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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended March 31, 1999
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[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From __________ to __________
Commission File Number
----------------------
1-10290
DQE, INC.
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-1598483
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Cherrington Corporate Center, Suite 100
500 Cherrington Parkway, Coraopolis, Pennsylvania 15108-3184
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 262-4700
Indicate by check mark whether 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 (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE Common Stock, no par value - 76,209,421 shares outstanding as of March 31,
1999 and 75,676,788 shares outstanding as of April 30, 1999.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
DQE
CONDENSED STATEMENT OF CONSOLIDATED INCOME
(Thousands, Except Per Share Amounts)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
-------------------------------
1999 1998
------------ ------------
<S> <C> <C>
Operating Revenues
Sales of Electricity $ 266,755 $ 274,129
Other 59,300 24,646
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Total Operating Revenues 326,055 298,775
------------ ------------
Operating Expenses
Fuel and purchased power 46,911 59,533
Other operating 115,066 80,025
Maintenance 20,337 20,283
Depreciation and amortization 57,845 57,185
Taxes other than income taxes 24,174 19,932
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Total Operating Expenses 264,333 236,958
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OPERATING INCOME 61,722 61,817
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Other Income 35,749 31,418
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Interest and Other Charges 27,100 27,618
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Income Before Income Taxes 70,371 65,617
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Income Taxes 21,906 20,487
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NET INCOME 48,465 45,130
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DIVIDENDS ON PREFERRED STOCK 392 --
------------ ------------
EARNINGS AVAILABLE FOR COMMON
STOCK $ 48,073 $ 45,130
============ ============
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 77,217 77,683
============ ============
BASIC EARNINGS PER
SHARE OF COMMON STOCK $ 0.62 $ 0.58
============ ============
DILUTED EARNINGS PER
SHARE OF COMMON STOCK $ 0.61 $ 0.57
============ ============
DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $ 0.38 $ 0.36
============ ============
</TABLE>
See notes to condensed consolidated financial statements.
2
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DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
ASSETS 1999 1998
------------------- -------------------
<S> <C> <C>
Current assets:
Cash and temporary cash investments $ 71,886 $ 108,790
Receivables 160,557 165,794
Other current assets, principally materials and supplies 98,813 100,168
---------------- ----------------
Total current assets 331,256 374,752
---------------- ----------------
Long-term investments 752,400 750,796
---------------- ----------------
Property, plant and equipment 4,924,099 4,884,138
Less: Accumulated depreciation and amortization (3,165,634) (3,167,328)
---------------- ----------------
Property, plant and equipment - net 1,758,465 1,716,810
---------------- ----------------
Other non-current assets:
Transition costs 2,084,098 2,132,980
Regulatory assets 61,848 64,568
Other 274,763 207,657
---------------- ----------------
Total other non-current assets 2,420,709 2,405,205
---------------- ----------------
TOTAL ASSETS $ 5,262,830 $ 5,247,563
================ ================
LIABILITIES AND CAPITALIZATION
Notes payable and current maturities $ 214,866 $ 100,822
---------------- ----------------
Other current liabilities $ 227,783 $ 253,442
---------------- ----------------
Deferred income taxes - net 759,649 777,017
---------------- ----------------
Deferred income 162,103 156,579
---------------- ----------------
Beaver Valley lease liability 475,570 475,570
---------------- ----------------
Other non-current liabilities 378,098 371,653
---------------- ----------------
Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,324,802 1,364,879
---------------- ----------------
Preferred and preference stock of subsidiaries 228,478 228,282
---------------- ----------------
Preferred stock 38,682 35,274
---------------- ----------------
Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
issued 109,679,154 shares) 993,489 994,996
Retained earnings 888,483 869,671
Less treasury stock (at cost) (33,469,733 and 32,305,726
shares, respectively) (432,933) (385,976)
Accumulated other comprehensive income 3,760 5,354
---------------- ----------------
Total common shareholders' equity 1,452,799 1,484,045
---------------- ----------------
Total capitalization 3,044,761 3,112,480
---------------- ----------------
TOTAL LIABILITIES AND CAPITALIZATION $ 5,262,830 $ 5,247,563
================ ================
</TABLE>
See notes to condensed consolidated financial statements.
3
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DQE
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
----------------------------------------
1999 1998
-------------- --------------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 105,374 $ 124,686
Changes in working capital other than cash 19,987 (43,781)
Increase in ECR -- (7,270)
Other (28,550) 1,804
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Net Cash Provided By Operating Activities 96,811 75,439
-------------- --------------
Cash Flows From Investing Activities
Acquisition of water companies (56,031) --
Capital expenditures (26,951) (42,638)
Long-term investments (5,763) (12,495)
Proceeds from the sale of investments 11,402 --
Other (2,789) 7,409
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Net Cash Used in Investing Activities (80,132) (47,724)
-------------- --------------
Cash Flows From Financing Activities
Repurchase of common stock (46,957) --
Dividends on common stock (29,285) (27,963)
Reductions of long term obligations net (4,808) (98,163)
Increase in notes payable 42,963 2,921
Other (15,496) (7,036)
-------------- --------------
Net Cash Used in Financing Activities (53,583) (130,241)
-------------- --------------
Net decrease in cash and temporary cash investments (36,904) (102,526)
Cash and temporary cash investments at beginning of period 108,790 356,412
-------------- --------------
Cash and temporary cash investments at end of period $ 71,886 $ 253,886
============== ==============
Non-Cash Investing and Financing Activities
Preferred stock issued in conjunction with long-term investments $ 3,408 $ 16,597
============== ==============
Capital lease obligations recorded $ 5,984 $ 2,552
============== ==============
</TABLE>
See notes to condensed consolidated financial statements.
4
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DQE
STATEMENT OF CONSOLIDATED COMPREHENSIVE INCOME
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
-----------------------------
1999 1998
------------ ------------
<S> <C> <C>
NET INCOME $ 48,465 $ 45,130
Other Comprehensive Income:
Unrealized holding gains (losses) during the
quarter, net of tax of $(135) and $219 (190) 308
Less: reclassification adjustment for gains
included in net income, net of tax of $756 and $0 (1,404) --
------------ ------------
Total Other Comprehensive Income (1,594) 308
------------ ------------
Comprehensive Income $ 46,871 $ 45,438
============ ============
</TABLE>
See notes to condensed consolidated financial statements.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES
DQE, Inc. (DQE) is a multi-utility delivery and services company. Its
subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc.
(AquaSource); DQE Capital Corporation (DQE Capital); DQE Energy Services, Inc.
(DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises, Inc. (DE); and
Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to
as "the Company."
The Company's utility operations include an electric utility engaged in the
generation, transmission, distribution and sale of electric energy and a water
resource management company that acquires, develops and manages water and
wastewater utilities. The Company's expanded business lines offer a wide range
of energy-related technologies, industrial and commercial energy services,
telecommunications and other complementary services. The expanded business
lines' initiatives include energy facility development and operation, domestic
and international independent power production, the production and supply of
innovative fuels, investments in communications systems and electronic commerce,
and long-term investments. In addition, one of the Company's subsidiaries is a
finance company that will provide financing for the expanded business lines.
The Pennsylvania Public Utility Commission (PUC) has approved the Company's
plan to divest itself of its generation assets through an auction (including an
auction of its provider of last resort service), and the pending exchange of
certain power station assets with FirstEnergy Corporation (FirstEnergy). Final
agreements governing these transactions must be approved by various regulatory
agencies. The Company currently expects these transactions to close in late 1999
or early 2000. (See "Rate Matters", Note 2, on page 7.)
All material intercompany balances and transactions have been eliminated in
the preparation of the condensed consolidated financial statements.
In the opinion of management, the unaudited condensed consolidated
financial statements included in this report reflect all adjustments that are
necessary for a fair presentation of the results of
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interim periods and are normal, recurring adjustments. Prior periods have been
reclassified to conform with accounting presentations adopted during 1999.
These statements should be read with the financial statements and notes
included in the Annual Report on Form 10-K filed with the Securities and
Exchange Commission (SEC) for the year ended December 31, 1998. The results of
operations for the three months ended March 31, 1999, are not necessarily
indicative of the results that may be expected for the full year. The
preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements. The
reported amounts of revenues and expenses during the reporting period may also
be affected by the estimates and assumptions management is required to make.
Actual results could differ from those estimates.
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters.
As a result of the PUC's May 29, 1998, final order regarding the Company's
restructuring plan under the Customer Choice Act (see "Rate Matters," Note 2, on
page 7), the electricity generation portion of the Company's business does not
meet the criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
However, pursuant to the PUC's final restructuring order, certain of the
Company's generation-related regulatory assets are being recovered through a
competitive transition charge (CTC) collected in connection with providing
transmission and distribution services (the electricity delivery business
segment). The Company continues to apply SFAS No. 71 with respect to such
assets. Additionally, pursuant to the PUC's final restructuring order, the
Company is recovering its above-market investment in generation assets through
the CTC, subject to receipt of the proceeds from the generation asset auction.
