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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 June 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 August 13, 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 June 30, 1998
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Consolidated statement of income -
Three and six months ended June 30, 1998 and 1997 3
Consolidated balance sheet - June 30, 1998
and December 31, 1997 4
Consolidated statement of cash flows -
Six months ended June 30, 1998 and 1997 5
Notes to consolidated financial statements 6-10
Management's discussion and analysis of financial
condition and results of operations 11-22
PART II--OTHER INFORMATION 23-25
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ALLEGHENY ENERGY, INC.
Statement of Income
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES:
Utility $ 564,005 $ 530,500 $ 1,160,383 $ 1,133,192
Nonutility 63,645 12,250 112,739 24,538
Total Operating Revenues 627,650 542,750 1,273,122 1,157,730
OPERATING EXPENSES:
Operation:
Fuel 139,555 133,277 279,286 273,742
Purchased power and exchanges, net 95,688 43,766 182,455 94,349
Deferred power costs, net 4,386 (4,870) (2,251) (6,953)
Other 82,163 71,863 156,966 144,688
Maintenance 55,929 59,807 112,471 121,287
Depreciation 68,512 68,754 136,880 137,536
Taxes other than income taxes 47,037 47,192 97,463 95,848
Federal and state income taxes 34,315 27,488 85,080 77,666
Total Operating Expenses 527,585 447,277 1,048,350 938,163
Operating Income 100,065 95,473 224,772 219,567
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 249 1,126 1,316 2,276
Other income, net 845 3,684 1,623 4,580
Total Other Income and Deductions 1,094 4,810 2,939 6,856
Income Before Interest Charges and
Preferred Dividends 101,159 100,283 227,711 226,423
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 40,831 43,554 83,549 86,934
Other interest 4,631 3,786 8,649 7,619
Allowance for borrowed funds used during
construction (504) (1,065) (1,226) (2,030)
Dividends on preferred stock of subsidiaries 2,310 2,325 4,611 4,626
Total Interest Charges and
Preferred Dividends 47,268 48,600 95,583 97,149
Consolidated Income Before
Extraordinary Charge 53,891 51,683 132,128 129,274
Extraordinary Charge, net (1) (265,446) - (265,446) -
CONSOLIDATED NET (LOSS) INCOME $ (211,555) $ 51,683 $ (133,318) $ 129,274
COMMON STOCK SHARES OUTSTANDING (average) 122,436,317 122,114,920 122,436,317 121,979,881
BASIC AND DILUTED EARNINGS PER AVERAGE SHARE:
Consolidated income before extraordinary charge $0.44 $0.42 $1.08 $1.06
Extraordinary charge, net (1) ($2.17) - ($2.17) -
Consolidated net (loss) income ($1.73) $0.42 ($1.09) $1.06
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
June 30, December 31,
1998 1997
(Thousands of Dollars)
ASSETS:
Property, Plant, and Equipment:
At original cost, including $199,637,000
and $229,785,000 under construction $ 8,485,290 $ 8,451,424
Accumulated depreciation (3,249,382) (3,155,210)
5,235,908 5,296,214
Investments and Other Assets:
Subsidiaries consolidated--excess of cost
over book equity at acquisition 15,077 15,077
Benefit plan's investments 81,591 79,474
Nonutility investments 6,386 4,992
Other 1,579 1,559
104,633 101,102
Current assets:
Cash and temporary cash investments 18,259 26,374
Accounts receivable:
Electric service, net of $20,048,000 and
$17,191,000 uncollectible allowance 305,217 296,082
Other 19,372 12,312
Materials and supplies--at average cost:
Operating and construction 82,134 80,836
Fuel 76,010 63,361
Prepaid taxes 66,728 51,724
Other 22,412 24,005
590,132 554,694
Deferred Charges:
Regulatory assets 744,074 586,125
Unamortized loss on reacquired debt 47,820 49,550
Other 64,023 66,406
855,917 702,081
Total Assets $ 6,786,590 $ 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 821,155 1,059,768
2,018,285 2,256,898
Preferred stock 170,086 170,086
Long-term debt and QUIDS 2,151,567 2,193,153
4,339,938 4,620,137
Current Liabilities:
Short-term debt 377,574 206,401
Long-term debt due within one year 10,000 185,400
Accounts payable 143,294 129,989
Taxes accrued:
Federal and state income 3,562 10,453
Other 40,820 55,428
Interest accrued 37,592 40,000
Other 83,203 74,170
696,045 701,841
Deferred Credits and Other Liabilities:
Unamortized investment credit 129,352 133,316
Deferred income taxes 866,752 1,031,236
Regulatory liabilities 84,651 91,178
Adverse power purchase commitments 585,918 -
Other 83,934 76,383
1,750,607 1,332,113
Total Capitalization and Liabilities $ 6,786,590 $ 6,654,091
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Cash Flows
