<PAGE>
Page 1 of 27
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 1-255-2
WEST PENN POWER COMPANY
(Exact name of registrant as specified in its charter)
Pennsylvania 13-5480882
(State of Incorporation) (I.R.S. Employer Identification No.)
800 Cabin Hill Drive, Greensburg, Pennsylvania 15601
Telephone Number - 724-837-3000
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, 24,361,586 shares of the Common Stock
(no par value) of the registrant were outstanding, all of which
are held by Allegheny Energy, Inc., the Company's parent.
<PAGE>
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WEST PENN POWER COMPANY AND SUBSIDIARIES
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 11-25
PART II--OTHER INFORMATION 26-27
<PAGE>
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Income
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
ELECTRIC OPERATING REVENUES:
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Utility $ 249,062 $ 288,272 $ 730,577 $ 831,998
Nonutility 146,600 - 310,084 -
Total Operating Revenues 395,662 288,272 1,040,661 831,998
OPERATING EXPENSES:
Operation:
Fuel 62,962 67,874 178,855 196,482
Purchased power and exchanges, net 156,415 31,790 286,947 90,221
Other 45,620 34,961 132,921 111,666
Maintenance 23,111 20,576 71,729 66,747
Depreciation and amortization 31,239 27,837 94,142 86,602
Taxes other than income taxes 19,611 22,568 63,483 67,433
Federal and state income taxes 14,409 26,418 64,526 63,353
Total Operating Expenses 353,367 232,024 892,603 682,504
Operating Income 42,295 56,248 148,058 149,494
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 41 (430) 126 315
Other income, net 3,934 2,614 8,571 8,174
Total Other Income and Deductions 3,975 2,184 8,697 8,489
Income Before Interest Charges 46,270 58,432 156,755 157,983
INTEREST CHARGES:
Interest on long-term debt 13,605 14,634 44,168 46,570
Other interest 2,064 1,777 4,291 4,623
Allowance for borrowed funds used during
construction (906) (814) (2,359) (1,354)
Total Interest Charges 14,763 15,597 46,100 49,839
Consolidated Income Before
Extraordinary Charge 31,507 42,835 110,655 108,144
Extraordinary Charge, net (1) - - - (265,446)
CONSOLIDATED NET INCOME (LOSS) $ 31,507 $ 42,835 $ 110,655 $ (157,302)
</TABLE>
See accompanying notes to consolidated financial statements.
(1) See Note 8 in the notes to the consolidated financial statements.
<PAGE>
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet
(Thousands of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
ASSETS: 1999 1998
Property, Plant, and Equipment:
At original cost, including $107,598
<S> <C> <C>
and $75,725 under construction $ 3,431,533 $ 3,365,784
Accumulated depreciation (1,437,430) (1,362,413)
1,994,103 2,003,371
Investments and Other Assets:
Allegheny Generating Company - common stock at equity 70,716 74,374
Other 568 646
71,284 75,020
Current Assets:
Cash and temporary cash investments 7,924 4,523
Accounts receivable:
Electric service 171,237 132,386
Affiliated and other 57,801 26,381
Allowance for uncollectible accounts (17,632) (14,760)
Materials and supplies - at average cost:
Operating and construction 44,076 43,167
Fuel 25,623 24,363
Prepaid taxes 9,624 14,534
Regulatory assets 18,460 17,372
Other 16,462 2,261
333,575 250,227
Deferred Charges:
Regulatory assets 475,494 475,776
Unamortized loss on reacquired debt 3,735 4,065
Other 18,452 34,610
497,681 514,451
Total Assets $ 2,896,643 $ 2,843,069
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 465,994 $ 465,994
Other paid-in capital 55,475 55,475
Retained earnings 232,687 210,692
754,156 732,161
Preferred stock - 79,708
Long-term debt and QUIDS 839,107 837,725
Funds on deposit with trustees (9,629) -
1,583,634 1,649,594
Current Liabilities:
Short-term debt 131,887 55,766
Notes payable to affiliates 48,400 9,300
Accounts payable 114,357 77,815
Accounts payable to affiliates 36,060 33,859
Taxes accrued:
Federal and state income 11,435 1,002
Other 5,888 16,711
Interest accrued 10,882 15,681
Refunds payable 6,160 28,151
Adverse power purchase commitments-ST 49,185 47,173
Other 18,946 15,393
433,200 300,851
Deferred Credits and Other Liabilities:
Unamortized investment credit 40,691 42,630
Deferred income taxes 300,884 260,477
Regulatory liabilities 28,393 28,325
