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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 March 31, 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 May 14, 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 March 31, 1998
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Consolidated statement of income -
Three months ended March 31, 1998 and 1997 3
Consolidated balance sheet - March 31, 1998
and December 31, 1997 4
Consolidated statement of cash flows -
Three months ended March 31, 1998 and 1997 5
Notes to consolidated financial statements 6-9
Management's discussion and analysis of financial
condition and results of operations 10-18
PART II--OTHER INFORMATION 19
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Income
<TABLE>
<CAPTION>
Three Months Ended
March 31
1998 1997
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES:
<S> <C> <C> <C> <C>
Utility $ 596,378 $ 602,692
Nonutility 49,094 12,288
Total Operating Revenues 645,472 614,980
OPERATING EXPENSES:
Operation:
Fuel 139,731 140,465
Purchased power and exchanges, net 86,767 50,583
Deferred power costs, net (6,637) (2,083)
Other 74,803 72,825
Maintenance 56,542 61,480
Depreciation 68,368 68,782
Taxes other than income taxes 50,426 48,656
Federal and state income taxes 50,765 50,178
Total Operating Expenses 520,765 490,886
Operating Income 124,707 124,094
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 1,067 1,150
Other income, net 778 896
Total Other Income and Deductions 1,845 2,046
Income Before Interest Charges and
Preferred Dividends 126,552 126,140
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 42,718 43,380
Other interest 4,018 3,833
Allowance for borrowed funds used during
construction (722) (965)
Dividends on preferred stock of subsidiaries 2,301 2,301
Total Interest Charges and
Preferred Dividends 48,315 48,549
CONSOLIDATED NET INCOME $ 78,237 $ 77,591
COMMON STOCK SHARES OUTSTANDING (average) 122,436,317 121,843,341
BASIC AND DILUTED EARNINGS PER AVERAGE SHARE $0.64 $0.64
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Consolidated Balance Sheet
<TABLE>
<CAPTION>
March 31, December 31,
1998 1997
(Thousands of Dollars)
ASSETS:
<S> <C> <C>
Property, Plant, and Equipment:
At original cost, including $233,684,000
and $229,785,000 under construction $ 8,487,292 $ 8,451,424
Accumulated depreciation (3,220,818) (3,155,210)
5,266,474 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
Other 6,716 6,551
103,384 101,102
Current assets:
Cash and temporary cash investments 15,366 26,374
Deposit with trustee for redemption
of long-term debt 43,142 -
Accounts receivable:
Electric service, net of $18,355,000 and
$17,191,000 uncollectible allowance 289,892 296,082
Other 14,024 12,312
Materials and supplies--at average cost:
Operating and construction 82,730 80,836
Fuel 74,179 63,361
Prepaid taxes 70,973 51,724
Other 13,034 24,005
603,340 554,694
Deferred Charges:
Regulatory assets 592,217 586,125
Unamortized loss on reacquired debt 49,171 49,550
Other 64,259 66,406
705,647 702,081
Total Assets $ 6,678,845 $ 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 1,085,358 1,059,768
2,282,488 2,256,898
Preferred stock 170,086 170,086
Long-term debt and QUIDS 2,215,604 2,193,153
4,668,178 4,620,137
Current Liabilities:
Short-term debt 198,281 206,401
Long-term debt due within one year 154,795 185,400
Accounts payable 119,009 129,989
Taxes accrued:
Federal and state income 46,212 10,453
Other 40,977 55,428
Interest accrued 41,130 40,000
Other 81,028 74,170
681,432 701,841
Deferred Credits and Other Liabilities:
Unamortized investment credit 131,334 133,316
Deferred income taxes 1,030,870 1,031,236
Regulatory liabilities 88,580 91,178
Other 78,451 76,383
1,329,235 1,332,113
Total Capitalization and Liabilities $ 6,678,845 $ 6,654,091
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Cash Flows
<TABLE>
<CAPTION>
Three Months Ended
March 31
1998 1997
(Thousands of Dollars)
CASH FLOWS FROM OPERATIONS:
<S> <C> <C> <C>
Consolidated net income $ 78,237 $ 77,591
Depreciation 68,368 68,782
Deferred investment credit and income taxes, net 14,193 11,652
Deferred power costs, net (6,637) (2,083)
Allowance for other than borrowed funds used
during construction (1,067) (1,150)
Restructuring liability (4,247) (16,805)
Changes in certain current assets and
