<PAGE>
Page 1 of 23
FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Quarterly Report under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For Quarter Ended March 31, 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 May 14, 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.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Form 10-Q for Quarter Ended March 31, 1999
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Consolidated Statement of Income -
Three months ended March 31, 1999 and 1998 3
Consolidated Balance Sheet - March 31, 1999
and December 31, 1998 4
Consolidated Statement of Cash Flows -
Three months ended March 31, 1999 and 1998 5
Notes to Consolidated Financial Statements 6-10
Management's Discussion and Analysis of Financial
Condition and Results of Operations 11-22
PART II--OTHER INFORMATION 23
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Income
(Thousands of Dollars)
Three Months Ended
March 31
1999 1998
ELECTRIC OPERATING REVENUES:
Utility $ 252,008 $ 280,703
Nonutility 65,722 -
Total Operating Revenues 317,730 280,703
OPERATING EXPENSES:
Operation:
Fuel 61,013 64,313
Purchased power and exchanges, net 46,828 30,717
Other 44,878 35,239
Maintenance 24,713 22,942
Depreciation 31,688 29,340
Taxes other than income taxes 20,773 23,125
Federal and state income taxes 29,163 22,408
Total Operating Expenses 259,056 228,084
Operating Income 58,674 52,619
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 63 618
Other income, net 2,161 2,666
Total Other Income and Deductions 2,224 3,284
Income Before Interest Charges 60,898 55,903
INTEREST CHARGES:
Interest on long-term debt 15,108 16,365
Other interest 956 878
Allowance for borrowed funds used during
construction (665) (341)
Total Interest Charges 15,399 16,902
CONSOLIDATED NET INCOME $ 45,499 $ 39,001
See accompanying notes to consolidated financial statements.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet
(Thousands of Dollars)
<TABLE>
<CAPTION>
March 31, December 31,
ASSETS: 1999 1998
Property, Plant, and Equipment:
<S> <C> <C>
At original cost, including $80,023
and $75,725 under construction $ 3,377,431 $ 3,365,784
Accumulated depreciation (1,387,946) (1,362,413)
1,989,485 2,003,371
Investments and Other Assets:
Allegheny Generating Company - common stock at equity 73,048 74,374
Other 619 646
73,667 75,020
Current Assets:
Cash and temporary cash investments 6,198 4,523
Accounts receivable:
Electric service 153,577 132,386
Affiliated and other 70,094 26,381
Allowance for uncollectible accounts (15,884) (14,760)
Materials and supplies - at average cost:
Operating and construction 45,227 43,167
Fuel 28,364 24,363
Prepaid taxes 32,706 14,534
Regulatory assets 17,372 17,372
Other 1,775 2,261
339,429 250,227
Deferred Charges:
Regulatory assets 479,862 475,776
Unamortized loss on reacquired debt 3,961 4,065
Other 36,824 34,610
520,647 514,451
Total Assets $ 2,923,228 $ 2,843,069
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 465,994 $ 465,994
Other paid-in capital 55,475 55,475
Retained earnings 198,392 210,692
719,861 732,161
Preferred stock 79,708 79,708
Long-term debt and QUIDS 838,000 837,725
1,637,569 1,649,594
Current Liabilities:
Short-term debt 64,197 55,766
Notes payable to affiliate 54,000 9,300
Accounts payable 78,537 77,815
Accounts payable to affiliates 56,900 33,859
Taxes accrued:
Federal and state income 20,005 1,002
Other 11,196 16,711
Interest accrued 11,431 15,681
Refunds payable 18,619 28,151
Adverse power purchase commitments-ST 47,173 47,173
Other 32,385 15,393
394,443 300,851
Deferred Credits and Other Liabilities:
Unamortized investment credit 41,981 42,630
Deferred income taxes 259,885 260,477
Regulatory liabilities 29,221 28,325
Adverse power purchase commitments-LT 526,952 538,745
Other 33,177 22,447
891,216 892,624
Total Capitalization and Liabilities $ 2,923,228 $ 2,843,069
</TABLE>
See accompanying notes to consolidated financial statements.