Adverse power purchase commitments-LT 501,354 538,745
Other 8,487 22,447
879,809 892,624
Total Capitalization and Liabilities $ 2,896,643 $ 2,843,069
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE>
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WEST PENN POWER COMPANY
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>
Consolidated net income (loss) $ 110,655 $ (157,302)
Extraordinary charge, net of taxes - 265,446
Consolidated income before extraordinary charge 110,655 108,144
Depreciation 94,142 86,602
Deferred investment credit and income taxes, net 20,952 3,139
Unconsolidated subsidiaries' dividends in excess of earnings 3,735 17,381
Allowance for other than borrowed funds used
during construction (126) (315)
Changes in certain assets and liabilities:
Accounts receivable, net (67,399) (13,522)
Materials and supplies (2,169) 3,788
Prepaid taxes 4,910 (5,309)
Accounts payable 38,743 14,358
Taxes accrued (390) (5,401)
Interest accrued (4,799) (4,541)
Adverse power purchase commitments (35,379) -
Restructuring settlement rate refund (18,940) -
Other, net (5,487) (18,558)
138,448 185,766
CASH FLOWS FROM INVESTING:
Utility construction expenditures (less allowance for
other than borrowed funds used during construction) (61,786) (62,193)
Nonutility construction expenditures (18,913) -
(80,699) (62,193)
CASH FLOWS FROM FINANCING:
Retirement of preferred stock (82,964) -
Issuance of long-term debt 97,830 92,834
Retirement of long-term debt (99,031) (161,435)
Short-term debt, net 76,121 (9,800)
Notes payable to affiliates 39,100 33,750
Dividends on capital stock:
Preferred stock (1,600) (2,537)
Common stock (83,804) (77,713)
(54,348) (124,901)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 3,401 (1,328)
Cash and temporary cash investments at January 1 4,523 4,056
Cash and temporary cash investments at September 30 $ 7,924 $ 2,728
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of amount capitalized) $49,870 $51,960
Income taxes 30,608 56,129
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE>
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. West Penn Power Company (the Company) is a wholly-owned
subsidiary of Allegheny Energy, Inc. (the Parent or Allegheny
Energy). The Company's Notes to Consolidated Financial
Statements 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.
2. 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.
3. The Company owns 45% of the common stock of Allegheny
Generating Company (AGC), and affiliates of the Company own
the remainder. AGC is reported by the Company in its
financial statements using the equity method of accounting.
AGC owns an undivided 40% interest, 840 megawatts (MW), in
the 2,100-MW pumped-storage hydroelectric station in Bath
County, Virginia, operated by the 60% owner, Virginia
Electric and Power Company, a nonaffiliated utility.
AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and
a return on its investment under a wholesale rate schedule
approved by the Federal Energy Regulatory Commission (FERC).
AGC's rates are set by a formula filed with and previously
accepted by the FERC. The only component which changes is
the return on equity (ROE). Pursuant to a settlement
agreement filed April 4, 1996 with the FERC, AGC's ROE was
set at 11% for 1996 and will continue until the time any
affected party seeks renegotiation of the ROE.
<PAGE>
- 7 -
Following is a summary of income statement information for
AGC:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Thousands of Dollars)
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
Electric operating revenues $18,072 $18,303 $53,739 $56,033
Operation and maintenance
expense 1,207 888 4,122 3,383
Depreciation 4,245 4,242 12,735 12,710
Taxes other than income taxes 1,137 1,168 3,398 3,505
Federal income taxes 2,662 2,708 7,622 8,480
Interest charges 3,305 3,707 9,993 10,518
Other income, net - (35) (2) (86)
Net income $ 5,516 $ 5,625 $15,871 $17,523
</TABLE>
The Company's share of the equity in earnings above was $2.5
million for the three months ended September 30, 1999 and
1998, and $7.1 million and $7.9 million for the nine months
ended September 30, 1999 and 1998, respectively, and was
included in other income, net, on the Company's Consolidated
Statement of Income.
