<PAGE>
Page 1 of 31
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Quarterly Report under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For Quarter Ended September 30, 1999
Commission File Number 1-267
ALLEGHENY ENERGY, INC.
(Exact name of registrant as specified in its charter)
Maryland 13-5531602
(State of Incorporation) (I.R.S. Employer Identification No.)
10435 Downsville Pike, Hagerstown, Maryland 21740-1766
Telephone Number - 301-790-3400
The registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months and (2) has been subject to such
filing requirements for the past 90 days.
At November 12, 1999, 110,436,317 shares of the Common Stock
($1.25 par value) of the registrant were outstanding.
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ALLEGHENY ENERGY, INC.
Form 10-Q for Quarter Ended September 30, 1999
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Consolidated Statement of Income -
Three and nine months ended September 30, 1999 and 1998 3
Consolidated Balance Sheet - September 30, 1999
and December 31, 1998 4
Consolidated Statement of Cash Flows -
Nine months ended September 30, 1999 and 1998 5
Notes to Consolidated Financial Statements 6-10
Management's Discussion and Analysis of Financial
Condition and Results of Operations 11-29
PART II--OTHER INFORMATION 30-31
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Income
<TABLE>
<CAPTION>
(Thousands of Dollars)
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
OPERATING REVENUES:
<S> <C> <C> <C> <C> <C> <C>
Utility $ 583,697 $ 620,254 $ 1,710,480 $ 1,780,637
Nonutility 157,662 106,353 364,270 219,092
Total Operating Revenues 741,359 726,607 2,074,750 1,999,729
OPERATING EXPENSES:
Operation:
Fuel 145,220 151,805 413,164 431,091
Purchased power and exchanges, net 166,834 145,545 355,041 328,000
Deferred power costs, net 12,915 932 25,971 (1,319)
Other 90,032 78,361 259,963 235,327
Maintenance 54,165 49,447 165,031 161,918
Depreciation and amortization 65,559 66,834 196,411 203,714
Taxes other than income taxes 45,947 49,631 141,864 147,094
Federal and state income taxes 43,511 55,448 148,138 140,528
Total Operating Expenses 624,183 598,003 1,705,583 1,646,353
Operating Income 117,176 128,604 369,167 353,376
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 662 (475) 1,438 841
Other income, net 2,149 (76) 1,109 1,547
Total Other Income and Deductions 2,811 (551) 2,547 2,388
Income Before Interest Charges and
Preferred Dividends 119,987 128,053 371,714 355,764
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 36,861 38,786 114,063 122,335
Other interest 8,060 5,630 18,175 14,279
Allowance for borrowed funds used during
construction (1,446) (1,417) (3,848) (2,643)
Dividends on preferred stock of subsidiaries 1,400 2,318 5,923 6,929
Redemption premium on preferred stock
of subsidiaries 3,780 - 3,780 -
Total Interest Charges and
Preferred Dividends 48,655 45,317 138,093 140,900
Consolidated Income Before
Extraordinary Charge 71,332 82,736 233,621 214,864
Extraordinary Charge, net (1) - - - (265,446)
CONSOLIDATED NET INCOME (LOSS) $ 71,332 $ 82,736 $ 233,621 $ (50,582)
COMMON STOCK SHARES OUTSTANDING (average) 114,120,202 122,436,317 118,192,404 122,436,317
BASIC AND DILUTED EARNINGS PER AVERAGE SHARE:
Consolidated income before extraordinary charge $0.63 $0.68 $1.98 $1.76
Extraordinary charge, net (1) - - - ($2.17)
Consolidated net income (loss) $0.63 $0.68 $1.98 ($0.41)
</TABLE>
See accompanying notes to consolidated financial statements.
(1) See Note 10 in the notes to the consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Consolidated Balance Sheet
<TABLE>
<CAPTION>
(Thousands of Dollars)
September 30, December 31,
ASSETS: 1999 1998 *
Property, Plant, and Equipment:
At original cost, including $255,754
<S> <C> <C>
and $166,330 under construction $ 8,593,349 $ 8,395,267
Accumulated depreciation (3,563,944) (3,395,603)
5,029,405 4,999,664
Investments and Other Assets:
Subsidiaries consolidated--excess of cost
over book equity at acquisition 15,077 15,077
Benefit plans' investments 88,735 87,468
Nonutility investments 10,858 9,361
Other 3,480 1,566
118,150 113,472
Current Assets:
Cash and temporary cash investments 24,352 17,559
Accounts receivable:
Electric service 330,597 294,877
Other 14,813 17,712
Allowance for uncollectible accounts (25,609) (19,560)
Materials and supplies - at average cost:
Operating and construction 98,965 99,439
Fuel 55,559 57,610
Prepaid taxes 51,043 56,658
Other, including current portion of regulatory assets 53,251 30,788
602,971 555,083
Deferred Charges:
Regulatory assets 696,890 704,506
Unamortized loss on reacquired debt 46,347 48,671
Other 109,240 91,931
852,477 845,108
Total Assets $ 6,603,003 $ 6,513,327
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 153,045 $ 153,045
Other paid-in capital 1,044,085 1,044,085
Retained earnings 919,288 836,759
Treasury stock (at cost) (398,407) -
1,718,011 2,033,889
Preferred stock 74,000 170,086
Long-term debt and QUIDS 2,058,293 2,179,288
Funds on deposit with trustees (21,532) -
3,828,772 4,383,263
Current Liabilities:
Short-term debt 697,392 258,837
Long-term debt due within one year 140,000 -
Accounts payable 155,016 153,107
Taxes accrued:
Federal and state income 47,706 17,442
Other 45,924 62,751
Interest accrued 37,210 35,945
Adverse power purchase commitments 24,895 22,622
Other 105,289 119,957
1,253,432 670,661
Deferred Credits and Other Liabilities:
Unamortized investment credit 119,451 125,396
Deferred income taxes 910,237 842,193
Regulatory liabilities 86,446 80,354
Adverse power purchase commitments 309,590 328,830
Other 95,075 82,630
1,520,799 1,459,403
Total Capitalization and Liabilities $ 6,603,003 $ 6,513,327
</TABLE>
* Certain amounts have been reclassified for comparative purposes.
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Cash Flows
(Thousands of Dollars)
<TABLE>
<CAPTION>
Nine Months Ended
September 30
1999 1998
CASH FLOWS FROM OPERATIONS:
<S> <C> <C> <C> <C>
Consolidated net income (loss) $ 233,621 $ (50,582)
Extraordinary charge, net of taxes - 265,446
Consolidated income before extraordinary charge 233,621 214,864
Depreciation and amortization 196,411 203,714
Deferred investment credit and income taxes, net 15,255 17,123
Deferred power costs, net 25,971 (1,319)
Allowance for other than borrowed funds used
during construction (1,438) (841)
Changes in certain assets and liabilities:
Accounts receivable, net (26,772) 4,613
Materials and supplies 2,525 6,264
Prepayments (16,105) (12,270)
Accounts payable 1,909 (16,964)
Taxes accrued 13,437 20,752
Interest accrued 1,265 (3,234)
Adverse power purchase commitments (16,967) -
Restructuring settlement rate refund (18,940) -
Other, net 15,392 12,885
425,564 445,587
CASH FLOWS FROM INVESTING:
Utility construction expenditures (less allowance for
other than borrowed funds used during construction) (155,919) (159,886)
Nonutility construction expenditures and investments (67,844) (4,866)
(223,763) (164,752)
CASH FLOWS FROM FINANCING:
Repurchase of Company common stock (398,407) -
Retirement of preferred stock (99,866) -
Issuance of long-term debt 114,830 211,952
Retirement of long-term debt (99,031) (357,125)
Short-term debt, net 438,555 12,199
Cash dividends on common stock (151,089) (157,943)
(195,008) (290,917)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 6,793 (10,082)
Cash and temporary cash investments at January 1 17,559 26,374
Cash and temporary cash investments at September 30 $ 24,352 $ 16,292
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of amount capitalized) $123,159 $129,923
Income taxes 113,704 107,519
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Notes to Consolidated Financial Statements
1. The Notes to Consolidated Financial Statements of Allegheny
Energy, Inc. (the Company) in its Annual Report on Form 10-K
for the year ended December 31, 1998 should be read with the
accompanying consolidated financial statements and the
following notes. With the exception of the December 31, 1998
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 September 30, 1999, the results of operations for the
three and nine months ended September 30, 1999 and 1998, and
cash flows for the nine months ended September 30, 1999 and
1998. Certain amounts have been reclassified for comparative
purposes.
