legislation the PUCO is
granted broad oversight responsibility and is required by the law
to promulgate rules for competitive retail electric generation
service. The law also gives the PUCO authority to approve a
transition plan for each electric utility company.
The law provides Ohio electric utilities with an opportunity
to recover PUCO approved allowable transition costs through
unbundled frozen generation rates paid through December 31, 2005 by
customers who do not switch generation suppliers and through a
wires charge for customers who switch generation suppliers.
Transition costs can include regulatory assets, impairments of
generating assets and other stranded costs, employee severance and
retraining costs, consumer education costs and other costs.
Recovery of transition costs can, under certain circumstances,
extend beyond the five-year frozen rate 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 law also provides that the property tax assessment
percentage on electric generation property be lowered from 100% to
25% of value effective January 1, 2001. Electric utilities will
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
tax 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. The gross receipts tax is
paid at the beginning of the tax year, deferred as a prepaid
expense and amortized to expense during the tax year pursuant to
the tax laws whereby the payment of the tax results in the
privilege to conduct business in the year following the payment of
the tax. The change in the tax law to impose an excise tax based
on kilowatt-hours sold to Ohio customers commencing before the
expiration of the gross receipts tax privilege period will result
in a 12 month period when electric utilities are recording as an
expense both the gross receipts tax and the excise tax. Management
intends to seek recovery of the overlap of the gross receipts and
excise taxes in the Ohio transition plan filing.
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 assets and liabilities certain
expenses and revenues consistent with the regulatory process in
accordance with Statement of Financial Accounting Standards (SFAS)
71, "Accounting for the Effects of Certain Types of Regulation."
Management has concluded that as of September 30, 1999 the
requirements to apply SFAS 71 continue to be met since the
Company's rates for generation will continue to be cost-based
regulated until the establishment of unbundled frozen generation
rates and a wires charge as provided in the law. The establishment
of unbundled frozen generation rates and the wires charge should
enable the Company to determine its ability to recover transition
costs including regulatory assets and other stranded costs, a
requirement to discontinue application of SFAS 71.
When unbundled generation rates and the wires charge are
established, the application of SFAS 71 will be discontinued for
the Ohio retail jurisdiction portion of the generation business.
At that time the Company will have to write-off its Ohio
jurisdictional generation-related regulatory assets to the extent
that they cannot be recovered under the unbundled frozen generation
rates and distribution wires charges approved by the PUCO under the
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 generation 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 an unbundled frozen generation rate, the wires charge and other
pertinent information, it is not possible at this time to determine
if any of the Company's generating assets are impaired in
accordance with SFAS 121. The amount of regulatory assets recorded
on the books at September 30, 1999 applicable to the Ohio retail
jurisdictional generating business is $327 million before related
tax effects. Due to the planned closing of affiliated mines
including the Meigs mine, and other anticipated events,
generation-related regulatory assets as of December 31, 2000 allocable to the
Ohio retail jurisdiction are estimated to exceed $500 million,
before federal income tax effects. Recovery of these regulatory
assets will be sought as a part of the Company's Ohio transition
plan filing.
An estimated determination of whether the Company will
experience any asset impairment loss regarding its Ohio retail
jurisdictional generating assets and any loss from a possible
inability to recover Ohio generation related regulatory assets and
other transition costs cannot be made until such time as the
unbundled frozen generation rates and the wires charge are
determined through the regulatory process. Management will seek
full recovery of generation-related regulatory assets, any stranded
costs and other transition costs in its transition plan filing.
The PUCO is required to complete its regulatory process and issue
a transition order establishing the transition rates and wires
charges by no later than October 31, 2000. Should the PUCO fail to
approve transition rates and wires charges that are sufficient to
recover the Company's generation-related regulatory assets, any
other stranded costs and transition costs, it could have a material
adverse effect on results of operations, cash flows and financial
condition.
Muskingum and Windsor Mine Closings
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
Windsor mine is estimated to be $48.4 million. In October 1999 the
Company closed the Muskingum coal mine.
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 shutdowns can be deferred for future recovery through the
Ohio fuel clause mechanism under terms of the Ohio fuel clause
predetermined price agreement. At September 30, 1999 the Company
has deferred $158 million 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 Muskingum and Windsor mines. Unless the cost
of the remaining coal production and deferred mine shutdowns are
recovered through the remaining Ohio fuel clause rates and Ohio
restructuring transition rates and/or a wires charge, results of
operations and cash flows would be adversely affected.
COLI 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
September 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.
The Company made payments of taxes and interest attributable
to COLI interest deductions for taxable years 1991-1998 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. A US Tax Court judge recently
decided in the Winn-Dixie Stores v. Commissioner case that a
corporate taxpayer's COLI interest deductions should be disallowed.
Notwithstanding the decision in Winn-Dixie, management believes,
and has been advised by outside counsel, that it has a meritorious
position and will vigorously pursue its lawsuit. In the event the
resolution of this matter is unfavorable, it will have a material
adverse impact on results of operations and cash flows.
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. 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). The
matter is currently being litigated.
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 that would impose NOx reduction requirements on
AEP System generating units which are approximately equivalent to
the reductions contemplated by the NOx emission reduction final
rules. The AEP System companies with generating plants, as well as
other utility companies, 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 originally 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.
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
PUCO approved unbundled generation transition rates, wires charges
and the future market price of electricity, they will have an
adverse effect on future results of operations, cash flows and
possibly financial condition.
Federal EPA Complaint and Notice of Violation
On November 3, 1999 the Department of Justice, at the request
of Federal EPA, filed a complaint in the U.S. District Court for
the Southern District of Ohio that alleges the Company made
modifications to generating units at its Muskingum River, Mitchell,
Philip Sporn and Cardinal plants over the course of the past 25
years to extend unit operating lives or to increase unit generating
capacity without a preconstruction permit in violation of the Clean
Air Act. Federal EPA also issued a Notice of Violation to the
Company alleging violations of the New Source Review and New Source
Performance Standard provisions of the Clean Air Act at these same
plants. A number of unaffiliated utilities also received Notices
of Violation, complaints or administrative orders.
Federal EPA's Notice of Violation and the government's
complaint are based on an investigation by Federal EPA to assess
compliance with the New Source Review and New Source Performance
Standard provisions of the Clean Air Act. Under these provisions
of the Clean Air Act, if a plant undertakes a major modification
that directly results in an emissions increase, permitting
requirements under the New Source Review program might be triggered
and the plant may be required to install additional pollution
control technology. This requirement does not apply to activities
such as routine maintenance, replacement of degraded equipment or
failed components, or other repairs needed for the reliable, safe
and efficient operation of the plant.