liabilities:
Accounts receivable, net 4,478 (2,587)
Materials and supplies (12,712) (14,221)
Accounts payable (10,980) (23,416)
Taxes accrued 21,308 18,557
Other, net (9,853) 20,418
141,088 136,738
CASH FLOWS FROM INVESTING:
Utility construction expenditures (less allowance
for equity funds used during construction) (39,541) (42,169)
Nonutility investments (140) (81)
(39,681) (42,250)
CASH FLOWS FROM FINANCING:
Sale of common stock - 8,041
Issuance of long-term debt 45,795 -
Retirement of long-term debt (54,300) (21,892)
Deposit with trustee for redemption
of long-term debt (43,142) -
Short-term debt, net (8,120) (22,684)
Cash dividends on common stock (52,648) (52,391)
(112,415) (88,926)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS (11,008) 5,562
Cash and Temporary Cash Investments at January 1 26,374 19,242
Cash and Temporary Cash Investments at March 31 $ 15,366 $ 24,804
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $41,604 $42,508
Income taxes 3,738 -
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Notes to Consolidated Financial Statements
1. The Company's Notes to Consolidated Financial Statements in
its Annual Report on Form 10-K for the year ended December
31, 1997, should be read with the accompanying 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 (which consist only of normal
recurring adjustments) necessary to present fairly the
Company's financial position as of March 31, 1998, and the
results of operations and cash flows for the three months
ended March 31, 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 is jointly (100%) owned by the Company's
operating subsidiaries and thus 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. 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. The combined company
will be called Allegheny Energy, Inc. (Allegheny Energy).
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 April 30, 1998, the Pennsylvania Public Utility Commission
(PUC) adopted a motion (the "Order") approving the merger
subject to a condition precedent that the merged entity joins
a Federal Energy Regulatory Commission (FERC) approved, fully
functioning Independent System Operator (ISO). The Order
specifically approved the Midwest ISO as satisfying the
condition precedent provided it was FERC approved and fully
functioning. The Company has joined the Midwest ISO,
contingent only on merger consummation, but it is not
projected to be FERC approved and fully functioning until on
or after January 1, 2000.
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The Order also noted that the Pennsylvania, New Jersey,
Maryland, L.L.C. ISO (PJM ISO) might also satisfy the pre-
condition but that it would require an updated study and
analysis be submitted to the PUC. The PJM ISO is FERC
approved and fully functioning. The PUC Order noted that the
merger would produce substantial savings and further noted
that an 18-month delay recommended by two Administrative Law
Judges (ALJs) in their recommended decision of March 25,
1998, was not in the public interest. The Company is
dismayed that the PUC nevertheless imposed a condition
precedent that could impose a delay likely to be as long or
longer than recommended by the ALJs. Upon official entry of
the PUC's Order, the Company is likely to file a motion for
reconsideration to allow the merger to go forward immediately
as it has already joined the Midwest ISO and has already
pledged sufficient interim mitigation measures until the
Midwest ISO is functioning, including temporary
relinquishment of control of 570 megawatts of generation to
mitigate market power concerns. The Company may also propose
additional interim mitigation measures. The Company is also
exploring further the PJM ISO. The Company believes the
merger is unlikely to be completed if the pre-condition in
the Order actually imposes significant delay.
The Nuclear Regulatory Commission (NRC) 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.
Merger-related decisions are expected by the end of the
second quarter from the FERC, the Department of
Justice/Federal Trade Commission, and the Securities and
Exchange Commission. The Company is also filing for review
of certain merger-related activities with the Public Service
Commission of West Virginia and the Virginia State
Corporation Commission.
