<PAGE>
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 September 30, 1999
----------------------
[_] 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.
---------
(Exact name of registrant as specified in its charter)
Pennsylvania 25-1598483
------------ ----------
(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
-------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 269-0700
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 - 75,313,376 shares outstanding as of September
30, 1999 and 73,905,219 shares outstanding as of October 31, 1999.
<PAGE>
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 Nine Months Ended
September 30, September 30,
------------------------------- ----------------------------------
1999 1998 1999 1998
------------ ------------ ------------ -------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity $ 321,967 $ 313,346 $ 842,889 $ 862,661
Other 76,278 41,352 209,012 94,322
------------ ------------ ------------ ------------
Total Operating Revenues 398,245 354,698 1,051,901 956,983
------------ ------------ ------------ ------------
Operating Expenses
Fuel and purchased power 84,341 85,335 180,921 216,443
Other operating 125,874 92,633 344,186 246,651
Maintenance 18,426 23,321 62,197 59,273
Depreciation and amortization 65,086 37,644 175,972 152,478
Taxes other than income taxes 25,280 21,095 71,200 60,702
Total Operating Expenses 319,007 260,028 834,476 735,547
------------ ------------ ------------ ------------
OPERATING INCOME 79,238 94,670 217,425 221,436
------------ ------------ ------------ ------------
Other Income 36,681 20,145 109,015 79,692
------------ ------------ ------------ ------------
Interest and Other Charges 40,526 27,609 115,244 82,540
------------ ------------ ------------ ------------
INCOME Before Income Taxes And
Extraordinary Item 75,393 87,206 211,196 218,588
------------ ------------ ------------ ------------
Income Taxes 26,176 25,137 71,908 71,185
------------ ------------ ------------ ------------
INCOME Before Extraordinary Item 49,217 62,069 139,288 147,403
Extraordinary Item (Net of Tax) -- -- -- (82,548)
------------ ------------ ------------ ------------
NET INCOME After Extraordinary Item $ 49,217 $ 62,069 $ 139,288 $ 64,855
============ ============ ============ ============
DIVIDENDS ON PREFERRED STOCK 425 -- 1,153 --
------------ ------------ ------------ ------------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 48,792 $ 62,069 $ 138,135 $ 64,855
============ ============ ============ ============
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 75,356 77,743 76,110 77,716
============ ============ ============ ============
BASIC EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
Before Extraordinary Item $ 0.64 $ 0.80 $ 1.81 $ 1.90
============ ============ ============ ============
Extraordinary Item $ -- $ -- $ -- $ (1.06)
============ ============ ============ ============
After Extraordinary Item $ 0.64 $ 0.80 $ 1.81 $ 0.84
============ ============ ============ ============
DILUTED EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
Before Extraordinary Item $ 0.63 $ 0.78 $ 1.77 $ 1.86
============ ============ ============ ============
Extraordinary Item $ -- $ -- $ -- $ (1.04)
============ ============ ============ ============
After Extraordinary Item $ 0.63 $ 0.78 $ 1.77 $ 0.82
============ ============ ============ ============
DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $ 0.38 $ 0.36 $ 1.14 $ 1.08
============ ============ ============ ============
</TABLE>
See notes to condensed consolidated financial statements.