In the fall of 1999 the State of New York, various
environmental groups and the State of Connecticut each separately
threatened to sue the Company under the Clean Air Act to compel
compliance with the New Source Review and New Source Performance
Standard provisions, alleging that modifications occurred at
certain units at the Company's Philip Sporn Plant, Kammer Plant,
Mitchell Plant, Muskingum River Plant, Gavin Plant and Cardinal
Plant. The State of New York also threatened to sue five
unaffiliated utilities. In addition, the State of New York
indicated that it may seek to recover, under state law,
compensation for alleged environmental damage caused by excess
emissions of sulfur dioxide and nitrogen oxides.
Management believes its maintenance, repair and replacement
activities were in conformity with the Clean Air Act and were
exempted from the New Source Review and New Source Performance
Standard requirements, and intends to vigorously pursue its defense
of this matter.
The Clean Air Act authorizes civil penalties of up to $27,500
per day per violation at each generating unit ($25,000 per day
prior to January 30, 1997). Civil penalties, if ultimately imposed
by the court, and the cost of any required new pollution control
equipment, if the court accepts all of Federal EPA's contentions,
could be substantial.
In the event the Company does not prevail, any capital and
operating costs of additional pollution control equipment that may
be required as well as any penalties imposed would adversely affect
future results of operations, cash flows and possibly financial
condition unless such costs can be recovered through PUCO approved
unbundled generation transition rates, wires charges and the future
market price for electricity.
Market Risk
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
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 September 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 and has been meeting with key vendors in this connection.
Another issue we are addressing is the impact of electric power
grid problems that may occur outside of our transmission system.
The AEP System, 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. NERC has classified the AEP System
as a "Y2K Ready" organization with respect to its electric systems.
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 also participated in a more
comprehensive second NERC-sponsored drill on September 8-9, 1999,
to prepare for operations under Y2K conditions. The drill gave
electric utilities in North America an opportunity to test how
workers would respond in emergency situations, such as an outage at
a major power plant or loss of the normal communications system.
The drill did not reveal any major problems or issues for AEP.
Through the Electric Power Research Institute, AEP is
participating in an electric utility industry-wide effort that has
been established to deal with Y2K problems affecting embedded
systems. 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 AEP System has completed the process of modifying,
replacing, retiring and testing those mission critical and high
priority digital-based systems with problems processing dates in
the Year 2000.
Costs to Address the Company's Year 2000 Issues - Through September
30, 1999, the Company has spent $12 million on the Y2K project and,
estimates spending an additional $2 million to $5 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 Company has benefited from the
sharing of Y2K remediation costs with its affiliates in the AEP
System. The cost of becoming Y2K ready is not expected to have a
material impact on the Company's results of operations, cash flows
or financial condition.
Risks of the Company's 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 could 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 (ECAR) as
part of NERC's review of regional and individual electric utility
contingency plans in 1999. In addition, the Company has
established detailed contingency plans for its business units to
address alternatives if Y2K related failures occur, including an
operating plan which is coordinated with other ECAR member
utilities. These contingency plans will be refined 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 5. Other Information.
American Electric Power Company, Inc. ("AEP") and Appalachian Power
Company ("APCo")
Reference is made to pages 17 and 18 of the Annual Report on
Form 10-K for the year ended December 31, 1998 ("1998 10-K") and
page II-1 of the Quarterly Report on Form 10-Q for the quarter
ended March 31, 1999, for a discussion of APCo's proposed
transmission facilities. Based on an extension of the procedural
schedule for the evidentiary hearing in Virginia, management has
revised its completion estimate. The earliest date that a Wyoming-Jacksons
Ferry line could be in service would be summer 2004. The
earliest in-service date for the longer Wyoming-Cloverdale line
would be the end of 2004.
AEP, AEP Generating Company ("AEGCo"), APCo, Columbus Southern
Power Company ("CSPCo"), Indiana Michigan Power Company ("I&M"),
Kentucky Power Company ("KEPCo") and Ohio Power Company ("OPCo")
On October 20, 1999, the U.S. District Court for the Southern
District of West Virginia issued an injunction and order, in a case
involving unaffiliated parties, prohibiting the issuance by the
West Virginia Division of Environmental Protection of surface
mining permits which authorize the placement of excess soil in
intermittent or perennial streams. On October 29, 1999, the
District Court stayed the effect of its order pending appeal of
this case to the U.S. Fourth Circuit Court of Appeals. Although
management is unable to predict the effect of this decision on AEP
System operations, the decision could have, among other things, a
substantial adverse impact on the supply of coal from West Virginia
to APCo's generating plants.
Reference is made to page 29 of the 1998 10-K and page II-3 of
the Quarterly Report on Form 10-Q for the quarter ended June 30,
1999 for a discussion of ambient air quality standards attainment.
On October 29, 1999, the U.S. Court of Appeals for the District of
Columbia Circuit issued panel and en banc decisions in this matter.
The panel granted rehearing regarding that portion of its
underlying decision relating to implementation of a secondary air
quality standard for ozone. The panel modified its order without
briefing or oral argument. The panel rejected the U.S.
Environmental Protection Agency's ("Federal EPA") request for
rehearing on the balance of its decision. The full court (two
judges abstaining) rejected Federal EPA's request for rehearing en
banc by a plurality. Federal EPA has 90 days within which to
petition the U.S. Supreme Court to hear an appeal.
II-1
Reference is made to page 33 of the 1998 10-K, pages II-1 and
II-2 of the Quarterly Report on Form 10-Q for the quarter ended
March 31, 1999, and pages II-3 and II-4 of the Quarterly Report on
Form 10-Q for the quarter ended June 30, 1999, for a discussion of
an investigation by Federal EPA under Section 114 of the Clean Air
Act focused on assessing compliance with the New Source Review and
New Source Performance Standard provisions.
In October 1999, Federal EPA, Region V, issued a request
seeking documents and information regarding capital and maintenance
expenditures at Conesville Plant and, in addition, Federal EPA,
Region III, issued such a request for Amos, Kanawha River, Kammer
and Clinch River plants. Federal EPA, Region III, has made site
visits to the four plants identified in its request. In November
1999, Federal EPA, Region V, issued an additional request for
Conesville, Picway, Muskingum River and Cardinal plants.
For a discussion of a complaint filed by the U.S. Department
of Justice and a Notice of Violation issued by Federal EPA, see
AEP's Management's Discussion and Analysis of Results of Operations
and Financial Condition.
Item 6. Exhibits and Reports on Form 8-K.
(a) Exhibits:
AEP, APCo and OPCo
Exhibit 10(a) - AEP System Excess Benefit Plan,
Amended and Restated as of August 1, 1999.
Exhibit 10(b) - AEP System Supplemental Savings
Plan, Amended and Restated as of November 1, 1999.