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WEST PENN POWER COMPANY
Consolidated Statement of Cash Flows
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended
March 31
1999 1998
CASH FLOWS FROM OPERATIONS:
<S> <C> <C> <C> <C>
Consolidated net income $ 45,499 $ 39,001
Depreciation 31,688 29,340
Deferred investment credit and income taxes, net 9,857 1,691
Unconsolidated subsidiaries' dividends in excess of earnings 1,353 950
Allowance for other than borrowed funds used
during construction (63) (618)
Internal restructuring liability - (3,547)
Changes in certain current assets and
liabilities:
Accounts receivable, net (63,780) 10,625
Materials and supplies (6,061) (3,136)
Prepaid taxes (18,172) (23,645)
Accounts payable 23,763 5,236
Taxes accrued 13,488 3,622
Interest accrued (4,250) (2,409)
Other, net (10,374) (3,628)
22,948 53,482
CASH FLOWS FROM INVESTING:
Utility construction expenditures (less allowance for
other than borrowed funds used during construction) (15,350) (17,825)
Nonutility construction expenditures (1,255) -
(16,605) (17,825)
CASH FLOWS FROM FINANCING:
Issuance of long-term debt - 59,435
Retirement of long-term debt - (45,000)
Deposit with trustee for redemption
of long-term debt - (14,601)
Short-term debt, net 8,431 19,342
Notes payable to affiliates 44,700 600
Dividends on capital stock:
Preferred stock (793) (838)
Common stock (57,006) (55,788)
(4,668) (36,850)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 1,675 (1,193)
Cash and temporary cash investments at January 1 4,523 4,056
Cash and temporary cash investments at March 31 $ 6,198 $ 2,863
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of amount capitalized) $ 19,302 $ 17,842
Income taxes 818 3,802
</TABLE>
See accompanying notes to consolidated financial statements.
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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 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 March 31, 1999, and the results of operations and cash
flows for the three months ended March 31, 1999 and 1998.
2. Statement of Financial Accounting Standards (SFAS) No. 130,
"Reporting Comprehensive Income," established standards for
reporting comprehensive income and its components (revenues,
expenses, gains, and losses) in the financial statements.
The Company does not have any elements of other comprehensive
income to report in accordance with SFAS No. 130. 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 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.
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Following is a summary of income statement information for
AGC:
Three Months Ended
March 31
1999 1998
(Thousands of Dollars)
Electric operating revenues $17,857 $18,604
Operation and maintenance expense 1,611 953
Depreciation 4,245 4,226
Taxes other than income taxes 1,132 1,160
Federal income taxes 2,414 2,865
Interest charges 3,403 3,513
Other income, net (1) (50)
Net income $ 5,053 $ 5,937
The Company's share of the equity in earnings above was $2.3
million and $2.7 million for the three months ended March 31,
1999 and 1998, respectively, and is included in other income,
net, on the Company's Consolidated Statement of Income.
Dividends received from AGC in the first quarter of 1999
approximated $3.6 million which reflects an effort to reduce
AGC equity to about 45% of total capitalization and short-
term debt.
4. 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 parent, Allegheny Energy, Inc., (Allegheny Energy)
motion for preliminary injunction, enjoining DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
from taking actions prohibited by the Merger Agreement. The
Circuit Court stated that if DQE breached the Merger
Agreement, Allegheny Energy would be entitled to specific
performance of the Merger Agreement. The Circuit Court also
stated that Allegheny Energy would 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.
In the District Court, discovery is ongoing, and Allegheny
Energy cannot predict the outcome of this litigation.
However, Allegheny Energy believes that DQE's basis for
seeking to terminate the merger is without merit.
Accordingly, Allegheny Energy continues to seek the remaining
regulatory approvals from the Department of Justice and the
Securities and Exchange Commission. It is not likely either
agency will act on the requests unless Allegheny Energy
obtains judicial relief requiring DQE to move forward.
All of the Company's incremental costs of the merger process
($7.9 million through March 31, 1999) are deferred. The
accumulated merger costs will be written off by the Company
when the merger occurs or if it is determined that the merger
will not occur.
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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."
March December
1999 1998
(Thousands of Dollars)
Property, plant and equipment at
original cost $1,799,627 $1,798,838
Amounts under construction included above 37,263 39,227
Accumulated depreciation (876,641) (859,455)
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. 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 Company's generation that has been freed up by
the Electricity Generation Customer Choice and Competition
Act (Customer Choice Act) in Pennsylvania and is no longer
regulated by the Pennsylvania Public Utility Commission
(Pennsylvania PUC).
Business segment information is summarized below.
Significant transactions between reportable segments are
eliminated to reconcile the segment information to
consolidated amounts.
