Page 1 of 25
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 1-267
ALLEGHENY ENERGY, INC.
(Exact name of registrant as specified in its charter)
Maryland 13-5531602
(State of Incorporation) (I.R.S. Employer Identification No.)
10435 Downsville Pike, Hagerstown, Maryland 21740-1766
Telephone Number - 301-790-3400
The registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months and (2) has been subject to such
filing requirements for the past 90 days.
At May 14, 1999, 116,600,317 shares of the Common Stock ($1.25
par value) of the registrant were outstanding.
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ALLEGHENY ENERGY, INC.
Form 10-Q for Quarter Ended March 31, 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 6-9
Management's Discussion and Analysis of Financial
Condition and Results of Operations 10-24
PART II--OTHER INFORMATION 25
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ALLEGHENY ENERGY, INC.
Consolidated Statement of Income
(Thousands of Dollars)
Three Months Ended
March 31
1999 1998
<TABLE>
<CAPTION>
OPERATING REVENUES:
<S> <C> <C> <C> <C>
Utility $ 592,592 $ 596,378
Nonutility 97,395 49,094
Total Operating Revenues 689,987 645,472
OPERATING EXPENSES:
Operation:
Fuel 140,609 139,731
Purchased power and exchanges, net 90,835 86,767
Deferred power costs, net 3,686 (6,637)
Other 82,301 74,803
Maintenance 56,434 56,542
Depreciation and amortization 66,865 68,368
Taxes other than income taxes 47,894 50,426
Federal and state income taxes 61,117 50,765
Total Operating Expenses 549,741 520,765
Operating Income 140,246 124,707
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 336 1,067
Other income, net 1,008 778
Total Other Income and Deductions 1,344 1,845
Income Before Interest Charges and
Preferred Dividends 141,590 126,552
INTEREST CHARGES AND PREFERRED DIVIDENDS:
Interest on long-term debt 38,502 42,718
Other interest 4,225 4,018
Allowance for borrowed funds used during
construction (1,168) (722)
Dividends on preferred stock of subsidiaries 2,256 2,301
Total Interest Charges and
Preferred Dividends 43,815 48,315
CONSOLIDATED NET INCOME $ 97,775 $ 78,237
COMMON STOCK SHARES OUTSTANDING (average) 122,395,644 122,436,317
BASIC AND DILUTED EARNINGS PER AVERAGE SHARE $0.80 $0.64
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
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 $164,458
and $166,330 under construction $ 8,427,571 $ 8,395,267
Accumulated depreciation (3,451,061) (3,395,603)
4,976,510 4,999,664
Investments and Other Assets:
Subsidiaries consolidated--excess of cost
over book equity at acquisition 15,077 15,077
Benefit plans' investments 88,735 87,468
Nonutility investments 10,360 9,361
Other 1,481 1,566
115,653 113,472
Current Assets:
Cash and temporary cash investments 30,515 17,559
Accounts receivable:
Electric service 333,529 294,877
Other 13,279 17,712
Allowance for uncollectible accounts (22,603) (19,560)
Materials and supplies - at average cost:
Operating and construction 101,390 99,439
Fuel 64,613 57,610
Prepaid taxes 66,343 56,658
Other, including current portion of regulatory assets 29,395 30,788
616,461 555,083
Deferred Charges:
Regulatory assets 710,760 704,506
Unamortized loss on reacquired debt 47,902 48,671
Other 99,441 91,931
858,103 845,108
Total Assets $ 6,566,727 $ 6,513,327
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 153,045 $ 153,045
Other paid-in capital 1,044,085 1,044,085
Retained earnings 881,886 836,759
Treasury stock (at cost) (22,517) -
2,056,499 2,033,889
Preferred stock 170,086 170,086
Long-term debt and QUIDS 2,179,616 2,179,288
4,406,201 4,383,263
Current Liabilities:
Short-term debt 241,138 258,837
Accounts payable 148,212 153,107
Taxes accrued:
Federal and state income 72,304 17,442
Other 44,196 62,751
Interest accrued 35,960 35,945
Deferred income taxes 33,627 18,718
Adverse power purchase commitments 22,622 22,622
Other 99,416 101,239
697,475 670,661
Deferred Credits and Other Liabilities:
Unamortized investment credit 123,412 125,396
Deferred income taxes 837,470 842,193
Regulatory liabilities 83,192 80,354
Adverse power purchase commitments 323,175 328,830
Other 95,802 82,630
1,463,051 1,459,403
Total Capitalization and Liabilities $ 6,566,727 $ 6,513,327
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
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 $ 97,775 $ 78,237
Depreciation and amortization 66,865 68,368