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, AEGCo, APCo,
CSPCo, I&M, KEPCo
and OPCo
September 15,
1999
Item 5. Other Events
II-2
<PAGE>
Signature
Pursuant to the requirements of the Securities Exchange Act of
1934, each registrant has duly caused this report to be signed on
its behalf by the undersigned thereunto duly authorized. The
signature for each undersigned company shall be deemed to relate
only to matters having reference to such company and any
subsidiaries thereof.
AMERICAN ELECTRIC POWER COMPANY, INC.
By: /s/ Armando A. Pena By: /s/ Leonard V. Assante
Armando A. Pena Leonard V. Assante
Treasurer Controller and
Chief Accounting Officer
(Duly Authorized Officer) (Chief Accounting Officer)
AEP GENERATING COMPANY
APPALACHIAN POWER COMPANY
COLUMBUS SOUTHERN POWER COMPANY
INDIANA MICHIGAN POWER COMPANY
KENTUCKY POWER COMPANY
OHIO POWER COMPANY
By: /s/ Armando A. Pena By: /s/ Leonard V. Assante
Armando A. Pena Leonard V. Assante
Vice President, Treasurer, Controller and
and Chief Financial Officer Chief Accounting Officer
(Duly Authorized Officer) (Chief Accounting Officer)
Date: November 12, 1999
II-3
<PAGE>
<PAGE>
EXHIBIT INDEX
Page
American Electric Power System
Supplement Savings Plan
Amended and Restated as of November 1, 1999. . . . . . . EX-1
American Electric Power System
Excess Benefit Plan
Amended and Restated as of August 1, 1999 . . . . . . . . EX-10
II-4
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER SYSTEM
SUPPLEMENTAL SAVINGS PLAN
AMENDED AND RESTATED AS OF NOVEMBER 1, 1999
ARTICLE I
Purposes and Effective Date
1.1 The American Electric Power System Supplemental Savings
Plan is established to provide to eligible employees a tax-deferred savings
opportunity otherwise not available to them
under the terms of the American Electric Power System Employees
Savings Plan because of contribution restrictions imposed by the
Internal Revenue Code.
1.2 The effective date of the American Electric Power
System Supplemental Savings Plan is January 1, 1994 and the
effective date of the Amended and Restated American Electric
Power System Supplemental Savings Plan is November 1, 1999.
ARTICLE II
DEFINITIONS
2.1 "Account" means the separate memo account established
and maintained by the Company or the recordkeeper employed by the
Company to record Contributions allocated to a Participant's
Account and to record any related Investment Income on the Fund
or Funds selected by the Participant.
2.2 "Applicable Federal Rate" means 120% of the applicable
federal long-term rate, with monthly compounding (as prescribed
under Section 1274(d) of the Code), published for the December
immediately prior to the Plan year.
2.3 "Code" means the Internal Revenue Code of 1986, as
amended from time to time.
2.4 "Committee" means the Employee Benefit Trusts Committee
as established by the Board of Directors of American Electric
Power Service Corporation.
2.5 "Compensation" means a Participant's regular base
salary or wage including any salary or wage reductions made
pursuant to sections 125 and 402(e)(3) of the Code and
contributions to this Plan, and excluding bonuses (such as but
not limited to project bonuses and sign-on bonuses), performance
pay awards, severance pay, relocation payments, or any other form
of additional compensation that is not considered to be part of
base salary or base wage.
EX-1
2.6 "Company" means the American Electric Power Service
Corporation and its subsidiaries and affiliates.
2.7 "Company Contributions" means the matching
contributions made by the Company pursuant to section 3.2.
2.8 "Contributions" means, as the context may require,
Participant Contributions and Company contributions.
2.9 "Corporation" means the American Electric Power
Company, Inc., a New York corporation.
2.10 "Eligible Employee" means an employee of the Company
whose compensation is in excess of the limits imposed by section
401(a)(17) of the Code.
2.11 "ERISA" means the Employee Retirement Income Security
Act of 1974, as amended from time to time.
2.12 "Fund" means the investment options made available to
participants in the Savings Plan and includes the Interest
Bearing Account.
2.13 "Investment Income" means with respect to Participant
Contributions and Company Contributions the earnings, gains and
losses derived from the investment of such Contributions in a
Fund or Funds.
2.14 "Interest Bearing Account" means an investment option
to be made available to Participants in this Plan in which the
Contributions invested in this option are credited with interest
at the Applicable Federal Rate.
2.15 "Participant" means an Eligible Employee who has
executed a Salary Reduction Agreement.
2.16 "Participant Contributions" means contributions made
by the Participant pursuant to an executed Salary Reduction
Agreement subject to the Participant Contribution limits
contained in section 3.1.
2.17 "Plan" means the American Electric Power System
Supplemental Savings Plan.
2.18 "Plan Year" means the calendar year commencing each
January 1 and ending each December 31.
2.19 "Salary Reduction Agreement" means an agreement
between the Company and the Participant in which the Participant
elects to reduce his or her Compensation for the Plan Year and
the Company agrees to treat the amount of the salary reduction as
a Participant Contribution to this Plan.
EX-2
2.20 "Savings Plan" means the American Electric Power
System Employees Savings Plan, a plan qualified under section
401(a) of the Code, as in effect from time to time.
ARTICLE III
CONTRIBUTIONS
3.1 A Participant may elect to make Participant
Contributions by executing a Salary Reduction Agreement. All
Participant Contributions (i) shall be made by payroll deductions
at the end of each payroll period, (ii) shall be based upon the
Compensation the Participant received during such payroll period,
and (iii) shall commence as soon as practicable after the
Participant completes and delivers to the Committee a Salary
Reduction Agreement. Participant Contributions are to be made in
multiples of one (1) whole percentage of Compensation, not to
exceed 17 percent of Compensation for any payroll period or Plan
Year. The maximum Participant Contribution for any Plan Year
shall not exceed the difference between (a) the Participant's
Compensation for the Plan Year times 17 percent and (b) the
aggregate amount of the Participant's Before-Tax and After-Tax
contributions to the Savings Plan.
3.2 Subject to the limitation contained in section 3.3, the
Company shall be deemed to contribute to the Plan on behalf of
each Participant an amount equal to 50% of the amount, not in
excess of 6% of a Participant's Compensation, contributed to the
Plan by the Participant.
3.3 The amount of Company Contributions deemed to be
contributed to the Plan on behalf of a Participant in combination
with contributions made by the Company to the Savings Plan on
behalf of the Participant, shall, in the aggregate be equal to
the lesser of (a) 50% of the Participant Contributions made by
the Participant to this Plan and the Savings Plan, or (b) 3% of
the Participant's Compensation. If the aggregate contributions
exceed the lesser limitation, Company Contributions credited to
the Participant's Account shall be reduced until the aggregate
Company Contributions made under both the Savings Plan and this
Plan do not exceed the limitation.