Six Months Ended
June 30
1998 1997
(Thousands of Dollars)
CASH FLOWS FROM OPERATIONS:
Consolidated net (loss) income $ (133,318) $ 129,274
Extraordinary charge, net of taxes 265,446 -
Consolidated income before extraordinary charge 132,128 129,274
Depreciation 136,880 137,536
Deferred investment credit and income taxes, net 16,118 27,711
Deferred power costs, net (2,251) (6,953)
Allowance for other than borrowed funds used
during construction (1,316) (2,276)
Restructuring liability (5,504) (24,321)
Changes in certain current assets and
liabilities:
Accounts receivable, net (16,195) 22,221
Materials and supplies (13,947) (19,910)
Accounts payable 13,305 (44,949)
Taxes accrued (21,499) (22,844)
Other, net 8,821 14,190
246,540 209,679
CASH FLOWS FROM INVESTING:
Utility construction expenditures (less allowance
for equity funds used during construction) (98,245) (100,065)
Nonutility investment (3,988) (2,253)
(102,233) (102,318)
CASH FLOWS FROM FINANCING:
Sale of common stock - 16,110
Issuance of long-term debt 45,795 -
Retirement of long-term debt (264,095) (21,892)
Short-term debt, net 171,173 5,140
Cash dividends on common stock (105,295) (104,899)
(152,422) (105,541)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS (8,115) 1,820
Cash and Temporary Cash Investments at January 1 26,374 19,242
Cash and Temporary Cash Investments at June 30 $ 18,259 $ 21,062
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $87,794 $89,401
Income taxes 86,214 59,960
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 June 30, 1998, the results of operations for the three
and six months ended June 30, 1998 and 1997, and cash flows
for the six months ended June 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. 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 ISO is the
regional transmission entity that will best serve the
interests of the Ohio customers of the Company and will best
mitigate the market power issue.
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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, 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 may be required to divest
up to 2,500 MW of generation, subject to a PUC Order.
In a letter dated July 28, 1998 to the Company, 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 will 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.
All of the Company's incremental costs of the merger process
($14.4 million through June 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
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, the Company's Pennsylvania subsidiary,
West Penn Power Company (West Penn), filed with the PUC a
comprehensive restructuring plan to implement full
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customer choice of electric generation suppliers as required
by the Customer Choice Act. The filing included a plan for
recovery of stranded costs through a Competitive Transition
Charge (CTC).
On May 29, 1998, West Penn received a final Order from the
PUC denying full recovery of its stranded cost claim. The
Order authorized recovery of $524 million in stranded costs,
with return, over the 1999 through 2005 period, of the
approximately $1.2 billion available for recovery under the
capped rates mandated by the Customer Choice Act.
On June 26, 1998, the PUC denied a request by West Penn for
reconsideration of the May 29, 1998 PUC Order on West Penn's
restructuring plan. In denying the request for
reconsideration, the PUC let stand the earlier Order under
which West Penn would provide 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
vary from one rate class to another and increase over a seven-
year transition period. Under the reconsideration Order,
West Penn would be allowed to collect $525 million ($.5
million more than the previous Order) in stranded costs, with
a return, over seven years, starting in January 1999, through
the CTC. Although in its restructuring application, West
Penn had listed $1.6 billion in stranded costs, because of
capped rates, West Penn would be limited to $1.2 billion in
stranded cost recovery under the Customer Choice Act.
Stranded costs are costs incurred under a regulated
environment, which are not expected to be recoverable in a
competitive market. Actual recovery of such costs will
depend upon the market prices for electricity in future
periods and the number of West Penn customers who choose
other generation suppliers. The PUC Order on West Penn's
restructuring plan assumed significantly higher electricity
prices in future years than the Company believed were
appropriate.