Deferred investment credit and income taxes, net 8,054 14,193
Deferred power costs, net 3,686 (6,637)
Allowance for other than borrowed funds used
during construction (336) (1,067)
Internal restructuring liability - (4,247)
Changes in certain current assets and
liabilities:
Accounts receivable, net (31,176) 4,478
Materials and supplies (8,954) (12,712)
Prepaid taxes (9,685) (19,249)
Accounts payable (4,895) (10,980)
Taxes accrued 36,307 21,308
Other, net (10,104) 9,396
147,537 141,088
CASH FLOWS FROM INVESTING:
Utility construction expenditures (less allowance for
other than borrowed funds used during construction) (34,048) (39,541)
Nonutility construction expenditures and investments (7,669) (140)
(41,717) (39,681)
CASH FLOWS FROM FINANCING:
Purchase of common stock (22,517) -
Issuance of long-term debt - 135,295
Retirement of long-term debt - (143,800)
Deposit with trustee for redemption
of long-term debt - (43,142)
Short-term debt, net (17,699) (8,120)
Cash dividends on common stock (52,648) (52,648)
(92,864) (112,415)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS 12,956 (11,008)
Cash and temporary cash investments at January 1 17,559 26,374
Cash and temporary cash investments at March 31 $ 30,515 $ 15,366
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of amount capitalized) $ 40,174 $ 41,604
Income taxes 2,791 3,738
</TABLE>
See accompanying notes to consolidated financial statements.
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ALLEGHENY ENERGY, INC.
Notes to Consolidated Financial Statements
1. The Notes to Consolidated Financial Statements of Allegheny
Energy, Inc. (the Company) in its Annual Report on Form 10-K
for the year ended December 31, 1998 should be read with the
accompanying consolidated financial statements and the
following notes. With the exception of the December 31, 1998
consolidated balance sheet in the aforementioned annual
report on Form 10-K, the accompanying consolidated financial
statements appearing on pages 3 through 5 and these notes to
consolidated financial statements are unaudited. In the
opinion of the Company, such consolidated financial
statements together with these notes contain all adjustments
(which consist only of normal recurring adjustments)
necessary to present fairly the Company's financial position
as of March 31, 1999, and the results of operations and cash
flows for the three months ended March 31, 1999 and 1998.
Certain amounts in the December 31, 1998 consolidated balance
sheet have reclassified for comparative purposes.
2. The Company owns all of the outstanding common stock of its
subsidiaries. The consolidated financial statements include
the accounts of the Company and all subsidiary companies
after elimination of intercompany transactions. Allegheny
Generating Company is jointly (100%) owned by the Company's
utility subsidiaries and thus is among the subsidiaries fully
consolidated into the financial statements of the Company.
3. 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.
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 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, the Company would be entitled to specific
performance of the Merger Agreement. The Circuit Court also
stated that the Company would be irreparably harmed if DQE
took actions that would prevent the Company from receiving
the specific performance remedy. The Circuit Court remanded
the case to the District Court for further proceedings
consistent with its opinion.
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In the District Court, discovery is ongoing, and the Company
cannot predict the outcome of this litigation. However, the
Company believes that DQE's basis for seeking to terminate
the merger is without merit. Accordingly, the Company
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 the Company obtains judicial relief requiring
DQE to move forward.
All of the Company's incremental costs of the merger process
($17.6 million through March 31, 1999) are deferred. The
accumulated merger costs will be written off by the combined
company when the merger occurs or by the Company if it is
determined that the merger will not occur.
5. The Consolidated Balance Sheet includes the amounts listed
below for assets, primarily generation, not subject to SFAS
No. 71, "Accounting for the Effects of Certain Types of
Regulation."