3.4 An Eligible Employee who becomes a Participant after
the start of a Plan Year due to an increase in the Eligible
Employee's Compensation or the Eligible Employee is first
employed after the start of the Plan Year, the limitations
described in sections 3.1 and 3.2 above shall apply to the
Compensation earned and Contributions made on and after the date
the Eligible Employee becomes a Participant.
EX-3
<PAGE>
ARTICLE IV
INVESTMENT OF CONTRIBUTIONS
4.1 Participant Contributions and Company Contributions
shall be invested in the Funds selected by the Participant. The
Participant may change the selected Funds by notifying the
Company or the recordkeeper retained by the Company. Any change
in the Funds selected by the Participant shall be implemented as
soon as practicable.
4.2 A Participant may elect to transfer all or a portion of
the Contributions from any Fund or Funds to any other Fund or
Funds by giving notice to the Company or the recordkeeper
retained by the Company. Transfers between Funds may be made in
any whole percentage or dollar amounts and shall be implemented
as soon as possible.
4.3 The Funds shall be valued daily at their fair market
value and each Participant's Account shall be valued daily at its
fair market value. The fair market value calculation for a
Participant's Account shall be made after all Contributions,
withdrawals, distributions, Investment Income and transfers for
the day are recorded.
4.4 The Plan is an unfunded non-qualified deferred
compensation plan and therefore the Contributions credited to a
Participant's Account and the investment of those Contributions
in the Fund or Funds selected by the Participant are memo
accounts that represent general, unsecured liabilities of the
Company payable exclusively out of the general assets of the
Company.
ARTICLE V
ELECTION, DISTRIBUTIONS AND BENEFICIARIES
5.1 In order for an election to make Participant
Contributions to be effective for any given Plan Year, the
Participant must deliver a signed Salary Reduction Agreement to
the Committee no later than December 31 of the year preceding the
Plan Year as to which the election is to take effect, or if an
employee becomes an Eligible Employee after the start of the Plan
Year the election must be made within 30 days after the employee
becomes an Eligible Employee. The Salary Reduction Agreement
shall remain in force as to the Plan Year for which it is
delivered and for each subsequent Plan Year until it is revoked
by a new Salary Reduction Agreement. Notwithstanding any other
provision of the Plan to the contrary, no election shall be
effective to defer under the Plan any Compensation which is
earned by the Participant on or before the date upon which the
signed Salary Reduction Agreement is delivered to the Committee.
The Salary Reduction Agreement and any revocation thereof shall
contain such information as may be reasonably required by the
Committee and shall be executed at the time and in the manner
prescribed by the Committee.
EX-4
5.2 Upon a Participant's termination of employment for any
reason other than death, all amounts which are credited to the
Participant's Account shall be distributed to the Participant in
the form of (1) a single lump-sum payment when the Participant's
employment is terminated or at the end of the post-termination
deferral period selected by the Participant, or (2) in
approximately equal annual or semi-annual installment payments
over not less than two or more than ten years commencing when the
Participant's employment is terminated or at the end of the
post-termination deferral period selected by the Participant.
A post-termination deferral shall be for a period of at least one year
but not more then five years from the date the Participant's
employment is terminate. The Participant's distribution election
shall be made when the Participant first elects to participate in
the Plan. The Participant may amend or revoke the distribution
election at any time prior to the Participant's termination of
employment, but any such amendment or revocation must be made at
least twelve months prior to the initial distribution. If the
Participant does not elect a post-termination deferral, the
distribution of a lump-sum payment or the first installment
payment shall be made within 120 days after the Participant's
termination of employment. If the Participant elected a post-termination
deferral, the lump-sum payment or the first
installment payment shall be made within 120 days after the end
of the deferral period. If the Participant elects a post-termination
deferral or elects installment payments, the
Participant shall be eligible to invest the remaining balance in
the Participant's Account as provided in section 4.2.
5.3 Upon a Participant's death prior to termination of
employment or prior to the complete distribution of the
Participant's Account, all amounts credited to the Participant's
Account shall be distributed to (a) the Participant's named
beneficiary, or (b) if the named beneficiary predeceases the
Participant or if the Participant did not name a beneficiary to
the Participant's estate. Distributions to the named beneficiary
shall be in the form of (1) a single lump-sum payment or (2) in
approximately equal annual or semi-annual installment payments
over not less than two nor more then ten years as elected by the
beneficiary. The beneficiary's distribution election must be
made within 90 days of the Participant's date of death. If an
election is not made, the beneficiary shall receive a lump-sum
payment. The distribution of a lump-sum payment or the first
installment payment to a beneficiary shall be made within 90 days
after the beneficiary makes or fails to make a distribution
election. In the event the beneficiary elects installment
payments, the beneficiary shall be eligible to invest the
remaining balance in the Account as provided in section 4.2 as if
the beneficiary is a Participant. In the event a beneficiary
receiving installment payments shall die prior to a complete
distribution of the Account, the remaining balance in the Account
shall be paid to the beneficiary's estate with 120 days after the
Committee is notified of beneficiary's death. The distribution
of a lump-sum payment to the Participant's estate shall be made
within 120 days after the Participant's date of death.
EX-5
5.4 Each Participant shall have the right to designate a
beneficiary or beneficiaries who shall receive the balance of the
Participant's Account if the Participant dies prior to the
complete distribution of the Participant's Account. Any
designation, or change or rescission thereof, shall be made in
writing by completing and furnishing to the Committee the
appropriate beneficiary form prescribed by the Committee. The
last designation of beneficiary received by the Committee prior
to the death of the Participant shall control.
ARTICLE VI
TAXES AND TAX TREATMENT
6.1 Each Participant agrees that as a condition of
participation in the Plan, the Company may withhold federal,
state and local income taxes, Social Security taxes and Medicare
Taxes from any distribution hereunder to the extent that such
taxes are then payable.
6.2 The adoption and maintenance of the Plan is
conditioned upon (1) the applicability of section 451(a) of the
Code to the Participant's recognition of gross income as a result
of participation herein, (2) the fact that the Participants will
not recognize gross income as a result of participation in the
Plan unless and until and then only to the extent that
distributions are received, (3) the applicability of section
404(a)(5) of the Code to the deductibility of the amounts
distributed to the Participants hereunder, (4) the fact that the
Company will not receive a deduction for amount credited to any
Account unless and until and then only to the extent that amounts
are actually distributed and (5) the inapplicability of the
provisions of Titles 2, 3, and 4 of ERISA. If the Internal
Revenue Service, Department of Labor or any court of competent
jurisdiction determines or finds as a fact or legal conclusion
that any of the above conditions is untrue and issues an
assessment, determination, opinion or report to such effect, or
if in the opinion of counsel to the Company any one of the above
assumptions is incorrect, then the Company shall have the option
to terminate this Plan as provided in section 8.1.