All of the Company's incremental costs of the merger process
($12.8 million through March 31, 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
the merger does 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 Pennsylvania customers. On
August 1, 1997, concurrent with the Company's merger approval
filing, the Company's Pennsylvania subsidiary, West Penn
Power Company (West Penn), filed with the PUC a comprehensive
stand-alone restructuring plan to implement full customer
choice of electric generation suppliers as required by the
Customer Choice Act. The filing included an unbundling of
West Penn's electric service rates into generation,
transmission, and distribution components; a plan to revise
how the Company's three utility subsidiaries share capacity,
energy, capacity reserves, transmission resources, and costs;
and a plan for recovery of stranded costs through a
Competitive Transition Charge (CTC). Recovery of stranded
costs is a key issue.
On April 30, 1998, the PUC, in a non-binding polling outlined
a restructuring plan for West Penn. Under the non-binding
polling, West Penn would provide residential customers who
shop for their electricity a
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shopping credit of about 3.12 cents per kilowatt-hour (kWh)
beginning in January 1999, and about 3.23 cents per kWh
beginning in January 2000. Shopping credits will vary from
one rate class to another and will increase over the
transition period. According to the polling, West Penn is
allowed to collect $524 million in stranded costs over seven
years, starting in January 1999, through a CTC. In its
restructuring application, West Penn had requested $1.6
billion in stranded costs. Stranded costs are costs incurred
under a regulated environment which are not recoverable in a
competitive market. The PUC polling indicated that one-third
of West Penn's customers will be able to buy power from the
supplier of their choice on January 1, 1999, another one-
third on the following day, January 2, 1999, and the
remainder on January 2, 2000. In a separate action, the PUC
directed that open enrollment for Pennsylvania customers to
choose their electric generation suppliers will begin on July
1, 1998. Starting in 1999, West Penn would unbundle its
rates to reflect separate prices for the generation charge,
the CTC, and transmission and distribution charges. While
generation would be open to competition, West Penn would
continue to provide transmission and distribution services to
its customers at PUC and FERC regulated rates. The Company
believes that the $524 million of stranded costs recommended
for recovery is inadequate and financially harmful to West
Penn. The non-binding polling of the PUC is a preliminary
step leading up to a final order on West Penn's restructuring
plan expected May 21, 1998. If the PUC's final order remains
as financially harmful as the polling, West Penn plans to
seek redress through reconsideration by the PUC and/or full
judicial review and/or legislative revision of the Customer
Choice Act.
In December 1997, in an initial Order followed by a second
Order revising certain implementation dates, the Maryland PSC
ordered an electric competition transition plan requiring
full retail customer choice by July 1, 2002, in yearly one-
third increments beginning July 1, 2000; a price cap
mechanism; recovery of verifiable and prudent stranded costs
(after mitigation); and roundtable and adjudicatory
proceedings to address issues such as universal service,
demand-side management programs, customer education, etc. In
its Order, the PSC stated its belief that it had the
authority under existing law to implement the Order, but
requested the legislature to enact certain "technical
amendments" to facilitate the transition.
6. In July 1997, the Emerging Issues Task Force (EITF) of the
Financial Accounting Standards Board (FASB) released Issue
Number 97-4, Deregulation of the Pricing of Electricity -
Issues Related to the Application of FASB Statement Numbers
71 and 101, which concluded that utilities should discontinue
application of Statement of Financial Accounting Standards
(SFAS) No. 71 for the generation portion of their business
when a deregulation plan is in place and its terms are known.
Since the Customer Choice Act in Pennsylvania and a December
1997 Maryland PSC Order requiring customer choice establish
such processes, West Penn and Potomac Edison have determined
that they will be required to discontinue use of SFAS No. 71
for the generation portion of their business (the Maryland
portion only for Potomac Edison) on May 21, 1998 for West
Penn, the date by which the PUC must issue its order on West
Penn's comprehensive restructuring plan, and an uncertain
future date for Potomac Edison. One of the conclusions of
the EITF is that after discontinuing SFAS No. 71 utilities
should continue to carry on their books the assets and
liabilities recorded under SFAS No. 71 if the regulatory cash
flows to
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settle them will be derived from the continuing regulated
transmission and distribution business. Additionally,
continuing costs and obligations of the deregulated
generation business which are similarly covered by the cash
flows from the continuing regulated business will meet the
criteria as regulatory assets and liabilities.