Remaining fixed assets related to the generation portion of the Company's
business are evaluated in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). The electricity delivery business segment continues to meet SFAS
No. 71 criteria and accordingly reflects regulatory assets and liabilities
consistent with cost-based ratemaking regulations. The regulatory assets
represent probable future revenue to the Company, because provisions for these
costs are currently included, or are expected to be included, in charges to
electric utility customers through the ratemaking process. (See "Rate Matters,"
Note 2, on page 7.)
Through the Energy Cost Rate Adjustment Clause (ECR), the Company
previously recovered (to the extent that such amounts were not included in base
rates) nuclear fuel, fossil fuel and purchased power expenses. Also through the
ECR, the Company passed to its customers the profits from short-term power sales
to other utilities (collectively, ECR energy costs). As a consequence of the
PUC's final order regarding the Company's restructuring plan (see "Rate
Matters," Note 2, on page 7), such fuel costs are no longer recoverable through
the ECR. Instead, effective May 29, 1998 (the date of the PUC's final
restructuring order), fuel costs are expensed as incurred and thus impact net
income. Under-recoveries from customers prior to May 29, 1998, were recorded on
the consolidated balance sheet as a regulatory asset. At March 31, 1999 and
December 31, 1998, $42.7 million was receivable from customers. The Company
expects to recover this amount through the CTC. (See "Restructuring Plan"
discussion, Note 2, on page 8.)
The Company's long-term investments include assets of nuclear
decommissioning trusts and marketable securities accounted for in accordance
with SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities. These investments are classified as available-for-sale and are
stated at market value. The amounts of unrealized holding gains related to
marketable securities
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were $6.4 million ($3.8 million, net of tax) at March 31, 1999, and $8.9 million
($5.4 million, net of tax) at December 31, 1998.
2. RATE MATTERS
Competition and the Customer Choice Act
Under historical ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral for
future recovery from customers (regulatory assets). As a result of this process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition and stranded costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1,
1997. The Customer Choice Act enables Pennsylvania's electric utility customers
to purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999).
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of April 30, 1999, approximately 13 percent of the Company's
customers had chosen alternative generation suppliers. Customers that have
chosen an electricity generation supplier other than the Company pay that
supplier for generation charges, and pay the Company the CTC (discussed below)
and charges for transmission and distribution. Customers that continue to buy
their generation from the Company pay for their service at current regulated
tariff rates divided into generation, transmission and distribution charges, and
the CTC. Under the Customer Choice Act, an electric distribution company, such
as Duquesne, remains a regulated utility and may only offer PUC-approved rates,
including generation rates. Also under the Customer Choice Act, electricity
delivery (including transmission, distribution and customer service) remains
regulated in substantially the same manner as under historical regulation.
In an effort to "jump start" retail competition, the Company has made 600
megawatts (MW) of power available to licensed electric generation suppliers, to
be used in supplying electricity to Duquesne's customers who have chosen
alternative generation suppliers. The power will be available for the first six
months of 1999 at a price of 2.6 cents per kilowatt-hour (KWH). This power
availability will be structured to ensure the power is used to benefit
Duquesne's retail customers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as long as
transition costs are being recovered, with certain exceptions.
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Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the
Company should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered
was $2,133 million ($1,485 million, net of tax) over a seven-year period
beginning January 1, 1999, as may be adjusted to account for the proceeds of the
generation asset auction. In addition, the transition costs as reflected on the
consolidated balance sheet are being amortized over the same period that the CTC
revenues are being recognized. The Company is allowed to earn an 11 percent pre-
tax return on the unrecovered balance.
As part of its restructuring plan filing, the Company requested recovery of
$11.5 million ($6.7 million, net of tax) through the CTC for energy costs
previously deferred under the ECR. Recovery of this amount was approved in the
PUC's final restructuring order. The Company also requested recovery of an
additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On
December 18, 1998, the PUC denied recovery of this additional amount. The
Company has appealed the PUC's denial of recovery to the Pennsylvania
Commonwealth Court. Based upon the Customer Choice Act, which mandates recovery
of all regulatory assets, and the PUC's specific authorization for the Company
to create a regulatory asset for these costs, the Company believes that it is
probable that these costs will be recovered through retail rates. In the event
that the Company does not prevail in its appeal, these costs would be written
off as a charge against income.
Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) is expected to be recovered from ratepayers through the CTC.
Until the divestiture is complete, Duquesne has been ordered to use an interim
system average CTC and price to compare based on the methodology approved in its
pilot program (approximately 2.9 cents per KWH for the CTC and approximately 3.8
cents per KWH for the price to compare).
On December 18, 1998, the PUC approved Duquesne's auction plan, including
an auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick, Elrama, Phillips and
Brunot Island power stations, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process began in April
1999, with potential buyers identified by Duquesne being asked to submit non-
binding bids. Final agreements governing the transactions must be approved by
various regulatory agencies, including the PUC, the FERC, the NRC, the
Department of Justice and/or the Federal Trade Commission. Duquesne currently
expects the sale to close at the end of 1999 or the beginning of 2000.
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999 (which remain subject to regulatory approval), Duquesne and
FirstEnergy will exchange ownership interests in certain power stations.
Duquesne will receive 100 percent ownership rights in three coal-fired power
plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania
(totaling approximately 1,300 MW), which the Company expects to sell
simultaneously as part of the auction of generation assets. FirstEnergy will
acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley
Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce
Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with
the power station exchange, the Company anticipates terminating the BV Unit 2
lease in December 1999. (See "Financing," discussion on page 19.) Pursuant to
the December 18, 1998, PUC order and subject to final approval, the proceeds
from the sale of the power stations received in the exchange will be used to
offset the transition costs associated with Duquesne's currently-held generation
assets and costs associated with completing the exchange. Duquesne expects this
exchange to enhance the value received from the auction, because participants
will bid on plants that are wholly owned by Duquesne, rather than plants
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that are jointly owned and/or operated by another entity. Additionally, the
auction will include only coal- and oil-fired plants, which are anticipated to
have a higher market value than nuclear plants. These value-enhancing features,
along with a minimum level of auction proceeds guaranteed by FirstEnergy, are
expected to maximize auction proceeds, minimize transition costs required to be
recovered through the CTC (by shortening the length of the CTC recovery period),
and thus reduce customer bills as rapidly as possible. Other benefits of this
exchange include the resolution of all joint ownership issues, and other risks
and costs associated with the jointly-owned units. In December 1998 the PUC said
the exchange appears to be in the public interest. The definitive exchange
agreement was submitted in early May 1999 for PUC approval. Certain aspects of
the exchange will also have to be approved by, among other agencies, the FERC,
the NRC and the Department of Justice. The power station exchange is expected to
occur simultaneously with the anticipated closing of the sale of Duquesne's
generation through the auction at the end of 1999 or in early 2000.
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement with Allegheny Energy, Inc. (AYE). The Company believes that
AYE suffered a material adverse effect as a result of the PUC's final
restructuring order regarding AYE's utility subsidiary, West Penn Power Company.
AYE filed suit in the United States District Court for the Western District of
Pennsylvania, seeking to compel the Company to proceed with the merger and
seeking a temporary restraining order and preliminary injunction to prevent the
Company from certain actions pending a trial, or in the alternative seeking an
unspecified amount of money damages. The parties continue to litigate this
matter. (See "Legal Proceedings" on page 27.) In a letter dated February 24,
1999, the PUC informed the Company that the merger application was deemed
withdrawn and the docket was closed.
3. RECEIVABLES
The components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
March 31, March 31, December 31,
1999 1998 1998
(Amounts in Thousands of Dollars)
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 88,970 $ 84,323 $ 87,262
Water customer accounts receivable 16,093 1,281 10,591
Other utility receivables 33,941 19,894 25,412
Other receivables 81,626 33,403 51,944
Less: Allowance for uncollectible accounts (10,073) (16,322) (9,415)
- ---------------------------------------------------------------------------------------------
Receivables less allowance for uncollectible accounts 210,557 122,579 165,794
Less: Receivables sold (50,000) -- --
=============================================================================================
Total Receivables $160,557 $122,579 $165,794
=============================================================================================
</TABLE>
The Company and an unaffiliated corporation have an agreement that entitles
the Company to sell and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. The accounts receivable sales agreement,
which expires in June 1999, is one of many sources of funds available to the
Company. The Company currently anticipates extending the agreement upon
expiration. At March 31, 1999, the Company had sold $50 million of receivables.
At March 31 and December 31, 1998, the Company had not sold any receivables.
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4. COMMITMENTS AND CONTINGENCIES
The Company anticipates divesting itself of its generation assets through
the auction and the power station exchange by early 2000 and, depending on the
regulatory approvals of the final agreements regarding the divestiture, expects
certain obligations related to the divested assets will be transferred to the
future owners. (See "Restructuring Plan" discussion, Note 2, on page 8.)
Construction
The Company currently estimates that during 1999 it will spend, excluding
the Allowance for Funds Used During Construction and nuclear fuel, approximately
$110 million for electric utility construction, including $30 million for
generation, and approximately $25 million for water utility construction.