4. As previously reported, on October 5, 1998, DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
notified Allegheny Energy that it had unilaterally decided to
terminate the merger. In response, Allegheny Energy 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 Allegheny Energy'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, Allegheny Energy
may be entitled to specific performance of the Merger
Agreement. The Circuit Court also stated that Allegheny
Energy could be irreparably harmed if DQE took actions that
would prevent Allegheny Energy 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
Allegheny Energy is entitled to specific performance. A
decision by the District Court is expected by the end of
1999. Allegheny Energy cannot predict the outcome of this
litigation. However, Allegheny Energy believes that DQE's
basis for terminating the merger is without merit.
Accordingly, Allegheny Energy continues to seek the necessary
regulatory approvals. It is not likely any agency will act
further on the merger unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.
<PAGE>
- 8 -
The $7.9 million deferred incremental costs of the merger
process recorded by the Company through March 31, 1999 were
transferred to the Parent company in the second quarter of
1999. The accumulated merger costs will be written off by
the Parent company when the merger occurs or if it is
determined that the merger will not occur.
5. The Consolidated Balance Sheet includes the amounts listed
below for generation assets not subject to SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation."
September 30 December 31
1999 1998
(Thousands of Dollars)
<TABLE>
<CAPTION>
Property, plant and equipment at
<S> <C> <C>
original cost $1,819,746 $1,798,838
Amounts under construction included above 55,169 39,227
Accumulated depreciation (907,062) (859,455)
</TABLE>
6. The Company's principal business segments are utility and
nonutility operations. The Company's utility business
includes the generation, purchase, transmission,
distribution, and sale of electric energy and is subject to
federal and state regulation. Nonutility operations consists
of the Energy Supply Division (ESD) of the Supply Business of
the Company, acting under the name of Allegheny Energy
Supply. The ESD has the primary objective of selling the
output of the Company's generation that has been freed up by
the Electricity Generation Customer Choice and Competition
Act (Customer Choice Act) in Pennsylvania (approximately
2,750 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.
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Thousands of Dollars)
<TABLE>
<CAPTION>
Operating Revenues:
<S> <C> <C> <C> <C>
Utility $249,062 $288,272 $730,577 $831,998
Nonutility 260,345* 573,271*
Eliminations (113,745) (263,187)
Depreciation:
Utility 18,161 27,837 55,063 86,602
Nonutility 13,078 39,079
Federal and State Income
Taxes:
Utility 7,510 26,418 41,184 63,353
Nonutility 6,899 23,342
Operating Income:
Utility 18,610 56,248 93,094 149,494
Nonutility 23,685 54,964
Interest Charges and
Preferred Dividends:
Utility 8,827 16,451 29,866 52,376
Nonutility 5,940 17,834
</TABLE>
<PAGE>
- 9 -
<TABLE>
<CAPTION>
Consolidated Income
Before Extraordinary
Charge:
<S> <C> <C> <C> <C>
Utility 12,835 42,835 72,626 108,144
Nonutility 18,672 38,029
Extraordinary Charge, Net:
Utility - 265,446
Nonutility
Capital Expenditures:
Utility 23,455 25,308 61,912 62,508
Nonutility 11,510 18,913
September 30 December 31
1999 1998
Identifiable Assets:
Utility $1,803,704 $2,843,069
Nonutility 1,092,939
</TABLE>
*Nonutility operating revenues includes $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.
7. The Company 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
<PAGE>
- 10 -
To the extent that the Company 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 the Company
during the years 1999 through 2002.
No Additional CTC Regulatory Asset was recorded by the
Company as of September 30, 1999.
The Company 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 the Company 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 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 the Company'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. The Company 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.
8. 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 the Company 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.
9. The Company 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 the Company
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.
The redemptions of the preferred stock allowed the Company to
revise its Articles of Incorporation providing greater
financial flexibility in restructuring debt.
10. The Company repurchased $96.4 million of first mortgage
bonds at par value during the second and third quarters of 1999.
<PAGE>
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WEST PENN POWER COMPANY AND SUBSIDIARIES
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 West Penn Power Company's (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 Pennsylvania, the proposed merger of the
Company's parent, Allegheny Energy, Inc. (Allegheny Energy) 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; environmental,
legislative, and regulatory changes; future economic conditions;
developments relating to the proposed merger of Allegheny Energy
with DQE; 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, its parent, Allegheny Energy, and affiliate,
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 the Company's
generating facilities. 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.
<PAGE>
- 12 -
During the fourth quarter, the Company will transfer its
deregulated generating capacity, which totals approximately 3,700
megawatts (MW), at book value as allowed by the final settlement
in the Company's Pennsylvania restructuring case to the new
generating company or GENCO.
