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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Quarterly Report under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For Quarter Ended September 30, 1998
Commission File Number 1-267
ALLEGHENY ENERGY, INC.
(Exact name of registrant as specified in its charter)
Maryland 13-5531602
(State of Incorporation) (I.R.S. Employer Identification No.)
10435 Downsville Pike, Hagerstown, Maryland 21740-1766
Telephone Number - 301-790-3400
The registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months and (2) has been subject to such
filing requirements for the past 90 days.
At November 16, 1998, 122,436,317 shares of the Common Stock
($1.25 par value) of the registrant were outstanding.
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ALLEGHENY ENERGY, INC.
Form 10-Q for Quarter Ended September 30, 1998
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Consolidated statement of income -
Three and nine months ended September 30, 1998 and 1997 3
Consolidated balance sheet - September 30, 1998
and December 31, 1997 4
Consolidated statement of cash flows -
Nine months ended September 30, 1998 and 1997 5
Notes to consolidated financial statements 6-12
Management's discussion and analysis of financial
condition and results of operations 13-26
PART II--OTHER INFORMATION 27
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Income
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
ELECTRIC OPERATING REVENUES:
<S> <C> <C> <C> <C> <C> <C>
Utility $ 620,254 $ 566,791 $ 1,780,637 $ 1,699,983
Nonutility 106,353 28,334 219,092 52,872
Total Operating Revenues 726,607 595,125 1,999,729 1,752,855
OPERATING EXPENSES:
Operation:
Fuel 151,805 143,901 431,091 417,643
Purchased power and exchanges, net 145,545 52,950 328,000 147,299
Deferred power costs, net 932 587 (1,319) (6,366)
Other 78,361 78,872 235,327 223,560
Maintenance 49,447 51,679 161,918 172,966
Depreciation 66,834 69,224 203,714 206,760
Taxes other than income taxes 49,631 45,867 147,094 141,715
Federal and state income taxes 55,448 41,410 140,528 119,076
Total Operating Expenses 598,003 484,490 1,646,353 1,422,653
Operating Income 128,604 110,635 353,376 330,202
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction (475) 1,033 841 3,309
Other income, net (76) 11,125 1,547 15,705
Total Other Income and Deductions (551) 12,158 2,388 19,014
Income Before Interest Charges and
Preferred Dividends 128,053 122,793 355,764 349,216
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 38,786 43,428 122,335 130,362
Other interest 5,630 3,233 14,279 10,852
Allowance for borrowed funds used during
construction (1,417) (1,010) (2,643) (3,040)
Dividends on preferred stock of subsidiaries 2,318 2,334 6,929 6,960
Total Interest Charges and
Preferred Dividends 45,317 47,985 140,900 145,134
Consolidated Income Before
Extraordinary Charge 82,736 74,808 214,864 204,082
Extraordinary Charge, net (1) - - (265,446) -
CONSOLIDATED NET INCOME (LOSS) $ 82,736 $ 74,808 $ (50,582) $ 204,082
COMMON STOCK SHARES OUTSTANDING (average) 122 436 317 122 430 327 122 436 317 122 131 679
BASIC AND DILUTED EARNINGS PER AVERAGE SHARE:
Consolidated income before extraordinary charge $0.68 $0.61 $1.76 $1.67
Extraordinary charge, net (1) - - ($2.17) -
Consolidated net income (loss) $0.68 $0.61 ($0.41) $1.67
</TABLE>
See accompanying notes to consolidated financial statements.
(1) See Note 6 in the notes to the consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Consolidated Balance Sheet
(Thousands of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
ASSETS:
Property, Plant, and Equipment:
<S> <C> <C> <C>
At original cost, including $226,709
and $229,785 under construction $ 8,536,668 $ 8,451,424
Accumulated depreciation (3,307,097) (3,155,210)
5,229,571 5,296,214
Investments and Other Assets:
Subsidiaries consolidated--excess of cost
over book equity at acquisition 15,077 15,077
Benefit plans' investments 81,591 79,474
Nonutility investments 6,847 4,992
Other 1,567 1,559
105,082 101,102
Current assets:
Cash and temporary cash investments 16,292 26,374
Accounts receivable:
Electric service, net of $19,757 and
$17,191 uncollectible allowance 285,490 296,082
Other 18,291 12,312
Materials and supplies--at average cost:
Operating and construction 80,864 80,836
Fuel 57,069 63,361
Prepaid taxes 66,205 51,724
Other, including current portion of
regulatory assets 45,046 24,005
569,257 554,694
Deferred Charges:
Regulatory assets 719,452 586,125
Unamortized loss on reacquired debt 46,568 49,550
Other 75,856 66,406
841,876 702,081
Total Assets $ 6,745,786 $ 6,654,091
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 153,045 $ 153,045
Other paid-in capital 1,044,085 1,044,085
Retained earnings 851,243 1,059,768
2,048,373 2,256,898
Preferred stock 170,086 170,086
Long-term debt and QUIDS 2,178,536 2,193,153
4,396,995 4,620,137
Current Liabilities:
Short-term debt 218,600 206,401
Long-term debt due within one year 60,000 185,400
Accounts payable 113,025 129,989
Taxes accrued:
Federal and state income 31,177 10,453
Other 55,456 55,428
Interest accrued 36,766 40,000
Adverse power purchase commitments 35,380 -
Other 77,877 74,170
628,281 701,841
Deferred Credits and Other Liabilities:
Unamortized investment credit 127,371 133,316
Deferred income taxes 870,488 1,031,236
Regulatory liabilities 83,567 91,178
Adverse power purchase commitments 550,539 -
Other 88,545 76,383
1,720,510 1,332,113
Total Capitalization and Liabilities $ 6,745,786 $ 6,654,091
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Cash Flows
(Thousands of Dollars)
<TABLE>
<CAPTION>
Nine Months Ended
September 30
1998 1997
CASH FLOWS FROM OPERATIONS:
<S> <C> <C>
Consolidated net (loss) income $ (50,582) $ 204,082
Extraordinary charge, net of taxes 265,446 -
Consolidated income before extraordinary charge 214,864 204,082
Depreciation 203,714 206,760
Deferred investment credit and income taxes, net 17,123 46,698
Deferred power costs, net (1,319) (6,366)
Allowance for other than borrowed funds used
during construction (841) (3,309)
Restructuring liability - (47,479)
Changes in certain current assets and
liabilities:
Accounts receivable, net 4,613 40,147
Materials and supplies 6,264 (11,512)
Accounts payable (16,964) (25,001)
Taxes accrued 20,752 (14,365)
Interest accrued (3,234) 2,462
Other, net 615 18,822
445,587 410,939
CASH FLOWS FROM INVESTING:
Utility construction expenditures (less allowance
for equity funds used during construction) (159,886) (161,226)
Nonutility investment (4,866) (3,613)
(164,752) (164,839)
CASH FLOWS FROM FINANCING:
Sale of common stock - 16,706
Issuance of long-term debt 211,952 -
Retirement of long-term debt (357,125) (36,892)
Short-term debt, net 12,199 (45,390)
Cash dividends on common stock (157,943) (157,547)
(290,917) (223,123)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS (10,082) 22,977
Cash and Temporary Cash Investments at January 1 26,374 19,242
Cash and Temporary Cash Investments at September 30 $ 16,292 $ 42,219
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $129,923 $135,324
Income taxes 107,519 87,071
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Notes to Consolidated Financial Statements
1. The Notes to Consolidated Financial Statements of Allegheny
Energy, Inc. (the Company) in its Annual Report on Form 10-K
for the year ended December 31, 1997 should be read with the
accompanying consolidated financial statements and the
following notes. With the exception of the December 31, 1997
consolidated balance sheet in the aforementioned annual
report on Form 10-K, the accompanying consolidated financial
statements appearing on pages 3 through 5 and these notes to
consolidated financial statements are unaudited. In the
opinion of the Company, such consolidated financial
statements together with these notes contain all adjustments
necessary to present fairly the Company's financial position
as of September 30, 1998, the results of operations for the
three and nine months ended September 30, 1998 and 1997, and
cash flows for the nine months ended September 30, 1998 and
1997.