Nuclear-Related Matters
The Company has an interest in three nuclear units, two of which it
operates. The operation of a nuclear facility involves special risks, potential
liabilities, and specific regulatory and safety requirements. Specific
information about risk management and potential liabilities is discussed below.
Nuclear Decommissioning. The Company expects to decommission BV Unit 1, BV
Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating
license in 2016, 2027 and 2026, respectively. At the end of its operating life,
BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be
decommissioned, at which time the units may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit 2,
and a 1997 update of the 1994 study for Perry Unit 1, the Company's approximate
share of the total estimated decommissioning costs, including removal and
decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently used to determine the Company's cost of
service related to decommissioning all three nuclear units is $224 million.
Funding for nuclear decommissioning costs is deposited in external, segregated
trust accounts and invested in a portfolio of corporate common stock and debt
securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances at
March 31, 1999, totaled approximately $65.8 million.
As part of the power station exchange, FirstEnergy has agreed to assume the
decommissioning liability for each of the nuclear plants in exchange for the
balance in the decommissioning trust funds, plus the decommissioning costs
expected to be collected through the CTC.
Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act of
1954 limit public liability from a single incident at a nuclear plant to $9.8
billion. The maximum available private primary insurance of $200 million has
been purchased by the Company. Additional protection of $9.6 billion would be
provided by an assessment of up to $88.1 million per incident on each licensed
nuclear unit in the United States. The Company's maximum total possible
assessment, $66.1 million, which is based on its ownership or leasehold
interests in three nuclear generating units, would be limited to a maximum of
$7.5 million per incident per year. This assessment is subject to indexing for
inflation and may be subject to state premium taxes. If assessments from the
nuclear industry prove insufficient to pay claims, the United States Congress
could impose other revenue-raising measures on the industry.
The Company's share of insurance coverage for property damage, decommissioning
and decontamination liability is $1.2 billion. The Company would be responsible
for its share of any damages in excess of insurance coverage. In addition, if
the property damage reserves of Nuclear Electric Insurance Limited (NEIL), an
industry mutual insurance company that provides a portion of this coverage, are
inadequate to cover claims arising from an incident at any United States nuclear
site covered by that insurer, the Company could be assessed retrospective
premiums totaling a maximum of $7.3 million. The Company also participates in a
NEIL program that provides insurance for the increased cost of generation and/or
purchased power resulting from an accidental
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outage of a nuclear unit. Subject to the policy deductible, terms and limit, the
coverage provides for a weekly indemnity of the estimated incremental costs
during the 162-week period starting 17 weeks after an accident, with no coverage
thereafter. If NEIL's losses for this program ever exceed its reserves, the
Company could be assessed retrospective premiums totaling a maximum of $2.6
million.
Beaver Valley Power Station (BVPS). BVPS's two units are equipped with steam
generators designed and built by Westinghouse Electric Corporation
(Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter
stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of
both units. BV Unit 1, which was placed in service in 1976, has removed
approximately 17 percent of its steam generator tubes from service through a
process called "plugging." However, BV Unit 1 still has the capability to
operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called "sleeving." No tubes at
either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 3 percent of BV Unit 2's tubes are
plugged; however, it is too early in the life of the unit to determine the
extent to which ODSCC may become a problem at that unit.
The Company has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and reduce susceptibility to ODSCC. Although the Company has taken these steps
to allay the effects of ODSCC, the inherent potential for future ODSCC in steam
generator tubes of the Westinghouse design still exists. Material acceleration
in the rate of ODSCC could lead to a loss of plant efficiency, significant
repairs or the possible replacement of the BV Unit 1 steam generators. The total
replacement cost of the BV Unit 1 steam generators is currently estimated at
$125 million. The Company would be responsible for $59 million of this total,
which includes the cost of equipment removal and replacement steam generators,
but excludes replacement power costs. The earliest that the BV Unit 1 steam
generators could be replaced during a currently scheduled refueling outage is
the spring of 2003.
The Company continues to explore all viable means of managing ODSCC, including
new repair technologies, and plans to continue to perform 100 percent tube
inspections during future refueling outages. However, the Company may be
required to perform an earlier inspection of BV Unit 1's tubes and other
equipment during a mid-cycle outage in 1999, to comply with NRC requirements to
conduct such inspections at BV Unit 1 at least every 20 months. The Company has
requested permission from the NRC to postpone these inspections until BV Unit
1's next refueling outage, currently scheduled to begin in the spring of 2000.
The Company completed its inspection of BV Unit 2's tubes during a forced outage
in 1998 to comply with NRC requirements to conduct such inspections at BV Unit 2
at least every 24 months. BV Unit 2 completed its seventh and, at 44 days,
shortest refueling outage in early April 1999. No steam generator tube
inspections were performed during the refueling outage, and none will be
performed until the next refueling outage, currently scheduled for the fall of
2000. The Company will continue to monitor and evaluate the condition of the
BVPS steam generators.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982 established
a federal policy for handling and disposing of spent nuclear fuel and a policy
requiring the establishment of a final repository to accept spent nuclear fuel.
Electric utility companies have entered into contracts with the United States
Department of Energy (DOE) for the permanent disposal of spent nuclear fuel and
high-level radioactive waste in compliance with this legislation. The DOE has
indicated that its repository under these contracts will not be available for
acceptance of spent nuclear fuel before 2010. The DOE has not yet established an
interim or permanent storage facility, despite a ruling by the United States
Court of Appeals for the District of Columbia Circuit that the DOE was legally
obligated to begin acceptance of spent nuclear fuel for disposal by January 31,
1998. Existing on-site spent nuclear fuel storage capacities at BV Unit 1, BV
Unit 2 and Perry Unit 1 are expected to be sufficient until 2018, 2012 and 2011,
respectively.
11
<PAGE>
In early 1997, the Company joined 35 other electric utilities and 46 states,
state agencies and regulatory commissions in filing suit in the United States
Court of Appeals for the District of Columbia Circuit against the DOE. The
parties requested the court to suspend the utilities' payments into the Nuclear
Waste Fund and to place future payments into an escrow account until the DOE
fulfills its obligation to accept spent nuclear fuel. The DOE had requested that
the court delay litigation while it pursued alternative dispute resolution under
the terms of its contracts with the utilities. The court ruling, issued November
14, 1997, and affirmed on rehearing May 5, 1998, denied the relief requested by
the utilities and states and permitted the DOE to pursue alternative dispute
resolution, but prohibited the DOE from using its lack of a spent fuel
repository as a defense. The United States Supreme Court declined to review the
decision. The utilities' remaining remedies are to sue the DOE in federal court
for money damages caused by the DOE's delay in fulfilling its obligations, or to
pursue an equitable contract adjustment before the DOE contracting officer.
Uranium Enrichment Obligations. Nuclear reactor licensees in the United States
are assessed annually for the decontamination and decommissioning of DOE uranium
enrichment facilities. Assessments are based on the amount of uranium a utility
had processed for enrichment prior to enactment of the National Energy Policy
Act of 1992, and are to be paid by such utilities over a 15-year period. At
March 31, 1999, the Company's liability for contributions
is being recovered through the CTC as part of transition costs.
Guarantees
The Company and the other owners of Bruce Mansfield Power Station (Bruce
Mansfield) have guaranteed certain debt and lease obligations related to a coal
supply contract for Bruce Mansfield. At March 31, 1999, the Company's share of
these guarantees was $5.7 million.
As part of the Company's investment portfolio in affordable housing, the
Company has received fees in exchange for guaranteeing a minimum defined yield
to third-party investors. A portion of the fees received has been deferred to
absorb any required payments with respect to these transactions. Based on an
evaluation of and recent experience with the underlying housing projects, the
Company believes that such deferrals are ample for this purpose.
Environmental Matters
Various federal and state authorities regulate the Company with respect to
air and water quality and other environmental matters. The Company believes it
is in current compliance with all material applicable environmental regulations.
Employees
As previously reported, in connection with the anticipated divestiture,
Duquesne has developed early retirement programs and enhanced separation
packages. To date, approximately 250 eligible employees have elected to
participate in early retirement.
Other
The Company is involved in various other legal proceedings and environmental
matters. The Company believes that such proceedings and matters, in total, will
not have a materially adverse effect on its financial position, results of
operations or cash flows.
5. BUSINESS SEGMENTS AND RELATED INFORMATION
Historically, Duquesne has been treated as a single integrated business
segment due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover the Company's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity is deregulated
and charged at a separate rate from the delivery of electricity beginning in the
first quarter of 1999. For the purposes of complying with SFAS No. 131,
Disclosures about Segments of an Enterprise and Related Information (SFAS No.
131), the Company is required to disclose information about its business
segments separately.
12
<PAGE>
Accordingly, the Company has used the PUC-approved separate rates for 1999 to
develop the financial information of the business segments for the period ended
March 31, 1998 (or as of December 31, 1998, with respect to assets).