The Customer Choice Act and the Maryland Order establish
definitive processes for transition to deregulation and
market-based pricing for electric generation, which include
continuing cost-of-service based ratemaking for transmission
and distribution services, subject to rate caps, and provide
for a nonbypassable CTC to give utilities the opportunity to
recover their stranded costs over the transition period.
Until relevant regulatory proceedings are complete and final
orders are received, West Penn and Potomac Edison are unable
to predict the effect of discontinuing SFAS No. 71, but they
may be required to write off significant unrecoverable
regulatory assets, impaired assets, and uneconomic
commitments.
7. Common stock dividends per share declared during the periods
for which income statements are included are as follows:
Three Months Ended
March 31
1998 1997
Number of Shares 122,436,317 121,840,327
Amount per Share $.43 $.43
8. For the most part, regulatory assets and liabilities are not
included in rate base. Income tax regulatory
assets/(liabilities), net of $422 million at March 31, 1998,
are primarily related to investments in electric facilities.
The portion related to transmission and distribution
facilities will be recovered over periods of from 20 to 40
years under the expected continuing regulated transmission
and distribution business. The portion related to generation
business in Pennsylvania has been included in West Penn's
stranded costs for CTC recovery. Similar treatment is
expected in the other states when they require the generation
business to be deregulated, which is expected. The remaining
recovery period for items other than income taxes is from
three to seven years in businesses that remain subject to
regulation. The final decision by the PUC related to
recovery of West Penn's stranded costs, as filed in its
restructuring application, is expected May 21, 1998.
9. Certain of the Company's subsidiaries use derivative
instruments to manage risk exposure associated with energy
contracts. Such instruments are used in accordance with a
risk management policy adopted by the Board of Directors.
The fair value of such instruments at March 31, 1998, is not
materially different from book value.
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ALLEGHENY ENERGY, INC.
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF FIRST QUARTER OF 1998 WITH FIRST QUARTER OF 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 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. 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; future economic conditions; earnings retention and
dividend payout policies; developments in the legislative,
regulatory, and competitive environments in which the Company
operates; environmental legislative and regulatory changes; and
other circumstances that could affect anticipated revenues and
costs, such as unscheduled maintenance or repair requirements and
compliance with laws and regulations.
Significant Events in the First Quarter of 1998
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
issuance of stock for the merger with DQE, Inc. (DQE). This
action was requested in connection with the proposed issuance of
Allegheny Energy stock to exchange for DQE stock to complete the
merger. Thereafter, the Nuclear Regulatory Commission approved
the transfer of control of the operating licenses for Duquesne
Light Company's (Duquesne) Beaver Valley Unit No.'s 1 and 2 and
Perry Unit No. 1 nuclear plants as required for the proposed
merger between Allegheny Power System, Inc. and DQE, parent
company of Duquesne. Duquesne will still be the licensee, but
the approval was necessary since control of Duquesne after the
merger will pass from DQE to the Company.
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On April 30, 1998, the Pennsylvania Public Utility
Commission (PUC) adopted a motion (the "Order") approving the
merger subject to a condition precedent that the merged entity
joins a Federal Energy Regulatory Commission (FERC) approved,
fully functioning Independent System Operator (ISO). The Order
specifically approved the Midwest ISO as satisfying the condition
precedent provided it was FERC approved and fully functioning.
The Company has joined the Midwest ISO, contingent only on merger
consummation, but it is not projected to be FERC approved and
fully functioning until on or after January 1, 2000. The Order
also noted that the Pennsylvania, New Jersey, Maryland, L.L.C.