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 Federal Energy Regulatory Commission
(FERC) regulated rates.
The Company believes that the $525 million of stranded costs
recommended for recovery is contrary to legal requirements
and does not adequately reflect the potential effects of
competition on West Penn. On June 26, 1998, West Penn filed
a formal appeal in state court and an action in federal court
challenging the PUC's restructuring Order. On July 23, 1998,
West Penn also filed in the Commonwealth Court of
Pennsylvania a petition for a stay of the two-thirds, one-
third phase-in schedule ordered by the PUC. On August 5,
1998, West Penn withdrew its petition for stay without
prejudice based on a PUC agreement to offer settlement
discussions on issues related to the PUC's restructuring
Order.
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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 March 1999. A second PSC proceeding is planned to
begin examining market power protective measures in December
1999.
6. As a result of the 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 has also
determined that under the provisions of SFAS No. 101 an
extraordinary charge of $450.6 million ($265.4 million after
taxes) is required to reflect a write-off of disallowances in
the PUC's Order. The 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:
(In Millions)
AES Beaver Valley nonutility generation contract $201.4
Allegheny Generating Company (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
(In Millions)
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
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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.
The Company continues to review the financial impact of the
PUC's Order. Ultimately, future financial effects depend on
the number of West Penn customers who choose other generation
suppliers and the market price of electricity during the
transition period.
7. Common stock dividends per share declared during the periods
for which income statements are included are as follows:
1998 1997
1st 2nd 1st 2nd
Quarter Quarter Quarter Quarter
Number of Shares 122,436,317 122,436,317 121,840,327 122,111,567
Amount per Share $.43 $.43 $.43 $.43
8. In June 1998, the Financial Accounting Standards Board 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 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 SECOND QUARTER AND SIX MONTHS ENDED JUNE 30, 1998
WITH SECOND QUARTER AND SIX MONTHS ENDED JUNE 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 if DQE seeks to
terminate the merger agreement; 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 Six Months of 1998
* Merger with DQE
In a letter dated July 28, 1998 to the Company, DQE
stated that its Board of Directors determined that DQE was not
required to proceed with the merger under present circumstances,
referring to the Pennsylvania Public Utility Commission (PUC)
Orders of July 23, 1998 and May 29, 1998. See Notes 4 and 5 to
the Consolidated Financial Statements for more information about
these Orders. 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
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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 will
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. The Company
believes that DQE's basis for seeking to terminate the merger is
without merit. Accordingly, the Company is continuing to seek
the remaining regulatory approvals from the Federal Energy
Regulatory Commission (FERC), the Department of Justice, and the
Securities and Exchange Commission. The Company cannot predict
the outcome of the requested approvals or of the differences
between it and DQE.
* Pennsylvania Deregulation
On May 29, 1998, West Penn Power Company (West Penn)
received a final Order from the PUC denying full recovery of its
stranded cost claim. The Order authorized recovery of $524
million in stranded costs, with return, over the 1999 through
2005 period, of the approximately $1.2 billion available for
recovery under the capped rates mandated by the Customer Choice
Act.
On June 26, 1998, the PUC denied a request by West Penn
for reconsideration of the May 29, 1998 PUC Order on West Penn's
restructuring plan. In denying the request for reconsideration,
the PUC let stand the earlier Order under which West Penn would
provide 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 vary from one rate class to another and
increase over a seven-year transition period. Under the
reconsideration Order, West Penn would be allowed to collect $525
million ($.5 million more than the previous Order) in stranded
costs, with a return over seven years, starting in January 1999,
through the Competitive Transition Charge (CTC). Although in its
restructuring application, West Penn had listed $1.6 billion in
stranded costs, because of capped rates, West Penn would be
limited to $1.2 billion in stranded cost recovery under the
Customer Choice Act. Stranded costs are costs incurred under a
regulated environment which are not expected to be recoverable in
a competitive market. Actual recovery of such costs will depend
upon the market prices for electricity in future periods and the
number of West Penn customers who choose other generation
suppliers. The PUC Order on West Penn's restructuring plan
assumed significantly higher electricity prices in future years
than the Company believed were appropriate.