2. The Company owns all of the outstanding common stock of its
subsidiaries. The consolidated financial statements include
the accounts of the Company and all subsidiary companies
after elimination of intercompany transactions. Allegheny
Generating Company (AGC) is jointly (100%) owned by the
Company's operating subsidiaries and is among the
subsidiaries fully consolidated into the financial statements
of the Company.
3. The Consolidated Statement of Income reflects the results of
past operations and is not intended as any representation as
to future results. The Company's comprehensive income does
not differ from its consolidated net income. For purposes of
the Consolidated Balance Sheet and Consolidated Statement of
Cash Flows, temporary cash investments with original
maturities of three months or less, generally in the form of
commercial paper, certificates of deposit, and repurchase
agreements, are considered to be the equivalent of cash.
4. On April 7, 1997, the Company and DQE, Inc. (DQE), parent
company of Duquesne Light Company in Pittsburgh,
Pennsylvania, announced that they had agreed to merge in a
tax-free, stock-for-stock transaction.
On March 25, 1998, the Maryland Public Service Commission
(PSC) approved a settlement agreement between the Company and
various parties, in which the PSC indicated its approval of
the merger. This action was requested in connection with the
proposed issuance of Allegheny Energy stock to exchange for
DQE stock to complete the merger.
On July 8, 1998, the City of Pittsburgh reached a settlement
agreement with the Company and agreed to support the merger.
On July 16, 1998, the Public Utilities Commission of Ohio
(PUCO) found that the proposed merger would be in the public
interest. The PUCO also stated that the Midwest Independent
System Operator (ISO) is the regional transmission entity
that will best serve the interests of the Ohio customers of
the Company and will best mitigate any market power issues
which might exist.
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The Nuclear Regulatory Commission has approved the transfer
of control of the operating licenses for DQE's nuclear
plants. While Duquesne Light Company (Duquesne), principal
subsidiary of DQE, will continue to be the licensee, this
approval was necessary since control of Duquesne will pass
from DQE to the Company after the merger.
On July 23, 1998, the Pennsylvania Public Utility Commission
(PUC) approved the Allegheny Energy-DQE merger with
conditions acceptable to the Company in response to a
Petition for Reconsideration filed by the Company on June 12,
1998. In its Petition for Reconsideration of a previous PUC
Order, the Company reiterated its commitment to staying in
and supporting the Midwest ISO subject to merger
consummation, and also offered to relinquish some generation
in order to mitigate market power concerns. The Company
committed to relinquishing control of the 570 megawatts (MW)
Cheswick, Pennsylvania, generating station through at least
June 30, 2000 and, in the event that the Midwest ISO has not
eliminated pancaked transmission rates by June 30, 2000, the
Company could be required to divest up to 2,500 MW of
generation, if the PUC were to so order.
In a letter to the Company dated July 28, 1998, DQE stated
that its Board of Directors determined that DQE was not
required to proceed with the merger under present
circumstances, referring to the PUC's Orders of July 23, 1998
(regarding the PUC's approval of the merger described above),
and May 29, 1998 (regarding the restructuring plan of the
Company's Pennsylvania subsidiary described in Note 5 below).
DQE took the position that the findings of both Orders
constitute a material adverse effect under the Agreement and
Plan of Merger and invited the Company to agree promptly to
terminate the merger agreement by mutual consent. DQE
asserted that the findings in the PUC Orders will result in a
failure of the conditions to DQE's obligation to consummate
the merger. DQE indicated that if the Company was not
amenable to a consensual termination, DQE would terminate the
agreement unilaterally not later than October 5, 1998 if
circumstances did not change sufficiently to remedy the
adverse effects DQE stated were associated with the PUC
Orders. In a letter dated July 30, 1998, the Company
informed DQE that DQE's allegations were incorrect, that the
Orders do not constitute a material adverse effect, that the
Company remains committed to the merger, and that if DQE
prevents completion of the merger, the Company would pursue
all remedies available to protect the legal and financial
interests of the Company and its shareholders. The Company
has also notified DQE that its letter and other actions
constitute a material breach of the merger agreement by DQE.
On September 16, 1998, the Federal Energy Regulatory
Commission (FERC) approved the Company's merger with DQE with
conditions that were acceptable to the Company. The
principal condition is divestiture of the Cheswick Generating
Station which enhances the proposal initially made by the
Company and DQE to mitigate market power concerns.
On October 5, 1998, DQE notified the Company that it had
decided to terminate the merger. In response, the Company
filed with the United States District Court for the Western
District of Pennsylvania on October 5, 1998, a complaint for
specific performance of the merger agreement or,
alternatively, damages and motions for a temporary
restraining order and preliminary injunction against DQE.
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On October 28, 1998, the District Court denied the Company's
motions for a temporary restraining order and preliminary
injunction. The District Court did not rule on the merits of
the complaint for specific performance or damages. On
October 30, 1998, the Company appealed the District Court's
order to the United States Court of Appeals for the Third
Circuit. The Company cannot predict the outcome of the
litigation between it and DQE.
All of the Company's incremental costs of the merger process
($16.9 million through September 30, 1998) are being
deferred. The accumulated merger costs will be written off
by the combined company when the merger occurs, or by the
Company if it is determined that the merger will not occur.
5. In December 1996, Pennsylvania enacted the Electricity
Generation Customer Choice and Competition Act (Customer
Choice Act) to restructure the electric industry in
Pennsylvania to create retail access to a competitive
electric energy generation market. Approximately 45% of the
Company's retail revenues are from its Pennsylvania
subsidiary, West Penn Power Company (West Penn). On August
1, 1997, West Penn filed with the PUC a comprehensive
restructuring plan to implement full customer choice of
electric generation suppliers as required by the Customer
Choice Act. The filing included a plan for recovery of
transition costs (sometimes referred to as stranded costs)
through a Competitive Transition Charge (CTC).