2
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DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
September 30, December 31,
1999 1998
----------------- -------------------
<S> <C> <C>
ASSETS
Current assets:
Cash and temporary cash investments $ 99,248 $ 108,790
Receivables 147,733 165,794
Other current assets, principally materials and supplies 172,331 100,168
---------------- ----------------
Total current assets 419,312 374,752
---------------- ----------------
Long-term investments 732,813 750,796
---------------- ----------------
Property, plant and equipment 4,902,264 4,884,138
Less: Accumulated depreciation and amortization (3,146,913) (3,167,328)
---------------- ----------------
Property, plant and equipment - net 1,755,351 1,716,810
---------------- ----------------
Other non-current assets:
Transition costs 1,977,305 2,132,980
Regulatory assets 61,031 64,568
Other 351,293 207,657
---------------- ----------------
Total other non-current assets 2,389,629 2,405,205
---------------- ----------------
TOTAL ASSETS $ 5,297,105 $ 5,247,563
================ ================
LIABILITIES AND CAPITALIZATION
Notes payable and current maturities $ 280,199 $ 100,822
---------------- ----------------
Other current liabilities 162,717 253,442
---------------- ----------------
Deferred income taxes - net 813,516 777,017
---------------- ----------------
Deferred income 138,390 156,579
---------------- ----------------
Beaver Valley lease liability 475,570 475,570
---------------- ----------------
Other non-current liabilities 334,537 371,653
---------------- ----------------
Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,367,072 1,364,879
---------------- ----------------
Preferred and preference stock of subsidiaries 229,237 228,282
---------------- ----------------
Preferred stock 43,786 35,274
---------------- ----------------
Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
issued - 109,679,154 shares) 994,965 994,996
Retained earnings 921,156 869,671
Less treasury stock (at cost) (34,365,778 and 32,305,726
shares, respectively) (469,391) (385,976)
Accumulated other comprehensive income 5,351 5,354
---------------- ----------------
Total common shareholders' equity 1,452,081 1,484,045
---------------- ----------------
Total capitalization 3,092,176 3,112,480
---------------- ----------------
TOTAL LIABILITIES AND CAPITALIZATION $ 5,297,105 $ 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>
Nine Months Ended
September 30,
----------------------------------------
1999 1998
-------------- --------------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 332,694 $ 364,610
Purchase of nuclear fuel (40,109) --
Changes in working capital other than cash (6,970) (119,450)
Increase in ECR -- (19,219)
Other (3,883) 17,519
-------------- --------------
Net Cash Provided By Operating Activities 281,732 243,460
-------------- --------------
Cash Flows From Investing Activities
Acquisition of water companies (142,496) (40,961)
Capital expenditures (102,768) (118,955)
Long-term investments (25,500) (50,862)
Acquisition of propane companies (17,315) --
Payment of funding obligations (14,057) --
Proceeds from the sale of investments 49,297 --
Proceeds from the sale of property 31,863 1,063
Other (24,871) (28,740)
-------------- --------------
Net Cash Used in Investing Activities (245,847) (238,455)
-------------- --------------
Cash Flows From Financing Activities
Dividends on common stock (86,650) (83,929)
Repurchase of common stock (83,415) --
Reductions of long term obligations - net (70,946) (36,732)
Increase in notes payable 226,233 4,375
Other (30,649) (7,690)
-------------- --------------
Net Cash Used in Financing Activities (45,427) (123,976)
-------------- --------------
Net decrease in cash and temporary cash investments (9,542) (118,971)
Cash and temporary cash investments at beginning of period 108,790 356,412
-------------- --------------
Cash and temporary cash investments at end of period $ 99,248 $ 237,441
============== ==============
Non-Cash Investing and Financing Activities
Preferred stock issued in conjunction with long-term investments $ 8,634 $ 25,056
============== ==============
Capital lease obligations recorded $ 6,470 $ 5,011
============== ==============
Equity funding obligations recorded $ 812 $ --
============== ==============
</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 Nine Months Ended
September 30, September 30,
1999 1998 1999 1998
------------ ------------- ------------ -------------
<S> <C> <C> <C> <C>
NET INCOME AFTER EXTRAORDINARY ITEM $ 49,217 $ 62,069 $ 139,288 $ 64,855
Other Comprehensive (Loss) Income:
Unrealized holding (losses) gains
net of tax of $(208), $(1,396), $994 and
$(2,114), respectively (294) (1,930) 1,401 (2,980)
Less: reclassification adjustment for
gains included in net income, net of
tax of $0, $0, $756 and $0, respectively -- -- (1,404) --
------------ ------------- ------------ -------------
Total Other Comprehensive (Loss) Income (294) (1,930) (3) (2,980)
------------ ------------- ------------ -------------
Comprehensive Income $ 48,923 $ 60,139 $ 139,285 $ 61,875
============ ============= ============ =============
</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 largest subsidiary, Duquesne, is an electric utility engaged
in the generation, transmission, distribution and sale of electric energy. 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 also
include a water resource management company that acquires, develops and manages
water and wastewater utilities, energy facility development and operation,
domestic and international independent power production, the production and
distribution of landfill gas, propane and synthetic fuels, investments in
communications systems and electronic commerce, and long-term investments. DQE
Capital provides financing for the expanded business lines.