March December
1999 1998
(Thousands of Dollars)
Property, plant and equipment at
original cost $1,975,840 $1,969,636
Amounts under construction included above 37,263 39,227
Accumulated depreciation (889,407) (870,777)
6. The Company began acquiring shares of its common stock in the
first quarter of 1999 in conjunction with a stock repurchase
program announced in March 1999. The program authorizes the
Company to repurchase common stock worth up to $500 million
from time to time at price levels the Company deems
attractive. The Company purchased 738,400 shares of its
common stock in the first quarter of 1999 at an aggregate
cost of $22.5 million.
7. The Company's principal business segments are utility and
nonutility operations. The utility subsidiaries, doing
business as Allegheny Power, include the generation,
purchase, transmission, distribution, and sale of electric
energy. Allegheny Power derives substantially all of its
income from operations of its utility subsidiaries,
Monongahela Power Company, The Potomac Edison Company, and
West Penn Power Company (West Penn). Nonutility operations
consists of AYP Capital, a wholly owned subsidiary, formed in
an effort to meet the challenges of the new competitive
environment in the electric industry and the Energy Supply
Division (ESD) of the Supply Business of West Penn, acting
under the name of Allegheny Energy Supply. The ESD has the
primary objective of selling West Penn'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.
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Three Months Ended
March 31
1999 1998
(Thousands of Dollars)
Operating Revenues:
Utility $ 592,592 $ 596,722
Nonutility 167,570* 49,094
Eliminations (70,175) (344)
Depreciation:
Utility 52,070 66,971
Nonutility 14,795 1,397
Federal and State Income Taxes:
Utility 51,596 53,124
Nonutility 9,521 (2,359)
Operating Income:
Utility 119,863 126,446
Nonutility 20,383 (1,739)
Interest Charges and Preferred Dividends:
Utility 35,622 45,757
Nonutility 8,193 2,558
Consolidated Net Income:
Utility 84,158 82,166
Nonutility 13,617 (3,929)
Capital Expenditures:
Utility 34,384 40,608
Nonutility 7,669 140
March 31 December 31
1999 1998
Identifiable Assets:
Utility $5,357,220 $6,299,909
Nonutility 1,209,507 213,418
*Includes $18.7 million of allocated Competitive Transition Charge
(CTC) revenues to compensate for certain transition costs
transferred to nonutility operations.
8. Common stock dividends per share declared during the periods
for which income statements are included are as follows:
Three Months Ended
March 31
1999 1998
Number of Shares 122,436,317 122,436,317
Amount per Share $.43 $.43
9. The Company's Pennsylvania subsidiary, West Penn, 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.
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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
To the extent that West Penn records any or all of the
Additional CTC Regulatory Asset, it will be amortized between
2005 and 2008. This Additional CTC Regulatory Asset was
approved by the Pennsylvania PUC to reduce the adverse
effects, if any, that competition will have on West Penn
during the years 1999 to 2002.
No Additional CTC Regulatory Asset was recorded by West Penn
as of March 31, 1999.
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ALLEGHENY ENERGY, INC.
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 states served by the Company, the proposed
merger with and related litigation against DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa., Year
2000 readiness disclosure, and results of operations. All such
forward-looking information is necessarily only estimated. There
can be no assurance that actual results will not materially
differ from expectations. Actual results have varied materially
and unpredictably from past expectations.
Factors that could cause actual results to differ
materially include, among other matters, electric utility
restructuring, including the ongoing state and federal
activities; potential Year 2000 operation problems; developments
in the legislative, regulatory, and competitive environments in
which the Company operates, including regulatory proceedings
affecting rates charged by the Company's subsidiaries;
environmental, legislative, and regulatory changes; future
economic conditions; earnings retention and dividend payout
policies; developments relating to the proposed merger with DQE,
including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.
Significant Events in the First Quarter of 1999
- - Unregulated Generating Subsidiary
The Company and two of its subsidiaries, West Penn Power
Company (West Penn) and AYP Energy, Inc., filed a Form U-1
application on April 16, 1999 with the Securities and Exchange
Commission (SEC) to form an unregulated generating subsidiary.