Transition costs are costs incurred under a regulated
environment, which are not expected to be recoverable in the
transition to a competitive market. The amount of transition
costs has been a key issue in the restructuring proceedings.
Since the installed costs of utility facilities are known,
the key variable in transition cost determinations in
Pennsylvania was the projection of market prices of
electricity in future periods. West Penn's restructuring
plan filing included its determination of its transition
costs based on its projection of future market prices. West
Penn's recoverable transition costs were limited to $1.2
billion by rate caps mandated by the Customer Choice Act.
On May 29, 1998, the PUC issued an Order authorizing West
Penn recovery of approximately $525 million in transition
costs, with a return, based on alternative projections of
future market prices. On June 26, 1998, the PUC denied,
except for minor corrections, a request by West Penn for
reconsideration of the May 29 Order. On that same day, West
Penn filed a formal appeal in state court and an action in
federal court challenging the PUC's restructuring Order.
West Penn also filed an original jurisdiction action in state
court. While pursuing its litigation, West Penn has
participated in PUC-sponsored settlement discussions with
interested parties regarding issues related to the
restructuring Order.
On November 4, 1998, the PUC tentatively approved an
agreement between West Penn and intervenors to settle the
restructuring proceeding. The settlement agreement includes
the following provisions:
* Agreement by the parties to withdraw all litigation related
to the Pennsylvania deregulation proceedings.
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* Establishment of an average shopping credit of 3.16 cents
per kilowatt-hour in 1999 for West Penn customers who shop for
the generation portion of electricity services.
* Two-thirds of West Penn's customers will have the option of
selecting a generation supplier on January 2, 1999, with all
customers able to shop on January 2, 2000.
* Provides for a 2.5 percent rate decrease (about $25 million)
throughout 1999, accomplished by an equal percentage decrease for
each rate class.
* Provides that customers will have the option of buying
electricity from West Penn at capped generation rates through
2008, and that transmission and distribution rates are capped
through 2005, except that the capped rates are subject to
increases prescribed in the Public Utility Code, including
prudent increases in power purchase costs.
* Prohibits complaints challenging West Penn's regulated
transmission and distribution rates through 2005.
* Provides about $16 million of West Penn funding for the
development and use of renewable energy and clean energy
technologies, energy conservation, energy efficiency, etc.
* Permits recovery of $670 million in transition costs over 10
years beginning in January 1999 for West Penn. In the event that
the merger of Allegheny Energy, Inc. and DQE, Inc. is
consummated, the transition costs will be adjusted to $630
million plus a regulated return to provide a sharing of merger
synergy savings with customers.
* Allows for income recognition of transition cost recovery in
the earlier years of the transition period to reflect the PUC's
projections that electricity market prices are lower in the
earlier years.
* Grants West Penn's application to issue bonds to
"securitize" up to $670 million (or $630 million in the event of
the merger) in transition costs and to provide 75 percent of the
associated savings to customers with 25 percent to shareholders.
* Authorizes the transfer of West Penn's generating assets to
a non-regulated corporate entity at book value and the
unregulated business received authorization, subject to a code of
conduct, to sell generation capacity and energy in unregulated
markets.
* If West Penn is forced to divest some generating assets or
chooses to divest all of its generation before 2002, the CTC will
be adjusted, either up or down, based on the results of such
divestiture.
Pursuant to PUC orders, including the tentatively approved
settlement agreement, starting in 1999 West Penn will
unbundle its rates to reflect separate prices for the
generation charge, the CTC, and transmission and distribution
charges. While generation will be open to competition, West
Penn will continue to provide regulated transmission and
distribution services to customers in its service area at PUC
and FERC regulated rates, and will be the electricity
provider of last resort (PLR) for those customers who decide
not to choose another electricity supplier.
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As stated above, West Penn made its filing concerning its
transition cost requirements based on its early 1997
projection of market prices. The PUC issued its May 29, 1998
Order to West Penn, as well as its 1998 orders to all other
Pennsylvania electric utilities, based on alternative
projections. Current prices, which the Company believes are
being influenced, among other things, by price volatility in
the summer of 1998, are equal to and in some cases slightly
higher than the projections adopted by the PUC in its
deregulation orders issued to the Company and other utilities
in Pennsylvania. If the PUC's projections are correct, West
Penn believes that the transition costs provided will be
sufficient to permit it to recover its embedded costs, with a
return, during the transition from regulation to deregulation
of electricity generation.
The terms of the settlement will require a charge to earnings
in the fourth quarter of about $55-60 million ($33-36 million
after tax) for the 1999 one-year rate decrease of about $25
million, the funding of renewable energy, etc., of about $15
million and an adjustment of about $15-20 million to the
amount of the extraordinary charge recorded in the second
quarter of 1998.
The Company anticipates the PUC tentative approval of the
settlement agreement will become final and nonappealable
before the end of 1998.
6. As required by the Maryland PSC, the Company's Maryland
subsidiary, The Potomac Edison Company, on July 1, 1998 filed
testimony in Maryland's investigation into stranded costs,
price protection, and unbundled rates. The filing also
requested a surcharge to recover the cost of the Warrior Run
cogeneration project which is scheduled to commence
production on October 1, 1999. Hearings are scheduled to
begin in April 1999. A second PSC proceeding is planned to
begin examining market power protective measures in December
1999. Under the PSC's current timetable, a third of the
state's electricity customers would be able to choose their
electricity suppliers beginning in July 2000, and all
customers would have choice by mid-2002. On October 9, 1998,
the Company and four other electric utilities operating in
Maryland, filed appeals which request judicial review of
decisions by the PSC in which the PSC asserted it has
authority to restructure the electric utility industry
without authorization from the state legislature. The
appeals allow the restructuring process to continue on
schedule, while preserving the legal rights of utility
companies to have state courts review PSC decisions.
7. As a result of the May 29, 1998 PUC Order described in Note 5
above, West Penn has determined that it is required to
discontinue the application of Statement of Financial
Accounting Standards (SFAS) No. 71 for electric generation
operations and to adopt SFAS No. 101, "Accounting for the
Discontinuation of Application of SFAS No. 71." In doing so,
West Penn determined that under the provisions of SFAS No.
101 an extraordinary charge of $450.6 million ($265.4 million
after taxes) was required to reflect a write-off of certain
disallowances in the PUC's Order. The
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write-off, recorded in June 1998, reflects adverse power
purchase commitments and deferred costs that are not
recoverable from customers under the PUC's Order as follows:
(Millions of Dollars)
AES Beaver Valley nonutility generation contract $201.4
AGC pumped storage capacity contract 177.2
Other 72.0
Total $450.6
In 1985, West Penn entered into a contract with AES
Corporation for the purchase of energy from AES's Beaver
Valley generating plant in Pennsylvania pursuant to the
requirements of the Public Utility Regulatory Policies Act of
1978 (PURPA) at prices then determined under the Act.
West Penn owns 45% of AGC, which owns an undivided 40%
interest in the 2,100-MW pumped-storage hydroelectric station
in Bath County, Virginia. West Penn buys AGC's capacity in
the station priced under a cost of service formula wholesale
rate schedule approved by the FERC.