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.
3. 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. As previously reported, on October 5, 1998 DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
notified the Company that it had unilaterally decided to
terminate the merger. In response, the Company filed with
the United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the Merger Agreement or, alternatively,
damages. On March 11, 1999, the United States Court of
Appeals for the Third Circuit vacated the United States
District Court for the Western District of Pennsylvania's
denial of the Company's motion for preliminary injunction,
enjoining DQE from taking actions prohibited by the Merger
Agreement. The Circuit Court stated that if DQE breached the
Merger Agreement, the Company may be entitled to specific
performance of the Merger Agreement. The Circuit Court also
stated that the Company could be irreparably harmed if DQE
took actions that would prevent the Company from receiving
the specific performance remedy. The Circuit Court remanded
the case to the District Court for further proceedings
consistent with its opinion.
The District Court denied DQE's motion for summary judgment.
The District Court held a trial on October 18-28, 1999,
without a jury, on the issues of whether DQE's termination of
the Merger Agreement breached the agreement and whether the
Company is entitled to specific performance. A decision by
the District Court is expected by the end of 1999. The
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Company cannot predict the outcome of this litigation.
However, the Company believes that DQE's basis for
terminating the merger is without merit. Accordingly, the
Company continues to seek the necessary regulatory approvals.
It is not likely any agency will act further on the merger
unless the Company obtains judicial relief requiring DQE to
move forward.
All of the Company's incremental costs of the merger process
($17.6 million through September 30, 1999) are deferred. The
accumulated merger costs will be written off by the combined
company when the merger occurs or by the Company if it is
determined that the merger will not occur.
5. The Consolidated Balance Sheet includes the amounts listed
below for assets, primarily generation, not subject to SFAS
No. 71, "Accounting for the Effects of Certain Types of
Regulation."
September 30 December 31
1999 1998
(Thousands of Dollars)
Property, plant and equipment at
original cost $2,037,981 $1,969,636
Amounts under construction included above 102,609 39,227
Accumulated depreciation (922,876) (870,777)
6. The Company began acquiring shares of its common stock in the
first quarter of 1999 in conjunction with a stock repurchase
program announced in March 1999. The program authorizes the
Company to repurchase common stock worth up to $500 million
from time to time at price levels the Company deems
attractive. The Company purchased 12,000,000 shares of its
common stock in the first nine months of 1999 at an aggregate
cost of $398.4 million. No further purchases are expected in
1999.
7. The Company's principal business segments are utility and
nonutility operations. The utility subsidiaries, doing
business as Allegheny Power, include the generation,
purchase, transmission, distribution, and sale of electric
energy and are subject to federal and state regulation. The
Company derives substantially all of its income from
operations of its utility subsidiaries, Monongahela Power
Company, The Potomac Edison Company, and West Penn Power
Company (West Penn). Nonutility operations consist of
Allegheny Ventures, Inc., a wholly owned subsidiary, formed
in an effort to meet the challenges of the new competitive
environment in the electric industry, and the Allegheny
Energy Supply Division (ESD) of West Penn. The ESD has the
primary objective of selling the output of the West Penn
generation that has been freed up by the Electricity
Generation Customer Choice and Competition Act (Customer
Choice Act) in Pennsylvania (approximately 2,570 megawatts in
1999) and is no longer regulated by the Pennsylvania Public
Utility Commission (Pennsylvania PUC). Nonutility operations
may be subject to federal regulation but are not subject to
state regulation of rates.
Business segment information is summarized below.
Significant transactions between reportable segments are
eliminated to reconcile the segment information to
consolidated amounts.
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Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Thousands of Dollars)
Operating Revenues:
Utility $583,697 $620,435 $1,710,480 $1,781,264
Nonutility 271,407* 106,352 627,457* 219,091
Eliminations (113,745) (180) (263,187) (626)
Depreciation:
Utility 50,790 65,391 152,661 199,476
Nonutility 14,769 1,443 43,750 4,238
Federal and State Income
Taxes:
Utility 35,886 58,772 125,530 149,447
Nonutility 7,625 (3,324) 22,608 (8,919)
Operating Income:
Utility 91,212 133,429 308,066 363,214
Nonutility 25,964 (4,825) 61,101 (9,838)
Interest Charges and
Preferred Dividends:
Utility 40,612 42,773 113,172 133,282
Nonutility 8,043 2,544 24,921 7,618
Consolidated Income
Before Extraordinary
Charge:
Utility 52,321 90,838 196,797 232,248
Nonutility 19,011 (8,102) 36,824 (17,384)
Extraordinary Charge, Net:
Utility 265,446
Nonutility
Capital Expenditures:
Utility 67,810 61,166 157,357 160,727
Nonutility 28,973 878 67,844 4,866
September 30 December 31
1999 1998
Identifiable Assets:
Utility $5,253,671 $6,299,909
Nonutility 1,349,332 213,418
*Nonutility operating revenues include $14.4 million and
$46.7 million in the three months and nine months ended
September 30, 1999 of allocated Competitive Transition Charge
(CTC) revenues to compensate for certain transition costs
transferred to nonutility operations.
8. Common stock dividends per share declared during the periods
for which income statements are included are as follows:
1999 1998
Number Amount Number Amount
of Shares Per Share of Shares Per Share
First Quarter 122,436,317 $.43 122,436,317 $.43
Second Quarter 116,600,317 $.43 122,436,317 $.43
Third Quarter 112,333,817 $.43 122,436,317 $.43
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9. The Company's Pennsylvania subsidiary, West Penn, is
authorized to collect transition costs through a CTC from its
distribution customers over the period 1999 through 2008 as a
result of a 1998 Order of the Pennsylvania PUC.
The November Order of the Pennsylvania PUC authorizes annual
recovery of transition costs from distribution customers as
follows:
Year Amount Year Amount
(Millions of Dollars) (Millions of Dollars)
1999 $122 2004 $104
2000 121 2005 99
2001 115 2006 98
2002 113 2007 97
2003 112 2008 97
CTC revenues recorded in the three months and nine months
ended September 30, 1999 totaled $30.1 million and $97.7
million, respectively.
The Order also authorized recognition of an additional CTC
regulatory asset (Additional CTC Regulatory Asset) as
follows:
Year Amount
(Millions of Dollars)
1999 $25
2000 45
2001 60
2002 50
To the extent that West Penn records any or all of the
Additional CTC Regulatory Asset, it will be amortized in 2005
through 2008. This Additional CTC Regulatory Asset was
approved by the Pennsylvania PUC to reduce the adverse
effects, if any, that competition will have on West Penn
during the years 1999 through 2002.
No Additional CTC Regulatory Asset was recorded by West Penn
as of September 30, 1999.
West Penn filed its Competitive Transition Charge
Reconciliation Statement pursuant to the Settlement Agreement
approved by the Pennsylvania PUC on August 12, 1999. The
Settlement Agreement provided that West Penn would file its
CTC Reconciliation Statement by August 30 of each year. It
also adopted a CTC reconciliation schedule whereby a hearing
should be held before October 29 with a Pennsylvania PUC
Final Order to be issued on or before December 28 each year.
A reconciliation was filed on August 30, 1999 and a hearing
was held on October 26, 1999. The reconciliation shows a
seven-month under-collection and its potential effects on the
CTC rate effective January 1, 2000. The seven-month
transition cost under-collection for the period ended July
31, 1999 is $15.9 million. The potential effect of the
transition cost under-collection on CTC rates for the year
2000 is an
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increase of approximately one mill per kilowatt-hour. The
Reconciliation Statement also shows CTC rates needed to avoid
CTC under-collection in the year 2000. The effect of the
reduction, compared to sales assumed in setting CTC rates, in
projected energy sales would be an increase in the CTC rates
for the year 2000 by about one mill per kilowatt-hour.