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
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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 $525 million of stranded
costs recommended for recovery is contrary to legal requirements
and does not adequately reflect the potential effects of
competition on West Penn. On June 26, 1998, West Penn filed a
formal appeal in state court and an action in federal court
challenging the PUC's restructuring Order. On July 23, 1998,
West Penn also filed in the Commonwealth Court of Pennsylvania a
petition for a stay of the two-thirds, one-third phase-in
schedule ordered by the PUC. On August 5, 1998, West Penn
withdrew its petition for stay without prejudice based on a PUC
agreement to offer settlement discussions on issues related to
the PUC's restructuring Order. The Company cannot predict the
outcome of settlement discussions or the related legal
proceedings.
* 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. Under the terms of the agreement,
Potomac Edison will increase its rates about 3% in each of the
years 1999, 2000, and 2001 (about $11 million each year). The
increases reflect the net effect of a rate increase of about $60
million for recovery of a power purchase commitment for energy
from AES Corporation's "Warrior Run" generation project beginning
October 1, 1999, offset by rate reductions reflecting Maryland's
share of Potomac Edison's merger savings (about $4.4 million
annually) when the Company merges with DQE, and other rate
reductions to reduce Potomac Edison's "excess earnings" alleged
by OPC. The net effect of the agreement over the 1999-2001 time
frame is expected to result in a pre-tax income reduction of
$16.4 million in 1999, $22.4 million in 2000, and $26.4 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. The settlement
agreement was filed with the Maryland Public Service Commission
on July 30, 1998. "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 5 to the Consolidated Financial
Statements for more information regarding the Maryland filing.
* Trading Activities
In June and July 1998, certain events combined to produce
very 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
- 14 -
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 in its electricity trading operations, 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 1998 differed between the Company's
utility and nonutility subsidiaries but was insignificant in
total.
Review of Operations
EARNINGS SUMMARY Consolidated Net (Loss) Income
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Utility Operations $ 59.2 $55.1 $ 141.4 $135.7
Nonutility Operations (5.4) (3.4) (9.3) (6.4)
Consolidated Income Before
Extraordinary Charge 53.8 51.7 132.1 129.3
Extraordinary Charge (265.4) (265.4)
Consolidated Net (Loss)
Income $(211.6) $51.7 $(133.3) $129.3
Cents Per Share
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
Utility Cents Per Share $ .48 $.45 $ 1.16 $1.11
Nonutility Cents Per Share (.04) (.03) (.08) (.05)
Cents Per Share Before
Extraordinary Charge .44 .42 1.08 1.06
Extraordinary Charge Per Share (2.17) (2.17)
Total Cents Per Share $(1.73) $.42 $(1.09) $1.06
Earnings for the second quarter and first six months of
1998 include an extraordinary charge of $450.6 million ($265.4
million, net of taxes, or $2.17 per share) to reflect a write-off
by West Penn of prudently incurred costs determined to be
unrecoverable as a result of the May 29, 1998 Order by the PUC in
connection with the deregulation proceedings in Pennsylvania.
See Note 6 to the Consolidated Financial Statements for more
information on the extraordinary charge.
The increase in utility earnings in the second quarter
and first six month periods before the extraordinary charge was
due primarily to increased kilowatt-hour (kWh) sales to
commercial and industrial customers. The increase in nonutility
losses for the three and six months ended June 30, 1998 resulted
from energy sales commitments in excess of owned generating
capacity which required settlement by open market purchases
during the period of wholesale price volatility previously
described.
- 15 -
SALES AND REVENUES
Total operating revenues for the second quarter and first
six months of 1998 and 1997 were as follows:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Operating revenues:
Utility revenues:
Bundled retail sales $508.6 $499.7 $1,063.5 $1,067.1
Unbundled retail sales 2.3 - 5.9 -
Wholesale and other 14.9 12.6 33.0 29.2
Utility bulk power,
including trans-
mission services 38.2 18.2 58.0 36.9
Total utility revenues 564.0 530.5 1,160.4 1,133.2
Nonutility revenues 63.6 12.2 112.7 24.5
Total operating
revenues $627.6 $542.7 $1,273.1 $1,157.7
The increase in second quarter bundled retail sales (full
service sales to retail customers) is due to increased commercial
and industrial kWh sales to retail customers. The decrease in
bundled retail sales for the six- month period was due primarily
to reduced residential kWh sales in the first six months due
primarily to first quarter winter weather which was 14% warmer
than 1997 and 21% warmer than normal as measured by 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, up to 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 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 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 and other revenues was due primarily to
$1.4 million and $3.3 million for the three and six months ended
June 30, 1998, respectively, of deferred net revenue losses
recorded as a regulatory asset to offset revenue losses suffered
as a result of the pilot.