Beginning in 1999, the Company has three principal business segments
(determined by products, services and regulatory environment) which consist of
the transmission and distribution by Duquesne of electricity (electricity
delivery business segment); the generation by Duquesne of electricity
(electricity generation business segment); and the collection of transition
costs (CTC business segment). To comply with SFAS No. 131, the Company has
reported the results for the first quarter of 1999 by these business segments
and an "all other" category. The all other category in the following table
includes the expanded business lines and Duquesne investments below the
quantitative threshold for separate disclosure. These expanded business lines
include water utilities, energy products and services, electronic commerce, and
other activities. Intercompany eliminations primarily relate to intercompany
sales of electricity, property rental, management fees and dividends. However,
as the Company was not yet collecting transition costs prior to 1999, the 1998
results are reported by the electricity delivery and electricity generation
business segments.
Financial data for business segments is provided as follows:
Business Segments for the Three Months Ended March 31,
<TABLE>
<CAPTION>
1999 (Thousands of Dollars)
- -----------------------------------------------------------------------------------------------------------------------------
Electricity Electricity All Elimina-
Delivery Generation CTC Other tions Consolidated
---------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 82,320 $106,631 $ 93,025 $ 48,453 $(4,374) $ 326,055
Operating expenses 39,161 119,748 4,093 49,094 (5,608) 206,488
Depreciation and
amortization expense 14,510 9,145 29,633 4,557 -- 57,845
- -----------------------------------------------------------------------------------------------------------------------------
Operating income
(loss) 28,649 (22,262) 59,299 (5,198) 1,234 61,722
Other income 1,183 2,433 -- 34,575 (2,442) 35,749
Interest and other charges 8,886 2,097 11,708 5,023 (614) 27,100
- -----------------------------------------------------------------------------------------------------------------------------
Income (loss) before 20,946 (21,926) 47,591 24,354 (594) 70,371
taxes
Income taxes 7,518 (10,698) 19,750 5,336 -- 21,906
- -----------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 13,428 $(11,228) $ 27,841 $ 19,018 $ (594) $ 48,465
=============================================================================================================================
Assets $1,303,555 $558,409 $2,084,098 $1,316,768 $ -- $5,262,830
=============================================================================================================================
Capital expenditures $ 13,426 $ 2,989 $ -- $ 10,536 $ -- $ 26,951
=============================================================================================================================
</TABLE>
13
<PAGE>
<TABLE>
<CAPTION>
1998 (Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------------------
Electricity Electricity
Delivery Generation All Other Eliminations Consolidated
----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 78,943 $ 206,214 $ 16,814 $(3,196) $ 298,775
Operating expenses 38,548 131,198 14,910 (4,883) 179,773
Depreciation and
amortization expense 12,345 43,783 1,057 -- 57,185
- -------------------------------------------------------------------------------------------------------------------------
Operating income 28,050 31,233 847 1,687 61,817
Other income 1,469 2,427 29,849 (2,327) 31,418
Interest and other charges 9,600 14,920 3,146 (48) 27,618
- -------------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 19,919 18,740 27,550 (592) 65,617
Income taxes 7,964 6,989 5,534 -- 20,487
- -------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 11,955 $ 11,751 $ 22,016 $ (592) $ 45,130
=========================================================================================================================
Assets (1) $1,314,266 $2,711,533 $1,221,764 $ -- $5,247,563
=========================================================================================================================
Capital expenditures $ 8,938 $ 4,446 $ 29,254 $ -- $ 42,638
=========================================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1998.
14
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with DQE, Inc. and its subsidiaries' Annual Report on Form 10-K
filed with the Securities and Exchange Commission (SEC) for the year ended
December 31, 1998 and the condensed consolidated financial statements, which are
set forth on pages 2 through 14 in Part I, Item 1 of this Report.
General
- --------------------------------------------------------------------------------
DQE, Inc. (DQE) is a multi-utility delivery and services company. Its
subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc.
(AquaSource); DQE Capital Corporation (DQE Capital); DQE Energy Services, Inc.
(DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises, Inc. (DE); and
Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to
as "the Company."
The Company's utility operations include an electric utility engaged in the
generation, transmission, distribution and sale of electric energy and a water
resource management company that acquires, develops and manages water and
wastewater utilities. The Company's expanded business lines offer a wide range
of energy-related technologies, industrial and commercial energy services,
telecommunications, and other complementary services. The expanded business
lines' initiatives include energy facility development and operation, domestic
and international independent power production, the production and supply of
innovative fuels, investments in communications systems and electronic commerce,
and long-term investments. In addition, one of the Company's subsidiaries is a
finance company that will provide financing for the expanded business lines.
The Pennsylvania Public Utility Commission (PUC) has approved the Company's
plan to divest itself of its generation assets through an auction (including an
auction of its provider of last resort service), and the pending exchange of
certain power station assets with FirstEnergy Corporation (FirstEnergy). Final
agreements governing these transactions must be approved by various regulatory
agencies. The Company currently expects these transactions to close in late 1999
or early 2000. (See "Rate Matters" on page 21.)
The Company's Service Areas
The Company's electric utility operations provide service to customers in
Allegheny County (including the City of Pittsburgh), Beaver County and to a
limited extent Westmoreland County. (See "Rate Matters" on page 21.) This
territory represents approximately 800 square miles in southwestern
Pennsylvania. In addition to serving approximately 580,000 direct customers, the
Company's utility operations also sell electricity to other utilities.
The Company's water operations currently provide service to approximately
335,000 water and wastewater customer connections and commercial bottled water
customers in 10 states and Canada.
Regulation
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters. (See "Rate Matters" on page 21.)
The Company's electric utility operations are also subject to regulation by
the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as
amended, with respect to the operation of its jointly owned/leased nuclear power
plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and
Perry Unit 1.
15
<PAGE>
The Company's water utility operations are subject to regulation by the
utility regulatory bodies in their respective states.
As a result of the PUC's May 29, 1998, final order regarding the Company's
restructuring plan under the Customer Choice Act (see "Rate Matters" on page
21), the electricity generation portion of the Company's business does not meet
the criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
However, pursuant to the PUC's final restructuring order, certain of the
Company's generation-related regulatory assets are being recovered through a
competitive transition charge (CTC) collected in connection with providing
transmission and distribution services (the electricity delivery business
segment). The Company continues to apply SFAS No. 71 with respect to such
assets. Additionally, pursuant to the PUC's final restructuring order, the
Company is recovering its above-market investment in generation assets through
the CTC, subject to receipt of the proceeds from the generation asset auction.
Remaining fixed assets related to the generation portion of the Company's
business are evaluated in accordance with SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of
(SFAS No. 121). The electricity delivery business segment continues to meet SFAS
No. 71 criteria, and accordingly reflects regulatory assets and liabilities
consistent with cost-based ratemaking regulations. The regulatory assets
represent probable future revenue to the Company, because provisions for these
costs are currently included, or are expected to be included, in charges to
electric utility customers through the ratemaking process. (See "Rate Matters"
on page 21.)
Results of Operations
- --------------------------------------------------------------------------------
Overall Performance
Earnings per share increased 6.9 percent in the first quarter of 1999, to
$0.62. This improvement resulted from a 6.6 percent increase in earnings
available for common stock coupled with a 1.2 million share reduction in
outstanding common stock. The net income contribution from Duquesne increased
by $2.4 million as the result of increased sales and decreased interest costs.
The net income contribution from the Company's expanded business lines increased
by $0.6 million, the result of the continuing water aggregation strategy.
Results by Business Segment
Historically, Duquesne has been treated as a single integrated business
segment due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover the Company's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity is deregulated
and charged at a separate rate from the delivery of electricity beginning in the
first quarter of 1999. For the purposes of complying with SFAS No. 131,
Disclosures about Segments of an Enterprise and Related Information (SFAS No.
131), the Company is required to disclose information about its business
segments separately. Accordingly, the Company has used the PUC-approved separate
rates for 1999 to develop the financial information of the business segments for
1998.
Beginning in 1999, the Company has three principal business segments
(determined by products, services and regulatory environment): (1) the
transmission and distribution by Duquesne of electricity (electricity delivery
business segment), (2) the generation by Duquesne of electricity (electricity
generation business segment), and (3) the collection of transition costs (CTC
business segment). The Company has reported the results for the first quarter of
1999 by these business segments and an "all other" category. The all other
category includes the Company's expanded business lines and Duquesne
investments. These expanded business lines include water utilities, energy
products and services and other activities. Intercompany transactions primarily
relate to sales of electricity, property rental, management fees and dividends.
However, as the Company was not yet collecting transition costs prior to 1999,
the 1998 results are reported by the electricity delivery
16
<PAGE>
and electricity generation business segments. (Additional information regarding
the Company's business segments is set forth in "Business Segments and Related
Information," Note 5 to the consolidated financial statements on page 12.)
Electricity Delivery Business Segment. The electricity delivery business
segment contributed $13.4 million to net income in the first quarter of 1999
compared to $12.0 million in the first quarter of 1998, an increase of 12.3
percent. Operating revenues for this business segment are primarily derived from
the Company's delivery of electricity.
Sales to residential and commercial customers are influenced by weather
conditions. Warmer summer and colder winter seasons lead to increased customer
use of electricity for cooling and heating. Commercial sales are also affected
by regional development. Sales to industrial customers are influenced by
national and global economic conditions.