The Company plans to divest itself of its generation assets through the
pending exchange of certain power station assets with FirstEnergy Corporation
(FirstEnergy) and the pending sale of generation assets to Orion Power Holdings,
Inc. (Orion). Final agreements governing the sale to Orion must be approved by
various regulatory agencies, including the Pennsylvania Public Utility
Commission (PUC). The Company currently expects these transactions to close in
December 1999 and the second quarter of 2000, respectively. (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.
5
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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 interim periods and are
normal, recurring adjustments. Prior periods have been reclassified to conform
with current accounting presentations.
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 and nine months ended September 30, 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. 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," 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).
Accordingly, 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). 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), and have been reclassified accordingly. 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. 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 costs are no longer recoverable through the
ECR. Instead, effective May 29, 1998 (the date of the PUC's final restructuring
order), such costs are expensed as incurred and thus impact net income. (See
"Restructuring Plan" discussion, Note 2, on page 8.)
6
<PAGE>
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 were $9.1 million ($5.4 million, net of tax) at September
30, 1999, and $8.9 million ($5.4 million, net of tax) at December 31, 1998.
(See "Power Station Exchange" discussion, Note 2, on page 8.)
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 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
Currently 66 percent of customers are eligible to participate in customer
choice (including customers covered by the pilot program); all customers will
have customer choice in January 2000. As of September 30, 1999, approximately 17
percent of the Company's customers had chosen alternative generation suppliers,
representing approximately 22 percent of the Company's non-coincident peak load.
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 "jumpstart" competition, Duquesne had made 600 megawatts
(MW) of power available through the first six months of 1999 to licensed
electric generation suppliers, to be used to supply electricity to Duquesne's
customers who had chosen alternative generation suppliers.
7
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Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs (discussed below), the
Company has agreed to extend this rate cap for an additional six months through
the end of 2001. 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 $1.49 billion, net of tax, of transition costs
was originally to be recovered over a seven-year period ending in 2005. However,
by applying expected net proceeds of the generation asset auction (discussed
below) to reduce transition costs, the Company currently anticipates early
termination of the CTC collection period in 2001 for most major rate classes.
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, net of tax balance of transition costs, as adjusted following the
generation asset auction.
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 appealed the PUC's denial of recovery to the Pennsylvania Commonwealth
Court. On October 26, 1999, the Company and the Pennsylvania Office of the
Consumer Advocate reached a settlement on this issue which would permit recovery
of the entire $42.7 million ($24.9 million, net of tax) in deferred fuel costs.
The PUC's decision on this settlement is pending.
Auction Plan. On December 18, 1998, the PUC approved Duquesne's auction
plan, including a purchased power agreement covering Duquesne's obligations for
its provider of last resort service, as well as an agreement in principle to
exchange certain generation assets with FirstEnergy. On September 24, 1999,
Duquesne and the winning auction bidder, Orion, entered into definitive
agreements pursuant to which Orion will purchase Duquesne's wholly owned
Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations to
be received from FirstEnergy in the power station exchange described below, for
approximately $1.71 billion. Under the purchased power agreement, Orion will
supply all of the electric energy requirements for Duquesne's customers who have
not chosen an alternative generation supplier (provider of last resort service).