Three Months Ended
March 31
1999 1998
(Thousands of Dollars)
Operating Revenues:
Utility $ 252,008 $ 280,703
Nonutility 135,897*
Eliminations (70,175)
Depreciation:
Utility 18,336 29,340
Nonutility 13,352
Federal and State Income Taxes:
Utility 17,812 22,408
Nonutility 11,351
Operating Income:
Utility 37,182 52,619
Nonutility 21,492
Interest Charges and Preferred Dividends:
Utility 10,407 17,740
Nonutility 5,786
Consolidated Net Income:
Utility 29,787 39,001
Nonutility 15,712
Capital Expenditures:
Utility 15,413 18,443
Nonutility 1,255
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March 31 December 31
1999 1998
Identifiable Assets:
Utility $1,932,658 $2,843,069
Nonutility 990,570
*Includes $18.7 million of allocated Competitive Transition
Charge (CTC) revenues to compensate for certain transition
costs transferred to nonutility operations.
7. The Company is authorized to collect a CTC from its
distribution customers over the period 1999 to 2008 as a
result of a 1998 Order of the Pennsylvania PUC.
The November 1998 Order of the Pennsylvania PUC provides for
annual recovery of "transition costs" from distribution
customers as follows:
Year Amount
(Millions of Dollars)
1999 $122
2000 121
2001 115
2002 113
2003 112
2004 104
2005 99
2006 98
2007 97
2008 97
The Order also provides that any over or underrecovery of
such annual amounts shall be adjusted through a change in the
following year recovery factor to insure customers pay no
more nor less than the allowable amounts. CTC revenues
recorded in the first quarter of 1999 totaled $39.2 million.
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
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To the extent that the Company records any or all of the
Additional CTC Regulatory Asset, it will be amortized between
2005 and 2008. The 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 to 2002.
No Additional CTC Regulatory Asset was recorded by the
Company as of March 31, 1999.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF FIRST QUARTER OF 1999 WITH FIRST QUARTER OF 1998
The Notes to Consolidated Financial Statements and
Management's Discussion and Analysis of Financial Condition and
Results of Operations in the Company's Annual Report on Form 10-K
for the year ended December 31, 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
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 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 Quarter 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. Regulatory approval must also
be obtained from the Federal Energy Regulatory Commission (FERC),
and the Pennsylvania Public Utility Commission (Pennsylvania PUC)
will review the proposed plan.
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Upon approval, the Company will transfer 3,722 megawatts
(MW) of owned generating capacity at book value as allowed by the
final settlement in the Company's Pennsylvania restructuring case
to the new generating company or GENCO. The Company will
transfer the generating assets to an unregulated, wholly owned
GENCO, which will be a subsidiary of Allegheny Energy. The
Energy Supply Division of the Company which currently sells
competitive retail and wholesale generation in deregulated
markets will also become part of the GENCO.
It is expected that the necessary approvals will be
received by the end of 1999.
- - Merger with DQE
See Note 4 to the consolidated financial statements for
information about the proposed merger of Allegheny Energy, Inc.,
the Company's parent, with DQE, Inc. (DQE), parent company of
Duquesne Light Company in Pittsburgh, Pa., and proposed
litigation.
Review of Operations
EARNINGS SUMMARY
Consolidated net income for the first quarter of 1999 was
$45.5 million compared with $39.0 million for the corresponding
1998 period. The increase in consolidated net income for the
first quarter of 1999 was due to increased kilowatt-hour (kWh)
sales and deliveries to retail customers, increased bulk power
transactions, and new sales in Pennsylvania's competitive
markets. The winter of 1999 was 24% cooler that the relatively
warm winter of 1998, as measured by the heating degree days, but
was still more than 3% warmer that normal. Residential kWh
deliveries to customers who have chosen an alternate supplier and
kWh sales to regular customers, which are very weather sensitive,
increased 15% in the first quarter of 1999. Current utility and
nonutility earnings are also supported by the beneficial effects
of transition cost recovery as authorized in our Pennsylvania
restructuring settlement.
SALES AND REVENUES
Total operating revenues for the first quarter of 1999
and 1998 were as follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Operating revenues:
Utility revenues:
Regulated $238.0 $263.4
Choice 6.8 3.6
Bulk power and transmission services sales 7.2 13.7
Total utility revenues 252.0 280.7
Nonutility revenues 135.9* -
Elimination between utility and nonutility (70.2)
Total operating revenues $317.7 $280.7
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*Includes $18.7 million of allocated Competitive Transition
Charge revenues to compensate for certain transition costs
transferred to nonutility operations.