Operating revenues increased by $3.4 million or 4.3 percent in the first
quarter of 1999 due to an increase in electricity usage customers of 1.9
percent. Industrial sales decreased primarily due to a reduction in electricity
consumption by steel manufacturers, which experienced a decline in demand. The
following table sets forth kilowatt-hours (KWH) delivered to electric utility
customers.
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------
KWH Delivered
-------------------------------------
(In Millions)
-------------------------------------
March 31, 1999 1998 Change
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 916.6 868.4 5.6 %
Commercial 1,440.3 1,379.7 4.4 %
Industrial 850.9 900.9 (5.6)%
- --------------------------------------------------------------------
Sales to Electric Utility Customers 3,207.8 3,149.0 1.9 %
================================================================================
</TABLE>
Operating expenses for the electricity delivery business segment are
primarily made up of costs to operate and maintain the transmission and
distribution system; meter reading and billing costs; customer service;
collection; administrative expenses; and non-income taxes, such as property and
payroll taxes. Operating expenses increased $0.6 million or 1.6 percent in the
first quarter of 1999.
Depreciation and amortization expense increased $2.2 million or 17.5
percent in the first quarter of 1999 due to additions to the plant and
equipment.
Other income is primarily comprised of interest and dividend income. A
decrease of $0.3 million or 19.5 percent was the result of lower interest income
from a smaller amount of cash available for investing in the first quarter of
1999.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the first quarter of
1999, there was $0.7 million or 7.4 percent less in interest and other charges
compared to the first quarter of 1998. The decrease was the result of the
refinancing of long-term debt at lower interest rates and the maturity of
approximately $75 million of long-term debt during 1998.
Electricity Generation and CTC Business Segments. In the first quarter of
1999, the electricity generation and CTC business segments reported net income
of $16.6 million compared to $11.8 million for the first quarter of 1998, an
increase of 41.4 percent.
During 1998, five percent of the Company's electric utility customers
participated in the customer choice pilot program under the Customer Choice Act,
and purchased electricity from alternative generation suppliers. Beginning in
the first quarter of 1999, up to 66 percent of the Company's electric utility
customers are eligible to participate in customer choice. Currently
approximately 13 percent of the Company's customers are purchasing electricity
from alternative generation suppliers.
17
<PAGE>
For the electricity generation and CTC business segments, operating
revenues are primarily derived from the Company's supply of electricity for
delivery to retail customers, the supply of electricity to wholesale customers
and, beginning in 1999, the collection of generation-related transition costs
from electricity delivery customers. Under fuel cost recovery provisions
effective in the first quarter of 1998, fuel revenues generally equaled fuel
expense, as costs were recoverable from customers through the Energy Cost Rate
Adjustment Clause (ECR), including the fuel component of purchased power, and
did not affect net income. In 1999, due to the PUC's final restructuring order,
fuel costs are expensed as incurred, and impact net income to the extent fuel
costs exceed amounts included in Duquesne's authorized generation rates. (See
"Rate Matters" on page 21.)
Energy requirements for electric utility customers are reduced as more
customers participate in customer choice. Energy requirements for residential
and commercial customers are also influenced by weather conditions. Warmer
summer and colder winter seasons lead to increased customer use of electricity
for cooling and heating. Commercial energy requirements are also affected by
regional development. Energy requirements for industrial customers are also
influenced by national and global economic conditions.
Short-term sales to other utilities are made at market rates. Fluctuations
in electricity sales to other utilities are related to the Company's customer
energy requirements, the energy market and transmission conditions, and the
availability of the Company's generating stations. Future levels of short-term
sales to other utilities will be affected by market rates, the level of
participation in customer choice, and the Company's divestiture of its
generation assets. (See "Rate Matters" on page 21.)
Operating revenues decreased by $6.6 million or 3.2 percent in the first
quarter of 1999. The decrease in revenues can be attributed to a decrease in
energy supplied to electric utility customers due to increased participation in
customer choice. Partially offsetting this decrease was a 74.6 percent increase
in energy supplied to other utilities in the first quarter of 1999, due to the
Company's decision to sell 600 MW to licensed generation suppliers to stimulate
competition, and increased capacity available to sell as a result of
participation in customer choice. The following table sets forth KWH supplied
for customers who have not chosen an alternative generation supplier.
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------
KWH Supplied
--------------------------------------
(In Millions)
March 31, 1999 1998 Change
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 822.7 826.3 (0.4)%
Commercial 1,152.4 1,310.5 (12.1)%
Industrial 822.6 888.9 (7.5)%
- -------------------------------------------------------------------
Sales to Electric Utility Customers 2,797.7 3,025.7 (7.5)%
- -------------------------------------------------------------------
Sales to Other Utilities 662.6 379.4 74.6 %
- -------------------------------------------------------------------
Total Sales 3,460.3 3,405.1 1.6 %
===============================================================================
</TABLE>
Operating expenses for the electricity generation and CTC business segments
are primarily made up of energy costs; costs to operate and maintain the power
stations; administrative expenses; and non-income taxes, such as property and
payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of
fuel, the mix between coal and nuclear generation, total KWH supplied, and
generating station availability. Because of the ECR, changes in fuel and
purchased power costs did not impact earnings for the first quarter of 1998.
Operating expenses decreased $7.4 million or 5.6 percent in the first
quarter of 1999 as a result of decreased energy costs, partially offset by
increased non-energy operating costs and taxes.
18
<PAGE>
In the first quarter of 1999, fuel and purchased power expense decreased by
$12.6 million or 21.2 percent compared to the first quarter of 1998. This
decrease was the result of decreased energy costs due to a favorable power
supply mix. During the first quarter of 1998, reduced availability of nuclear
generating stations due to an increase in outage hours required the Company to
purchase power and generate power from the higher fuel cost fossil stations.
Depreciation and amortization expense includes the depreciation of the
power stations' plant and equipment, accrued nuclear decommissioning costs and
the amortization of transition costs. A decrease of $5.0 million or 11.4 percent
in the first quarter of 1999 was the result of accelerated transition cost
reduction efforts during that period. Beginning in 1999, the Company is
recovering its $2,133 million ($1,485 million, net of tax) of transition costs,
as may be adjusted to account for the proceeds of the generation asset auction,
through the CTC and is reflecting amortization expense related to this recovery
based upon the level of KWH delivered.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the first quarter of 1999
there was a $1.1 million or 7.5 percent reduction in interest and other charges
compared to the first quarter of 1998. The decrease reflected the refinancing of
long-term debt at lower interest rates and the maturity of approximately $75
million of long-term debt during 1998.
Increased taxable income during the first quarter of 1999 resulted in
higher income tax expense by $2.1 million or 29.5 percent.
All Other. The all other category contributed $19.0 million to net income
in the first quarter of 1999 compared to $22.0 million in the first quarter of
1998, a decrease of 13.6 percent.
Operating revenues primarily include revenues from operating activities of
the expanded business lines. Operating revenues increased in the first quarter
of 1999 by $31.6 million to almost triple the level in the first quarter of
1998. This increase was primarily the result of increased revenues from
AquaSource and Control Solutions (a subsidiary of DE).
Operating expenses include expenses from operating activities of the
expanded business lines and Duquesne investments. In the first quarter of 1999,
operating expenses increased $34.2 million or more than triple the level in the
first quarter of 1998. The growth of the expanded business lines' start-up and
developmental activities and acquisitions accounted for most of the increase.
Depreciation and amortization expense primarily includes the depreciation
of plant and equipment of the expanded business lines and amortization of
certain investments. In the first quarter of 1999, depreciation and amortization
expense increased by $3.5 million, primarily due to the acquisition of water and
water-related companies by AquaSource throughout 1998.
Other income primarily includes long-term investment income, and interest
and dividend income related to the expanded business lines and Duquesne
investments. Other income in the first quarter of 1999 was $4.7 million or 15.8
percent higher than in the first quarter of 1998. This increase was the result
of new investments made by the expanded business lines throughout 1998.
Interest and other charges are made up of interest on long-term debt, other
interest and preferred stock dividends of the expanded business lines, and
Duquesne investments. An increase of $1.9 million or 59.7 percent in the first
quarter of 1999 was the result of higher long-term debt expense associated with
higher average borrowings outstanding.
Liquidity and Capital Resources
- -------------------------------------------------------------------------------
Financing
The Company expects to meet its current obligations and debt maturities
through the year 2003 with funds generated from operations, through new
financings and short-term borrowings, and through the proceeds from the auction
of generation assets. To the extent that acquisition and long-term investment
opportunities prior to the generation divestiture exceed current expectations,
the
19
<PAGE>
Company may explore various financing alternatives. At March 31, 1999, the
Company was in compliance with all of its debt covenants.
On April 23, 1999, the Company incorporated DQE Capital, a finance company
subsidiary. DQE Capital has been authorized to issue up to $500 million in debt
securities in order to fund the expanded business lines.
Mortgage bonds in the amount of $75 million will mature in July 1999. The
Company expects to retire these bonds with available cash, or to refinance the
bonds.