This agreement, which expires upon Duquesne's final collection of the CTC,
effectively transfers to Orion all of the financial risks and rewards associated
with electricity supply. The purchase must be approved by various regulatory
agencies, including the PUC, the FERC, and the Federal Trade Commission.
Duquesne currently expects the sale to close in the second quarter of 2000.
Although Duquesne expects to apply the net auction proceeds to reduce transition
costs, until the divestiture is complete, Duquesne has been ordered to use an
interim CTC and price to compare for each rate class based on the methodology
approved in its pilot program (on average, approximately 2.9 cents per kilowatt
hour (KWH) for the CTC and approximately 3.8 cents per KWH for the price to
compare).
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three fossil-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company plans
to sell 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
8
<PAGE>
1,400 MW). In connection with the power station exchange, the Company
anticipates terminating the BV Unit 2 lease in the fourth quarter of 1999. (See
"Financing" discussion on page 23.) Pursuant to the December 18, 1998, PUC order
and subject to final approval, the proceeds from the sale to Orion 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. Benefits of this exchange include the resolution
of all joint ownership issues, and other ongoing risks and costs associated with
the jointly-owned units. The Federal Trade Commission approved the exchange on
June 30, 1999. The PUC approved the definitive exchange agreement on July 15,
1999, having found the exchange to be in the public interest. On September 15,
1999, the FERC approved the exchange. On September 30, 1999, the NRC approved
the transfer of the BV Unit 1 and BV Unit 2 operating licenses, as well as
Duquesne's ownership interest in Perry, to FirstEnergy. The Public Utilities
Commission of Ohio approved the exchange agreement on October 28, 1999. The
power station exchange is expected to occur in December 1999. (See "Legal
Proceedings" on page 31.)
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. Trial was held from October 20 through 28,
1999. Post-trial pleadings were filed November 10, 1999, and closing arguments
are scheduled for November 23, 1999. The Company expects the judge's decision
prior to the scheduled closing of the power station exchange in December. (See
"Legal Proceedings" on page 31.)
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>
September 30, September 30, December 31,
1999 1998 1998
(Amounts in Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 97,005 $ 99,608 $ 87,262
Water customer accounts receivable 28,364 3,328 10,591
Other utility receivables 27,733 28,306 25,412
Other receivables 54,581 50,398 51,944
Less: Allowance for uncollectible accounts (9,950) (15,281) (9,415)
- ---------------------------------------------------------------------------------------------------------------
Receivables less allowance for uncollectible accounts 197,733 166,359 165,794
Less: Receivables sold (electric customer accounts) (50,000) -- --
===============================================================================================================
Total Receivables $147,733 $166,359 $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,
the expiration of which has been extended until February 2000, is one of many
sources of funds available to the Company. The Company currently anticipates
further extending the agreement or replacing it with a similar arrangement upon
expiration. At September 30, 1999, the Company had sold $50 million of
receivables. At September 30 and December 31, 1998, the Company had not sold
any receivables.
9
<PAGE>
4. COMMITMENTS AND CONTINGENCIES
The Company anticipates divesting itself of its generation assets, through
the power station exchange with FirstEnergy in December 1999 and the sale to
Orion in the second quarter of 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 $35 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. 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 described
below, plus the decommissioning costs to be collected through the CTC, as
approved by the PUC. The Company expects BV Unit 1, BV Unit 2 and Perry Unit 1
will be decommissioned 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, would be $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
September 30, 1999, totaled approximately $69.8 million.
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 $9.7
billion. The maximum available private primary insurance of $200 million has
been purchased by the Company. Additional protection of $9.5 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 $7.9 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 outage of a
nuclear unit. Subject to the policy deductible, terms and limit, the coverage
provides for a
10
<PAGE>
weekly indemnity of the estimated incremental costs during a period of
approximately three years, starting 12 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 $2.9
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. Based on its current ownership interest in BV Unit 1, 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.