Because West Penn's retail rates are capped, a two-mill
increase in CTC rates for the year 2000 would force a two-
mill decrease in generation-reflected rates in shopping
credits. West Penn is proposing to mitigate the CTC increase
and the resulting equal decrease in shopping credit by
deferring recovery of the amount of the under-collection.
The amount deferred as a regulatory asset will be included in
the CTC rates that are calculated for the year 2001.
10.The nine months ended September 30, 1998 period includes a
previously reported 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 Pennsylvania PUC in connection with the
deregulation proceedings in Pennsylvania.
11.West Penn redeemed all outstanding shares of its cumulative
preferred stock on July 15, 1999 with proceeds from new five-
year unsecured medium-term notes issued by West Penn in the
second quarter at a 6.375% coupon rate. The cumulative
preferred stock was redeemed at its combined par value of
$79.7 million plus redemption premiums of $3.3 million.
Potomac Edison redeemed all outstanding shares of its
cumulative preferred stock on September 30, 1999 with funds
on hand. The cumulative preferred stock was redeemed at its
combined par value of $16.4 million plus redemption premiums
of $.5 million.
The redemptions of the preferred stock allowed West Penn and
will allow Potomac Edison to revise their Articles of
Incorporation providing greater financial flexibility in
restructuring debt.
12.West Penn repurchased $96.4 million of first mortgage bonds
during the second and third quarters of 1999.
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ALLEGHENY ENERGY, INC.
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1999
WITH THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1998
The Notes to Consolidated Financial Statements and Management's
Discussion and Analysis of Financial Condition and Results of
Operations in the Allegheny Energy, Inc. (the Company) Annual
Report on Form 10-K for the year ended December 31, 1998 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. These include
statements with respect to deregulation activities and movements
toward competition in states served by the Company, the proposed
merger with and related litigation against DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa., Year
2000 readiness disclosure, and results of operations. All such
forward-looking information is necessarily only estimated. There
can be no assurance that actual results will not materially
differ from expectations. Actual results have varied materially
and unpredictably from past expectations.
Factors that could cause actual results to differ
materially include, among other matters, electric utility
restructuring, including the ongoing state and federal
activities; potential Year 2000 operation problems; developments
in the legislative, regulatory, and competitive environments in
which the Company operates, including regulatory proceedings
affecting rates charged by the Company's subsidiaries;
environmental, legislative, and regulatory changes; future
economic conditions; earnings retention and dividend payout
policies; developments relating to the proposed merger with DQE,
including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.
Significant Events in the First Nine Months of 1999
* Unregulated Generating Subsidiary
The Company and two of its subsidiaries, West Penn Power
Company (West Penn) and AYP Energy, Inc., filed a Form U-1
application on April 16, 1999 with the Securities and Exchange
Commission (SEC) to form an unregulated generating subsidiary and
to transfer West Penn's generating facilities and AYP Energy to
the new subsidiary. An order approving the subsidiary and the
transfer was issued on November 12, 1999. Regulatory approval for
the transfer was obtained from the Federal Energy Regulatory
Commission (FERC) on October 25, 1999, and the Pennsylvania Public
Utility Commission (Pennsylvania PUC) has reviewed the proposed plan.
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During the fourth quarter, West Penn will transfer its
deregulated generating capacity, which totals approximately 3,700
megawatts (MW), at book value as allowed by the final settlement
in West Penn's Pennsylvania restructuring case, and AYP Energy,
Inc. will transfer its 276 MW merchant capacity at Fort Martin
Unit No. 1 to the new generating company or GENCO.
Initially, West Penn will transfer to a new unregulated
subsidiary generating company all of its ownership interests in
generating assets and its contractual rights to generating
capacity other than those arising under the Public Utility
Regulatory Policies Act of 1978 (PURPA). As consideration, the
generating subsidiary will pay West Penn the book value of the
generating assets in a combination of cash and a note secured by
a purchase money mortgage on the generating assets. It is
expected that West Penn, in order to obtain the release of the
generating assets from the lien of the first mortgage, will pay
the cash and assign the note and the purchase money mortgage to
the trustee of its first mortgage bonds. The generating assets
will subsequently be transferred to a subsidiary of the new
unregulated subsidiary generating company.
Thereafter, the first tier subsidiary will dividend its
ownership interest in the unregulated generating subsidiary, and
West Penn will dividend up to the Company its ownership interest
in the new generating subsidiary. After this dividend, West Penn
will no longer have any ownership interest in generating assets
or contractual rights to generating capacity other than those
arising under the PURPA.
All necessary regulatory approvals to commence these
transfers and dividend have been received. It is expected that
West Penn will complete the transfers of generating assets and
the dividend to the Company in 1999.
* Installation of Combustion Turbines
A new Company subsidiary, Allegheny Energy Unit No. 1 and
Unit No. 2, LLC, will be installing two 44-MW simple-cycle gas
combustion turbines at the Springdale power station in Allegheny
County, Pa., at a cost of approximately $46 million. These units
will be unregulated merchant plants. The two units are expected
to be in service by the end of 1999 and will be capable of
running on either No. 2 diesel oil or natural gas. As part of
the installation, 500,000 gallons of oil storage capacity will be
built and existing gas lines will be upgraded. Transmission
facilities at the site and the nearby interconnection with
Duquesne Light Company will also be upgraded.
The generation output will be sold into the competitive
power markets in the eastern United States.
* Development of 100-MW Generation Project
The Company has signed an agreement with Foster Wheeler
Power Systems, Inc. (Foster Wheeler) and United Refining Company
(United Refining) to develop a 100-MW generation project in
Warren County in northwestern Pennsylvania.
The project will include an upgrade by Foster Wheeler to
United Refining's facility in the city of Warren with the
installation of a petroleum coker and associated equipment.
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The generation project, to be co-developed and owned by
the Company, Foster Wheeler, and United Refining, will
incorporate circulating fluidized-bed technology and use waste by-
products from the petroleum coking process in production of
electricity for the refinery and for sale in the open market.
Excess capacity from the generation will be marketed by the
Allegheny Energy Supply Business of West Penn, and steam produced
by the project will be used by the refinery.
The project is valued up to $400 million, and
construction is anticipated to begin in early 2001. A memorandum
of understanding to develop the facility has been signed among
all the parties, but a satisfactory feasibility study, acceptable
financing terms and conditions, permitting, and execution of
definitive project agreements are necessary before construction
can begin.
* Acquisition of Assets
The Company plans to purchase from UtiliCorp United,
headquartered in Kansas City, Missouri, the assets of West
Virginia Power, an electric and natural gas distribution company
located adjacent to the Company's service territory in southern
West Virginia for approximately $95 million, and the assets of
Appalachian Electric Heating, a heating, ventilation, and air
conditioning installation and service operation with locations in
or near West Virginia Power's service area for $3.45 million. As
part of the transaction, the Company signed a 20-year option
agreement with UtiliCorp United's subsidiary,
Aquila Energy, for gas supply to the Company. Electricity will
be supplied under an existing contract with American Electric
Power until December 31, 2001, and thereafter from existing
Monongahela Power Company generation or from the market.
The proposed acquisition includes 26,000 electric and
24,000 gas customers, 1,989 miles of electric distribution lines
and 670 miles of gas pipelines, and 1,360 square miles of
electric and 500 miles of gas service territory. West Virginia
Power has approximately 120 employees, and Appalachian Electric
Heating has approximately 52 employees. The Company has proposed
to the W.Va. PSC to generally freeze both electric and gas rates
to West Virginia Power customers for seven years except that the
fuel portion of gas rates would be allowed to fluctuate with the
gas market.
The transaction has been approved by the Boards of
Directors of UtiliCorp United and the Company. The purchase of
the assets is conditioned upon the acceptable approvals of the
Public Service Commission of West Virginia, the SEC, FERC, and
the Department of Justice/Federal Trade Commission. The Company
has made the appropriate filings and anticipates that all
required approvals will be received and the transaction completed
in the fourth quarter of 1999.