ISO (PJM ISO) might also satisfy the pre-condition but that it
would require an updated study and analysis be submitted to the
PUC. The PJM ISO is FERC approved and fully functioning. The
PUC Order noted that the merger would produce substantial savings
and further noted that an 18-month delay recommended by two
Administrative Law Judges (ALJs) in their recommended decision of
March 25, 1998, was not in the public interest. The Company is
dismayed that the PUC nevertheless imposed a condition precedent
that could impose a delay likely to be as long or longer than
recommended by the ALJs. Upon official entry of the PUC's Order,
the Company is likely to file a motion for reconsideration to
allow the merger to go forward immediately as it has already
joined the Midwest ISO and has already pledged sufficient interim
mitigation measures until the Midwest ISO is functioning,
including temporary relinquishment of control of 570 megawatts of
generation to mitigate market power concerns. The Company may
also propose additional interim mitigation measures. The Company
is also exploring further the PJM ISO. The Company believes the
merger is unlikely to be completed if the pre-condition in the
Order actually imposes significant delay.
On April 30, 1998, the PUC, in a non-binding polling
outlined a restructuring plan for West Penn. Under the non-
binding polling, West Penn would provide residential customers
who shop for their electricity a shopping credit of about 3.12
cents per kilowatt-hour (kWh) beginning in January 1999, and
about 3.23 cents per kWh beginning in January 2000. Shopping
credits will vary from one rate class to another and will
increase over the transition period. According to the polling,
West Penn is allowed to collect $524 million in stranded costs
over seven years, starting in January 1999, through a Competitive
Transition Charge (CTC). In its restructuring application, West
Penn had requested $1.6 billion in stranded costs. Stranded
costs are costs incurred under a regulated environment, which are
not recoverable in a competitive market. The PUC polling
indicated that one-third of West Penn's customers will be able to
buy power from the supplier of their choice on January 1, 1999,
another one-third on the following day, January 2, 1999, and the
remainder on January 2, 2000. In a separate action, the PUC
directed that open enrollment for Pennsylvania customers to
choose their electric generation suppliers will begin on July 1,
1998. Starting in 1999, West Penn would unbundle its rates to
reflect separate prices for the generation charge, the CTC, and
transmission and distribution charges. While generation would be
open to competition, West Penn would continue to provide
transmission and distribution services to its customers at PUC
and FERC regulated rates. The Company believes that the $524
million of stranded costs recommended for recovery is inadequate
and financially harmful to West Penn. The non-binding polling of
the PUC is a preliminary step leading up to a final order on West
Penn's restructuring plan expected May 21, 1998. If the PUC's
final order remains as financially harmful as the polling, West
Penn plans to seek redress through reconsideration by the PUC
and/or full judicial review and/or legislative revision of the
Customer Choice Act.
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In Maryland on January 30, 1998, the Office of People's
Counsel filed a petition to reduce the rates of The Potomac
Edison Company (Potomac Edison). In response, the Maryland PSC
ordered Potomac Edison to file a rate case by May 22, 1998.
Review of Operations
EARNINGS SUMMARY
Three Months Ended March
Earnings Per Share
1998 1997 1998 1997
(Millions of Dollars) (Dollars Per Share)
Utility Operations $82.1 $80.6 $ .67 $ .66
Nonutility Operations (3.9) (3.0) (.03) (.02)
Consolidated Net Income $78.2 $77.6 $ .64 $ .64
Earnings for the first quarter of 1998 were up slightly
from the first quarter of 1997 despite a 4.4% reduction in
residential kilowatt-hour (kWh) sales to regular utility
customers resulting from the extremely mild winter weather in
1998. The 1998 winter was 14% warmer than 1997 and 21% warmer
than normal as measured by heating degree days and was the
warmest in more than 100 years. The slight increase in earnings
was achieved by continuing efforts to reduce operations and
maintenance (O&M) expenses and a 4.3% increase in kWh sales to
industrial customers.