ARTICLE VII
Administration
7.1 The Committee shall (i) administer and interpret the
terms and conditions of the Plan, (ii) establish reasonable
procedures with which Participants must comply to exercise any
right established hereunder, and (iii) be permitted to delegate
its responsibilities or duties hereunder to any person or entity.
The rights and duties of the Participants and all other persons
and entities claiming an interest under the Plan are subject to,
and governed by, such acts of administration, interpretation,
procedure and delegation.
EX-6
<PAGE>
7.2 The Committee may employ agents, attorneys,
accountants, or other persons and allocate or delegate to them
powers, rights, and duties all as the Committee may consider
necessary or advisable to properly carry out the administration
of the Plan.
7.3 The Company shall maintain, or cause to be maintained,
records showing the individual credit balances of each
Participant's Account. Each Participant shall be furnished with
quarterly statements setting forth the value of the total credits
to the Participant's Account.
ARTICLE VIII
Amendment or Termination
8.1 The Company intends to continue the Plan indefinitely
but reserves the right to modify the Plan from time to time, or
to terminate the Plan entirely or to direct the permanent
discontinuance or temporary suspension of Contributions under the
Plan; provided that no such modification, termination,
discontinuance or suspension shall affect or otherwise deprive a
Participant or beneficiary of any distributions to which they may
be entitled under the Plan.
ARTICLE IX
Miscellaneous
9.1 Nothing in the Plan shall interfere with or limit in
any way the right of the Company to terminate any Participant's
employment at any time, nor confer upon a Participant any right
to continue in the employ of the Company.
9.2 In the event the Committee shall find that a
Participant or beneficiary is unable to care for his or her
affairs because of illness or accident, the Committee may direct
that any payment due the Participant or the beneficiary be paid
to the duly appointed legal representative of the Participant or
beneficiary, and any such payment so made shall be a complete
discharge of the liabilities of the Plan and the Company.
9.3 The Plan shall be construed and administered according
to the laws of the State of Ohio.
ARTICLE X
Change In Control
10.1 Notwithstanding any provisions of the Plan to the
contrary, if a Change in Control, as defined in Section 10.2, of
the Corporation occurs, all benefits accrued as of the date of
the Change in Control shall be fully vested and non-forfeitable.
EX-7
<PAGE>
10.2 A "Change in Control" of the Corporation shall be
deemed to have occurred if (i) any "person" or "group" (as such
terms are used in Sections 13(d) and 14(d) of the Securities
Exchange Act of 1934 ("Exchange Act")), other than any company
owned, directly or indirectly, by the shareholders of the
Corporation in substantially the same proportions as their
ownership of stock of the Corporation or a trustee or other
fiduciary holding securities under an employee benefit plan of
the Corporation, becomes the "beneficial owner" (as defined in
Rule 13d-3 under the Exchange Act), directly or indirectly, of
more than 25 percent of the then outstanding voting stock of the
Corporation, (ii) during any period of two consecutive years,
individuals who at the beginning of such period constitute the
Board, together with any new Directors (other than a director
nominated by a person (x) who has entered into an agreement with
the Corporation to effect a transaction described in Section
10.2(i), (iii) or (iv) or (y) who publicly announces an intention
to take or to consider taking actions (including, but not limited
to, an actual or threatened proxy contest) which if consummated
would constitute a Change In Control) whose election or
nomination for election was approved by a vote of at least two-thirds of the
Directors then still in office who were either
Directors at the beginning of the period or whose election or
nomination for election was previously so approved, cease for any
reason to constitute at least a majority of the Board; or (iii)
the consummation of a merger or consolidation of the Corporation
with any other entity, other than a merger or consolidation which
would result in the voting securities of the Corporation
outstanding immediately prior thereto continuing to represent
(either by remaining outstanding or by being converted into
voting securities of the surviving entity) at least 50 percent of
the total voting power represented by the voting securities of
the Corporation or such surviving entity outstanding immediately
after such merger or consolidation; or (iv) the shareholders of
the Corporation approve a plan of complete liquidation of the
Corporation, or an agreement for the sale or disposition by the
Corporation (in one transaction or a series of transactions) of
all or substantially all of the Corporation's assets.
Notwithstanding the foregoing, a Change in Control shall not
be deemed to occur as a result of the consummation of the
transactions contemplated in the Agreement and Plan of Merger by
and among the Corporation, Augusta Acquisition Corporation and
Central and South West Corporation dated as of December 21, 1997,
nor thereafter as a result of any event in (i) or (iii) above, if
Directors who were members of the Board prior to such event
continue to constitute a majority of the Board after such event.
For purposes of this Section 10.2, "Board" shall mean the
Board of Directors of the Corporation, and "Director" shall mean
an individual who is a member of the Board.
EX-8
ARTICLE XI
Claims Procedure
11.1 If a Participant makes a written request alleging a
right to receive benefits under the Plan or alleging a right to
receive an adjustment in benefits being paid under the Plan, the
Committee shall treat it as a claim for benefits. All claims for
benefits under the Plan shall be sent to the Committee and must
be received within 30 days after the Participant's termination of
employment. If the Committee determines that any Participant who
has claimed a right to receive benefits, or different benefits,
under the Plan is not entitled to receive all or any part of the
benefits claimed, it will inform the claimant in writing of its
determination and the reasons therefor in terms calculated to be
understood by the claimant. The notice will be sent within 90
days of the claim unless the Committee determines additional
time, not exceeding 90 days, is needed. The notice shall make
specific reference to the pertinent Plan provisions on which the
denial is based, and describe any additional material or
information, if any, necessary for the claimant to perfect the
claim and the reason any such addition material or information is
necessary. Such notice shall, in addition, inform the claimant
what procedure the claimant should follow to take advantage of
the review procedures set forth below in the event the claimant
desires to contest the denial of the claim. The claimant may
within 90 days thereafter submit in writing to the Committee a
notice that the claimant contests the denial of the claim by the
Committee and desires a further review. The Committee shall
within 60 days thereafter review the claim and authorize the
claimant to appear personally and review pertinent documents and
submit issues and comments relating to the claim to the persons
responsible for making the determination on behalf of the
Committee. The Committee will render its final decision with
specific reasons therefore in writing and will transmit it to the
claimant within 60 days of the written request for review, unless
the Committee deterines additional time, not exceeding 60 days,
is needed, and so notifies the claimant. If the Committee fails
to respond to a claim filed in accordance with the foregoing
within 60 days or any such extended period, the Committee shall
be deemed to have denied the claim.
EX-9
<PAGE>
<PAGE>
AMERICAN ELECTRIC POWER SYSTEM
EXCESS BENEFIT PLAN
AMENDED AND RESTATED AS OF AUGUST 1, 1999
ARTICLE I
Purposes and Effective Date
1.1 The American Electric Power System Excess Benefit Plan
is established to provide Supplemental Retirement Benefits for
eligible employees whose retirement benefits from the American
Electric Power System Retirement Plan are restricted due to
limitations imposed by provisions of the Internal Revenue Code or
who are entitled to Supplemental Retirement Benefits under the
terms of an employment agreement between the eligible employee
and an employer.