* Proposed Merger with DQE
See Note 4 to the consolidated financial statements for
information about the proposed merger with DQE and related
litigation.
* Virginia Rate Settlement and Agreement
On February 25, 1999, the Virginia State Corporation
Commission (Virginia SCC) approved the Company's rate reduction
request for its subsidiary, The Potomac Edison Company (Potomac
Edison), which decreased the fuel portion of Virginia customers'
bills by approximately 7.6% (a decrease in
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annual fuel revenue of about $2.2 million). The decrease is
primarily due to refunding a prior overrecovery of fuel costs,
coupled with a small decrease in projected energy costs. The new
rates were effective with bills rendered on or after March 9,
1999.
On May 21, 1999, the Virginia SCC approved an agreement
reached between Potomac Edison and the staff of the Virginia SCC
which reduced base rates for Virginia customers effective June 1,
1999 by about $3 million annually. The review of rates is
required by an annual information filing in Virginia.
* West Virginia Fuel Review
On February 26, 1999, the Public Service Commission of
West Virginia (W.Va. PSC) entered an Order to initiate a fuel
review proceeding to establish a fuel increment in rates for
Potomac Edison and Monongahela Power Company (Monongahela Power)
to be effective July 1, 1999 through June 30, 2000. On June 29,
1999, the W.Va. PSC approved a joint stipulation and agreement
between Potomac Edison and Monongahela Power and the intervenors.
Under the agreement, the parties are to negotiate further in an
effort to more closely align Potomac Edison and Monongahela Power
rate schedules and to petition to reopen this case if they are
successful. Absent such agreement by October 15, 1999, the rates
were to revert to the originally proposed rates in this case.
This change would have been effective November 1, 1999 and would
have increased Monongahela Power's fuel rates by $10.9 million
and decreased Potomac Edison's fuel rates by $8.0 million. On
October 15, 1999, the parties filed a "Status Report and
Agreement to Continue." The Agreement stated that the parties
had met and exchanged proposals but more time was needed to
review the matter. The parties agreed to continue discussions
until January 31, 2000. If the parties have not reached an
agreement by that date, then the rates as previously proposed
would become effective February 15, 2000 with no further approval
or action required of the W.Va. PSC. These changes, if
implemented, will have no effect on the companies' net income.
* Maryland Fuel Rate Filing
On November 8, 1999, Potomac Edison filed with the
Maryland Public Service Commission (Maryland PSC) a request to
decrease the fuel portion of Maryland customers' bills by about
$6.4 million annually. The requested decrease is primarily due
to greater efficiencies, lower fuel costs, and increased
nonaffiliated generation and transmission sales. If approved by
the Maryland PSC, the new fuel rates will become effective with
bills rendered on or after December 7, 1999. This change, if
implemented, will have no effect on Potomac Edison's net income.
* Articles of Incorporation
As a result of the passage of Maryland legislation
affecting corporate governance of companies incorporated in the
state, the Board of Directors by resolution amended the Company's
Articles of Incorporation. The Board resolution adopted a
provision creating three classes of directors of nearly even
size, with the term of each director continuing for the full
initial term of the class to which he or she is designated, a
provision that directors cannot be removed from the Board except
by a two-thirds vote of all votes entitled to be cast by
shareholders in an election of directors, that vacancies may be
filled only by the Board and for the full remainder of the term,
and the number of directors may be fixed only by the Board.
<PAGE>
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* Maryland, Ohio, Virginia, and West Virginia Deregulation
See Electric Energy Competition on page 26 for ongoing
information regarding restructuring in Maryland, Ohio, Virginia,
and West Virginia.
* Toxics Release Inventory (TRI)
On Earth Day 1997, President Clinton announced the
expansion of Right-to-Know TRI reporting to include electric
utilities, limited to facilities that combust coal and/or oil for
the purpose of generating power for distribution in commerce.
The purpose of TRI is to provide site-specific information on
chemical releases to the air, land, and water. On June 4, 1999,
the Company joined with other members of the Edison Electric
Institute in reporting power station releases to the public.
Packets of information about the Company's releases were provided
to media in the Company's area and posted on the Company's web
site. The Company filed its first TRI report with the
Environmental Protection Agency prior to the July 1, 1999
deadline date, reporting 18 million pounds of total releases for
calendar year 1998.
Review of Operations
EARNINGS SUMMARY
Consolidated Net Income (Loss)
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations $52.3 $90.8 $196.8 $232.2
Nonutility operations 19.0 (8.1) 36.8 (17.4)
Consolidated income before
extraordinary charge 71.3 82.7 233.6 214.8
Extraordinary charge, net (265.4)
Consolidated net income
(loss) $71.3 $82.7 $233.6 $(50.6)
Earnings (Loss) Per Average Share
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
Utility operations $.46 $.74 $1.67 $1.90
Nonutility operations .17 (.06) .31 (.14)
Earnings per average share
before extraordinary charge .63 .68 1.98 1.76
Extraordinary charge, net (2.17)
Total earnings (loss) per
average share $.63 $.68 $1.98 $(.41)
The decrease in earnings in the third quarter of 1999 is
primarily attributed to increased energy costs and higher
operation and maintenance costs in 1999 compared to third quarter
1998, and $3.8 million of premiums paid to retire preferred stock
in 1999. The decrease in earnings per share for the quarter
compared to the prior year was partly offset by the lower number
of shares outstanding due to the Company's common stock
repurchase
<PAGE>
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program (see Note 6 on page 7). Earnings for the first nine
months of 1998 include a previously reported 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 Pennsylvania PUC in connection with the
deregulation proceedings in Pennsylvania. The increase in
earnings in the first nine months of 1999 before the 1998
extraordinary charge is primarily attributed to increased
kilowatt-hour sales, including increased sales to residential
customers due to winter weather that was 22% colder than the
relatively warm winter of 1998. Nonutility sales also
contributed to the year-to-date increase in earnings.
SALES AND REVENUES
Total operating revenues for the third quarter and first
nine months of 1999 and 1998 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Operating revenues:
Utility revenues:
Regulated $550.3 $573.9 $1,627.7 $1,670.8
Choice 8.3 4.6 24.2 10.5
Bulk power and trans-
mission services sales 25.1 41.9 58.6 99.9
Total utility revenues 583.7 620.4 1,710.5 1,781.2
Nonutility revenues 271.4* 106.4 627.5* 219.1
Elimination between utility
and nonutility (113.7) (.2) (263.2) (.6)
Total operating
revenues $741.4 $726.6 $2,074.8 $1,999.7
*Nonutility operating revenues include $14.4 million and $46.7
million in the three months and nine months ended September 30,
1999 of allocated Competitive Transition Charge revenues to
compensate for certain transition costs transferred to nonutility
operations.
The decreases in regulated revenues (regulated revenues
include revenues from West Penn customers eligible to choose an
alternate energy supplier but electing not to do so) in the three
and nine months ended September 30, 1999 were due primarily to
the result of Pennsylvania competition which gave two-thirds of
West Penn's regulated customers the ability to choose another
energy supplier and to a reduction in Potomac Edison's Maryland
rates as part of a settlement agreement. These decreases to
regulated revenues were offset in part in the nine-month period
by colder winter weather in 1999 which led to increased
residential and commercial kWh sales.