SALES AND REVENUES
Total operating revenues for the first quarter of 1998
and 1997 were as follows:
Three Months Ended
March 31
1998 1997
(Millions of Dollars)
Operating revenues:
Utility revenues:
Bundled retail sales $554.9 $567.4
Unbundled retail sales 3.6 -
Wholesale and other 18.1 16.6
Utility bulk power, including
transmission services 19.8 18.7
Total utility revenues 596.4 602.7
Nonutility revenues 49.1 12.3
Total operating revenues $645.5 $615.0
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The decrease in bundled retail sales (full service sales
to retail customers) is due in part to reduced residential kWh
sales to retail customers due to the mild first quarter winter
weather. The 1998 first quarter winter weather was 14% warmer
than 1997 and 21% warmer than normal as measured by heating
degree days. The decrease in bundled retail sales revenue was
also due in part to 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
must choose a generation supplier other than their own local
franchise utility. As a result, up to 5% of previously fully
bundled customers were able to participate in the Pennsylvania
pilot program and were allowed to buy energy from a supplier of
their choice. The pilot programs began on November 1, 1997, and
will continue through December 31, 1998. Unbundled retail sales
revenues represents transmission and distribution revenues for
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 will reach agreement with an alternate supplier as to
the price for energy. The credit established by the PUC is
artificially high (greater than West Penn's generation costs),
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 includes an accrual of such revenue losses, 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 and other was
due primarily to $1.9 million of deferred net revenue losses
recorded as a regulatory asset to offset revenue losses suffered
as a result of the pilot.
The increase in nonutility revenues resulted primarily
from increased sales by the Company's nonutility exempt wholesale
generator and power marketer, AYP Energy, Inc., which began
operations in late 1996. Also, Allegheny Energy Solutions, Inc.
which was formed in the third quarter of 1997 to market energy to
retail customers in deregulated markets and other energy-related
services, recorded $5.5 million of revenues for its first full
quarter of operations in 1998.
OPERATING EXPENSES
Fuel expenses for the first quarter of 1998 and 1997 were
as follows:
Three Months Ended
March 31
1998 1997
(Millions of Dollars)
Utility operations $134.7 $134.7
Nonutility operations 5.0 5.8
Total fuel expenses $139.7 $140.5
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Fuel expenses for utility operations for the first
quarter remained unchanged. The decrease in fuel expenses for
nonutility operations was due primarily to a decrease in kWh's
generated at Unit No. 1 of the Fort Martin Power Station which is
50% owned by the Company's nonutility subsidiary, AYP Energy,
Inc.
Purchased power and exchanges, net represents power
purchases from and exchanges with other companies and purchases
from qualified facilities under the Public Utility Regulatory
Policies Act of 1978 (PURPA), and consists of the following
items:
Three Months Ended
March 31
1998 1997
(Millions of Dollars)
Purchased power:
Utility operations:
From PURPA generation* $34.2 $34.7
Other 8.9 8.5
Total purchased power for utility operations 43.1 43.2
Power exchanges, net 3.5 4.1
Nonutility operations 40.2 3.3
Purchased power and exchanges, net $86.8 $50.6
* PURPA cost (cents per kWh) 5.5 5.7
Nonutility operations' purchases were the result of power
replacement requirements and transaction opportunities by AYP
Energy, which began operations in late 1996.
A PURPA power station project in The Potomac Edison
Company's (Potomac Edison) Maryland jurisdiction is scheduled to
commence generation in 1999. Because of the high cost of this
energy, 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.
None of the subsidiaries' purchased power contracts are
capitalized since there are no minimum payment requirements
absent associated kWh generation and under a regulated
environment recovery of the costs are reasonably assured.