1.2 The effective date of the Excess Benefit Plan is
January 1, 1990 and the effective date of this amended and
restated Plan is July 1, 1999.
ARTICLE II
Definitions
2.1 "Accredited Service" means the period of time taken
into account under the terms of the Retirement Plan for the
purpose of computing a Retirement Plan benefit.
2.2 "Base Compensation" means a Participant's regular base
salary or wage including any salary or wage reductions made
pursuant to sections 125 and 402(e)(3) of the Code and
contributions to the American Electric Power System Supplemental
Savings Plan; and excluding bonuses (such as but not limited to
project bonuses and sign-on bonuses), performance pay awards,
severance pay, relocation payments, or any other form of
additional compensation that is not considered to be part of base
salary or base wage.
2.3 "Code" means the Internal Revenue Code of 1986, as
amended from time to time.
2.4 "Committee" means the Employee Benefit Trusts
Committee.
2.5 "Company" means the American Electric Power Service
Corporation and its subsidiaries and affiliates who adopt the
Excess Benefit Plan.
2.6 "Corporation" means the American Electric Power
Company, Inc., a New York corporation, and its affiliates and
subsidiaries.
EX-10
<PAGE>
2.7 "Employment Contract" means a contract between the
Company and a Participant that provides the Participant with a
non-qualified retirement benefit.
2.8 "ERISA" means the Employee Retirement Income Security
Act of 1974 as amended from time to time.
2.9 "Excess Benefit Plan" means the American Electric Power
System Excess Benefit Plan, as amended or restated from time to
time.
2.10 "Incentive Compensation" means incentive compensation
earned by a Participant under the terms of the Senior Officer
Incentive Compensation Plan, the Management Incentive
Compensation Plan, or incentive compensation to be included
pursuant to the terms of an Employment Contract. An Incentive
Compensation award, the payment of which is deferred according to
the terms of the plan or by the election of the Participant,
shall be deemed earned at the end of the Plan Year for the
Incentive Compensation Plan.
2.11 "Lump Sum Benefit" means the present value of the
difference between the Participant's Supplemental Retirement
Benefit calculated using the Retirement Plan early retirement
reduction factors from age 65 to age 55 and, if necessary,
actuarially reduced from age 55 to the date the Supplemental
Retirement Benefit is paid and the Participant's Supplemental
Retirement Benefit actuarially reduced from age 65 to the date
the Supplemental Retirement Benefit is paid; or, when applicable
for computing the pre-retirement surviving spouse annuity, the
present value of the difference between 50% of the Participant's
Supplemental Retirement Benefit calculated using the Retirement
Plan early retirement reduction factors from age 65 to age 55
and, if necessary, actuarially reduced from age 55 to the
Participant's date of death and (b) 50% of the Participant's
Supplemental Retirement Benefit actuarially reduced from age 65
to the date the Participant's date of death.
2.12 "Maximum Benefit" means the maximum early, normal,
disability or deferred vested retirement benefit permitted by the
Code to be paid to a Participant from the Retirement Plan upon
the Participant's early, normal, disability or deferred
retirement or the pre-retirement surviving spouse annuity
permitted by the Code to be paid to the Surviving Spouse upon the
death of the Participant.
EX-11
<PAGE>
2.13 "Participant" means any exempt salaried employee of
the Company who is a participant in the Retirement Plan, and (i)
whose base salary or base compensation exceeds the limitation of
section 401(a)(17) of the Code, or (ii) who is entitled to a
Supplemental Retirement Benefit under the terms of an Employment
Contract. If in any Plan Year after a salaried employee becomes
a Participant, the Participant's Base Compensation is lower than
the compensation limits imposed by section 401(a)(17) of the Code
due to an increase in the 401(a)(17) limits, the Participant
shall nevertheless continue as a Participant in the Excess
Benefit Plan until the Participant terminates employment or the
Excess Benefit Plan is terminated.
2.14 "Plan Year" means the calendar year commencing each
January 1 and ending each December 31.
2.15 "Retirement Plan" means the American Electric Power
System Retirement Plan, as amended from time to time.
2.16 "Supplemental Retirement Benefit" means the difference
between the Participant's Unrestricted Benefit and the
Participant's Maximum Benefit.
2.17 "Surviving Spouse" means the spouse of a Participant
who is legally married to the Participant and whose marriage to
the Participant occurred at least one year prior to the earlier
of the Participant's termination of employment or death.
2.18 "Unrestricted Benefit" means the early, normal,
disability or deferred vested retirement benefit payable to a
Participant upon a Participant's early, normal, disability or
deferred vested retirement or the pre-retirement surviving
annuity payable to the Surviving Spouse upon the death of the
Participant under the terms of the Retirement Plan assuming (i)
the Code restrictions on benefits that can be provided by the
Retirement Plan are not applicable and (ii) the compensation upon
which the benefit is based is the Participant's Base Compensation
and Incentive Compensation, or the non-qualified retirement
benefit provided for in an Employment Agreement.
ARTICLE III
Benefits
3.1 Upon a Participant's normal retirement, in accordance
with the terms of the Retirement Plan, the Participant shall be
entitled to a Supplemental Retirement Benefit reduced by any
qualified or non-qualified retirement benefits the Participant is
entitled to receive from any prior employer as identified in an
Employment Contract.
EX-12
3.2 Upon a Participant's early retirement, in accordance
with the terms of the Retirement Plan, the Participant shall be
entitled to a Supplemental Retirement Benefit, adjusted by the
early retirement factors contained in the Retirement Plan,
reduced by any qualified or non-qualified retirement benefits the
Participant is entitled to receive from any prior employer as
identified in an Employment Contract.
3.3 Upon a Participant's termination of employment prior to
qualifying for early retirement under the terms of the Retirement
Plan, the Participant shall be entitled to a Supplemental
Retirement Benefit that is adjusted in accordance with the
reductions specified in the Retirement Plan for deferred vested
Retirement Plan participants reduced by any qualified or non-qualified
retirement benefits the Participant is entitled to
receive from any prior employer as identified in an Employment
Contract.
3.4 A Participant whose employment is terminated prior to
age 55 due to a restructuring, consolidation or downsizing of the
Company and who, at the time of termination, has (i) completed 25
or more years of Accredited Service under the terms of the
Retirement Plan or (ii) has attained age 50 and has completed 10
or more years of Accredited Service under the terms of the
Retirement Plan shall be entitled to an early retirement
Supplemental Retirement Benefit as described in section 3.3 above
and a Lump Sum Benefit, the sum of which shall be reduced by any
qualified or non-qualified retirement benefits the Participant is
entitled to receive from any prior employer as identified in an
Employment Contract.