<PAGE>
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Settlement agreement revenue reductions in the three and
nine months ended September 30, 1999 of $6.5 million and $15.4
million, respectively, reflect a settlement agreement by Potomac
Edison settling the Maryland Office of People's Counsel's
petition for a reduction in Potomac Edison's Maryland rates. Of
that amount, in the three and nine months ended September 30,
1999, $3.9 million and $7.7 million, respectively, are related to
Potomac Edison creating a provision to share earnings above a
return on equity of 11.4% in Maryland as discussed below, and in
the three and nine months ended September 30, 1999, $2.6 million
and $7.7 million, respectively, are related to a deferral of 1999
revenues per the settlement agreement. The agreement, which
includes recognition of costs to be incurred from the AES Warrior
Run cogeneration project being developed under the PURPA, was
approved by the Maryland PSC on October 27, 1998. Under the
terms of that agreement, Potomac Edison will increase its rates
about 4% ($13 million) in each of the years 1999, 2000, and 2001
(a $39 million annual effect in 2001). The increases are
designed to recover additional costs of about $131 million over
the period 1999-2001 for capacity purchases from the AES Warrior
Run cogeneration project, net of alleged over-earnings of $52
million for the same period. The net effect of these changes
over the 1999-2001 time frame results in a pre-tax income
reduction of $12 million in 1999, $18 million in 2000, and $22
million in 2001. In addition, the settlement requires that
Potomac Edison share, on a 50% customer, 50% shareholder basis,
earnings above a return on equity of 11.4% in Maryland for 1999-
2001. This sharing will occur through an annual true-up.
Utility choice revenues for 1999 represent transmission
and distribution revenues from West Penn franchised customers
(customers in West Penn's territory) who chose another supplier
to provide their energy needs. In 1998, the choice revenues
represent the 5% of previously fully bundled customers (full
service customers) who participated in the Pennsylvania pilot and
were required to buy energy from an alternate supplier. The
approximate doubling of choice revenues from 1998 to 1999
indicates very few of West Penn's customers have chosen alternate
energy suppliers. The Energy Supply Division of West Penn has
the primary objective of selling the output from the two-thirds
of West Penn's generation that has been freed up by the
Electricity Generation Customer Choice and Competition Act
(Customer Choice Act) in Pennsylvania. As a result of the Energy
Supply Division selling to the nonutility market, utility bulk
power sales have decreased due to reduced regulated generation
available for sale.
Nonutility revenues have increased due primarily to bulk
power sales to nonaffiliated companies and to new sales in
Pennsylvania's competitive marketplace by the Energy Supply
Division. The Energy Supply Division officially began supplying
electricity to customers on January 1, 1999. It uses West Penn's
generation transferred from utility operations to nonutility
operations pursuant to the Customer Choice Act in Pennsylvania
and engages in other transactions in the unregulated marketplace
to sell electricity to both wholesale and retail customers.
The elimination between utility and nonutility revenues
is necessary to remove the effect of affiliated revenues.
See Note 9 to the consolidated financial statements for
information regarding the Competitive Transition Charge.
<PAGE>
- 18 -
OPERATING EXPENSES
Fuel expenses for the third quarter and first nine months
of 1999 and 1998 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations $ 96.1 $146.2 $273.6 $415.9
Nonutility operations 49.1 5.6 139.6 15.2
Total fuel expenses $145.2 $151.8 $413.2 $431.1
Total fuel expenses decreased 4% in each of the three and
nine months ended September 30, 1999 periods vs. the three and
nine months ended September 30, 1998 periods. The decrease in
the three months ended period is due to a 10% decrease in average
fuel prices offset by a 6% increase in kWh generated. The
decrease in the nine-month period is due to a 7% decrease in
average fuel prices offset by a 3% increase in kWh generated.
The decrease in fuel expenses for utility operations and the
increase in fuel expenses for nonutility operations was due to
the fuel expenses associated with the two-thirds of West Penn's
freed up generation now being marketed by the ESD as part of
nonutility operations.
Purchased power and exchanges, net, represents power
purchases from and exchanges with other companies and purchases
from qualified facilities under the PURPA, and consists of the
following items:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations:
Purchased power:
From PURPA generation* $ 21.7 $ 30.6 $ 75.5 $ 98.5
Other 14.9 20.3 45.7 35.6
Total purchased power
for utility operations 36.6 50.9 121.2 134.1
Power exchanges, net (4.1) (3.3) (3.1) (1.5)
Nonutility operations
purchased power 139.5 97.9 255.6 195.4
Elimination (5.2) (18.7)
Purchased power and
exchanges, net $166.8 $145.5 $355.0 $328.0
*PURPA cost (cents per kWh) 4.8 5.3 4.9 5.4
Utility purchased power from PURPA generation decreased
$8.9 million and $23.0 million in the third quarter and nine
months ended September 30, 1999. These decreases reflect (a) a
$2.7 million and $8.1 million reduction in the third quarter and
nine months ended September 30, 1999, respectively, related to
West Penn's purchase commitment at costs in excess of the market
value of the AES Beaver Valley contract, (b) and a decrease of
$2.4 million
<PAGE>
- 19 -
and $9.6 million in the third quarter and nine months ended
September 30, 1999, respectively, in the purchase price for that
contract due to a scheduled capacity rate decrease defined
annually in the contract. The reduction related to the purchase
commitment in excess of costs reflects the amortization of excess
cost accruals recorded in 1998 as an adverse power purchase
commitment net of the Competitive Transition Charge revenue
recovery in conjunction with deregulation proceedings in
Pennsylvania.
The decrease in other utility operations purchased power
in the three months ended September 30, 1999 resulted primarily
from decreased purchases for sales. The increase in other
utility operations purchased power in the nine months ended
September 30, 1999 was due primarily to West Penn's purchase of
power from nonaffiliated companies and marketers in order to
provide energy to the two-thirds of its customers eligible to
choose an alternate supplier but electing not to do so.
The elimination between utility and nonutility purchased
power is necessary to remove the effect of affiliated purchased
power expenses.
The AES Warrior Run PURPA cogeneration contract in
Potomac Edison's Maryland service territory will increase the
cost of power purchases $60 million or more annually.
Commencement of operation was scheduled for October 1999. Pre-
commencement testing is not completed. AES Warrior Run has until
October 1, 2000 to complete pre-commencement testing. The
Maryland Public Utility Commission has approved Potomac Edison's
recovery of the AES Warrior Run purchased power cost as part of a
settlement agreement. See Sales and Revenues starting on page 16
for more information on the settlement agreement.
None of the subsidiaries' purchased power contracts are
capitalized since there are no minimum payment requirements
absent associated kWh generation.
Other operation expenses for the third quarter and first
nine months of 1999 and 1998 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations $77.0 $71.9 $222.2 $221.6
Nonutility operations 16.9 6.5 50.3 13.7
Elimination (3.9) (12.5)
Total other operation
expenses $90.0 $78.4 $260.0 $235.3
The increase in total other operation expenses for the
third quarter of $11.6 million was due primarily to increases in
salaries and wages and merger litigation expenses. The increase
in total other operation expenses in the nine months ended
September 30, 1999 of $24.7 million was due primarily to costs
associated with certain PURPA regulations, increased allowances
for uncollectible accounts, Year 2000 expenses, increases in
salaries and wages, and merger litigation expenses. Nonutility
other operation expenses reflect increased business activity.
The elimination between utility and nonutility operation
expenses is necessary to remove the effect of affiliated
transmission purchases.
<PAGE>
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Maintenance expenses for the third quarter and first nine
months of 1999 and 1998 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations $44.1 $48.2 $134.0 $157.8
Nonutility operations 10.1 1.2 31.0 4.1
Total maintenance expenses $54.2 $49.4 $165.0 $161.9
Total maintenance expenses for the third quarter and nine
months ended September 30, 1999 increased from the same periods
in 1998 by $4.8 million and $3.1 million, respectively, due
primarily to increased power station maintenance expenses. The
decrease in utility maintenance and the increase in nonutility
maintenance was due to the maintenance associated with the two-
thirds of West Penn generation deregulated and now being
classified as nonutility maintenance. 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 and amortization expenses for the third
quarter and first nine months of 1999 and 1998 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations $50.8 $65.4 $152.7 $199.5
Nonutility operations 14.8 1.4 43.7 4.2
Total depreciation and
amortization expenses $65.6 $66.8 $196.4 $203.7
Total depreciation and amortization expense in the third
quarter and nine months ended September 30, 1999 decreased $1.2
million and $7.3 million, respectively, due primarily to a $6.1
million and $18.4 million reduction in the third quarter and nine
months ended September 30, 1999, respectively, related to a 1998
write-down of West Penn's share of costs in excess of the fair
value of the Allegheny Generating Company (AGC) pumped storage
project. Depreciation expense will be reduced $234 million
during the period 1999-2016 related to the AGC contract as a
result of the 1998 extraordinary charge recorded by West Penn.