Under both of these contracts, West Penn has purchase
commitments at costs in excess of the market value of energy
from the plants. Because of utility restructuring under the
Customer Choice Act, these commitments have been determined
to be adverse purchase commitments requiring accrual as loss
contingencies pursuant to SFAS No. 5, "Accounting for
Contingencies." The extraordinary charge for these contracts
is the net result of such excess cost accruals (recorded in
June as adverse power purchase commitments) less estimated
revenue recoveries authorized in the PUC Order (recorded in
June 1998 as regulatory assets) as follows:
AES AGC
Beaver Valley Bath County
(Millions of Dollars)
Projected costs in excess of market value
of energy $351.5 $234.4
Estimated recovery 150.1 57.2
Net unrecoverable extraordinary charge $201.4 $177.2
The other $72.0 million of extraordinary charges represents
$55.0 million of deferred unrecovered expenditures for
previous PURPA buyouts, $15.4 million for an abandoned
generating plant, and $1.6 million of other generation-
related regulatory assets.
As described in Note 5 above, the PUC issued a tentative
Order on November 4, 1998, tentatively approving a
settlement agreement between West Penn and parties to its
restructuring proceedings in Pennsylvania. As a result, West
Penn in the fourth quarter expects to increase the amount of
the write-off by about $15-20 million to reflect the
agreement provision that future recoveries should be
allocated first to return and then to cost recovery,
resulting in a decrease to regulatory assets recorded in June
1998.
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The Consolidated Balance Sheet includes the amounts listed
below for generation assets not subject to SFAS 71.
September December
1998 1997
(Thousands of Dollars)
Property, plant and equipment at
original cost $1,916,639 $1,951,066
Amounts under construction included above 39,618 51,715
Accumulated depreciation (816,511) (793,166)
8. Common stock dividends per share declared during the periods
for which income statements are included are as follows:
1998 1997
Number Amount Number Amount
of Shares Per Share of Shares Per Share
First Quarter 122,436,317 $.43 121,840,327 $.43
Second Quarter 122,436,317 $.43 122,111,567 $.43
Third Quarter 122,436,317 $.43 122,436,317 $.43
9. In June 1997, the Financial Accounting Standards Board (FASB)
issued SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information" to establish standards
for reporting information about operating segments in
financial statements. The Company currently reports utility
and nonutility segments and continues to review this standard
for further potential effect on the Company's financial
statement disclosures.
In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," to establish
accounting and reporting standards for derivatives. The new
standard requires recognizing all derivatives as either
assets or liabilities on the balance sheet at their fair
value and specifies the accounting for changes in fair value
depending upon the intended use of the derivative. The new
standard is effective for fiscal years beginning after June
15, 1999. The Company expects to adopt SFAS No. 133 in the
first quarter of 2000. The Company makes only limited use of
derivative instruments and hedging activities, and is in the
process of evaluating the impact of SFAS No. 133.
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ALLEGHENY ENERGY, INC.
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1998
WITH THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1997
The Notes to Consolidated Financial Statements and
Management's Discussion and Analysis of Financial Condition and
Results of Operations in the Company's Annual Report on Form 10-K
for the year ended December 31, 1997 should be read in
conjunction with the following management's discussion and
analysis information.
Factors That May Affect Future Results
This Management's Discussion and Analysis of Financial
Condition and Results of Operations contains forecast information
items that are "forward-looking statements" as defined in the
Private Securities Litigation Reform Act of 1995. These include
statements with respect to deregulation activities and movements
toward competition in states served by the Company and the DQE,
Inc. (DQE) merger as well as results of operations. All such
forward-looking information is necessarily only estimated. There
can be no assurance that actual results will not materially
differ from expectations. Actual results have varied materially
and unpredictably from past expectations.
Factors that could cause actual results to differ
materially include, among other matters, electric utility
restructuring, including the ongoing state and federal
activities; potential Year 2000 operation problems; developments
in the legislative, regulatory, and competitive environments in
which the Company operates, including regulatory proceedings
affecting rates charged by the Company's subsidiaries;
environmental legislative and regulatory changes; future economic
conditions; earnings retention and dividend payout policies;
developments relating to the proposed merger with DQE, including
expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.
Significant Events in the First Nine Months of 1998
* Merger with DQE
In a letter to the Company dated October 5, 1998, DQE
stated that it had decided to terminate the merger. In response,
the Company filed with the United States District Court for the
Western District of Pennsylvania on October 5, 1998 a complaint
for specific performance of the merger agreement or, in the
alternative, damages, and also filed a request for a temporary
restraining order and preliminary injunction against DQE. See
Note 4 to the Consolidated Financial Statements for more
information about the merger. The Company believes that DQE's
basis for seeking to terminate the merger is
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without merit. Accordingly, the Company continues to seek the
remaining regulatory approvals from the Department of Justice and
the Securities and Exchange Commission. It is not likely either
agency will act on the requests unless the Company obtains
judicial relief requiring DQE to move forward. The Company
cannot predict the outcome of the litigation between it and DQE.
* Pennsylvania Deregulation
On November 4, 1998, the Pennsylvania Public Utility
Commission (PUC) tentatively approved an agreement between West
Penn Power Company (West Penn), the Company's Pennsylvania
electric utility subsidiary, and intervenors in West Penn's
restructuring proceedings related to legislation in Pennsylvania
to provide customer choice of electric supplier and deregulate
electricity generation. See Notes 5 and 7 to the Consolidated
Financial Statements for details of the settlement agreement and
other information about the deregulation process.
Under the deregulation legislation, all utilities were
provided an opportunity to recover their transition (or stranded)
costs, as further described in Note 5. As also further described
in Note 5, the determination of transition costs relied heavily
on projections of future market prices of electricity. West
Penn's transition cost recovery claim of $1.2 billion was the
subject of significant disagreement and debate, as were the
transition cost claims of the other Pennsylvania utilities.
Under the tentatively approved settlement agreement, West
Penn has been authorized to recover $670 million of transition
costs ($630 million if the DQE merger is consummated, see Note
5), plus a return, and to record the income therefrom in the
earlier years of the transition period when electricity market
prices are assumed to be lowest. Additionally, as described in
Note 7, West Penn will have written off as an extraordinary item
in 1998 about $465-470 million of costs which it deemed not
recoverable under the deregulation process. $451 million of this
amount was recorded in the second quarter.
Under the terms of the settlement agreement, two-thirds
of West Penn's customers will be permitted to choose an alternate
generation supplier beginning in January 1999. All West Penn
customers can do so beginning in January 2000. (West Penn
customers represent about 45% of the Company's electricity
generation business.) They can also choose to remain as a West
Penn customer at West Penn's capped generation rates, or to
alternate back and forth. Under the law all electric utilities,
including West Penn, retain the responsibility of electricity
provider of last resort (PLR) to all customers in their
respective franchise territories that do not choose an alternate
supplier.