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.
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. Duquesne has elected not to participate in further
litigation regarding this matter. Pursuant to the power station exchange,
FirstEnergy will assume responsibility for disposal of the spent fuel.
11
<PAGE>
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 September 30, 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 September 30, 1999, the Company's share
of these guarantees was $4.5 million. These guarantees expire in January 2000.
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 concerning air
and water quality and other environmental matters. With respect to its electric
utility operations and non-water related expanded business lines, the Company
believes it is in current compliance with all material applicable environmental
regulations.
On November 3, 1999, the Environmental Protection Agency and the Department
of Justice filed suit against seven electric utility companies, including
FirstEnergy. The suit alleges that the companies made illegal modifications to
certain power plants, including Sammis, which is operated by FirstEnergy.
Although not a party to the suit, Duquesne is currently a partial owner of
Sammis Unit 7 (one of the interests to be acquired by FirstEnergy in the power
station exchange). The ultimate outcome of this suit, and any potential impact
it may have on Duquesne, cannot be determined at this time.
With respect to Federal water regulations, AquaSource recently met the
water quality reporting requirement under the Safe Drinking Water Act by timely
providing reports to all of its customers. In connection with its acquisition
strategy, AquaSource is aware of various compliance issues at its water and
wastewater facilities, and is communicating and working closely with the
appropriate regulators to correct those issues in a timely manner. The Company
does not believe that any of these compliance issues will have a material effect
on its financial position, results of operations or cash flows.
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.
12
<PAGE>
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
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 the three and
nine months ended September 30, 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 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:
13
<PAGE>
Business Segments for the Three Months Ended
<TABLE>
<CAPTION>
September 30, 1999 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------
Electricity Electricity All Elimina-
Delivery Generation CTC Other tions Consolidated
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 95,848 $ 129,742 $ 107,840 $ 65,868 $ (1,053) $ 398,245
Operating expenses 41,812 139,656 4,745 70,853 (3,145) 253,921
Depreciation and
amortization expense 7,830 2,466 46,075 8,715 -- 65,086
- ------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 46,206 (12,380) 57,020 (13,700) 2,092 79,238
Other income (loss) 512 942 -- 40,525 (5,298) 36,681
Interest and other charges 9,065 11,772 11,908 10,399 (2,618) 40,526
- ------------------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 37,653 (23,210) 45,112 16,426 (588) 75,393
Income taxes 13,660 (11,631) 18,721 5,426 -- 26,176
- ------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 23,993 $ (11,579) $ 26,391 $ 11,000 $ (588) $ 49,217
==============================================================================================================================
Assets $ 1,297,693 $ 561,111 $ 1,977,305 $ 1,460,996 $ -- $ 5,297,105
==============================================================================================================================
Capital expenditures $ 10,446 $ 6,748 $ -- $ 14,219 $ -- $ 31,413
==============================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
September 30, 1998 (Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------
Electricity Electricity All Elimina-
Delivery Generation Other tions Consolidated
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 89,250 $ 237,724 $ 30,679 $ (2,955) $ 354,698
Operating expenses 41,195 158,302 26,314 (3,427) 222,384
Depreciation and
amortization expense 14,265 21,347 2,032 -- 37,644
- ---------------------------------------------------------------------------------------------------------------------
Operating income 33,790 58,075 2,333 472 94,670
Other income (loss) 1,310 2,306 17,928 (1,399) 20,145
Interest and other charges 9,332 14,505 4,128 (356) 27,609
- ---------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 25,768 45,876 16,133 (571) 87,206
Income taxes 10,063 18,103 (3,029) -- 25,137
- ---------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 15,705 $ 27,773 $ 19,162 $ (571) $ 62,069
=====================================================================================================================
Assets (1) $ 1,314,266 $ 2,711,533 $ 1,221,764 $ -- $ 5,247,563
=====================================================================================================================
Capital expenditures $ 21,509 $ 12,920 $ 15,821 $ -- $ 50,250
=====================================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1998.