Other operation expenses were as follows:
Three Months Ended
March 31
1998 1997
(Millions of Dollars)
Utility operations $71.1 $70.2
Nonutility operations 3.7 2.6
Total other operation expenses $74.8 $72.8
<PAGE>
- 15 -
The increase in utility other operation expenses resulted
primarily from increased expenses related to competition and the
Pennsylvania pilot ($1.6 million) and increased allowances for
uncollectible accounts ($1.4 million). These increases were
offset in part by a reduction in expenses related to provisions
for uninsured claims ($1.8 million). A contributing factor to
the increased nonutility operation expenses was $1.1 million of
expenses incurred by Allegheny Energy Solutions, Inc. (Allegheny
Energy Solutions) in marketing energy to retail customers in the
Pennsylvania pilot. The first quarter of 1998 was the first full
quarter of operations for Allegheny Energy Solutions. Both West
Penn and Allegheny Energy Solutions expect to incur increased
advertising and other sales-related expenditures to enhance sales
and to build brand name recognition.
Maintenance expenses decreased $4.9 million for the first
quarter due primarily to reduced utility expenses of $5.6 million
achieved through restructuring efforts and other cost controls.
This reduction was offset in part by increased nonutility
maintenance expense of $.7 million related to AYP Energy, Inc.'s
50% ownership in Unit No. 1 of the Fort Martin Power Station.
Maintenance expenses represent costs incurred to maintain the
power stations, the transmission and distribution (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 in the first quarter decreased $.4
million, the net result of a $.5 million decrease for utility
operations and a $.1 million increase for nonutility operations.
The utility decrease reflects a reduction in West Penn's annual
depreciation expense determined to be necessary as part of its
comprehensive restructuring filing required by the Customer
Choice Act.
Taxes other than income taxes increased $1.8 million in
the first quarter due primarily to increased utility taxes of
$1.5 million due primarily to increased West Virginia Business
and Occupation Taxes resulting from an adjustment for a prior
period and increased property taxes related to an increase in the
assessment of property in Maryland. Nonutility taxes other than
income increased $.3 million due primarily to an increase in
gross receipts taxes resulting from higher revenues due to
Allegheny Energy Solutions sales to retail customers. The first
quarter of 1998 was the first full quarter of operations for
Allegheny Energy Solutions.
Financial Condition and Requirements
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 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 and 5 to the
<PAGE>
- 16 -
Consolidated Financial Statements for information about merger
activities, the Pennsylvania Customer Choice Act, and the
Maryland initial Order.
The Financial Accounting Standards Board's Statement of
Financial Accounting Standards No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of", establishes standards for impairment of long-lived
assets and certain identifiable intangibles and requires
companies to recognize an impairment loss if the expected future
undiscounted cash flows are less than the carrying value of an
asset. Due in part to the evolving process of the electric
utility industry in the United States changing from a
historically regulated monopolistic market to a competitive
marketplace, the competitive market price of energy and the
resultant undiscounted cash flows could be less than the carrying
value of power stations. If that were to occur, an impairment
loss would be required to be recognized in an amount by which the
book value of the power stations exceeded their market value. As
part of the final PUC Order expected on May 21, 1998, the PUC
will make a final decision as to the amount of stranded costs
allowed to be recovered by West Penn through a CTC. At its non-
binding polling on April 30, 1998, the PUC indicated a plan for
West Penn to recover $524 million of the $1.6 billion of stranded
costs requested by West Penn in its restructuring filing. In its
final order, if the PUC does not increase the proposed $524
million of stranded costs that West Penn would be allowed to
recover, the resultant decrease in future undiscounted cash flows
related to energy recovery associated with the power stations may
become less than the book value of West Penn's power stations.
In that event, an asset impairment loss would be required to be
recognized. Dependent upon the May 21, 1998, final PUC order
associated with the amount of West Penn's stranded costs approved
for future recovery, West Penn may need to record an impairment
loss in the second quarter of 1998 to write-down the book value
of its power stations. The Company and West Penn are currently
evaluating West Penn's power station assets for potential
impairment, contingent upon the expected May 21, 1998, final PUC
Order. The Company and West Penn are also evaluating the
possibility that a write-off may also be required for
unrecoverable regulatory assets and the excess costs of a PURPA
project if the May 21 Order remains substantially similar to the
polling.