Beginning in 1999, in Pennsylvania, electricity supply
and electricity delivery will be two separate businesses. The
transmission and distribution "wires" business will be under
traditional regulated rate making, and the electricity generation
business will be deregulated with pricing determined by the
market place. The "wires" business will have the PLR
responsibility and will generally obtain its electricity supply
from the market primarily by competitive bidding, including bids
from an affiliated generation business. The generation business
will be free to sell, subject to a code of conduct, West Penn's
generation capacity and energy in the open wholesale and retail
markets, except that it is not permitted to sell at retail in
West Penn's franchise territory through the year 2003.
<PAGE>
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The settlement agreement permits the transfer of West
Penn's generation assets to the unregulated generation business
at West Penn's embedded cost book values.
Current electricity supply prices are below the level
required to produce results of operations equal to that obtained
in the regulated environment primarily because, in the Company's
opinion, of abundant generation from other states, as well as in
Pennsylvania, to supply the limited market of Pennsylvania. The
Company believes that the utilities in states that are not yet
deregulated are now selling and will continue to sell electricity
into Pennsylvania at marginal cost while their fixed costs are
recovered from franchise customers in their home state
territories.
The PUC's projections of electricity market prices
recognized this possibility, among others, and accordingly
assumed depressed prices in the earlier years of the transition
process from regulation to deregulation. The projections further
assumed that prices would increase in later years due to
increasing demand from deregulation in other states and normal
increases in customer demand, particularly because of
competition.
The forward-looking statements above are provided to
describe the Company's plans and its reasoning for actions taken.
Of necessity its plans are based on assessments of future events.
There can be no assurance that actual results will not materially
differ from expectations.
* Maryland Settlement and Deregulation
After substantial negotiations, the Company's Maryland
subsidiary, The Potomac Edison Company (Potomac Edison) reached a
settlement agreement with various parties on the Office of
People's Counsel's (OPC) petition for a reduction in Potomac
Edison's Maryland rates. The agreement, which includes
recognition of costs to be incurred from the Warrior Run
cogeneration project, was filed with the Maryland Public Service
Commission (Maryland PSC) on July 30, 1998 and approved by that
Commission on October 27, 1998. Under the terms of the
agreement, Potomac Edison will increase its rates about 4% ($13
million) in each of the years 1999, 2000, and 2001 (a $39 million
annual effect in 2001). The increases are designed to recover
additional costs of about $131 million, over the period 1999-
2001, for capacity purchases from AES's Warrior Run generation
project net of alleged overearnings of $52 million for the same
period absent these adjustments. The net effect of these changes
over the 1999-2001 time frame results in a pre-tax income
reduction of $12.0 million in 1999, $18.0 million in 2000, and
$22.0 million in 2001. In addition, the settlement requires that
Potomac Edison share, on a 50% customer, 50% shareholder basis,
earnings above a threshold return on equity (ROE) level of 11.4%
for 1999-2001. This sharing will occur through an after-the-fact
true-up conducted after each calendar year is completed. In the
event the merger with DQE is consummated, an additional rate
reduction of $4.4 million annually will occur. "Warrior Run" is
a cogeneration project being built by AES Corporation in western
Maryland. Potomac Edison is required to purchase the project's
energy at above-market prices pursuant to the requirements of the
Public Utility Regulatory Policies Act of 1978 (PURPA).
On July 1, 1998, Potomac Edison filed testimony in
Maryland's investigation into stranded costs, price protection,
and unbundled rates. See Note 6 to the Consolidated Financial
Statements for more information regarding the Maryland filing.
<PAGE>
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* Virginia Rate Settlement
On August 7, 1998, the Virginia State Corporation
Commission (Virginia SCC) approved an agreement reached between
Potomac Edison and the Staff of the Virginia SCC which will
reduce base rates for Virginia customers beginning September 1,
1998 by about $2.5 million annually. The review of rates was
required by an annual information filing in Virginia.
Review of Operations
EARNINGS SUMMARY
Consolidated Net Income (Loss)
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Utility Operations $90.8 $79.2 $232.2 $214.9
Nonutility Operations (8.1) (4.4) (17.4) (10.8)
Consolidated Income Before
Extraordinary Charge 82.7 74.8 214.8 204.1
Extraordinary Charge (265.4)
Consolidated Net Income (Loss) $82.7 $74.8 $(50.6) $204.1
Earnings Per Share
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
Utility Operations $.74 $.65 $1.90 $1.76
Nonutility Operations (.06) (.04) (.14) (.09)
Consolidated Income Before
Extraordinary Charge .68 .61 1.76 1.67
Extraordinary Charge (2.17)
Consolidated Net Income (Loss) $.68 $.61 $(.41) $1.67
The increase in utility earnings in the third quarter and
first nine month periods, before the previously reported second
quarter extraordinary charge, was due primarily to increased
kilowatt-hour (kWh) sales to retail customers. The increase in
nonutility losses for the three and nine months ended September
30, 1998 resulted primarily from energy sales commitments in
excess of owned generating capacity which required settlement by
open market purchases during a period of high wholesale prices.
See Note 7 to the Consolidated Financial Statements for
information about the extraordinary charge.
<PAGE>
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SALES AND REVENUES
Total operating revenues for the third quarter and first
nine months of 1998 and 1997 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Operating revenues:
Utility revenues:
Bundled retail sales $555.9 $527.5 $1,619.4 $1,594.7
Unbundled retail sales 4.6 - 10.5 -
Wholesale and other 17.8 14.2 50.8 43.4
Bulk power and trans-
mission services sales 41.9 25.1 99.9 61.9
Total utility revenues 620.2 566.8 1,780.6 1,700.0
Nonutility revenues 106.4 28.3 219.1 52.9
Total operating
revenues $726.6 $595.1 $1,999.7 $1,752.9
The increase in third quarter and first nine months
bundled retail sales (full service sales to retail customers) is
primarily due to increased kWh sales to retail customers due to
third quarter weather which was 50% warmer than 1997 and 16%
warmer than normal as measured in cooling degree days. Retail
sales include sales to residential, commercial, industrial, and
street lighting customers. The increase in the first nine months
is also due to an increase in the number of customers. However,
the first nine months included reduced residential kWh sales
which resulted from first quarter winter weather which was 14%
warmer than 1997 and 21% warmer than normal as measured in
heating degree days. Bundled retail sales revenues were also
affected by the Customer Choice Act in Pennsylvania. As part of
the Customer Choice Act, all utilities in Pennsylvania were
required to administer retail access pilot programs under which
customers representing 5% of the load of each rate class would
choose a generation supplier other than their own local franchise
utility. As a result, 5% of previously fully bundled customers
chose to participate in the Pennsylvania pilot program and were
required to buy energy from another supplier of their choice.
The pilot program began on November 1, 1997 and will continue
through December 31, 1998. Unbundled retail sales revenues
represent transmission and distribution revenues from
Pennsylvania pilot customers who chose another supplier to
provide their energy needs.