14
<PAGE>
Business Segments for the Nine Months Ended
<TABLE>
<CAPTION>
September 30, 1999 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------------
Electricity Electricity All Elimina-
Delivery Generation CTC Other tions Consolidated
-------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 259,246 $ 339,155 $ 290,244 $ 173,058 $ (9,802) $ 1,051,901
Operating expenses 122,653 359,007 12,771 179,626 (15,553) 658,504
Depreciation and
amortization expense 43,076 12,953 101,138 18,805 -- 175,972
- ------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 93,517 (32,805) 176,335 (25,373) 5,751 217,425
Other income (loss) 3,107 6,407 -- 112,489 (12,988) 109,015
Interest and other charges 27,108 35,294 35,623 22,681 (5,462) 115,244
- ------------------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 69,516 (61,692) 140,712 64,435 (1,775) 211,196
Income taxes 25,693 (29,569) 58,396 17,388 -- 71,908
- ------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 43,823 $ (32,123) $ 82,316 $ 47,047 $ (1,775) $ 139,288
==============================================================================================================================
Assets $ 1,297,693 $ 561,111 $ 1,977,305 $ 1,460,996 $ -- $ 5,297,105
==============================================================================================================================
Capital expenditures $ 39,090 $ 18,864 $ -- $ 44,814 $ -- $ 102,768
==============================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
September 30, 1998 (Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------------
Electricity Electricity All Elimina-
Delivery Generation Other tions Consolidated
-----------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 244,547 $ 654,620 $ 66,970 $ (9,154) $ 956,983
Operating expenses 116,846 417,503 60,500 (11,780) 583,069
Depreciation and
amortization expense 39,122 109,171 4,185 -- 152,478
- ---------------------------------------------------------------------------------------------------------------------
Operating income 88,579 127,946 2,285 2,626 221,436
Other income (loss) 4,153 7,169 73,798 (5,428) 79,692
Interest and other charges 28,364 44,086 10,528 (438) 82,540
- ---------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 64,368 91,029 65,555 (2,364) 218,588
Income taxes 26,737 37,471 6,977 -- 71,185
- ---------------------------------------------------------------------------------------------------------------------
Net income (loss)
before extraordinary item $ 37,631 $ 53,558 $ 58,578 $ (2,364) $ 147,403
Extraordinary item, net of tax -- (82,548) -- -- (82,548)
- ---------------------------------------------------------------------------------------------------------------------
Net income (loss)
after extraordinary item $ 37,631 $ (28,990) $ 58,578 $ (2,364) $ 64,855
=====================================================================================================================
Assets (1) $ 1,314,266 $ 2,711,533 $ 1,221,764 $ -- $ 5,247,563
=====================================================================================================================
Capital expenditures $ 40,620 $ 28,430 $ 49,905 $ -- $ 118,955
=====================================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1998.
15
<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 15 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 largest subsidiary, Duquesne, is an electric utility engaged
in the generation, transmission, distribution and sale of electric energy. 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 also
include a water resource management company that acquires, develops and manages
water and wastewater utilities, energy facility development and operation,
domestic and international independent power production, the production and
distribution of landfill gas, propane and synthetic fuels, investments in
communications systems and electronic commerce, and long-term investments. DQE
Capital provides financing for the expanded business lines.
The Company plans to divest itself of its generation assets through the
pending exchange of certain power station assets with FirstEnergy Corporation
(FirstEnergy) and the pending sale of generation assets to Orion Power Holdings,
Inc. (Orion). Final agreements governing the sale to Orion must be approved by
various regulatory agencies, including the Pennsylvania Public Utility
Commission (PUC). The Company currently expects these transactions to close in
December 1999 and the second quarter of 2000, respectively. (See "Rate Matters"
on page 25.)
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 25.) 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 more than
300,000 water and wastewater customer connections and commercial bottled water
customers in 13 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 25.)