Initially, the Company 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 the Company 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 the Company, 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 the Company's 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
the Company will dividend up to Allegheny Energy its ownership
interest in the new generating subsidiary. After this dividend,
the Company will no longer have any ownership interest in
generating assets or contractual rights to generating capacity
other than those arising under the PURPA.
All regulatory approvals to commence these transfers and
dividend have been received. It is expected that the Company
will complete the transfers of generating assets and
the dividend to Allegheny Energy in 1999.
* Proposed Merger with DQE
See Note 4 to the consolidated financial statements for
information about the proposed merger of Allegheny Energy with
DQE, and related litigation.
* 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 Allegheny Energy companies (the System) joined with other
members of the Edison Electric Institute in reporting power
station releases to the public. Packets of information about the
System's releases were provided to media in the System's area and
posted on the Parent Company's web site. The System 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.
<PAGE>
- 13 -
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 $12.8 $42.8 $ 72.6 $ 108.1
Nonutility operations 18.7 - 38.1 -
Consolidated income before
extraordinary charge 31.5 42.8 110.7 108.1
Extraordinary charge, net - - - (265.4)
Consolidated net income
(loss) $31.5 $42.8 $110.7 $(157.3)
The decrease in consolidated net income for the third
quarter of 1999 was primarily attributed to increased energy
costs during periods of high summer demand and higher operation
and maintenance costs in 1999 compared to third quarter 1998.
The increase in consolidated net income for the first
nine months of 1999 before the 1998 extraordinary charge was
primarily attributed to increased kilowatt-hour (kWh) sales,
including increased sales to residential customers due to winter
weather that was 24% cooler than the relatively warm winter of
1998, nonutility sales, and, to a lesser extent, reduced interest
expenses. Consolidated net income for the first nine months of
1998 include a previously reported extraordinary charge of $450.6
million ($265.4 million, net of taxes) to reflect a write-off by
the Company 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.
<PAGE>
- 14 -
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 $232.8 $261.7 $ 683.5 $763.9
Choice 8.3 4.6 24.2 10.5
Bulk power and trans-
mission services sales 8.0 22.0 22.9 57.6
Total utility revenues 249.1 288.3 730.6 832.0
Nonutility revenues 260.4* - 573.3* -
Elimination between utility
and nonutility (113.8) - (263.2) -
Total operating
revenues $395.7 $288.3 $1,040.7 $832.0
*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 the Company's 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 the Company's regulated customers the ability to choose
another energy supplier. These decreases to regulated revenue
were offset in part in the nine-month period by colder winter
weather in 1999 which led to increased residential and commercial
kWh sales.
Utility choice revenues for 1999 represent transmission
and distribution revenues from the Company's franchised customers
(customers in the Company'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 the Company's customers have chosen
alternate energy suppliers. The Energy Supply Division (ESD) of
the Company has the primary objective of selling the output from
the two-thirds of the Company'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 increased for the third quarter and
nine months ended September 30, 1999 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
<PAGE>
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electricity to customers on January 1, 1999. It uses the
Company'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 7 to the Consolidated Financial statements for
information regarding the Competitive Transition Charge.
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 $19.3 $67.9 $ 55.6 $196.5
Nonutility operations 43.7 - 123.3 -
Total fuel expenses $63.0 $67.9 $178.9 $196.5
Total fuel expenses decreased 7% and 9%, respectively, in
the three and nine months ended September 30, 1999 periods when
compared to the three and nine months ended September 30, 1998
periods. The decrease in the three months ended period is due to
an 11% decrease in average fuel prices offset by a 4% increase in
kWh's generated. The decrease in the nine-month period is due to
a 6% decrease in average fuel prices and a 3% decrease in kWh's
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 the
Company'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 PURPA, capacity charges paid to
Allegheny Generating Company (AGC), an affiliate partially owned
by the Company, and other transactions with affiliates made
pursuant to a power supply agreement whereby each company uses
the most economical generation available in the Allegheny Energy
System at any given time, and consists of the following items:
<PAGE>
- 16 -
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Utility operations:
Nonaffiliated transactions:
Purchased power:
From PURPA generation* $ 8.5 $14.7 $ 27.4 $47.5
Other 5.6 9.7 22.6 16.7
Power exchanges, net (.7) (1.4) .4 (.7)
Affiliated transactions:
AGC capacity charges 3.3 7.7 9.7 23.9
Energy and spinning
reserve charges .6 1.1 2.7 2.8
Total utility pur-
chased power and
exchanges, net 17.3 31.8 62.8 90.2
Nonutility operations: 144.2 - 242.7 -
Elimination (5.1) - (18.6) -
Purchased power and
exchanges, net $156.4 $31.8 $286.9 $90.2
*PURPA cost (cents per kWh) 4.8 5.8 4.5 5.8
Utility purchased power from PURPA generation decreased
$6.2 million and $20.1 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
the Company'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 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 was due 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
the Company'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.