Regulatory approval must also be obtained from the Federal Energy
Regulatory Commission, and the Pennsylvania Public Utility
Commission (Pennsylvania PUC) will review the proposed plan.
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Upon approval, West Penn will transfer 3,722 megawatts
(MW) of owned generating capacity at book value as allowed by the
final settlement in our Pennsylvania restructuring case, and AYP
Energy, Inc. will transfer its 276 MW merchant capacity at Fort
Martin Unit No. 1 to the new generating company or GENCO. West
Penn will transfer the generating assets to an unregulated,
wholly owned GENCO, which will be a subsidiary of the Company.
The Energy Supply Division of West Penn which currently sells
competitive retail and wholesale generation in deregulated
markets, will also become part of the GENCO. The AYP Energy,
Inc. generation (276 MW of coal-fired capacity) will be
transferred to the new subsidiary.
It is expected that the necessary approvals will be
received by the end of 1999.
- - Installation of Combustion Turbines
The Company will be installing two 44-MW simple-cycle gas
combustion turbines at its Springdale power station in Allegheny
County, Pa. The two units are expected to be in service by the
end of 1999 and will be capable of running on either No. 2 diesel
oil or natural gas. As part of the installation, 500,000 gallons
of oil storage capacity will be built and existing gas lines will
be upgraded. Transmission facilities at the site and the nearby
interconnection with Duquesne Light Company will also be
upgraded.
The generation output will be sold at times of peak
demand into the competitive wholesale and retail power markets in
the eastern United States through the Energy Supply Division of
West Penn. The Company has filed for an air quality permit from
the Allegheny County Department of Health. No further regulatory
approvals are required.
- - Merger with DQE
See Note 4 to the consolidated financial statements for
information about the proposed merger with DQE, parent company of
Duquesne Light Company in Pittsburgh, Pa., and proposed
litigation.
- - Virginia Rate Settlement and Agreement
On February 25, 1999, the Virginia State Corporation
Commission (Virginia SCC) approved the Company's rate reduction
request for its subsidiary, The Potomac Edison Company (Potomac
Edison), which will decrease the fuel portion of Virginia
customers' bills by approximately 7.6% from 1.278 cents per
kilowatt-hour (kWh) to 1.181 cents per kWh (a decrease in annual
fuel revenue of about $2.2 million). The decrease is primarily
due to refunding a prior overrecovery of fuel costs, coupled with
a small decrease in projected energy costs. The new rates were
effective with bills rendered on or after March 9, 1999.
As a result of Potomac Edison's March 31, 1999 Annual
Information filing in Virginia, the staff of the Virginia SCC and
Potomac Edison have reached an agreement, pending Virginia SCC
approval, which will reduce base rates for Virginia customers
effective June 1, 1999 by about $3 million annually. The review
of rates is required by an annual information filing in Virginia.
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- - Shareholder Rights Plan
The Company filed a Form U-1 application on March 2, 1999
with the SEC for approval of a Shareholder Rights Plan. The
proposal, if approved by the SEC and adopted by the Board of
Directors of the Company, would be triggered if any potential
suitor acquired 15 percent or more of the Company's outstanding
common stock. All shareholders, except the acquiring
shareholder, would then be given the right to protect the value
of their investment by purchasing Company common stock at a two-
for-one price.
- - Maryland and Virginia Deregulation
See Electric Energy Competition on page 21 for ongoing
information regarding restructuring in Maryland and Virginia.
Review of Operations
EARNINGS SUMMARY
Three Months Ended March
Earnings Per Share
1999 1998 1999 1998
(Millions of Dollars) (Dollars Per Share)
Utility operations $84.2 $82.1 $.69 $ .67
Nonutility operations 13.6 (3.9) .11 (.03)
Consolidated net income $97.8 $78.2 $.80 $ .64
The increase in earnings for the first quarter of 1999
was due primarily to colder weather that led to increased
kilowatt-hour (kWh) sales to regular utility customers, new sales
in Pennsylvania's competitive markets, and to reduced interest
expenses offset in part by increases in other operation expenses.
The winter of 1999 was 22% cooler than the relatively warm winter
of 1998, as measured by heating degree days, but was still 3%
warmer than normal. Residential kWh sales to regular customers,
which are very weather sensitive, increased 8% 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.