Absent these decreases, depreciation expense would have risen due
to increased investment. Utility and nonutility depreciation
expense reflects the movement of depreciation expense associated
with the two-thirds of West Penn's generation transferred from
utility operations to nonutility operations.
<PAGE>
- 21 -
Taxes other than income taxes for the third quarter and
first nine months of 1999 and 1998 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations $38.6 $47.8 $118.5 $141.9
Nonutility operations 7.3 1.8 23.4 5.2
Total taxes other than
income taxes $45.9 $49.6 $141.9 $147.1
Total taxes other than income taxes decreased $3.7
million in the third quarter of 1999 due primarily to lower
capital stock taxes relating to the 1998 asset write down as a
result of Pennsylvania restructuring. Total taxes other than
income taxes decreased $5.2 million in the nine months ended
September 30, 1999 primarily due to increased West Virginia
Business and Occupation Taxes in the first quarter of 1998
resulting from an adjustment of $1.4 million for a previous
period, lower capital stock taxes relating to the 1998 asset
write down as a result of Pennsylvania restructuring, and
decreased gross receipts taxes, partially offset by higher FICA
taxes. Utility and nonutility taxes other than income taxes
reflect the movement of taxes other than income taxes associated
with the two-thirds of West Penn's generation transferred from
utility operations to nonutility operations.
Federal and state income taxes decreased $11.9 million in
the three months ended September 30, 1999 vs. the three months
ended September 30, 1998 and increased $7.6 million in the nine
months ended September 30, 1999 vs. the nine months ended
September 30, 1998 primarily due to changes in income before
taxes.
Other income, net increased $2.2 million in the three
months ended September 30, 1999 vs. the three months ended
September 30, 1998 primarily due to reduced costs of $1.3 million
resulting from the termination in June 1999 of the swap and
option agreement for AYP Energy, Inc., a subsidiary of Allegheny
Ventures, Inc.
Interest on long-term debt for the third quarter and
first nine months of 1999 and 1998 was as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations $29.8 $36.3 $ 91.1 $114.7
Nonutility operations 7.1 2.5 23.0 7.6
Total interest on
long-term debt $36.9 $38.8 $114.1 $122.3
The decreases in total interest on long-term debt in the
third quarter and nine months ended September 30, 1999 of $1.9
million and $8.2 million, respectively, resulted primarily from
reduced long-term debt and lower interest rates.
<PAGE>
- 22 -
Other interest expense reflects changes in the levels of
short-term debt maintained by the companies, as well as the
associated rates. The increases in other interest expense result
primarily from the increase in short-term debt outstanding in
conjunction with the repurchase of the Company's common stock
that began in the first quarter of 1999.
Dividends on preferred stock of subsidiaries decreased
due to the redemption by West Penn of its cumulative preferred
stock on July 15, 1999.
The redemption premium on preferred stock of subsidiaries
represents the premium paid by Potomac Edison on September 30,
1999 and West Penn on July 15, 1999 to retire their cumulative
preferred stock.
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,
1998 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 Note 4 to the Consolidated Financial
Statements for information about the proposed merger with DQE.
* Market Risk
The Company's utility subsidiaries and certain of the
Company's nonutility subsidiaries, supply power in nonregulated
power markets. At September 30, 1999, the marketing books for
such operations consisted primarily of fixed-priced, forward-
purchase and/or sale contracts which require settlement by
physical delivery of electricity. These transactions result in
market risk, which occurs when the market price of a particular
obligation or entitlement varies from the contract price.
* Transition Bonds
The Company's Pennsylvania subsidiary, West Penn, plans
to issue about $600 million in transition bonds in November 1999
in accordance with its 1998 restructuring settlement. The
restructuring settlement, approved by the Pennsylvania PUC,
allows West Penn to recover up to $670 million in transition
costs which might otherwise prove unrecoverable in a competitive
environment. The settlement also requires that a portion of the
benefits achieved from the lower financing costs due to the
issuance of transition bonds sales be passed through to customers
by reducing the competitive transition charge. This transition
charge is a temporary per-kilowatt-hour charge designed to
collect a company's transition cost in a competitive environment.
The Company plans to reduce transition costs and related
capitalization with the proceeds from the transition bonds.
<PAGE>
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* Repurchase of Common Stock
The Company began acquiring shares of its common stock in
the first quarter of 1999 in conjunction with a stock repurchase
program announced in March 1999. The program authorizes the
Company to repurchase common stock worth up to $500 million from
time to time at price levels the Company deems attractive. The
Company purchased 12,000,000 shares of its common stock in the
first nine months of 1999 at an aggregate cost of $398.4 million.
No further purchases are expected in 1999.
* Redemption of Preferred Stock
West Penn redeemed all outstanding shares of its
cumulative preferred stock on July 15, 1999 with proceeds from
new five-year unsecured medium-term notes issued by West Penn in
the second quarter at a 6.375% coupon rate. The cumulative
preferred stock was redeemed at its combined par value of $79.7
million plus redemption premiums of $3.3 million.
Potomac Edison redeemed all outstanding shares of its
cumulative preferred stock on September 30, 1999 with funds on
hand. The cumulative preferred stock was redeemed at its
combined par value of $16.4 million plus redemption premiums of
$.5 million.
The redemptions of the preferred stock allowed West Penn
and will allow Potomac Edison to revise their Articles of
Incorporation providing greater financial flexibility in
restructuring debt.
* Repurchase of First Mortgage Bonds
During the second and third quarters of 1999, West Penn
repurchased $96.4 million of first mortgage bonds. This reduced
West Penn's outstanding first mortgage bonds to $428.6 million.
West Penn expects to repurchase all outstanding first mortgage
bonds during the fourth quarter of 1999 through a call priced at
par value.
* Issuance of Long-Term Debt
In April 1999, Monongahela Power, Potomac Edison, and
West Penn issued $7.7 million, $9.3 million, and $13.83 million,
respectively, of 5.50% 30-year pollution control revenue notes to
Pleasants County, West Virginia.
In June 1999, West Penn issued $84 million of five-year
unsecured medium-term notes at an interest rate of 6.375%. The
proceeds were used to redeem all outstanding shares of its
cumulative preferred stock with a combined par value of $79.7
million plus redemption premiums of $3.3 million.
* Increase in Short-Term Debt Limit
The SEC on October 8, 1999 authorized an increase for
West Penn in the aggregate limit of short-term debt financing
from $182 million to $500 million through December 31, 2001.
This increase in the short-term debt limit is related to meeting
the requirements of restructuring in Pennsylvania.
<PAGE>
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* Increase in Short-Term Debt Outstanding
Short-term debt increased $438.6 million primarily due to
borrowings in conjunction with the repurchase of the Company's
common stock of $398.4 million that began in the first quarter of
1999.
* Long-Term Debt Due Within One Year
The long-term debt due within one year at September 30,
1999 of $140 million represents $65 million Monongahela Power 5-
5/8% first mortgage bonds due April 1, 2000, and $75 million
Potomac Edison 5-7/8% first mortgage bonds due March 1, 2000.
* Nonutility Construction Expenditures and Investments
The increase in nonutility construction expenditures and
investments of $63 million in the nine months ended September 30,
1999 vs. the nine months ended September 30, 1998 is primarily
due to expenditures of $40 million by the new Company subsidiary,
Allegheny Energy Unit No. 1 and Unit 2, LLC for gas combustion
turbines.
* Year 2000 Readiness Disclosure
The transition from 1999 into the Year 2000 (Y2K) has the
potential to cause serious problems to most organizations,
including the Company, related to software and various equipment
with embedded chips which may not properly recognize calendar
dates. To minimize such problems, the Company has been working
under a comprehensive Y2K program to identify and remediate the
problem areas in order to continue operations without significant
problems in 2000 and beyond. An Executive Task Force is
coordinating the efforts of 24 separate Y2K Teams, representing
all business and support units in the Company.
In May 1998, the North American Electric Reliability
Council (NERC), of which the Company is a member, accepted a
request from the United States Department of Energy to coordinate
the industry's Y2K efforts. The electric utility industry and
the Company have segmented the Y2K problem into the following
components:
* Computer hardware and software;
* Embedded chips in various equipment; and
* Vendors and other organizations on which the Company relies
for critical materials and services.