In connection with the power station exchange with FirstEnergy, the Company
anticipates terminating the BV Unit 2 lease in December 1999, in which case the
lease liability recorded on the consolidated balance sheet would no longer be an
obligation of the Company. The underlying collateralized lease bonds ($371.0
million at March 31, 1999) would become obligations of the Company and be
recorded on the consolidated balance sheet. The Company anticipates redeeming
the bonds on December 1, 2002 (the first redemption date), using funds generated
from operations, the generation asset auction proceeds, the CTC, and/or through
new financings. The Company would also pay approximately $230 million in
termination costs, which the Company expects to recover through the proceeds of
the generation asset auction and the CTC. (See "Power Station Exchange"
discussion on page 22.)
In connection with customer choice, cash flow from Duquesne's operations will
be reduced by an amount equal to the price to compare applicable to those
customers choosing alternative generation suppliers. This reduction is expected
to be offset in large part by reduced cash requirements associated with
supplying energy. The current impact on cash flows at Duquesne is also
minimized, as Duquesne continues to collect the CTC. A greater impact is
anticipated to occur when, as part of the divestiture, Duquesne auctions its
provider of last resort service and all customers will be buying generation from
alternative suppliers. The greatest impact is expected to occur when the CTC
collection period is completed. However, it is anticipated that Duquesne will
apply the proceeds of the auction of its generation assets and provider of last
resort service in a manner that would reduce the impact of any resulting
shortfall by the end of the CTC collection period. The foregoing statements are
forward-looking regarding the impact on cash flows of customer choice and
Duquesne's divestiture. Actual results could materially differ from those
implied by such statements due to known and unknown risks and uncertainties,
including, but not limited to, the amount and timing of the receipt of auction
proceeds. (See "Restructuring Plan" on page 22.)
As of March 31, 1999, 386,660 shares of Preferred Stock, Series A
(Convertible), $100 liquidation preference per share (DQE Preferred Stock), were
outstanding, including 34,077 shares issued in the first quarter of 1999.
The Company and an unaffiliated corporation have an agreement that entitles
the Company to sell and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. The Company currently anticipates extending
the accounts receivable sale arrangement upon its expiration in June 1999. At
March 31, 1999, the Company had sold $50 million of receivables.
The Company maintains two extendable revolving credit facilities, one for
$125 million which expires in June 1999 and one for $150 million which expires
in October 1999. At March 31, 1999, $42 million was outstanding under the $125
million facility, and no amounts were outstanding under the $150 million
facility. Interest rates can, in accordance with the option selected at the
time of the borrowing, be based on prime, Eurodollar or certificate of deposit
rates. Commitment fees are based on the unborrowed amount of the commitments.
Each facility contains a two-year repayment period for any amounts outstanding
at the expiration of the revolving credit period. The Company also has an
aggregate of $150 million in bank term loans outstanding at March 31, 1999, with
$65 million maturing in 2000 and $85 million maturing in 2001.
The Company repurchased shares of its common stock on the open market
during the first quarter of 1999.
20
<PAGE>
Investments and Acquisitions
- -------------------------------------------------------------------------------
The Company has historically made long-term investments in leases,
affordable housing, gas reserves and energy solutions. The Company is studying
restructuring its current investment portfolio, and is considering proposals for
the divestiture of its $120 million portfolio of affordable housing investments.
Investing activities during the first three months of 1999 and 1998 totaled
approximately $6 million and $12 million, respectively.
In the first three months of 1999 the Company issued 34,077 shares of DQE
Preferred Stock, as part of a total investment of approximately $220 million in
water companies.
Rate Matters
- -------------------------------------------------------------------------------
Competition and the Customer Choice Act
Under historical ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral for
future recovery from customers (regulatory assets). As a result of this process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition and stranded costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1,
1997. The Customer Choice Act enables Pennsylvania's electric utility customers
to purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999).
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of April 30, 1999, approximately 13 percent of the Company's
customers had chosen alternative generation suppliers. Customers that have
chosen an electricity generation supplier other than the Company pay that
supplier for generation charges, and pay the Company the CTC (discussed below)
and charges for transmission and distribution. Customers that continue to buy
their generation from the Company pay for their service at current regulated
tariff rates divided into generation, transmission and distribution charges, and
the CTC. Under the Customer Choice Act, an electric distribution company, such
as Duquesne, remains a regulated utility and may only offer PUC-approved rates,
including generation rates. Also under the Customer Choice Act, electricity
delivery (including transmission, distribution and customer service) remains
regulated in substantially the same manner as under historical regulation.
In an effort to "jump start" retail competition, the Company has made 600
megawatts (MW) of power available to licensed electric generation suppliers, to
be used in supplying electricity to Duquesne's customers who have chosen
alternative generation suppliers. The power will be available for the first six
months of 1999 at a price of 2.6 cents per kilowatt-hour (KWH). This power
availability will be structured to ensure the power is used to benefit
Duquesne's retail customers.
21
<PAGE>
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as
long as transition costs are being recovered, with certain exceptions.
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the
Company should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered
was $2,133 million ($1,485 million, net of tax) over a seven-year period
beginning January 1, 1999, as may be adjusted to account for the proceeds of the
generation asset auction. In addition, the transition costs as reflected on the
consolidated balance sheet are being amortized over the same period that the CTC
revenues are being recognized. The Company is allowed to earn an 11 percent pre-
tax return on the unrecovered balance.
As part of its restructuring plan filing, the Company requested recovery of
$11.5 million ($6.7 million, net of tax) through the CTC for energy costs
previously deferred under the ECR. Recovery of this amount was approved in the
PUC's final restructuring order. The Company also requested recovery of an
additional $31.2 million ($18.2 million, net of tax) in deferred fuel costs. On
December 18, 1998, the PUC denied recovery of this additional amount. The
Company has appealed the PUC's denial of recovery to the Pennsylvania
Commonwealth Court. Based upon the Customer Choice Act, which mandates recovery
of all regulatory assets, and the PUC's specific authorization for the Company
to create a regulatory asset for these costs, the Company believes that it is
probable that these costs will be recovered through retail rates. In the event
that the Company does not prevail in its appeal, these costs would be written
off as a charge against income.
Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) is expected to be recovered from ratepayers through the CTC.
Until the divestiture is complete, Duquesne has been ordered to use an interim
system average CTC and price to compare based on the methodology approved in its
pilot program (approximately 2.9 cents per KWH for the CTC and approximately 3.8
cents per KWH for the price to compare).
On December 18, 1998, the PUC approved Duquesne's auction plan, including
an auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick, Elrama, Phillips and
Brunot Island power stations, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process began in April
1999, with potential buyers identified by Duquesne being asked to submit non-
binding bids. Final agreements governing the transactions must be approved by
various regulatory agencies, including the PUC, the FERC, the NRC, the
Department of Justice and/or the Federal Trade Commission. Duquesne currently
expects the sale to close at the end of 1999 or the beginning of 2000.
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999 (which remain subject to regulatory approval), Duquesne and
FirstEnergy will exchange ownership interests in certain power stations.
Duquesne will receive 100 percent ownership rights in three coal-fired power
plants located in Avon Lake and Niles, Ohio and New Castle, Pennsylvania
(totaling approximately 1,300 MW), which the Company expects to sell
simultaneously as part of the auction of generation assets. FirstEnergy will
acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley
Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and
22
<PAGE>
Bruce Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In
connection with the power station exchange, the Company anticipates terminating
the BV Unit 2 lease in December 1999. (See "Financing," discussion on page 19)
Pursuant to the December 18, 1998, PUC order and subject to final approval, the
proceeds from the sale of the power stations received in the exchange will be
used to offset the transition costs associated with Duquesne's currently-held
generation assets and costs associated with completing the exchange. Duquesne
expects this exchange to enhance the value received from the auction, because
participants will bid on plants that are wholly owned by Duquesne, rather than
plants that are jointly owned and/or operated by another entity. Additionally,
the auction will include only coal- and oil-fired plants, which are anticipated
to have a higher market value than nuclear plants. These value-enhancing
features, along with a minimum level of auction proceeds guaranteed by
FirstEnergy, are expected to maximize auction proceeds, minimize transition
costs required to be recovered through the CTC (by shortening the length of the
CTC recovery period), and thus reduce customer bills as rapidly as possible.
Other benefits of this exchange include the resolution of all joint ownership
issues, and other risks and costs associated with the jointly-owned units. In
December 1998 the PUC said the exchange appears to be in the public interest.
The definitive exchange agreement was submitted in early May 1999 for PUC
approval. Certain aspects of the exchange will also have to be approved by,
among other agencies, the FERC, the NRC and the Department of Justice. The power
station exchange is expected to occur simultaneously with the anticipated
closing of the sale of Duquesne's generation through the auction at the end of
1999 or in early 2000.