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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 $571.4 $573.0
Choice 6.8 3.6
Bulk power and transmission services
sales 14.4 19.8
Total utility revenues 592.6 596.4
Nonutility revenues 167.6* 49.1
Elimination between utility and nonutility (70.2)
Total operating revenues $690.0 $645.5
*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 West Penn customers eligible to choose an alternate energy
supplier but electing not to do so) was due primarily to certain
of West Penn's customers choosing another energy supplier and
from a reduction in Potomac Edison's Maryland rates as part of a
settlement agreement. These decreases to regulated revenues were
offset in part by colder weather which led to increased
residential and commercial kWh sales. The decrease related to
competition occurred as a result of Pennsylvania competition
which gave two-thirds of West Penn's regulated customers the
ability to choose another energy supplier.
Settlement agreement reductions of $4.5 million in the
first quarter of 1999 reflect a reduction as a result of a
settlement agreement by Potomac Edison with various parties on
the Maryland Office of People's Counsel's petition for a
reduction in Potomac Edison's Maryland rates. Of that amount,
$2.6 million is related to Potomac Edison creating a provision to
share earnings above a return on equity of 11.4% as discussed
below, and $1.9 million is related to a deferral of 1999 revenues
per the settlement agreement. The agreement, which includes
recognition of costs to be incurred from the AES Warrior Run
cogeneration project being developed under the Public Utility
Regulatory Policies Act of 1978 (PURPA), was approved by the
Maryland Public Service Commission (Maryland PSC) on October 27,
1998. Under the terms of that agreement, Potomac Edison will
increase its rates about 4% ($13 million) in each of the years
1999, 2000, and 2001 (a $39 million annual effect in 2001). The
increases are designed to recover additional costs of about $131
million over the period 1999-2001 for capacity purchases from the
AES Warrior Run cogeneration project, net of alleged over-
earnings of $52 million for the same period. The net effect of
these changes over the 1999-2001 time frame results in a pre-tax
income reduction of $12 million in 1999, $18 million in 2000, and
$22 million in 2001. In addition, the settlement requires that
Potomac Edison share, on a 50% customer, 50% shareholder basis,
earnings above a return on equity of 11.4% for 1999-2001. This
sharing will occur through an annual true-up.
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Utility choice revenues for 1999 represent transmission
and distribution revenues from West Penn franchised customers
(customers in West Penn's territory) who chose another supplier
to provide their energy needs and 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
Energy Supply Division (ESD) of the Supply Business has the
primary objective of selling West Penn's two-thirds of 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 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 9 to the consolidated financial statements for
information regarding the Competitive Transition 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 $ 93.7 $134.7
Nonutility operations 46.9 5.0
Total fuel expenses $140.6 $139.7
Total fuel expenses for the first quarter remained
unchanged due to a 3% increase in kwh's generated offset by a 3%
decrease in average fuel prices. The decrease in fuel expenses
for utility operations and the increase in fuel expenses for
nonutility fuel expenses was due to the fuel expenses associated
with the two-thirds of West Penn's freed up generation now being
marketed by the ESD as part of nonutility operations.
Purchased power and exchanges, net, represents power
purchases from and exchanges with other companies and purchases
from qualified facilities under the Public Utility Regulatory
Policies Act of 1978 (PURPA), and consists of the following
items:
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Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Purchased power:
Utility operations:
From PURPA generation* $28.0 $34.2
Other 20.0 8.9
Total purchased power for utility
operations 48.0 43.1
Power exchanges, net 4.3 3.5
Nonutility operations 41.5 40.2
Elimination (3.0)
Purchased power and exchanges, net $90.8 $86.8
*PURPA cost (cents per kWh) 5.0 5.5
The decrease of $6.2 million in utility purchased power
from PURPA generation reflects a $2.7 million reduction related
to West Penn'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 costs reflects the amortization of excess costs
accruals recorded as an adverse power purchase commitment net of
the Competitive Transition Charge revenue recovery in conjunction
with deregulation proceedings in Pennsylvania.