The industry's and the Company's efforts for each of
these three components include inventory, assessment and, where
possible, remediation of the problem areas by repair, replacement
or removal, supplemented by confirmation testing and contingency
plans. Contingency plans include alternate methods of certain
operations to help avoid electric service or business
interruptions, and the review and update of restoration of
service plans to mitigate the severity and length of
interruptions in the unlikely event that any should occur.
<PAGE>
- 25 -
Based on this work, the Company has determined that as of
September 30, 1999 all of its critical components and systems
related to safety and the production and distribution of
electricity are Y2K Ready, and all but one of its important
business systems are also Ready. Remediation on this one
remaining system related to customer billing has been completed
and system testing is in progress. Although the system is
expected to be Y2K Ready in November, the Company has contingency
plans to continue operations without the system if necessary.
The Company has defined Y2K Ready to mean that a determination
has been made by testing or other means that a component or
system will be able to perform its critical functions.
The Company's readiness program has been conducted in
accordance with time schedules recommended by state regulatory
commissions and by NERC. As is the case of most electric
utilities, Allegheny is interconnected with neighboring
utilities, which provide added strength of supply diversity and
flexibility. But the interconnections also mean that any one
utility's Y2K readiness is related to the readiness of the group.
Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, a cascading failure of the
entire electrical system. The Company is working with the Edison
Electric Institute, the Electric Power Research Institute, the
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.
Since the Company and its neighboring utilities in the ECAR group
are all participants in the NERC Y2K effort (which had a target
completion date of June 30 for critical systems related to
production and delivery of electricity), the Company believes
that this worst case possibility has been reduced to an unlikely
event. The Company has recently re-tested its existing
contingency plans for restoration of service even if this
unlikely event were to occur.
As part of the on-going NERC program, the Company
participated in industry-wide Y2K drills on April 9 and September
9, 1999. While the electric utility industry is aware of the
extensive Y2K programs of the major telecommunications companies,
the industry has determined that telecommunication facilities are
so important to continued operations that we must have
contingency plans just in case some of those facilities may not
be available. The drills were dry runs designed primarily to
test the ability of utilities to continue to operate with less
than normal telecommunication facilities. During the tests, the
Company was able to maintain adequate communications under
simulated failures of selected systems, and obtained valuable
information for improvement of its plans. NERC has reported that
the industry-wide tests produced similar results. On December
31, 1999, the Company will have extra staff in critical areas of
the system to implement these and other contingency plans if they
are required.
The SEC requires that each company disclose its estimate
of the "most reasonably likely worst case scenario" of a negative
Y2K event. Since the Company and the industry are working
diligently to avoid any disruption of electric service, the
Company believes its customers will not experience any
significant long-term disruptions of electric service. It is the
Company's opinion that the "most reasonably likely worst case
scenario" is a Y2K event or series of events that may cause
isolated disruptions of service. All utilities, including the
Company, have experience in the implementation of existing
restoration of service plans. As stated above, the Company's Y2K
program includes a review and update of these plans to respond
quickly to any such events.
<PAGE>
- 26 -
The Company is aware of the importance of electricity to 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 of any such event.
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 Y2K work has been significant, it primarily represents
a labor-intensive effort of remediation, component testing,
multiple systems testing, documentation, and contingency
planning. While outside contractors and equipment vendors have
been employed for some of the work, the Company has used 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 total incremental expenditures for the Y2K
effort since it began identification of Y2K costs will be up to
about $20 million of which $16 million has been incurred through
September 30, 1999. These expenditures are financed by internal
sources and primarily result from the purchase of external expert
assistance by the Generation and Information Services
departments. The expenditures have not required a material
reduction in the normal budgets and work efforts of these
departments.
The descriptions herein of the Company's Y2K effort are
made pursuant to the Year 2000 Information and Readiness
Disclosure Act. Forward-looking statements herein are made
pursuant to the Private Securities Litigation Reform Act of 1995.
There can be no assurance that actual results will not materially
differ from expectations.
* Electric Energy Competition
The electricity supply segment of the electric utility
industry in the United States is becoming increasingly
competitive. The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems. Since 1992, the wholesale
electricity market has become more competitive as companies began
to engage in nationwide power trading. In addition, an
increasing number of states have taken active steps toward
allowing retail customers the right to choose their electricity
supplier. The Company has been an advocate of federal
legislation to create competition in the retail electricity
markets to avoid regional dislocations and ensure level playing
fields. Legislation before the U.S. Congress to restructure the
nation's electric utility industry cleared an important hurdle on
October 28, 1999 when a House Commerce Committee subcommittee
gave its approval to the bill. The bill will now move on to the
full Commerce Committee where it will be considered next year.
In the absence of federal legislation, state-by-state
implementation has begun. All of the states the operating
subsidiaries serve are at various stages of implementation or
investigation of programs that allow customers to choose their
electric supplier. Pennsylvania is furthest along with a retail
<PAGE>
- 27 -
program in place, while Maryland, Virginia, and Ohio passed
legislation this year to implement retail choice. West Virginia
continues to actively study this issue. West Penn is currently
implementing a settlement agreement to create competition for
electricity supply in Pennsylvania. Potomac Edison filed a
settlement agreement to introduce generation competition with the
Maryland PSC on September 23, 1999. Maryland PSC approval is
expected before the end of 1999.
Activities at the Federal Level
The Company continues to seek enactment of federal
legislation to bring choice to all retail electric customers,
deregulate the generation and sale of electricity on a national
level, and create a more liquid, free market for electric power.
Fully meeting challenges in the emerging competitive environment
will be difficult for the Company unless certain outmoded and
anti-competitive laws, specifically the Public Utility Holding
Company Act of 1935 (PUHCA) and Section 210 of the Public Utility
Regulatory Policies Act of 1978 (PURPA), are repealed or
significantly revised. The Company continues to advocate the
repeal of PUHCA and PURPA on the grounds that they are obsolete
and anti-competitive and that PURPA results in utility customers
paying above-market prices for power. H.R. 2944, which was
sponsored by Representative Joe Barton, was favorably reported
out of the House Commerce Subcommittee on Energy and Power.
While the bill does not mandate a date certain for customer
choice, several key provisions favored by the Company are
included in the legislation, including an amendment that allows
existing state restructuring plans and agreements to remain in
effect. Other provisions address important Company priorities by
repealing the PUHCA and the mandatory purchase provisions of the
PURPA. Consensus remains elusive with significant hurdles
remaining in both houses of Congress. It is too early to tell
whether momentum on the issue will result in legislation in the
current Congress.
Maryland
On April 8, 1999, Maryland Governor Glendening signed the
legislation that will bring competition to Maryland's electric
generation market. The Maryland PSC is in the process of
implementing the new law. Final Electric Restructuring
Roundtable reports were filed with the Commission in May and
legislative-style hearings were held this summer on the
Roundtable reports. The Commission is expected to issue
decisions on those aspects of restructuring by the end of the
year.
On September 23, the Company filed a Settlement Agreement
(covering the Company's stranded cost quantification mechanism,
price protection mechanism, and unbundled rates) with the
Maryland PSC. The Agreement was signed by all parties active in
the case except Eastalco, who stated although they did not sign
the agreement, they would not oppose it. The settlement
agreement, which is subject to Commission approval, includes the
following provisions:
* The ability for nearly all of our 208,000 Maryland customers
to have the option of choosing an electric generation supplier
starting July 1, 2000.
* The authorization to transfer generating assets to a non-
regulated corporate entity at book value on July 1, 2000.
<PAGE>
- 28 -
* A reduction in base rates of 7% for residential customers
from 2002 through 2008 ($10.4 million each year, totaling $72.8
million). A reduction in base rates of one-half a percent for
the majority of commercial and industrial customers from 2002
through 2008 ($1.5 million each year, totaling $10.5 million).
* Standard Offer Service (provider of last resort) will be
provided to residential customers during a transition period from
July 1, 2000 to December 31, 2008 and to all other customers
during a transition period of July 1, 2000 to December 31, 2004.