To assure participation in the pilot program, pilot
participants are receiving an energy credit from their local
utility and a price for energy pursuant to an agreement with an
alternate supplier. The credit established by the PUC is
artificially high, with the result that West Penn could suffer a
revenue loss of up to $10 million in 1998 for the pilot. The PUC
has approved West Penn's pilot compliance filing and thus has
indicated its intent to treat the revenue losses as a regulatory
asset. Wholesale and other revenues include an accrual of such
revenue losses, as well as sales to wholesale customers
(cooperatives and municipalities that own their own distribution
systems and buy all or part of their bulk power needs from the
subsidiaries under regulation by the FERC) and non-kWh revenues.
The increase in wholesale
<PAGE>
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and other revenues was due primarily to $2.5 million and $5.8
million for the three and nine months ended September 30, 1998,
respectively, of deferred net revenue losses recorded as a
regulatory asset to offset revenue losses suffered as a result of
the pilot.
Utility and nonutility sales include sales of bulk power
to power marketers and other utilities. Utility sales also
include sales of transmission services to such marketers and
utilities. Significant bulk power sales acted as a hedge to
offset certain second and third quarter trading losses in
nonutility operations. The Company has discontinued the types of
trading activities which caused the losses. Bulk power and
transmission sales for the third quarter and first nine months
were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
KWh Sales (in billions):
Utility:
Bulk power .9 .6 2.4 1.2
Transmission services 2.6 3.0 6.4 9.8
Total utility 3.5 3.6 8.8 11.0
Nonutility bulk power 2.7 1.1 6.4 2.3
Revenues (in millions):
Utility:
Bulk power $23.3 $15.1 $61.9 $30.3
Transmission services 18.6 10.0 38.0 31.6
Total utility $41.9 $25.1 $99.9 $61.9
Nonutility bulk power $95.9 $27.6 $194.9 $51.1
The increase in revenues from utility bulk power was due
to increased sales which occurred primarily in the second quarter
as a result of warm weather which increased the demand and price
for energy. The increase in revenues from utility transmission
services was due to an increase in price.
In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level. These events included extremely hot weather and
Midwest generation unit outages and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The potential exists for such volatility to significantly
affect the Company's operating results. The impact on such
results, either positively or negatively, depends on whether the
Company's subsidiaries are net buyers or sellers of electricity
during such periods, the open commitments which exist at such
times, and whether the effects of such transactions by the
Company's utility subsidiaries are includable in fuel or energy
cost recovery clauses in their respective jurisdictions. The
impact of such price volatility in June and the third quarter of
1998 differed between the Company's utility and nonutility
subsidiaries but was insignificant in total.
<PAGE>
- 19 -
The increase in nonutility revenues resulted primarily
from increased bulk power sales by the Company's nonutility
exempt wholesale generator and power marketer, AYP Energy, Inc.,
which began operations in late 1996, and from Allegheny Energy
Solutions, Inc. (Allegheny Energy Solutions) which was formed in
the third quarter of 1997 to market energy to retail customers in
deregulated markets and other energy-related services. Increased
prices for energy in the wholesale market also contributed to the
increase. Allegheny Energy Solutions recorded $6.6 million and
$18.9 million of revenues for the three and nine months ended
September 30, 1998, respectively. While Allegheny Energy
Solutions will cease operations as an electric generation
supplier and will discontinue supplying generation services upon
January 1999 customer meter reading dates, the Company will
continue to market nonutility energy sales to retail customers
under the brand name of Allegheny Energy under the direction of a
newly created Energy Supply Business Unit. The Energy Supply
Business Unit will also market nonutility energy sales to
wholesale customers.
OPERATING EXPENSES
Fuel expenses for the third quarter and first nine months
of 1998 and 1997 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Utility operations $146.2 $138.0 $415.9 $399.8
Nonutility operations 5.6 5.9 15.2 17.8
Total fuel expenses $151.8 $143.9 $431.1 $417.6
Fuel expenses for utility operations for the three and
nine months ended September 30, 1998 increased 6% and 4%,
respectively, primarily due to a 5% and 4% increase in kWhs
generated. The decrease in fuel expense for nonutility
operations for the three and nine months ended September 30, 1998
was primarily due to a decrease in kWhs generated as a result of
a scheduled outage at Unit No. 1 of the Fort Martin Power Station
which is 50% owned by the Company's nonutility subsidiary, AYP
Energy, Inc. (AYP Energy).
<PAGE>
- 20 -
Purchased power and exchanges, net, represents power
purchases from and exchanges with other companies and purchases
from qualified facilities under PURPA, and consists of the
following items:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Purchased power:
Utility operations:
From PURPA generation* $ 30.6 $30.4 $ 98.5 $100.2
Other 20.3 8.2 35.6 24.4
Total purchased power
for utility operations 50.9 38.6 134.1 124.6
Power exchanges, net (3.3) (2.7) (1.5) .1
Nonutility operations 97.9 17.1 195.4 22.6
Purchased power and
exchanges, net $145.5 $53.0 $328.0 $147.3
*PURPA cost (cents per kWh) 5.3 5.3 5.4 5.6
PURPA purchased power costs will be reduced $201 million
during the period 2006-2016 related to the AES Beaver Valley
nonutility generation contract as a result of a June 1998
extraordinary charge. See Note 7 to the Consolidated Financial
Statements for further information.
The increases in other purchased power for utility
operations resulted primarily from increased purchases for sales.
As described earlier, an increase in price caused by volatility
in the spot prices for electricity at the wholesale level in June
as well as in the third quarter of 1998 also contributed to the
increases.
Nonutility purchased power is the result of power
replacement requirements and transaction opportunities by AYP
Energy which began operations in late 1996. The increases in
nonutility purchases are due primarily to an increase in volume
attributable to AYP Energy's increased participation in the
market and increased prices.
The AES Warrior Run PURPA power station project in
Potomac Edison's Maryland jurisdiction is scheduled to commence
generation in 1999. Potomac Edison unsuccessfully sought a
buyout or restructuring of the existing contract to reduce the
cost of power purchases ($60 million or more annually) and to
prevent the need for increases in Potomac Edison's rates in
Maryland because of the high cost of this energy. On July 30,
1998, a settlement agreement was filed with the Maryland PSC.
The settlement was approved by the Maryland PSC on October 27,
1998. See page 15 for further information on the agreement.
<PAGE>
- 21 -
Other operation expenses were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Utility operations $71.9 $74.0 $221.6 $213.0
Nonutility operations 6.5 4.9 13.7 10.6
Total other operation
expenses $78.4 $78.9 $235.3 $223.6
The increase in utility other operation expenses for the
nine months ended September 30, 1998 was due primarily to
increased allowances for uncollectible accounts ($3.7 million),
expenses related to competition and the Pennsylvania pilot ($2.8
million), and increases in salaries and wages and employee
benefits. The Company's West Penn subsidiary expects to incur
increased advertising and other sales-related expenditures to
enhance nonutility energy sales.