The increase in other utility operations purchased power
was due primarily to West Penn's purchase of power from
nonaffiliated companies and marketers in order to provide energy
to the two-thirds of its customers eligible to choose an
alternate supplier but electing not to do so. The generation
previously available to serve those customers has been freed up
by customer choice in Pennsylvania and is being marketed by the
Energy Supply Division of West Penn to the unregulated
marketplace.
The elimination between utility and nonutility purchased
power is necessary to remove the effect of affiliated purchase
power expenses.
The AES Warrior Run PURPA cogeneration contract in
Potomac Edison's Maryland service territory, scheduled to
commence operation in October 1999, will increase the cost of
power purchases $60 million or more annually. In 1999, utility
revenues will reflect a reduction for a settlement agreement with
various parties on the Maryland Office of People's Counsel's for
a reduction in The Potomac Edison Company's Maryland rates. The
net effect of changes related to the settlement results in a pre-
tax income reduction of $12 million in 1999. See Sales and
Revenues starting on page 13 for more information on the
settlement agreement.
None of the subsidiaries' purchased power contracts are
capitalized since there are no minimum payment requirements
absent associated kWh generation.
<PAGE>
- 16 -
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 $70.3 $71.1
Nonutility operations 16.3 3.7
Elimination (4.3)
Total other operation expenses $82.3 $74.8
The increase in total other operation expenses of $7.5
million resulted primarily from increased allowances for
uncollectible accounts ($1.8 million), higher salaries and wages
($1.7 million), and increased expenses related to provisions for
uninsured claims ($1.5 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 $46.0 $55.3
Nonutility operations 10.4 1.2
Total maintenance expenses $56.4 $56.5
Total maintenance expenses for the first quarter of 1999
remained about the same as the first quarter of 1998. The
decrease in utility maintenance and the increase in nonutility
maintenance was due to the maintenance associated with the two-
thirds of West Penn generation deregulated and now being
classified as nonutility maintenance. Maintenance expenses
represent costs incurred to maintain the power stations, the
transmission and distribution (T&D) system, and general plant,
and reflect routine maintenance of equipment and rights-of-way,
as well as planned major repairs and unplanned expenditures,
primarily from forced outages at the power stations and periodic
storm damage on the T&D system. Variations in maintenance
expense result primarily from unplanned events and planned major
projects, which vary in timing and magnitude depending upon the
length of time equipment has been in service without a major
overhaul and the amount of work found necessary when the
equipment is dismantled.
<PAGE>
- 17 -
Depreciation and amortization expenses for the first
quarter of 1999 and 1998 were as follows:
Three Months Ended
March 31
1999 1998
(Millions of Dollars)
Utility operations $52.1 $67.0
Nonutility operations 14.8 1.4
Total depreciation expenses $66.9 $68.4
Total depreciation expense in the first quarter decreased
$1.5 million due to a $4.8 million reduction in depreciation
expense related to West Penn's purchase commitments at costs in
excess of the market value of the AGC pumped storage capacity
contract. Depreciation 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 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 decrease of $4.8 million was offset in
part by higher depreciation expense 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 $40.1 $48.7
Nonutility operations 7.8 1.7
Total taxes other than income taxes $47.9 $50.4
Total taxes other than income taxes decreased $2.5
million in the first quarter of 1999 due primarily to increased
West Virginia Business and Occupation Taxes in the first quarter
of 1998 resulting from an adjustment for a prior period, and
decreased gross receipts taxes in the first quarter of 1999 for a
prior period adjustment. Utility and nonutility taxes other than
income taxes reflects 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.
<PAGE>
- 18 -
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 $30.7 $40.2
Nonutility operations 7.8 2.5
Total interest on long-term debt $38.5 $42.7
The decrease in total interest on long-term debt in the
first quarter of 1999 of $4.2 million resulted primarily from
reduced long-term debt and lower interest 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 subsidiaries are
subject to various contingencies and uncertainties relating to
their operations and construction programs, including legal
actions and regulations and uncertainties related to
environmental matters. See Note 4 to the Consolidated Financial
Statements for information about merger activities.
- - Market Risk
The Company's utility subsidiaries and certain of the
Company's nonutility subsidiaries, supply 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's Pennsylvania subsidiary, West Penn, 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 West Penn 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
competitive transition charge. This transition charge is a
temporary per-kilowatt-hour charge designed to collect a
company's transition cost in a competitive environment.