* A cap on generation rates for residential customers from
2002 through 2008. Generation rates for non-residential
customers are capped from 2002 through 2004.
* A cap on transmission and distribution rates for all
customers from 2002 through 2004.
* Unless the Company is subject to significant changes that
would materially affect the Company's financial condition, the
parties agree not to seek a reduction in rates which would be
effective prior to January 1, 2005.
* The recovery of all purchased power costs incurred as a
result of our contract to buy generation from the AES Warrior Run
PURPA cogeneration contract.
* The establishment of a fund for the development and use of
energy-efficient technologies.
On October 4, the Company filed unbundled rates covering
the period 2000-2008. The Commission held public hearings
regarding the settlement agreement on October 14 and October 18.
A final Commission decision is expected before the end of 1999.
Ohio
The Ohio General Assembly ended five years of debate on
June 22, 1999 when it passed legislation to restructure the
electric utility industry. Governor Taft added his signature
soon thereafter, and all of the state's customers will be able to
choose their electricity supplier starting January 1, 2001,
beginning a five-year transition to market rates. Total electric
rates will be frozen over that period, and residential customers
are guaranteed a five percent cut in the generation portion of
their rate. The determination of stranded cost recovery will be
handled by The Public Utilities Commission of Ohio. The bill
stipulates that no entity shall own or control transmission
facilities after the start of competitive retail electric
service. Customer protections were kept intact with a low-income
assistance plan and a one-time forgiveness of past debts for low-
income and handicapped customers. In regard to renewable energy,
the bill requires that electric generators purchase excess
electricity from small businesses and homes using renewable
energy sources. In addition, a customer's bill will list what
fuel was expended to produce the electricity and what emissions
were created.
<PAGE>
- 29 -
Virginia
The Virginia Electric Utility Restructuring Act (the
"Restructuring Act") was passed by the Virginia General Assembly
on March 25, 1999 and signed by the Governor of Virginia on March
29, 1999. The Legislative Transition Task Force on Electric
Utility Restructuring, which was established by the Restructuring
Act, held hearings this summer on a number of issues concerning
the implementation of retail competition in Virginia. Working
groups continued to meet with State Corporation Commission staff,
comments were filed, and Commission hearings were held to discuss
the nature of and the rules governing the proposed retail pilot
programs of other utilities in the state.
West Virginia
In March 1998, legislation was passed by the West
Virginia Legislature that directed the W.Va. PSC to meet with all
interested parties to develop a restructuring plan which would
meet the dictates and goals of the legislation. Interested
parties formed a Task Force that met during 1998, but the Task
Force was unable to reach a consensus on a model for
restructuring. The W.Va. PSC held hearings in August 1999 that
addressed certification, licensing, bonding, reliability,
universal service, consumer protection, code of conduct,
subsidies, and stranded costs. The August hearings have
concluded and the W.Va. PSC has stated that it would issue an
order after November 1, 1999. The Order will have a
determination as to whether deregulation is in the best interest
of West Virginia, and if so, a plan may be issued with it.
Informal negotiations with all of the parties will continue
beyond the November 1 Commission-imposed deadline to seek
consensus on a restructuring plan, although no agreements have
been reached to date.
Accounting for the Effects of Price Deregulation
In July 1997, the Emerging Issues Task Force (EITF) of
the Financial Accounting Standards Board (FASB) released Issue
No. 97-4, "Deregulation of the Pricing of Electricity - Issues
Related to the Application of FASB Statement Nos. 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. Because Maryland, Ohio, and
Virginia have passed legislation for a deregulation plan, the
Company has determined that it will be required to discontinue
use of SFAS No. 71 for the generation portion of its business
(the Maryland, Ohio, and Virginia portion) on an uncertain future
date. West Virginia has not yet developed a restructuring plan.
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 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 Maryland, Ohio, and
Virginia legislations establish definitive processes for
transition to deregulation and market-based pricing for electric
generation. Until relevant regulatory proceedings are complete
and final orders are received, the Company is unable to predict
the effect of discontinuing SFAS No. 71, but it may be required
to write off significant unrecoverable regulatory assets,
impaired assets, and uneconomic commitments.
<PAGE>
- 30 -
ALLEGHENY ENERGY, INC.
Part II - Other Information to Form 10-Q
for Quarter Ended September 30, 1999
ITEM 1. LEGAL PROCEEDINGS
The MidAtlantic case, previously reported as an ongoing
litigation matter, has been settled and an Order was entered on
July 9, 1999 dismissing the case with prejudice.
As of September 30, 1999, Monongahela Power Company has been
named as a defendant, along with multiple other defendants in a
total of approximately 8,626 asbestos cases. The Potomac Edison
Company and West Penn Power Company were named as defendants
along with multiple other defendants in approximately one-half of
those cases. As of September 30, 1999, a total of 878 cases have
been settled and/or dismissed against Monongahela Power Company,
The Potomac Edison Company, and West Penn Power Company for
reasonable settlement amounts. While the operating subsidiaries
believe that all of the cases are without merit, they cannot
predict the outcome nor are they able to determine whether
additional cases will be filed.
As previously reported, on October 5, 1998 DQE, Inc.
(DQE), parent company of Duquesne Light Company in Pittsburgh,
Pa., notified the Company that it had unilaterally decided to
terminate the merger. In response, the Company filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the Merger Agreement or, alternatively, damages.
On March 11, 1999, the United States Court of Appeals for the
Third Circuit vacated the United States District Court for the
Western District of Pennsylvania's denial of the Company's motion
for preliminary injunction, enjoining DQE from taking actions
prohibited by the Merger Agreement. The Circuit Court stated
that if DQE breached the Merger Agreement, the Company may be
entitled to specific performance of the Merger Agreement. The
Circuit Court also stated that the Company could be irreparably
harmed if DQE took actions that would prevent the Company from
receiving the specific performance remedy. The Circuit Court
remanded the case to the District Court for further proceedings
consistent with its opinion.
The District Court denied DQE's motion for summary
judgment. The District Court has held a trial on October 18-28,
1999, without a jury, on the issues of whether DQE's termination
of the Merger Agreement breached the agreement and whether the
Company is entitled to specific performance. A decision by the
District Court is expected by the end of 1999. The Company
cannot predict the outcome of this litigation. However, the
Company believes that DQE's basis for terminating the merger is
without merit. Accordingly, the Company continues to seek the
necessary regulatory approvals. It is not likely any agency will
act further on the merger unless the Company obtains judicial
relief requiring DQE to move forward.
<PAGE>
- 31 -
ITEM 5. OTHER EVENTS
The Attorney General of the State of New York and the
Attorney General of the State of Connecticut in their letters
dated September 15, 1999 and November 3, 1999, respectively,
notified Allegheny Energy, Inc. (Allegheny Energy) of their
intent to commence civil actions against Allegheny Energy or its
subsidiaries (West Penn Power Company, Monongahela Power Company,
The Potomac Edson Company, and AYP Energy, Inc.) alleging violations
at the Fort Martin power station under the Federal Clean Air Act,
which requires power plants that make major modifications to comply
with the same emission standards applicable to new power plants.
Similar actions may be commenced by other governmental authorities
in the future. Fort Martin is a station located in West Virginia
jointly owned by West Penn Power Company, Monongahela Power Company,
The Potomac Edison Company, and AYP Energy, Inc. Both Attorneys
General stated their intent to seek injunctive relief and penalties.
In addition, the Attorney General of the State of New York
in his letter indicated that he may assert claims under the State
common law of public nuisance seeking to recover, among other
things, compensation for alleged environmental damage caused in
New York by the operation of Fort Martin power station.
At this time, Allegheny Energy and its subsidiaries are not
able to determine what impact, if any, these actions taken by the
Attorneys General of New York and Connecticut may have on them.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(27) Financial Data Schedule
(b) The Company filed Form 8-K's on July 20, 1999 and
September 10, 1999.
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/ T. J. KLOC
T. J. Kloc, Vice President
and Controller
(Chief Accounting Officer)
November 15, 1999
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<S> <C>
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<PERIOD-START> JUL-01-1999
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0
74,000
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