- 16 -
Utility and nonutility bulk power sales consist of sales
of power and transmission services to power marketers and other
utilities. Significant bulk power sales acted as a hedge to
mostly offset second quarter trading losses. Bulk power sales
for the second quarter and first six months were as follows:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
KWh Sales (in billions):
Utility:
Bulk power 1.0 .4 1.5 .6
Transmission services 2.1 2.7 3.8 6.8
Total utility 3.1 3.1 5.3 7.4
Nonutility bulk power 1.9 .6 3.7 1.2
Revenues (in millions):
Utility:
Bulk power $27.4 $ 9.4 $38.6 $15.1
Transmission services 10.8 8.8 19.4 21.8
Total utility $38.2 $18.2 $58.0 $36.9
Nonutility bulk power $56.4 $11.4 $99.0 $23.4
The increase in revenues from utility bulk power was due
to increased sales which occurred primarily in the month of June
as a result of a heat wave which increased the demand and prices
for energy.
The increase in nonutility revenues resulted primarily
from increased bulk power sales (as shown in the table above) 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. which was formed in the
third quarter of 1997 to market energy to retail customers in
deregulated markets and other energy-related services. Allegheny
Energy Solutions, Inc. (Allegheny Energy Solutions) recorded $6.6
million and $12.1 million of revenues for the three and six
months ended June 30, 1998, respectively.
OPERATING EXPENSES
Fuel expenses for the second quarter and first six months
of 1998 and 1997 were as follows:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Utility operations $135.1 $127.2 $269.8 $261.8
Nonutility operations 4.5 6.1 9.5 11.9
Total fuel expenses $139.6 $133.3 $279.3 $273.7
- 17 -
Fuel expenses for utility operations for three and six
months ended June 30, 1998 increased primarily due to an increase
in generation. The decrease in fuel expense for nonutility
operations for the three and six months ended June 30, 1998 was
due to a decrease in kWhs generated. This decrease was due
primarily to a scheduled power station 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).
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 Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Purchased power:
Utility operations:
From PURPA generation* $33.7 $35.2 $ 67.9 $69.8
Other 6.4 7.7 15.3 16.2
Total purchased power
for utility operations 40.1 42.9 83.2 86.0
Power exchanges, net (1.7) (1.3) 1.8 2.8
Nonutility operations 57.3 2.2 97.5 5.5
Purchased power and
exchanges, net $95.7 $43.8 $182.5 $94.3
*PURPA cost (cents per kWh) 5.4 5.7 5.5 5.7
Nonutility purchased power is the result of power
replacement requirements and transaction opportunities by AYP
Energy which began operations in late 1996. The increase
in nonutility purchases was due primarily to an increase in
volume attributable to AYP Energy's increased participation
in the market. Also contributing to the increase was an increase
in price caused by the volatility in the spot prices for
electricity in June.
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 Public
Service Commission. See page 13 for further information on the
agreement.
Other operation expenses were as follows:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Utility operations $78.7 $68.8 $149.8 $139.0
Nonutility operations 3.5 3.1 7.2 5.7
Total other operation
expenses $82.2 $71.9 $157.0 $144.7
- 18 -
The increase in utility other operation expenses for the
three months ended June 30 was due primarily to increased
provisions for uninsured claims ($2.8 million), allowances for
uncollectible accounts ($1.1 million), rents ($.7 million),
expenses related to competition and the Pennsylvania pilot ($.7
million), and research and development expenditures ($.7
million). The increase for the six months ended June 30, 1998
was similarly due primarily to increased allowances for
uncollectible accounts ($2.5 million), expenses related to
competition and the Pennsylvania pilot ($2.2 million), research
and development expenditures ($1.5 million), and provisions for
uninsured claims ($1.1 million).