The decrease in regulated revenues (includes revenues
from the Company's customers eligible to choose an alternate
energy supplier but elected not to do so) was due primarily to
certain of the Company's customers choosing another energy
supplier. These decreases to regulated revenues were offset in
part by colder weather which led to increased retail sales. The
decrease related to competition occurred as a result of
Pennsylvania competition which gave two-thirds of the Company's
regulated customers the ability to choose another energy
supplier.
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 Electricity Generation
Customer Choice and Competition Act (Customer Choice Act) in
Pennsylvania. As a result of the ESD 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 ESD. The ESD
officially began supplying electricity to retail customers on
January 1, 1999. It uses the two-thirds of generation freed up
by the Customer Choice Act in Pennsylvania to sell electricity to
both wholesale and retail customers in the unregulated
marketplace.
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 Transmission Charge.
OPERATING EXPENSES
Fuel expenses for the first quarter of 1999 and 1998 were as
follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Utility operations $19.5 $64.3
Nonutility operations 41.5 -
Total fuel expenses $61.0 $64.3
Total fuel expenses for the first quarter of 1999
decreased 5% primarily due to a 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.
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Purchased power and exchanges, net, represents power
purchases from and exchanges with other companies and purchases
from qualified facilities under the Public Utility Regulatory
Policies Act of 1978 (PURPA), 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:
Three Months Ended
March 31
1999 1998
Utility: (Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
From PURPA generation* $ 9.5 $16.5
Other 14.7 4.1
Power exchanges, net 2.5 1.4
Affiliated transactions:
AGC capacity charges 3.2 7.9
Energy and spinning reserve charges 1.2 .8
Total Utility purchased power and
exchanges, net 31.1 30.7
Nonutility operations 18.7
Elimination (3.0)
Purchased power and exchanges, net $46.8 $30.7
*PURPA cost (cents per kWh) 4.5 5.8
The decrease of $7 million in utility purchased power
from PURPA generation reflects a $2.7 million reduction related
to the Company's purchase commitment at costs in excess of the
market value of the AES Beaver Valley contract and also a
decrease of $3.7 million 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 cost reflects the amortization of excess costs accruals
recorded as an adverse power purchase commitment net of the
Competitive Transition Charge (CTC) revenue recovery in
conjunction with deregulation proceedings in Pennsylvania.
The increase in other utility operations purchased power
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. The generation
previously available to serve those customers has been freed up
by the Customer Choice Act in Pennsylvania and is being marketed
by the Energy Supply Division of the Company to the unregulated
marketplace.
The decrease in Allegheny Generating Company (AGC)
capacity charges was due to a $4.8 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. Purchased power expense will be reduced $166
million during the period 1999-2016 related to the AGC contract
as a result of the 1998 extraordinary charge recorded by West
Penn. The
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extraordinary charge reflects adverse power purchase commitments
that are 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 first quarter of 1999
and 1998 were as follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Utility operations $33.9 $35.2
Nonutility operations 13.6 -
Elimination (2.6)
Total other operation expenses $44.9 $35.2
The increase in total other operation expense of $9.7
million resulted primarily from increased salaries and wages and
employee benefits ($3.1 million), the reversal of a restructuring
liability in the 1998 period ($2 million), expenses related to
FICA taxes recorded in other operation expense ($1.6 million),
increased allowances for uncollectible accounts ($1.1 million),
and increased expenses related to provisions for uninsured claims
($.8 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 first quarter of 1999 and
1998 were as follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Utility operations $15.2 $22.9
Nonutility operations 9.5 -
Total maintenance expenses $24.7 $22.9
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
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.
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Depreciation expenses for the first quarter of 1999 and
1998 were as follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Utility operations $18.3 $29.3
Nonutility operations 13.4 -
Total depreciation expenses $31.7 $29.3
Depreciation expense in the first quarter of 1999
increased $2.4 million primarily due to increased investment.
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 first quarter of
1999 and 1998 were as follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Utility operations $14.4 $23.1
Nonutility operations 6.4 -
Total taxes other than income taxes $20.8 $23.1
Total taxes other than income taxes decreased $2.3
million in the first quarter of 1999 due primarily to expense
related to FICA taxes recorded in other operation expense ($1.6
million) and decreased property taxes ($.7 million) due primarily
to an additional assessment related to a prior year. Utility and
nonutility taxes other than income taxes reflect the movement of
taxes other than income taxes associated with the two-thirds of
freed up generation from utility operations to nonutility
operations.