ARTICLE IV
Spousal Death Benefits
4.1 Upon the death of a Participant prior to the
Participant's early or normal retirement as provided under the
terms of the Retirement Plan, the Surviving Spouse shall be
entitled to a Supplemental Retirement Benefit reduced by any
qualified or non-qualified retirement benefits the Surviving
Spouse is entitled to receive from the Participant's prior
employer or employers as identified in an Employment Contract.
4.2 Upon the death of the Participant after the
Participant's early or normal retirement under the terms of the
Retirement Plan, the Surviving Spouse shall be entitled to a
Supplemental Retirement Benefit equal to the survivor annuity
option elected by the Participant at the time of the
Participant's retirement, as provided in section 5.1, reduced by
any qualified or non-qualified retirement benefits the Surviving
Spouse is entitled to receive from the Participant's prior
employer or employers as identified in an Employment Contract
EX-13
<PAGE>
4.3 Upon the death of a Participant described in section
3.4 prior to the Participant's election to commence benefits, the
Surviving Spouse shall be entitled to a Supplemental Retirement
Benefit that would be paid to the Surviving Spouse of a
Participant described in section 3.3 and shall be entitled to a
Lump Sum Benefit the sum of which is to be reduced by any
qualified or non-qualified retirement benefits the Surviving
Spouse is entitled to receive from the Participant's prior
employer or employers as identified in an Employment Contract.
ARTICLE V
Payment of Supplemental Retirement Benefits
5.1 The Participant's election under the Retirement Plan of
a single life annuity, a 50% joint and survivor annuity, or an
optional form of payment (with the valid consent of the
Participant's spouse where required under the terms of the
Retirement Plan) shall be deemed to be the election made by the
Participant for the Supplemental Retirement Benefit payable under
the Excess Benefit Plan.
5.2 The payment of a Supplemental Retirement Benefit shall
commence at the same time benefit payments from the Retirement
Plan commence.
5.3 A Participant described in section 3.4, may elect to
commence payments of the Participant's Supplemental Retirement
Benefit as of the first day of any month following the
Participant's termination of employment, provided that the
Participant also elects to receive retirement benefits from the
Retirement Plan as of the same date. Supplemental Retirement
Benefits that commence prior to age 55 shall be reduced
actuarially from age 55 to the Participant's age at the time the
Supplemental Retirement Benefit payments commence. The Lump Sum
Benefit payable to the Participant shall be calculated and paid
as of the date the Participant elects to receive payment of the
Supplemental Retirement Benefits.
ARTICLE VI
Administration
6.1 The Committee shall administer the Excess Benefit Plan.
The Committee shall have the authority to interpret the Excess
Benefit Plan and to prescribe, amend and rescind rules and
regulations relating to the administration of the Excess Benefit
plan, and all such interpretations, rules and regulations shall
be conclusive and binding on all Participants.
6.2 The Committee may employ agents, attorneys,
accountants, or other persons and allocate or delegate to them
powers, rights, and duties all as the Committee may consider
necessary or advisable to properly carry out the administration
of the Excess Benefit Plan.
EX-14
ARTICLE VII
Amendment or Termination
7.1 The Company intends the Excess Benefit Plan to be
permanent but reserves the right to amend or terminate the Excess
Benefit Plan when, in the sole opinion of the Company, such
amendment or termination is advisable. Any such amendment or
termination shall be made pursuant to a resolution of the Board
of Directors of the Company.
7.2 No amendment or termination of the Excess Benefit Plan
shall directly or indirectly deprive any current or former
Participant or Surviving Spouse of all or any portion of any
Supplemental Retirement Benefit which commenced prior to the
effective date of such amendment or termination or which would be
payable if the Participant terminated employment for any reason,
including death, on such effective date.
ARTICLE VIII
Miscellaneous
8.1 Nothing in this Excess Benefit Plan shall interfere
with or limit in any way the right of the Company to terminate
any Participant's employment at any time, nor confer upon a
Participant any right to continue in the employ of the Company.
8.2 In the event the Committee shall find that a
Participant or Surviving Spouse is unable to care for his or her
affairs because of illness or accident, the Committee may direct
that any payment due the Participant or the Surviving Spouse be
paid to the duly appointed legal representative of the
Participant or Surviving Spouse, and any such payment so made
shall be a complete discharge of the liabilities of the Excess
Benefit Plan.
8.3 Except as otherwise expressly provided herein, all
terms, conditions and actuarial assumptions of the Retirement
Plan applicable to benefits payable under the terms of the
Retirement Plan shall also be applicable to the Supplemental
Retirement Benefits paid under the terms of the Excess Benefit
Plan.
8.4 The Supplemental Retirement Benefits paid under the
Excess Benefit Plan shall not be funded, but shall constitute
liabilities of the Company to be paid out of general corporate
assets. Nothing contained in the Excess Benefit Plan shall
constitute a guaranty by the Company or any other entity or
person that the assets of the Company will be sufficient to pay
any benefit hereunder.
8.5 The Excess Benefit Plan shall be construed and
administered according to the laws of the State of Ohio.
EX-15
ARTICLE IX
Change In Control
9.1 Notwithstanding any provisions of the Excess Benefit
Plan to the contrary, if a Change in Control, as defined in
Section 9.2, of the Corporation occurs, all Supplemental
Retirement Benefits accrued as of the date of the Change in
Control shall be fully vested and non-forfeitable.
9.2 A "Change in Control" of the Corporation shall be
deemed to have occurred if (i) any "person" or "group" (as such
terms are used in Sections 13(d) and 14(d) of the Securities
Exchange Act of 1934 ("Exchange Act")), other than any company
owned, directly or indirectly, by the shareholders of the
Corporation in substantially the same proportions as their
ownership of stock of the Corporation or a trustee or other
fiduciary holding securities under an employee benefit plan of
the Corporation, becomes the "beneficial owner" (as defined in
Rule 13d-3 under the Exchange Act), directly or indirectly, of
more than 25 percent of the then outstanding voting stock of the
Corporation, (ii) during any period of two consecutive years,
individuals who at the beginning of such period constitute the
Board, together with any new Directors (other than a director
nominated by a person (x) who has entered into an agreement with
the Corporation to effect a transaction described in Section
9.2(i), (iii) or (iv) or (y) who publicly announces an intention
to take or to consider taking actions (including, but not limited
to, an actual or threatened proxy contest) which if consummated
would constitute a Change In Control) whose election or
nomination for election was approved by a vote of at least two-thirds of
the Directors then still in office who were either
Directors at the beginning of the period or whose election or
nomination for election was previously so approved, cease for any
reason to constitute at least a majority of the Board; or (iii)
the consummation of a merger or consolidation of the Corporation
with any other entity, other than a merger or consolidation which
would result in the voting securities of the Corporation
outstanding immediately prior thereto continuing to represent
(either by remaining outstanding or by being converted into
voting securities of the surviving entity) at least 50 percent of
the total voting power represented by the voting securities of
the Corporation or such surviving entity outstanding immediately
after such merger or consolidation; or (iv) the shareholders of
the Corporation approve a plan of complete liquidation of the
Corporation, or an agreement for the sale or disposition by the
Corporation (in one transaction or a series of transactions) of
all or substantially all of the Corporation's assets.