The increase in nonutility operation expenses was due to
sales expense incurred in marketing energy to retail customers in
the Pennsylvania pilot program and startup expenses of non-energy
businesses incurred by the Company's AYP Capital, Inc.
subsidiary.
Maintenance expenses decreased $2.2 million and $11.0
million for the three and nine months ended September 30, 1998
due to decreased utility expenses of $2.0 million and $12.6
million for the three and nine months ended September 30, 1998,
respectively, because of a management program to postpone such
expenses for the year in response to limited sales growth in the
first quarter due to the warm winter weather. The Company is
postponing these expenses primarily by extending the time between
maintenance outages. The nine months ended September 30, 1998
period includes approximately $4.4 million of incremental
transmission and distribution (T&D) expenses primarily incurred
in the second quarter for unusually strong thunderstorms in the
subsidiaries' service territories. Utility reductions in the
nine months ended September 30, 1998 period were offset in part
by increased nonutility maintenance expense of $1.6 million
primarily related to a planned outage for maintenance of Unit No.
1 of the Fort Martin Power Station, 50% owned by AYP Energy.
Maintenance expenses represent costs incurred to maintain the
power stations, the T&D system, and general plant, and reflect
routine maintenance of equipment and rights-of-way as well as
planned major repairs and unplanned expenditures, primarily from
forced outages at the power stations and periodic storm damage on
the T&D system. Variations in maintenance expense result
primarily from unplanned events and planned major projects, which
vary in timing and magnitude depending upon the length of time
equipment has been in service without a major overhaul and the
amount of work found necessary when the equipment is dismantled.
Depreciation expense decreased $2.4 million and $3.0
million for the three and nine months ended September 30, 1998
primarily due to decreased utility depreciation of $1.5 million
and $2.3 million, respectively, reflecting a change in the
retirement dates for West Penn for the Mitchell Power Station and
the Pleasants Power Station scrubbers.
<PAGE>
- 22 -
Taxes other than income taxes increased $3.8 million and
$5.4 million in the three and nine months ended September 30,
1998, respectively. The increase in the three months ended
September 30, 1998 period was primarily due to an increase in
utility and nonutility gross receipts taxes resulting from higher
revenues from retail customers. The increase in the nine months
ended September 30, 1998 period was due to increased utility West
Virginia Business and Occupation Taxes resulting from an
adjustment for a prior period, increased property taxes related
to an increase in the assessment of property in Maryland, and
increased utility and nonutility gross receipts taxes.
The increases in federal and state income taxes for the
three and nine months ended September 30, 1998 were primarily due
to increases in utility income before taxes, exclusive of other
income which is reported net of taxes.
The decreases in allowance for other than borrowed funds
used during construction of $1.5 million and $2.5 million for the
three and nine months ended September 30, 1998, respectively,
reflect a shift in the rate calculated under the Federal Energy
Regulatory Commission formula to lower cost short-term debt
financing. The allowance for borrowed funds used during
construction component of the formula receives greater weighting
when short-term debt increases. The decreases also reflect
adjustments of prior periods.
The decreases in other income, net, of $11.2 million and
$14.2 million in the three and nine months ended September 30,
1998, respectively, were primarily due to an interest refund on a
tax-related contract settlement in the three and nine months
ended September 30, 1997. The nine months ended September 30,
1997 also reflected a sale of land and timber by West Virginia
Power and Transmission Company, a subsidiary of West Penn.
The decreases in interest on long-term debt of $4.6
million and $8.0 million for the three and nine months ended
September 30, 1998, respectively, result from reduced long-term
debt and lower interest rates.
Other interest expense reflects changes in the levels of
short-term debt maintained by the companies throughout the year,
as well as the associated rates.
Financial Condition
The Company's discussion on Financial Condition,
Requirements, and Resources and Significant Continuing Issues in
its Annual Report on Form 10-K for the year ended December 31,
1997 should be read in conjunction with the following
information.
In the normal course of business, the subsidiaries are
subject to various contingencies and uncertainties relating to
their operations and construction programs, including legal
actions and regulations and uncertainties related to
environmental matters. See Notes 4, 5, 6, and 7 to the
Consolidated Financial Statements for information about merger
activities, the Pennsylvania Customer Choice Act, and Maryland
activities relating to the deregulation of electricity
generation.
<PAGE>
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* Nonutility Operations
AYP Energy, one of the Company's nonutility
subsidiaries, is an exempt wholesale generator and power
marketer. At September 30, 1998, the marketing books of AYP
Energy consisted primarily of physical contracts with fixed
pricing. Most contracts were fixed-priced, forward-purchase
and/or sale contracts which require settlement by physical
delivery of electricity. These transactions result in market
risk which occurs when the market price of a particular
obligation or entitlement varies from the contract price. The
Company's exposure to volatility in the price of electricity and
other energy commodities is maintained within approved policy
limits.
* Year 2000 Readiness Disclosure
As the year 2000 approaches, most organizations,
including the Company, could experience serious problems related
to software and various equipment with embedded chips which may
not properly recognize calendar dates. To minimize such
problems, the Company is proceeding with a comprehensive effort
to continue operations without significant problems in the Year
2000 (Y2K) and beyond. An Executive Task Force is coordinating
the efforts of 23 separate Y2K Teams, representing all business
and support units in the Company.
The Company has segmented the Y2K problem into the
following components:
* Computer software
* Embedded chips in various equipment
* Vendors and other organizations on which the Company relies
for critical materials and services.
The Company's effort for each of these three components
includes assessment of the problem areas, remediation, testing
and contingency plans for critical functions for which
remediation and testing are not possible or which do not provide
reasonable assurance.
The Company has expended significant time and money over
the past several years on upgrading and replacing its large and
complex computer systems and software to achieve greater
efficiency as well as Y2K readiness. As a result, the Company
expects these systems to achieve a state of Y2K readiness on or
about March 31, 1999, subject to continuing review and testing.
Various equipment used by the Company includes thousands
of embedded chips. Most are not date sensitive, but identifying
those which are, and which are critical to operations, is a labor
intensive task. Identification, remediation, and testing in many
cases require the assistance of the original equipment
manufacturers. Even they frequently cannot state with certainty
if the chips they used are date sensitive. The Company's review
calls for the inventory and assessment of suspect embedded chips
in critical systems to be completed by December 31, 1998, with
remediation initiated as needs are identified, and with 1999 to
complete remediation and testing.
<PAGE>
- 24 -
Integrated electric utilities are uniquely reliant on
each other to avoid, in a worst case situation, cascading failure
of the entire electrical system. The Company is working with the
Edison Electric Institute (EEI), the Electric Power Research
Institute (EPRI), the North American Electric Reliability Council
(NERC), and the East Central Area Reliability Agreement group
(ECAR) to capitalize on industry-wide experiences and to
participate in industry-wide testing and contingency planning.
The effort with regard to vendors and other organizations is to
obtain reasonable assurance of their readiness to conduct
operations at the Year 2000 and beyond and, where reasonable
assurance is questionable, to develop contingency plans. Of
particular concern are telecommunications systems which are
integral to the Company's electricity production and distribution
operations. While the Company will develop contingency plans for
critical telecommunication needs, there can be no assurance that
the contingency plans could cope with a significant failure of
major telecommunication systems.