The first quarter increase in federal and state income
taxes was primarily due to increased income in the first quarter
of 1999 compared with 1998.
Interest on long-term debt for the first quarter of 1999
and 1998 was as follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Utility operations $ 9.6 $16.4
Nonutility operations 5.5 -
Total interest on long-term debt $15.1 $16.4
The decrease in interest on long-term debt in the first
quarter of 1999 of $1.3 million resulted primarily from reduced
long-term debt and lower interest rates.
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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 merger activities.
- - Market Risk
The Company supplies power in the bulk power market. At
March 31, 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 plans to issue about $670 million in
transition bonds in July 1999 in accordance with its 1998
restructuring settlement. That settlement, approved by the
Pennsylvania PUC, allows the Company to recover $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 bond sales be passed
through to customers by reducing the CTC. 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.
- - Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations,
including the Company, could experience serious problems related
to software and various equipment with embedded chips which may
not properly recognize calendar dates. To minimize such
problems, the Company and its affiliates in the System are
proceeding with a comprehensive effort 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:
<PAGE>
- 18 -
- - 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 assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.
The NERC has established a goal of having the industry
achieve a state of Y2K readiness for critical systems by June 30,
1999, and to monitor progress, requires each utility to prepare
and submit a monthly report showing progress and dated plans. By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999 for mission critical systems to
file contingency plans by that date. On March 30, 1999, the
System reported to the Pennsylvania PUC that, except for a few
items, its critical electricity production and delivery systems
were Y2K ready pending final confirmation system testing of its
power stations in April and May. The Company anticipates that
all of its critical systems, including its business applications
systems as well as the electricity production and delivery
systems, will be Y2K ready by June 30, 1999 in accordance with
the NERC targets.
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,
or that contingency plans are in place to overcome any inability
to do so. The Company's progress towards completion of the Y2K
processes on its critical systems (business applications systems
and electricity production and delivery systems) at mid-April,
1999, is as follows: inventory, 100%; assessment, 99%; remediation,
75%; testing, 70%; and contingency planning, 64% for a total of 77%.
As stated above, the Company expects all such systems to be Y2K
Ready by June 30, 1999.
Integrated electric utilities are uniquely reliant on
each other to avoid, in a worst case situation, 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.
The NERC, on April 30, 1999, issued a press release stating,
"that millennium-related problems in most of the electric utility
industry will have been tested and fixed by June 30," and that it
will focus its attention on the exceptions which are expected to
be completed later in the year. Since the Company and its
neighboring utilities in the ECAR group are all participants in
the NERC Y2K effort, 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 an industry-wide Y2K drill on April 9, 1999 and
will participate in a more extensive industry-wide drill planned
for 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 are
designed to test the ability of utilities to continue to operate
if telecommunications service is interrupted. During the April
test, the Company was able to maintain adequate communications
under a simulated failure 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.
<PAGE>
- 19 -
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 does not believe it or its customers will experience any
significant long-term disruptions of electric service. It is the
Company's opinion that the "most reasonably likely worst case
scenario" is that there could be isolated problems at various
Company facilities or at the facilities of neighboring utilities
that may have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service. All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency 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 remaining Y2K work is 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 are
being employed for some of the work, the Company believes it must
rely on System 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
within a range of $7 to $10 million, of which about $5 million
has been incurred through March 31, 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.
Of necessity, the Company's Y2K effort is based on estimates of
assessment, remediation, testing, and contingency planning
activities. There can be no assurance that actual results will
not materially differ from expectations.
<PAGE>
- 20 -
- - Electric Energy Competition
The electricity supply segment of the electric utility
industry in the United States is in the midst of becoming a
competitive marketplace. 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 increasingly competitive
as companies began to engage in nationwide power trading. In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries of Allegheny
Energy have investigated or implemented retail access to
alternate electricity suppliers. 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. In the absence of federal
legislation, state-by-state implementation has begun.
The status of electric energy competition in Ohio, West
Virginia, Virginia, and Maryland in which affiliates of the
Company serve are as follows.
Ohio
In early 1999, Ohio's legislative leadership developed a
framework that would restructure the state's electric utility
industry. Since that time, active input has continued from all
interested parties, but a formal bill is still not available.