The increase in nonutility operation expenses in the six
months ended June 30, 1998 was due primarily to sales expenses
incurred by Allegheny Energy Solutions in marketing energy to
retail customers in the Pennsylvania pilot program. The first
six months of 1998 was the first full period 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 $3.9 million and $8.8
million for the three and six months ended June 30, 1998 due to
decreased utility expenses of $5.0 million and $10.6 million for
the three and six months ended June 30, 1998, respectively. Both
1998 periods include $4.2 million of incremental transmission and
distribution (T&D) storm damage expenses incurred in June for
three unusually strong thunderstorms in the subsidiaries' service
territories. The decreases in utility maintenance expense were
achieved through restructuring efforts and other cost controls.
These utility reductions were offset in part by increased
nonutility maintenance expense of $1.1 million and $1.8 million
for the three and six months ended June 30, 1998, 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 in the first six months decreased
$.7 million, the net result of a $.8 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 $1.6 million in
the first six months due to increased utility taxes of $1.4
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.
- 19 -
The increases in federal and state income taxes for the
three and six months ended June 30, 1998 were primarily due to
increases in utility income before taxes.
The decrease in other income, net, of $2.8 million in the
second quarter of 1998 was due primarily to a 1997 second quarter
deferral of merger-related expenditures. The decrease in other
income, net, of $3.0 million in the six months ended June 30,
1998 was due primarily to a sale of land in the 1997 period by
West Virginia Power and Transmission Company, a subsidiary of
West Penn.
The decreases in interest on long-term debt of $2.7
million and $3.4 million for the three and six months ended June
30, 1998, respectively, result from reduced long-term debt and
lower rates on refunded debt.
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, and 6 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.
* Risk Management
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 formal 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 June 30, 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 require 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
- 20 -
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. See page
13 for more information on trading activities.
* Year 2000 Readiness
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 21 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,
remediation initiated as needs are identified, with 1999 to
complete remediation and testing.
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
- 21 -
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 noncompliant 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 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.
- 22 -
* 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. Although several
restructuring bills were introduced in the House and Senate in
1998, Congress is not expected to move legislation on
restructuring this year.
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 House Bill on
March 14, 1998 which sets the stage for the restructuring of the
electric utility industry in West Virginia. The House Bill
directed the West Virginia Public Service Commission (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 which is
nearing the end of its official schedule with little apparent
progress concerning a defined plan for restructuring. The
deadline to file a consensus workshop report and comments
regarding the Commission's public interest determination is
August 26, 1998. The Commission also announced a series of five
public hearings in August and September to allow for broader
public input into the process. Evidentiary hearings are
scheduled for September 29, 1998 to address utility unbundling
and stranded cost filings.
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 State Corporation Commission (SCC) ordered two
utilities, but not Potomac Edison, to develop retail pilot
programs. Those utilities have until November 1, 1998 to develop
and submit their retail pilot programs to the 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. A new version of the bills is being developed.
- 23 -
ALLEGHENY ENERGY, INC.
Part II - Other Information to Form 10-Q
for Quarter Ended June 30, 1998
ITEM 1. LEGAL PROCEEDINGS
On September 29, 1997, the City of Pittsburgh filed an
antitrust and breach of contract lawsuit in the United States
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 for an injunction
preventing the proposed merger between the Company and DQE, Inc.
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 the federal claims for failure to state a
claim, and dismissed the state claims for lack of subject matter
jurisdiction. On January 14, 1998, the City appealed the Order
to the United States Court of Appeals for the Third Circuit. On
June 12, 1998, the United States Third Circuit Court of Appeals
affirmed the District Court's decision of January 1998 to dismiss
the City of Pittsburgh's lawsuit against the Company, West Penn,
DQE, Inc., and Duquesne Light Company. The City filed a motion
for reconsideration en banc with the Third Circuit. On July 8,
1998, the City of Pittsburgh reached a settlement with the
Company in the City's pursuit of lower electric utility costs for
consumers. Under the terms of the settlement, the City agreed to
withdraw all opposition to the proposed merger, to dismiss its
motion for reconsideration in federal court, and not to re-file
any claims in state court. The Company agreed to pay the City's
legal fees and to support the City's efforts to obtain favorable
redevelopment zone rates from the Pennsylvania Public Utility
Commission (PUC). In addition, if the merger is consummated, the
Company agreed to make a contribution of $4,000,000 to the
Pittsburgh Development Fund of the Urban Redevelopment Authority
and to maintain annual charitable giving in the City. The
Company also repeated in the settlement the same commitments it
had made to the PUC regarding participation in an independent
system operator and relinquishment of control of 570 MW of
capacity.