EX-16
Notwithstanding the foregoing, a Change in Control shall not
be deemed to occur as a result of the consummation of the
transactions contemplated in the Agreement and Plan of Merger by
and among the Corporation, Augusta Acquisition Corporation and
Central and South West Corporation dated as of December 21, 1997,
nor thereafter as a result of any event in (i) or (iii) above, if
Directors who were members of the Board prior to such event
continue to constitute majority of the Board after such event.
For purposes of this Section 9.2, "Board" shall mean the
Board of Directors of the Corporation, and "Director" shall mean
an individual who is a member of the Board.
ARTICLE X
Claims Procedure
10.1 If a Participant makes a written request alleging a
right to receive benefits under the Excess Benefit Plan or
alleging a right to receive an adjustment in benefits being paid
under the Excess Benefit Plan, the Committee shall treat it as a
claim for benefits. All claims for benefits under the Excess
Benefit Plan shall be sent to the Committee and must be received
within 30 days after the Participant's termination of employment.
If the Committee determines that any Participant who has claimed
a right to receive benefits, or different benefits, under the
Excess Benefit Plan is not entitled to receive all or any part of
the benefits claimed, it will inform the claimant in writing of
its determination and the reasons therefor in terms calculated to
be understood by the claimant. The notice will be sent within 90
days of the claim unless the Committee determines additional
time, not exceeding 90 days, is needed. The notice shall make
specific reference to the pertinent Excess Benefit Plan
provisions on which the denial is based, and describe any
additional material or information, if any, necessary for the
claimant to perfect the claim and the reason any such addition
material or information is necessary. Such notice shall, in
addition, inform the claimant what procedure the claimant should
follow to take advantage of the review procedures set forth below
in the event the claimant desires to contest the denial of the
claim. The claimant may within 90 days thereafter submit in
writing to the Committee a notice that the claimant contests the
denial of the claim by the Committee and desires a further
review. The Committee shall within 60 days thereafter review the
claim and authorize the claimant to appear personally and review
pertinent documents and submit issues and comments relating to
the claim to the persons responsible for making the determination
on behalf of the Committee. The Committee will render its final
decision with specific reasons therefore in writing and will
transmit it to the claimant wthin 60 days of the written request
for review, unless the Committee determines additional time, not
exceeding 60 days, is needed, and so notifies the claimant. If
the Committee fails to respond to a claim filed in accordance
with the foregoing within 60 days or any such extended period,
the Committee shall be deemed to have denied the claim.
EX-17
<TABLE>
EXHIBIT 12
KENTUCKY POWER COMPANY
Computation of Ratio of Earnings to Fixed Charges
(in thousands except ratio data)
<CAPTION>
Twelve
Months
Year Ended December 31, Ended
1994 1995 1996 1997 1998 9/30/99
<S> <C> <C> <C> <C> <C> <C>
Fixed Charges:
Interest on First Mortgage Bonds . . . . . . $19,090 $19,090 $14,914 $14,867 $13,936 $13,383
Interest on Other Long-term Debt . . . . . . - 2,422 6,446 8,597 12,188 12,837
Interest on Short-term Debt. . . . . . . . . 1,621 2,242 2,849 3,034 2,455 2,321
Miscellaneous Interest Charges . . . . . . . 485 510 555 559 634 764
Estimated Interest Element in Lease Rentals. 700 700 800 1,700 1,500 1,500
Total Fixed Charges . . . . . . . . . . $21,896 $24,964 $25,564 $28,757 $30,713 $30,805
Earnings:
Net Income . . . . . . . . . . . . . . . . . $25,273 $25,128 $16,973 $20,746 $21,676 $24,205
Plus Federal Income Taxes. . . . . . . . . . 2,178 3,914 5,119 9,415 9,785 12,247
Plus State Income Taxes. . . . . . . . . . . 1,154 1,420 598 2,190 2,096 2,471
Plus Fixed Charges (as above). . . . . . . . 21,896 24,964 25,564 28,757 30,713 30,805
Total Earnings. . . . . . . . . . . . . $50,501 $55,426 $48,254 $61,108 $64,270 $69,728
Ratio of Earnings to Fixed Charges . . . . . . 2.30 2.22 1.88 2.12 2.09 2.26
</TABLE>
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0000055373
<NAME> KENTUCKY POWER COMPANY
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 9-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 731,406
<OTHER-PROPERTY-AND-INVEST> 17,048
<TOTAL-CURRENT-ASSETS> 94,437
<TOTAL-DEFERRED-CHARGES> 6,231
<OTHER-ASSETS> 94,321
<TOTAL-ASSETS> 943,443
<COMMON> 50,450
<CAPITAL-SURPLUS-PAID-IN> 158,750
<RETAINED-EARNINGS> 67,524
<TOTAL-COMMON-STOCKHOLDERS-EQ> 276,724
0
0
<LONG-TERM-DEBT-NET> 260,838
<SHORT-TERM-NOTES> 175
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 65,790
<LONG-TERM-DEBT-CURRENT-PORT> 60,000
0
<CAPITAL-LEASE-OBLIGATIONS> 12,355
<LEASES-CURRENT> 3,526
<OTHER-ITEMS-CAPITAL-AND-LIAB> 264,035
<TOT-CAPITALIZATION-AND-LIAB> 943,443
<GROSS-OPERATING-REVENUE> 271,911
<INCOME-TAX-EXPENSE> 11,335
<OTHER-OPERATING-EXPENSES> 220,739
<TOTAL-OPERATING-EXPENSES> 232,074
<OPERATING-INCOME-LOSS> 39,837
<OTHER-INCOME-NET> (44)
<INCOME-BEFORE-INTEREST-EXPEN> 39,793
<TOTAL-INTEREST-EXPENSE> 21,392
<NET-INCOME> 18,401
0
<EARNINGS-AVAILABLE-FOR-COMM> 18,401
<COMMON-STOCK-DIVIDENDS> 22,329
<TOTAL-INTEREST-ON-BONDS> 9,917
<CASH-FLOW-OPERATIONS> 42,295
<EPS-BASIC> 0<F1>
<EPS-DILUTED> 0<F1>
<FN>
<F1> All common stock owned by parent company; no EPS required.
</FN>
</TABLE>