Major provisions of the anticipated legislation include a start
date for competition of January 1, 2001; a four-year transition
to full competition; stranded cost recovery; require owners to
join an independent transmission entity; and following the
transition period, an annual competitive auction of generation
service would be held for customers who do not choose an
alternate supplier; and a reduction in utilities' personal
property taxes to the same level as other businesses, with the
difference to be made up by a kilowatt-hour tax on consumers.
Hearings are currently being held in both the Senate and House.
West Virginia
A task force established to further investigate
restructuring issues anticipates reconvening in 1999 to further
discuss restructuring. The Public Service Commission of West
Virginia has since issued an order setting a schedule for a
series of hearings in 1999 on major issues such as transition
costs, codes of conduct, and customer protections.
Virginia
Legislation concerning restructuring was introduced in
the Virginia General Assembly on January 21, 1999. The Virginia
General Assembly passed the Virginia Electric Utility
Restructuring Act (the "Restructuring Act") on March 25, 1999.
On March 29, 1999, the Governor of Virginia signed the
Restructuring Act. Major provisions of the Restructuring Act
include:
<PAGE>
- 21 -
- Customer choice of electric energy supply begins January 1,
2002, to be phased in by January 1, 2004, a schedule which is
subject to acceleration or delay under certain conditions.
- Incumbent utilities are required to join a regional
transmission entity by January 1, 2001.
- The Virginia State Corporation Commission (Virginia SCC) is
to develop rules and regulations to implement customer choice.
- Utilities are required to unbundle rates, functionally
separate generation, transmission, and distribution, and separate
regulated and unregulated functions.
- Utilities are permitted but not required to sell generation.
- Retail rates for generation, transmission, and distribution
are capped from January 1, 2001 through July 1, 2007, although
after January 1, 2004 a utility may petition the Virginia SCC for
termination of capped rates under certain circumstances or
petition for a one-time change in the nongeneration component of
rates.
- A wires charge mechanism is set forth for recovery of
stranded costs and other costs associated with the transition to
retail choice.
- The utility may be designated in its service territory as
default service provider at regulated rates.
Maryland
On April 2, 1999, the Maryland General Assembly passed
legislation to restructure the electric utility industry. On
April 8, 1999, the Governor of Maryland signed the legislation
that will bring competition to Maryland's electric generation
market. Major provisions of the restructuring legislation
include:
- Phase-in of retail choice begins July 1, 2000, with all
customers being able to shop for electricity by July 1, 2002, a
schedule subject to acceleration or delay under certain
conditions.
- A methodology is set forth to provide an opportunity to
recover certain net costs associated with the transition to
retail choice.
- Retail rates are capped from July 1, 2000 through July 1,
2004, with residential rate reductions of between 3% and 7.5%
during the cap period, and certain flexibility in price
protection matters if approved as part of a settlement.
- Generation, supply, and pricing of electricity are
deregulated, and the legislation provides for the transfer of
generating assets to an affiliate.
- Voluntary sales of generating assets are permitted but not
mandated.
<PAGE>
- 22 -
- Costs of purchased power contracts may remain regulated or
be recovered through the distribution function as part of a
settlement.
- Functional, operational, structural, or legal separation
between regulated and unregulated utility businesses is required,
and utilities must unbundle their electric rate components into
separate charges.
- Creates a Universal Service fund and program to benefit low-
income customers.
- Requires utilities to provide Standard Offer Service at
regulated rates through July 1, 2003, with certain provisions for
extension thereafter.
<PAGE>
- 23 -
WEST PENN POWER COMPANY AND SUBSIDIARIES
Part II - Other Information to Form 10-Q
for Quarter Ended March 31, 1999
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDER
1. (a) Date and Kind of Meeting:
The annual meeting of shareholders was held at
Greensburg, Pennsylvania, on April 21, 1999. No
proxies were solicited.
(b) Election of Directors:
The holder of all 24,361,586 shares of common stock
voted to elect the following Directors at the annual
meeting to hold office until the next annual meeting
of shareholders and until their successors are duly
chosen and qualified:
Eleanor Baum Alan J. Noia
William L. Bennett Jay S. Pifer
Wendell F. Holland Steven H. Rice
Phillip E. Lint Gunnar E. Sarsten
Frank A. Metz, Jr. Peter J. Skrgic
Michael P. Morrell
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 March 31, 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, Vice President
(Chief Accounting Officer)
May 17, 1999
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