On June 26, 1998, West Penn filed a complaint in the
United States District Court for the Western District of
Pennsylvania challenging the PUC's interpretation and application
of the Competition Act in Pennsylvania. The Complaint alleges
various violations of federal law and the constitutional rights
of West Penn. The Complaint seeks monetary relief, a declaration
that the Competition Act violates federal law and the United
States Constitution, and a permanent injunction prohibiting the
PUC from acting on its Order. Also, on June 26, 1998, West Penn
filed a petition for review of the PUC Order in the Commonwealth
Court of Pennsylvania, alleging numerous errors of law and abuse
of discretion by the PUC. Various other parties have cross-
appealed or intervened in West Penn's case. The Company filed a
motion for stay with the Commonwealth Court on July 23, 1998
specifically seeking to stay the PUC's accelerated implementation
schedule for competition. On August 5, 1998, West Penn withdrew
its petition for stay without prejudice based on a PUC agreement
to offer settlement discussions on issues related to the PUC's
restructuring Order.
- 24 -
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITIES HOLDERS
(a) Date and kind of meeting:
At the annual meeting of stockholders held on May 14,
1998, votes were taken for the election of directors to serve
until the next annual meeting of stockholders, the approval of
the appointment of Price Waterhouse LLP (now
PricewaterhouseCoopers LLP) as independent accountants, the
implementation of a long-term incentive plan, and a pay package
for executives indexed to the Company's stock performance. The
total number of votes cast was 96,343,891 with the following
results:
Nominees for Director Votes for Votes Withheld
Eleanor Baum 95,551,985 791,906
William L. Bennett 95,539,374 804,517
Wendell F. Holland 95,555,989 787,902
Phillip E. Lint 95,496,489 847,402
Frank A. Metz, Jr. 95,544,655 799,236
Alan J. Noia 95,557,831 786,060
Steven H. Rice 95,569,301 774,590
Gunnar E. Sarsten 95,572,452 771,439
Votes For Votes Against Abstentions
Approval of independent
accountants 92,946,325 2,161,834 1,235,725
Proposal to approve the
implementation of a
long-term incentive plan 56,710,698 23,994,706 1,437,157
Stockholder proposal recommending
that the complete pay package of
the Company's ten highest paid
executives be indexed to the
Company's stock performance 12,798,167 65,561,926 3,783,567
The stockholders approved the Company's independent
accountants and the implementation of a long-term incentive plan.
The stockholders did not approve the stockholder proposal that
the complete pay package of the Company's ten highest paid
executives be indexed to the Company's stock performance.
- 25 -
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(3)(ii) By-laws of the Company, as amended, dated May 14, 1998.
(27) Financial Data Schedule
(b) On April 2, 1998, the Company filed a Form 8-K concerning
the March 25, 1998 recommendations of the Pennsylvania
Administrative Law Judges (ALJs) in the Company's merger case and
West Penn Power Company's restructuring case, and the March 25,
1998 settlement agreement approved by the Maryland Public Service
Commission. A copy of the press release issued by the Company on
March 26, 1998 concerning the ALJs decisions in both the merger
case and the restructuring case was filed as an exhibit.
On June 12, 1998, the Company filed a Form 8-K and a Form
8-K/A concerning the Pennsylvania Public Utility
Commission's final orders on West Penn Power Company's
restructuring plan and on the Company's application for
approval to merge. The Company filed motions for
reconsideration of both Orders.
On July 27, 1998, the Company filed a Form 8-K concerning
the Pennsylvania Public Utility Commission's May 29, 1998
Order on West Penn Power Company's stand-alone
restructuring plan which was denied in part and accepted
in part as to West Penn's claim to stranded cost
recovery. As determined under SFAS No. 101, a write-off
of the disallowances in the PUC's Order was required.
On July 30, 1998, the Company filed a Form 8-K which
consisted of a July 28, 1998 letter from the President
and Chief Executive Officer of DQE, Inc. to the Chairman,
President, and Chief Executive Officer of the Company.
The filing also included a July 30, 1998 press release
which responded to the letter referenced above and
included a letter from the Company to DQE, Inc.
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)
August 13, 1998