<PAGE>
- 17 -
The decreases in Allegheny Generating Company (AGC)
capacity charges were due to a $4.8 million and $14.4 million
reduction in purchased power expense related to the Company's
purchase commitments at costs in excess of the market value of
the AGC pumped storage capacity contract in the third quarter and
nine months ended September 30, 1999, respectively. As reported
previously, the Company, in 1998, recorded an extraordinary
charge to reflect the cost of this and another adverse power
purchase commitment that is not recoverable from customers under
the Pennsylvania Public Utility Commission's 1998 Order and
settlement agreement.
The elimination between utility and nonutility purchased
power is necessary to remove the effect of affiliated purchased
power expenses.
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 $33.6 $35.0 $ 96.8 $111.7
Nonutility operations 13.6 - 42.3 -
Elimination (1.6) - (6.2) -
Total other operation
expenses $45.6 $35.0 $132.9 $111.7
Total other operation expenses for the third quarter of
1999 increased $10.6 million when compared to the same period in
1998. This increase was due primarily to increases in salaries,
wages, and employee benefits ($3.9 million), provisions for
uninsured claims ($2.4 million), and transmission costs ($2.0
million). Total other operation expenses for the nine months
ended September 30, 1999 increased $21.2 million when compared to
the same period in 1998. This increase resulted primarily from
increased salaries, wages and employee benefits ($8.5 million),
provisions for uninsured claims ($1.9 million), allowances for
uncollectible accounts ($1.9 million), the reversal of a
restructuring liability in the 1998 period ($2.0 million), and
Year 2000 expenses ($1.1 million). 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.
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 $13.9 $20.6 $43.4 $66.7
Nonutility operations 9.2 - 28.3 -
Total maintenance expenses $23.1 $20.6 $71.7 $66.7
<PAGE>
- 18 -
Total maintenance expenses for the third quarter and nine
months ended September 30, 1999 increased from the same periods
in 1998 by $2.6 million and $5.0 million, respectively, due
primarily to increased power station maintenance expenses. The
year-to-date decrease was also due to $1.7 million of incremental
transmission and distribution (T&D) storm damage expenses
incurred in June 1998 for an unusually large thunderstorm in the
Company's service territory. The decrease in utility maintenance
and the increase in nonutility maintenance was due to the
maintenance associated with the two-thirds of the Company's
deregulated generation now being classified as nonutility
maintenance. 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 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 $18.1 $27.8 $55.0 $86.6
Nonutility operations 13.1 - 39.1 -
Total depreciation and
amortization expense $31.2 $27.8 $94.1 $86.6
Total depreciation and amortization expenses in the third
quarter and first nine months of 1999 increased $3.4 million and
$7.5 million, respectively. The increases in both periods were
due to increased investment and the amortization of a regulatory
asset. The amortization of the generation-related regulatory
asset is related to the Company's 1998 settlement agreement.
Utility and nonutility depreciation expense reflects the movement
of depreciation expense associated with the two-thirds of freed
up generation from utility operations to nonutility operations.
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 $13.6 $22.6 $44.2 $67.4
Nonutility operations 6.0 - 19.3 -
Total taxes other than
income taxes $19.6 $22.6 $63.5 $67.4
<PAGE>
- 19 -
Total taxes other than income taxes decreased $3.0
million and $3.9 million in the third quarter and nine months
ended September 30, 1999. The decreases were due primarily to
lower capital stock taxes relating to the 1998 asset write down
as a result of Pennsylvania restructuring. Utility and
nonutility taxes other than income taxes reflect the movement of
taxes other than income taxes associated with the two-thirds of
the Company's generation transferred from utility operations to
nonutility operations.