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement between the Company and Allegheny Energy, Inc. (AYE). The
Company believes that AYE suffered a material adverse effect as a result of the
PUC's final restructuring order regarding AYE's utility subsidiary, West Penn
Power Company. AYE filed suit in the United States District Court for the
Western District of Pennsylvania, seeking to compel the Company to proceed with
the merger and seeking a temporary restraining order and preliminary injunction
to prevent the Company from certain actions pending a trial, or in the
alternative seeking an unspecified amount of money damages. The parties continue
to litigate this matter. (See "Legal Proceedings" on page 27.) In a letter
dated February 24, 1999, the PUC informed the Company that the merger
application was deemed withdrawn and the docket was closed.
Year 2000
- -------------------------------------------------------------------------------
Many existing computer programs and embedded microprocessors use only two
digits to identify a year (for example, "99" is used to represent "1999"). Such
programs read "00" as the year 1900, and thus may not recognize dates beginning
with the year 2000, or may otherwise produce erroneous results or cease
processing when dates after 1999 are encountered.
Year 2000 Plan. The Company fully expects normal operations into the Year
2000 and beyond as a result of the extensive and systematic approach the Company
has taken to address the Year 2000 issue. In 1994, the Company began reviewing
its critical information systems that impact operations and financial reporting
in order to develop a strategy to address required computer software and system
changes and upgrades. The Company has since assembled a Year 2000 team,
comprised of management representatives from all functional areas of the
Company, which continues to explore the exposure to Year 2000-related issues in
computer software and in devices and equipment (such as plant components,
substations, elevators, and heating and cooling systems) containing embedded
microprocessors that may not correctly identify the year. The team is also
exploring potential related issues that may originate with third parties with
whom the Company does business. To support the planning, organization and
management of its efforts, the team has retained Year 2000 consultants.
23
<PAGE>
In general, the Company's overall strategy to address the Year 2000 issue is
comprised of four phases that, in some cases, are performed simultaneously.
These phases are: inventory, assessment, remediation, and testing and
implementation.
Inventory consists of identifying the various components, equipment, hardware,
and software used in the Company's operations that may potentially be faced with
Year 2000 issues. The Company inventoried over 100,000 items during this phase
of the project. The inventory process involved reviewing existing listings and
subsequent verification through physical inspections and walk-downs. This
inventory effort was completed during the fourth quarter of 1998.
Assessment consists of evaluating all inventoried items for Year 2000
compliance or readiness. This was accomplished by contacting the vendors and
manufacturers, inspecting software and code, researching the results of other
companies' assessment of like components, and various other means. Assessment
activities were completed during the first quarter of 1999. The Company's
business is dependent upon external suppliers for the reliable delivery of their
products and services. The Company has inquired in writing of its suppliers and
service providers with regard to their Year 2000 readiness. The Company
continues to meet with critical suppliers and service providers to further
validate evidence of their Year 2000 readiness.
Remediation refers to the activities necessary to fix or replace those
components that have Year 2000 issues that will adversely affect the Company's
operations. Remediation concentrates first on those systems, components, and
equipment that substantially impact the Company's ability to perform its
essential business functions ("mission critical"). Remediation of mission
critical systems was completed during the first quarter of 1999. This
remediation is in addition to previously planned improvements to the Company's
systems with benefits beyond Year 2000 solutions, such as total system
replacements discussed below.
Testing and implementation consists of placing renovated processes, systems,
equipment, and other items into use within the Company's operations. Testing is
performed on all mission critical processes, whether or not remediation
activities were involved in the process. Testing and implementation of mission
critical processes was substantially completed in the first quarter of 1999.
Throughout the execution of its Year 2000 plan, the Company has been providing
and will continue to provide information on its activities to the PUC, the NRC
and the North American Electric Reliability Counsel (NERC), which coordinates
the network of interconnected utilities across the nation. The Company's plan is
in accordance with NRC guidelines, and the Company is working with the NRC to
certify that its nuclear power station safety and operations systems, and issues
related to suppliers, will be ready for the Year 2000. NERC has been requested
by the DOE to review the national electric power production and delivery
infrastructure to ensure a reliable power supply during the Year 2000 transition
period. The Company is working with NERC to address these issues through monthly
status reporting and participation in regional Year 2000 tests. The Company
participated in the industry-wide NERC communication drill that was conducted on
April 9, 1999. All of the Company's communications systems exercised in this
drill performed as expected. The Company will also be participating in the NERC
Year 2000 readiness drill to be conducted on September 9, 1999. The Company
also participates in the Electric Power Research Institute's project to share
information about technical issues regarding Year 2000 with other entities in
the electric utility industry.
Risks and Contingency Plans. The Company currently believes that
implementation of its plan will minimize the Year 2000 issues relating to its
systems and equipment. The Company's goal is to ensure that all components and
services that in any material manner contribute to operational reliability,
customer relations, safety, revenue, and regulatory compliance will be suitable
for continued use beyond December 31, 1999. The Company understands that many
variables outside the control of the Company may have an adverse affect on the
ability of the Company to perform its mission critical processes. Management
believes that the most reasonably likely worst case scenario would be a
temporary disruption of service to customers caused by potential disruptions in
the operations of critical suppliers, such as fuel supply or telecommunications.
In addition, there could be a temporary
24
<PAGE>
reduction in energy needs of customers due to their Year 2000 issues. In the
event either scenario occurs, it is not anticipated that the Company would incur
a material adverse impact on financial position or the consolidated results of
operations.
In the normal course of business, the Company has developed redundant
operations and contingency plans to minimize the risk of interrupted operations.
As part of the Year 2000 program, the Company has reviewed these plans in terms
of Year 2000 related risks, and either refined the existing plans or developed
new contingency plans for all mission critical processes. These contingency
plans address training, testing and rehearsal of procedures, as well as the need
for back-up equipment. The contingency plans also include provisions for extra
staffing and back-up communications. The Company continues to review its
operations and its critical external suppliers and service providers, in order
to determine any adverse scenarios it could face as a result of Year 2000
problems. To date, nothing has been found that would prevent the Company from
generating or providing electricity to the public.
Costs. The estimated total cost of implementing the Company's Year 2000 plan
is approximately $49 million, which includes costs related to total system
replacements (i.e., the Year 2000 solution comprises only a portion of the
benefit resulting from such replacements). These costs to date, primarily
incurred as a result of software and system changes and upgrades by Duquesne,
have been approximately $39 million. Of this amount, approximately $35 million
are capital costs attributable to the licensing and installation of new software
for total system replacements. The remaining $4 million has been expensed as
incurred. Funds for the Company's Year 2000 plan have come from the Company's
operating and capital budgets. Approximately $10 million has been budgeted for
1999 to address Year 2000 issues. The Company does not anticipate that Year 2000
issues and related costs will be material to the Company's operations, financial
condition and results of operations.
The foregoing paragraphs contain forward-looking statements regarding the
timetable, effectiveness and ultimate cost of the Company's Year 2000 strategy.
Actual results could materially differ from those implied by such statements due
to known and unknown risks and uncertainties, including, but not limited to, the
possibility that changes and upgrades are not timely completed, that corrections
to the systems of other companies on which the Company's systems rely may not be
timely completed, and that such changes and upgrades may be incompatible with
the Company's systems; the availability and cost of trained personnel; and the
ability to locate and correct all relevant computer code and microprocessors.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Funding for nuclear decommissioning costs is deposited by the Company in
external, segregated trust accounts and invested in a portfolio of corporate
common stock and debt securities, municipal bonds, certificates of deposit and
United States government securities. The market value of the aggregate trust
fund balances at March 31, 1999 totaled approximately $65.8 million. The amount
funded into the trusts is based on estimated returns which, if not achieved as
projected, could require additional unanticipated funding requirements.
______________________________
25
<PAGE>
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
known and unknown risks, uncertainties and other factors that may cause the
actual results, performance or achievements of the Company to be materially
different from any future results, performance or achievements expressed or
implied by such forward-looking statements. Such factors may affect the
Company's operations, markets, products, services and prices, and include, among
others, the following: the Company's decision not to consummate the merger with
AYE; the related lawsuit initiated by AYE; Duquesne's plan to auction its
generating assets; the power station exchange; general and economic and business
conditions; industry capacity; changes in technology; changes in political,
social and economic conditions; pending regulatory decisions regarding industry
restructuring in Pennsylvania; the loss of any significant customers; and
changes in business strategy or development plans.
26
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, the Company commenced arbitration against The Cleveland
Electric Illuminating Company (CEI), seeking damages, termination of the
operating agreement for Eastlake Unit 5 (Eastlake) and partition of the parties'
interests in Eastlake through a sale and division of the proceeds. The
arbitration demand alleged, among other things, the improper allocation by CEI
of fuel and related costs; the mismanagement of the administration of the
Saginaw coal contract in connection with the closing of the Saginaw mine, which
historically supplied coal to Eastlake; and the concealment by CEI of material
information. CEI also seeks monetary damages from the Company for alleged unpaid
joint costs in connection with the operation of Eastlake. The Company removed
the action to the United States District Court for the Northern District of
Ohio, Eastern Division, where it is now pending. Pursuant to the agreement
regarding the power station exchange between Duquesne and FirstEnergy, the
parties have jointly sought and received a court order staying all proceedings
pending the closing of the exchange. (See "Power Station Exchange" discussion on
page 22.)