Certain of the Company's subsidiaries use derivative
instruments to manage the risk exposure associated with contracts
they write for the purchase and/or sale of electricity for
receipt or delivery at future dates. Such instruments are used
in accordance with a risk management policy adopted by the Board
of Directors and monitored by an Exposure Management Committee of
senior management. The policy requires continuous monitoring,
reporting, and stress testing of all open positions for
conformity to policies which limit value at risk and market risk
associated with the credit standing of trading counterparties.
Such credit standings must be investment grade or better, or be
guaranteed by a parent company with such a credit standing for
all over-the-counter instruments.
At March 31, 1998, the trading books of the Company's
subsidiaries consisted primarily of physical contracts with fixed
pricing. Most contracts were fixed-priced, forward purchase
and/or sale contracts which required settlement by physical
delivery of electricity. During 1998, the subsidiaries also
entered into option contracts which, if exercised, were settled
with physical delivery of electricity. These transactions result
in market risk which occurs when the market price of a particular
obligation or entitlement
<PAGE>
- 17 -
varies from the contract price. As the Company continues to
develop its power marketing and trading business, its exposure to
volatility in the price of electricity and other energy
commodities may increase within approved policy limits.
The Company's subsidiaries have spent considerable time
and effort over the past several years on the issue of the year
2000 software compliance, and the effort is continuing. Certain
software has already been made year 2000 compliant by upgrades
and replacement, and analysis is continuing on others, in
accordance with a schedule planned to permit the subsidiaries to
process information in the year 2000 and beyond without
significant problems. Expenditures for year 2000 compliance are
not expected to have a material effect on the Company's results
of operations or financial position.
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.
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 Public Utility Holding
Company Act of 1935 and PURPA.
In addition to Pennsylvania, which has enacted
legislation to bring competition to the electric utility
industry, the Company serves customers in four other states which
are actively exploring the move toward competition and
deregulation.
The West Virginia Legislature passed a House Bill on
March 14, 1998, which sets the stage for the restructuring of the
electric utility industry in West Virginia. The House Bill
directs the West Virginia Public Service Commission to determine
if deregulation is in the best interests of the state and, if so,
to develop a transition plan. It also sets up a task force of all
interested parties to participate in the plan development. When
complete, the plan will be returned to the Legislature for
approval or rejection.
In early March, 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.
<PAGE>
- 18 -
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.
In late March, on the federal level, the Clinton
Administration outlined its electricity deregulation proposal in
a set of "principles" for Congress. The proposal sets January 1,
2003, as the start date for customer choice. States that have
already deregulated would be allowed to maintain the structures
they have created, and low-cost states could opt out if they
believe their consumers would not benefit from competition.
<PAGE>
- 19 -
ALLEGHENY ENERGY, INC.
Part II - Other Information to Form 10-Q
for Quarter Ended March 31, 1998
ITEM 1. LEGAL PROCEEDINGS
On September 29, 1997, the City of Pittsburgh filed an
antitrust and conspiracy lawsuit in the Federal District Court
for the Western District of Pennsylvania against the Company,
West Penn, DQE, Inc. and Duquesne Light Company. The complaint
alleged eight counts, two of which were claimed violations of the
antitrust statutes and six were state law claims. The relief
sought included a request that the proposed merger between the
Company and DQE, Inc. be stopped. The complaint also requested
unspecified monetary damages relating to alleged collusion
between the two companies in their actions dealing with proposals
to provide electric service to redevelopment zones in the city.
On October 27, 1997, all defendants filed motions to dismiss the
complaint. On January 6, 1998, the District Court issued an
order which granted the motions to dismiss. On January 14, 1998,
the city appealed the order to the United States Court of Appeals
for the Third Circuit. The Company and West Penn cannot predict
the outcome of this appeal.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(27) Financial Data Schedule
(b) On March 23, 1998, the Company filed a Form 8-K
concerning the Senior Officer Separation Plan which may
be offered to certain of its officers after consummation
of the merger between Allegheny Energy, Inc. and DQE,
Inc. At the Company's December 4, 1997, Board of
Directors Meeting, the Board approved the Separation
Plan.
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)
May 14, 1998
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