The decrease in federal and state income taxes in the
third quarter of 1999 was due to a decrease in income before
taxes and the Company's share of tax savings in consolidation
related to its parent, Allegheny Energy, 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 $ 8.6 $14.6 $28.2 $46.6
Nonutility operations 5.0 - 16.0 -
Total interest on
long-term debt $13.6 $14.6 $44.2 $46.6
The decrease in interest on long-term debt in the third
quarter and the nine months ended September 30, 1999 of $1.0
million and $2.4 million, respectively, resulted primarily from
reduced long-term debt and lower interest rates.
Other interest expense reflects changes in the levels of
short-term debt maintained by the Company as well as the
associated rates.
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 Company is subject
to various contingencies and uncertainties relating to its
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 Allegheny Energy's proposed merger with DQE.
* Market Risk
The Company supplies 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.
<PAGE>
- 20 -
* Transition Bonds
The Company 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 the Company 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 bond 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.
* Redemption of Preferred Stock
The Company 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 the Company
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.
The redemption of the preferred stock allowed the Company
to revise its Articles of Incorporation providing greater
financial flexibility in restructuring debt.
* Repurchase of First Mortgage Bonds
During the second and third quarters of 1999, the Company
repurchased $96.4 million of first mortgage bonds. This reduced
the Company's outstanding first mortgage bonds to $428.6 million.
The Company 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, the Company issued $13.8 million of 5.50%
30-year pollution control revenue notes to Pleasants County, West
Virginia.
In June 1999, the Company 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 the
Company 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>
- 21 -
* 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 and its affiliates
in the System have 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
System.
In May 1998, the North American Electric Reliability
Council (NERC), of which the System 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 System 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 System relies
for critical materials and services.
The industry's and the System'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.
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, the System is interconnected with neighboring
utilities, which provides 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 System 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
<PAGE>
- 22 -
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.
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 $10 million of which $7 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.
<PAGE>
- 23 -
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 served by the
utility subsidiaries of Allegheny Energy 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 program in place, while Maryland, Virginia
and Ohio passed legislation this year to implement retail choice.
West Virginia continues to actively study this issue. The
Company is currently implementing a settlement agreement to
create competition for electricity supply in Pennsylvania.
Potomac Edison, an affiliate of the Company, 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 System 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 System 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 System 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 Allegheny Energy are
included in the legislation, including an amendment that allows
existing state restructuring plans and agreements to remain in
effect. Other provisions address important
<PAGE>
- 24 -
Allegheny Energy 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.
The status of electric energy competition in Ohio, West Virginia,
Virginia, and Maryland in which affiliates of the Company serve
are as follows:
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.
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.
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.
<PAGE>
- 25 -
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, Allegheny Energy filed a Settlement
Agreement (covering Allegheny Energy'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.
* 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 Allegheny Energy is subject to significant changes
that would materially affect Allegheny Energy'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 Allegheny Energy's 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, Allegheny Energy 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.
<PAGE>
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Part II - Other Information to Form 10-Q
for Quarter Ended September 30, 1999
ITEM 1. LEGAL PROCEEDINGS
As of September 30, 1999, Monongahela Power Company, an
affiliate of the Company, was named as a defendant, along with
multiple other defendants in a total of approximately 8,626
asbestos cases. The Company and The Potomac Edison Company, also
an affiliate of the 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 the Company, Monongahela Power
Company, and The Potomac Edison Company for reasonable settlement
amounts. While the Company, Monongahela Power Company, and The
Potomac Edison Company 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's parent, Allegheny Energy, Inc.
(Allegheny Energy) that it had unilaterally decided to terminate
the merger. In response, Allegheny Energy 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 Allegheny Energy'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, Allegheny Energy may
be entitled to specific performance of the Merger Agreement. The
Circuit Court also stated that Allegheny Energy could be
irreparably harmed if DQE took actions that would prevent
Allegheny Energy 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
Allegheny Energy is entitled to specific performance. A decision
by the District Court is expected by the end of 1999. Allegheny
Energy cannot predict the outcome of this litigation. However,
Allegheny Energy believes that DQE's basis for terminating the
merger is without merit. Accordingly, Allegheny Energy continues
to seek the necessary regulatory approvals. It is not likely any
agency will act further on the merger unless Allegheny Energy
obtains judicial relief requiring DQE to move forward.
<PAGE>
- 27 -
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 Edison 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) No reports on Form 8-K were filed on behalf of the
Company for the quarter ended September 30, 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.
WEST PENN POWER COMPANY
/s/ T. J. KLOC
T. J. Kloc, Controller
(Chief Accounting Officer)
November 15, 1999
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