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement with AYE. More information regarding this termination is set
forth in the Company's Current Report on Form 8-K dated October 5, 1998. AYE
promptly filed suit in the United States District Court for the Western District
of Pennsylvania, seeking to compel the Company to proceed with the merger and
seeking a temporary restraining order and preliminary injunction to prevent the
Company from certain actions pending a trial, or in the alternative seeking an
unspecified amount of money damages. On October 28, 1998, the judge denied AYE's
motion for the temporary restraining order and preliminary injunction. AYE
appealed to the United States Court of Appeals for the Third Circuit, asking for
an injunction pending the appeal and expedited treatment of the appeal. On
November 6, 1998, the Third Circuit denied the motion for an injunction and
granted the motion to expedite the appeal.
On March 11, 1999, the Third Circuit vacated the October 28 denial of a
preliminary injunction. The Third Circuit remanded the case to the District
Court for further proceedings to address certain issues, including whether AYE
could demonstrate a reasonable likelihood of success on the merits, before
determining whether any injunctive relief is warranted. On March 12, 1999, AYE
filed a motion for a temporary restraining order with the district court, and a
hearing was held that same day. On March 16, 1999, AYE and DQE entered into a
consent agreement, which was approved by the district court on March 18.
Pursuant to the consent agreement, AYE and DQE have agreed, among other things,
that pending the consolidated hearing on AYE's application for a preliminary
injunction and/or an expedited trial on the merits, both parties will give each
other 10 business days' notice before taking or omitting to take any action
which would prevent the merger from qualifying for "pooling of interests"
accounting treatment. This would not prevent either party from entering into any
agreement, but would require the 10 business days' notice prior to closing any
transaction which prevents pooling. The consent agreement shall terminate on
September 16, 1999, unless earlier terminated or extended by mutual agreement or
an order of the district court. On March 25, 1999, the Company petitioned the
Third Circuit for rehearing.
The Company continues to believe that AYE's claim is entirely without merit
in light of the $1 billion disallowance of its stranded costs, which constituted
a material adverse effect under the merger agreement and entitled the Company to
terminate it as of October 5, 1998. The Company will continue to defend itself
vigorously against AYE's claims and intends to pursue a prompt resolution of the
litigation. The ultimate outcome of this suit cannot be determined at this time.
27
<PAGE>
Item 4. Submission of Matters to a Vote of Security Holders
a. On April 27, 1999, DQE held its 1999 Annual Meeting of Stockholders.
b. Proxies for the Annual Meeting were solicited pursuant to Regulation 14
under the Securities and Exchange Act of 1934, as amended. There was no
solicitation in opposition to management's nominees for directors as listed
in the proxy statement dated March 10, 1999, and all nominees were elected.
c. Two proposals were submitted to stockholders for a vote at the Annual
Meeting.
Proposal 1 was the election of four directors to the Board of Directors to
serve until the 2002 Annual Meeting and until their respective successors
have been chosen and qualified. The vote on this proposal was as follows:
<TABLE>
<CAPTION>
Nominee Type of Stock For Withheld Broker Non-Votes
------------------ ------------- ---------- -------- ----------------
<S> <C> <C> <C> <C>
Sigo Falk Common 67,679,710 794,846 2,579,778
Preferred 852,111 -- --
Eric W. Springer Common 67,471,614 794,846 2,579,778
Preferred 852,111 -- --
</TABLE>
The following Directors terms continue after the Annual Meeting of
Stockholders:
until 2000 - Daniel Berg, Robert P. Bozzone, William H. Knoell and Thomas
J. Murrin;
until 2001 - Doreen E. Boyce and, David D. Marshall.
Proposal 2 was the ratification of the appointment, by the Board of
Directors, of Deloitte & Touche LLP as independent public accountants to
audit the books of the Company for the year ending December 31, 1999. The
vote on this proposal was as follows:
<TABLE>
<CAPTION>
Type of Stock For Against Broker Non-Votes Abstain
------------- ---------- ------- ---------------- -------
<S> <C> <C> <C> <C>
Common 67,618,469 319,279 2,579,778 465,342
Preferred 852,111 -- -- --
</TABLE>
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividend Requirements.
EXHIBIT 27.1 - Financial Data Schedule
28
<PAGE>
b. Two reports on Form 8-K were filed during the fiscal quarter ended March
31, 1999:
A report was filed March 19, 1999, to report the consent agreement entered
into by DQE and AYE. No financial statements were filed with this report.
A report was filed March 26, 1999, to report the execution of definitive
power station exchange agreements. No financial statements were filed with
this report.
_____________________________
29
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
DQE, Inc.
----------------------------------------
(Registrant)
Date May 11, 1999 /s/ Gary L. Schwass
---------------------- ----------------------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer
Date May 11, 1999 /s/ Morgan K. O'Brien
---------------------- ----------------------------------------
(Signature)
Morgan K. O'Brien
Vice President, Treasurer and Controller
(Principal Accounting Officer)
30
<PAGE>
Exhibit 12.1
DQE, Inc. and Subsidiaries
Calculation of Ratio of Earnings to Combined Fixed Charges
and Preferred and Preference Stock Dividend Requirements
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended ------------------------------------------------------------------
March 31, 1999 1998 1997 1996 1995 1994
-------------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 18,788 81,076 $ 87,420 $ 88,478 $ 95,391 $101,027
Other interest 4,491 14,556 13,823 10,926 7,033 4,050
Portion of lease payments representing
an interest factor 11,132 44,146 44,208 44,357 44,386 44,839
Dividend requirement 4,076 15,612 21,649 14,385 7,374 9,355
--------- --------- --------- --------- --------- ---------
Total Fixed Charges $ 38,487 155,390 $167,100 $158,146 $154,184 $159,271
--------- --------- --------- --------- --------- ---------
EARNINGS:
Income from continuing operations $ 48,495 196,688 $199,101 $179,138 $170,563 $156,816
Income taxes 21,906 * 100,982 * 95,805 * 87,388 * 96,661 * 92,973 *
Fixed Charges as above 38,487 155,390 167,100 158,146 154,184 159,271
--------- --------- --------- --------- --------- ---------
Total Earnings $108,888 453,060 $462,006 $424,672 $421,408 $409,060
--------- --------- --------- --------- --------- ---------
RATIO OF EARNINGS TO FIXED CHARGES 2.83 2.92 2.76 2.69 2.73 2.57
========= ========= ========= ========= ========= =========
</TABLE>
The Company's share of the fixed charges of an unaffiliated coal supplier,
which amounted to approximately $0.6 million for the three months ended March
31, 1999, has been excluded from the ratio.
* Earnings related to income taxes reflect a $2.0 million decrease for the
three months ended March 31, 1999, a $12 million, $17 million, $12 million,
$13.5 million and $13.5 million decrease for the twelve months ended December
31, 1998, 1997, 1996, 1995 and 1994, respectively, due to financial statement
reclassification related to Statement of Financial Accounting Standards No.
109, Accounting for Income Taxes. The ratio of earnings to fixed charges,
absent this reclassification, equals 2.88 for the three months ended March 31,
1999, and 2.99, 2.87, 2.76, 2.82 and 2.65 for the twelve months ended December
31, 1998, 1997, 1996, 1995 and 1994, respectively.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,453,063
<OTHER-PROPERTY-AND-INVEST> 1,057,802
<TOTAL-CURRENT-ASSETS> 331,256
<TOTAL-DEFERRED-CHARGES> 2,420,709
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 5,262,830
<COMMON> 73,119
<CAPITAL-SURPLUS-PAID-IN> 924,130
<RETAINED-EARNINGS> 888,483
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,452,799<F1>
4,500
262,660<F2>
<LONG-TERM-DEBT-NET> 1,324,802
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 47,488
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 123,636
0
<CAPITAL-LEASE-OBLIGATIONS> 15,168
<LEASES-CURRENT> 43,742
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,988,035
<TOT-CAPITALIZATION-AND-LIAB> 5,262,830
<GROSS-OPERATING-REVENUE> 326,055
<INCOME-TAX-EXPENSE> 21,906<F3>
<OTHER-OPERATING-EXPENSES> 264,333
<TOTAL-OPERATING-EXPENSES> 264,333
<OPERATING-INCOME-LOSS> 61,722
<OTHER-INCOME-NET> 35,749
<INCOME-BEFORE-INTEREST-EXPEN> 97,471
<TOTAL-INTEREST-EXPENSE> 27,100<F4>
<NET-INCOME> 48,465
392
<EARNINGS-AVAILABLE-FOR-COMM> 48,073
<COMMON-STOCK-DIVIDENDS> 29,285
<TOTAL-INTEREST-ON-BONDS> 18,788
<CASH-FLOW-OPERATIONS> 96,811
<EPS-PRIMARY> 0.62
<EPS-DILUTED> 0.61
<FN>
<F1>Includes $(432,933) of Treasury Stock at cost
<F2>Includes $13,370 of Preference Stock
<F3>Non-operating expense
<F4>Includes $4,159 of Preferred and Preference Stock Dividends
</FN>
</TABLE>