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.
16
<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
25), 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).
Accordingly, 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). 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), and have been reclassified accordingly. 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. 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 25.)
Results of Operations
- --------------------------------------------------------------------------------
Overall Performance
In the second quarter of 1998, the PUC issued an order related to the
Company's plan to recover its transition costs from electric utility customers.
As a result of the order, the Company recorded an extraordinary charge against
earnings of $82.5 million, or $1.06 per share. The following discussion of
results of operations excludes the impact of such charge.
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. Basic earnings per share decreased 20 percent in the third quarter of
1999, to $0.64. This decline resulted from a 21 percent decrease in earnings
available for common stock, partially offset by a 2.4 million share reduction in
average shares of common stock outstanding. The net income contribution from
Duquesne decreased $11.2 million. During the latter part of July 1999, a
prolonged, wide-spread heat wave in the eastern half of the United States,
combined with regional capacity constraints, resulted in unexpected net
purchased power costs of approximately $24 million. As a result of these
unprecedented purchased power prices, Duquesne's net revenues did not increase
enough to offset the anticipated increased depreciation and amortization expense
due to amortization of the CTC. The net income contribution from the Company's
expanded business lines decreased by $2.0 million, as a result of decreased
investment income due to the previous disposition of certain of the Company's
investments, and less income from the Company's landfill gas investments.
Partially offsetting these decreases were the Company's continuing water
aggregation strategy and a gain on the sale of certain real estate investments.
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
Basic earnings per share decreased 4.7 percent for the nine months ended
September 30, 1999, to $1.81. This decline resulted from a 6.3 percent decrease
in earnings available for common stock slightly offset by a 1.6 million share
reduction in average shares of common stock outstanding. Duquesne's net income
contribution decreased $10.8 million, while the Company's expanded business
lines contributed $1.5 million more to net income in 1999 than in 1998.
Duquesne's earnings were impacted by the unprecedented July purchased power
prices. The expanded business line results reflect an increased level of gains
from investment dispositions.
17
<PAGE>
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
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 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 borrowings, 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. (Additional information regarding the Company's business segments is
set forth in "Business Segments and Related Information," Note 5 to the
condensed consolidated financial statements on page 13.)
In accordance with Accounting Principles Board Opinion No. 30, Reporting
the Results of Operations - Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions (APB 30), a segment of a company's business is reported as
discontinued operations if a formal disposition plan has been approved and the
disposition is expected within 12 months. The Company believes that its
electricity generation business segment will meet the criteria of APB 30 for
discontinued operations upon completion of the power station exchange with
FirstEnergy. The allocation of certain costs to the electricity generation
business segment under APB 30 will differ from those allocations presented in
Note 5, Business Segments and Related Information.
Electricity Delivery Business Segment
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. The electricity delivery business segment contributed $24.0 million to
net income in the third quarter of 1999 compared to $15.7 million in the third
quarter of 1998, an increase of 52.9 percent. Operating revenues for this
business segment are primarily derived from the Company's delivery of
electricity and services provided to electric generation suppliers.
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 $6.6 million or 7.4 percent in the third
quarter of 1999 due to an increase in electricity usage by customers of 5.5
percent and due to revenues from services provided to electric generation
suppliers. The increased sales are driven primarily by the warm weather
experienced in Duquesne's service territory during July. The following table
sets forth KWH delivered to electric utility customers during the third quarter:
18
<PAGE>
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
KWH Delivered
-----------------------------------------------
(In Millions)
-----------------------------------------------
Three Months Ended September 30, 1999 1998 Change
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 1,104.5 1,018.5 8.4%
Commercial 1,720.8 1,664.8 3.4%
Industrial 893.3 842.8 6.0%
- --------------------------------------------------------------------------------
Sales to Electric Utility Customers 3,718.6 3,526.1 5.5%
================================================================================================
</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; allocated administrative expenses; and non-income taxes, such as
property and payroll taxes. Operating expenses increased $0.6 million or 1.5
percent in the third quarter of 1999.