The Company plans to reduce transition costs and related
capitalization with the proceeds from the transition bonds.
<PAGE>
- 19 -
- - 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 is 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 Company.
In May 1998, the North American Electric Reliability
Council (NERC), of which the Company is a member, accepted a
request from the United States Department of Energy to coordinate
the industry's Y2K efforts. The electric utility industry and
the Company have segmented the Y2K problem into the following
components:
- - Computer hardware and software;
- - Embedded chips in various equipment; and
- - Vendors and other organizations on which the Company relies
for critical materials and services.
The industry's and the Company's efforts for each of
these three components include 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
Company 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 Company is working with the
Edison Electric Institute, the Electric Power Research Institute,
the NERC, and the East Central Area Reliability Agreement group
(ECAR) to capitalize on industry-wide experiences and to
participate in industry-wide testing and contingency planning.
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
<PAGE>
- 20 -
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.
The Securities and Exchange Commission 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 its own employees for most of the effort because of their
experience with the Company's systems and equipment. The Company
<PAGE>
- 21 -
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $15 to $20 million of which about $10 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.
- - 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 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.
In addition to Pennsylvania, which has enacted
legislation to bring competition to the electric utility
industry, the Company serves customers in four other states which
are actively exploring the move toward competition and
deregulation.
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:
- 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.
<PAGE>
- 22 -
- 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.
- 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.
<PAGE>
- 23 -
- 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.
As previously reported, Potomac Edison, the Company's
Maryland subsidiary, filed testimony in Maryland's investigation
into transition costs, price protection, and unbundled rates.
The filing requested recovery of transition costs and a surcharge
to recover the cost of the AES Warrior Run cogeneration project
beyond 2001. The staff of the Maryland Public Service Commission
(Maryland PSC) advised the commission that a tentative settlement
agreement was achieved with the majority of the parties
participating in the negotiations. The parties are in the
process of finalizing the agreement for presentation to the
Maryland PSC. The restructuring proceeding hearings that were
scheduled to begin the week of April 26, 1999 were suspended.
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.
Accounting for the Effects of Price Deregulation
In July 1997, the Emerging Issues Task Force (EITF) of the
Financial Accounting Standards Board (FASB) released Issue No. 97-
4, "Deregulation of the Pricing of Electricity - Issues Related
to the Application of FASB Statement Nos. 71 and 101," which
concluded that utilities should discontinue application of
Statement of Financial Accounting Standards (SFAS) No. 71 for the
generation portion of their business when a deregulation plan is
in place and its terms are known. Because Maryland and Virginia
have passed legislation for a deregulation plan, the Company has
determined that it will be required to discontinue use of SFAS
No. 71 for the generation portion of
<PAGE>
- 24 -
its business (the Maryland and Virginia portion only) on an
uncertain future date. One of the conclusions of the EITF is
that after discontinuing SFAS No. 71, utilities should continue
to carry on their books the assets and liabilities recorded under
SFAS No. 71 if the regulatory cash flows to settle them will be
derived from the continuing regulated transmission and
distribution business. Additionally, continuing costs and
obligations of the deregulated generation business which are
similarly covered by the cash flows from the continuing regulated
business will meet the criteria as regulatory assets and
liabilities. The Maryland and Virginia legislation establishes
definitive processes for transition to deregulation and market-
based pricing for electric generation. Until relevant regulatory
proceedings are complete and final orders are received, the
Company is unable to predict the effect of discontinuing SFAS No.
71, but it may be required to write off significant unrecoverable
regulatory assets, impaired assets, and uneconomic commitments.
<PAGE>
- 25 -
ALLEGHENY ENERGY, INC.
Part II - Other Information to Form 10-Q
for Quarter Ended March 31, 1999
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(27) Financial Data Schedule
(b) The Company filed Form 8-K's on March 9, 1999 and April
19, 1999.
Signature
Pursuant to the requirements of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly
authorized.
ALLEGHENY ENERGY, INC.
/s/ T. J. KLOC
T. J. Kloc, Vice President
(Chief Accounting Officer)
May 14, 1999
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