The Company is aware of the importance of electricity to
its service territory and its customers and is using its best
efforts to avoid any serious Y2K problems. Despite the Company's
best efforts, including working with internal resources, external
vendors, and industry associations, the Company cannot guarantee
that it will be able to conduct all of its operations without Y2K
interruptions. To the extent that any Y2K problem may be
encountered, the Company is committed to resolution as
expeditiously as possible to minimize the effect.
Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents an internal labor intensive effort of assessment,
remediation, and component testing for non-compliant embedded
chips in equipment, and a substantial labor intensive effort of
multiple systems testing, documentation, and working with other
parties. While outside contractors and equipment vendors will be
employed for some of the work, the Company believes it must rely
on its own employees for most of the effort because of their
experience with the Company's systems and equipment. The Company
currently estimates that its incremental expenditures for the
remaining Y2K effort will not exceed $15 million.
The descriptions herein of the elements of the Company's
Y2K effort are forward-looking statements as defined in the
Private Securities Litigation Reform Act of 1995. Of necessity,
this effort is based on estimates of assessment, remediation,
testing and contingency planning activities and dates for
perceived problems not yet identified. There can be no assurance
that actual results will not materially differ from expectations.
* Environmental Issues
The Environmental Protection Agency (EPA) issued its
final regional NOx State Implementation Plan (SIP) call rule on
September 24, 1998. EPA's SIP call rule finds that 22 eastern
states (including Maryland, Pennsylvania, and West Virginia) and
the District of Columbia are all contributing significantly to
ozone non-attainment in downwind states. The final rule
<PAGE>
- 25 -
declares that this downwind non-attainment will be eliminated (or
sufficiently mitigated) if the upwind states reduce their NOx
emissions by an amount that is precisely set by EPA on a state-by-
state basis. The final SIP call rule requires that all state-
adopted NOx reduction measures must be incorporated into SIPs by
September 24, 1999 and must be implemented by May 1, 2003. The
Company's compliance with these requirements would require the
installation of post-combustion control technologies on most, if
not all, of its power stations at a cost of approximately $360
million. The Company continues to work with other coal-burning
utilities and other affected constituencies in coal-producing
states to challenge this EPA action.
The regulated subsidiaries previously reported that the
EPA had identified them and approximately 875 others as
potentially responsible parties in a Superfund site subject to
cleanup. A final determination has not been made for the
subsidiaries' share of the remediation costs based on the amount
of materials sent to the site. The regulated subsidiaries have
also been named as defendants along with multiple other
defendants in pending asbestos cases involving one or more
plaintiffs. The subsidiaries believe that provisions for
liabilities and insurance recoveries are such that final
resolution of these claims will not have a material effect on
their financial position.
* Electric Energy Competition
The Company is working actively within its states to
advance customer choice. However, the Company believes that
federal legislation is necessary to ensure that electric
restructuring is implemented consistently across state and
regional boundaries so that all electric customers have an equal
opportunity to benefit from competition and customer choice by a
date certain. Federal legislation is also needed to remove
barriers to competition, including the repeal of both the Public
Utility Holding Company Act of 1935 and PURPA. The Company has
been working with Congress to advance these goals.
In addition to deregulation activities in Pennsylvania
and Maryland, the Company serves customers in three other states
which are exploring the move toward competition and deregulation.
The West Virginia Legislature passed a bill on March 14,
1998 which sets the stage for the restructuring of the electric
utility industry in West Virginia. The bill directed the Public
Service Commission of West Virginia (West Virginia PSC) to
determine if deregulation is in the best interests of the state
and, if so, to develop a transition plan. It also set up a task
force of all interested parties to participate in the plan
development. The West Virginia PSC has been conducting meetings
of the Task Force on Restructuring over the summer to examine if
competition is in the best interest of the state and, if so, to
develop a transition plan. All interested parties have
participated in the process with little apparent progress
concerning a defined plan for restructuring. Due to the workshop
participants' inability to file a consensus position on or before
November 16, 1998, the West Virginia PSC has scheduled additional
meetings in November to discuss how the West Virginia PSC and
workshop participants "should continue to explore electric
industry restructuring." Evidentiary hearings originally
scheduled for September 29, 1998 to address utility unbundling
and stranded cost filings were cancelled.
<PAGE>
- 26 -
In early March 1998, the Virginia Senate joined the House
of Delegates in approving a timetable for restructuring the
state's electric utility industry to allow retail competition.
The legislation will give Virginians choice of their electric
power suppliers beginning on January 1, 2004. The details will
be worked out over the coming year by a special Senate-House
subcommittee that has been studying restructuring for two years.
The joint legislative subcommittee studying utility restructuring
has held a series of meetings to examine the issues associated
with restructuring. Two subcommittees have been established to
examine structure and transmission issues and stranded costs.
All interested parties have been invited to participate in the
process. The Virginia State Corporation Commission (Virginia
SCC) ordered two utilities, but not the Company's Virginia
subsidiary, Potomac Edison, to develop and submit their retail
pilot programs to the Virginia SCC by November 1, 1998. Potomac
Edison has been filing monthly reports on the status of
Independent System Operator (ISO) discussions with the Virginia
SCC.
In late March, bills to start competition in Ohio were
introduced in both houses of the General Assembly. In their
current form, the bills would allow residential customers to
choose their electric provider beginning July 1, 1999, for
service beginning January 1, 2000. However, the bills have not
been fully supported by legislative bodies or by the utilities in
the state. In order to strike a compromise, the Ohio legislative
leadership asked the Ohio utilities to offer a compromise bill,
which the utilities recently presented. Negotiations are
continuing for introduction of the compromise bill.
<PAGE>
- 27 -
ALLEGHENY ENERGY, INC.
Part II - Other Information to Form 10-Q
for Quarter Ended September 30, 1998
ITEM 1. LEGAL PROCEEDINGS
On October 5, 1998, the Company filed a lawsuit in the
United States District Court for the Western District of
Pennsylvania against DQE, Inc. (DQE) for specific performance of
the Agreement and Plan of Merger among DQE, the Company, and AYP
Sub Inc., dated as of April 5, 1997 (the "Merger Agreement"), or
for damages. The Company also filed motions for a temporary
restraining order and preliminary injunction against DQE. On
October 28, 1998, the court denied the Company's motions for
temporary restraining order and preliminary injunction. On
October 30, 1998, the Company appealed the District Court's order
to the Third Circuit Court of Appeals. The Company cannot
predict the outcome of the litigation between it and DQE.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(27) Financial Data Schedule
(b) The Company filed 8-K's on July 27, 1998, July 30,
1998, October 7, 1998, and November 6, 1998.
Signature
Pursuant to the requirements of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly
authorized.
ALLEGHENY ENERGY, INC.
/s/ K. M. JONES
K. M. Jones, Vice President
(Chief Accounting Officer)
November 16, 1998
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