Depreciation and amortization expense decreased $6.4 million due to less
amortization of a regulatory tax receivable and due to an adjustment recorded in
the third quarter related to new depreciation rates resulting from a life
service study effective January 1, 1999.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the third quarter of
1999, there was $0.3 million or 2.9 percent less in interest and other charges
compared to the third 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.
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
The electricity delivery business segment contributed $43.8 million to net
income in the first nine months of 1999 compared to $37.6 million in the first
nine months of 1998, an increase of 16.5 percent.
Operating revenues increased by $14.7 million or 6.0 percent in the first
nine months of 1999 due to a 3.2 percent increase in electricity usage by
customers and to services provided to electric generation suppliers. Sales to
residential and commercial customers increased due to weather conditions, while
industrial sales were relatively consistent between periods. The following table
sets forth KWH delivered to electric utility customers during the first nine
months of 1999 and 1998:
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------
KWH Delivered
-----------------------------------------------
(In Millions)
-----------------------------------------------
Nine Months Ended September 30, 1999 1998 Change
- ------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 2,772.9 2,617.8 5.9%
Commercial 4,618.5 4,478.7 3.1%
Industrial 2,617.1 2,597.1 0.8%
- ---------------------------------------------------------------------------------
Sales to Electric Utility Customers 10,008.5 9,693.6 3.2%
===================================================================================================
</TABLE>
Operating expenses for the electricity delivery business segment increased
$5.8 million or 5.0 percent in the first nine months of 1999, primarily due to
the timing of non-recurring charges related to meter reading in both 1999 and
1998.
Depreciation and amortization expense increased $4.0 million or 10.1
percent in the first nine months of 1999 due to additions to the plant and
equipment.
Other income is primarily comprised of interest and dividend income. A
decrease of $1.0 million or 25.2 percent was the result of lower interest income
from a smaller amount of cash available for investing in the first nine months
of 1999.
19
<PAGE>
In the first nine months of 1999, there was $1.3 million or 4.4 percent
less in interest and other charges compared to the first nine months 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
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. In the third quarter of 1999, the electricity generation and CTC business
segments reported net income of $14.8 million compared to $27.8 million for the
third quarter of 1998, a decrease of 46.8 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
1999, up to 66 percent of the Company's electric utility customers are eligible
to participate in customer choice. As of September 30, 1999, approximately 17
percent of the Company's customers are purchasing electricity from alternative
generation suppliers.
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 through May 29, 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 25.)
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 25.)
Operating revenues decreased by $0.1 million or 0.1 percent in the third
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 offset by an 80.1 percent increase in energy supplied
to other utilities. As of September 30, 1999, 17.0 percent of residential non-
coincident peak load, 31.0 percent of commercial load, and 9.8 percent of
industrial load have selected alternative generation suppliers. The increase in
energy supplied to other utilities is due to increased capacity available to
sell as a result of participation in customer choice and improved generating
station availability. The following table sets forth KWH supplied for customers
who have not chosen an alternative generation supplier and sales to other
utilities:
20
<PAGE>
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
KWH Supplied
-----------------------------------------------------
(In Millions)
Three Months Ended September 30, 1999 1998 Change
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 911.9 956.5 (4.7)%
Commercial 1,241.7 1,575.4 (21.2)%
Industrial 866.9 827.0 4.8 %
- ---------------------------------------------------------------------------------
Sales to Electric Utility Customers 3,020.5 3,358.9 (10.1)%
- ---------------------------------------------------------------------------------
Sales to Other Utilities 919.1 510.2 80.1 %
- ---------------------------------------------------------------------------------
Total Sales 3,939.6 3,869.1 1.8 %
=====================================================================================================
</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; allocated 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 five months of 1998.
Operating and maintenance expenses decreased $13.9 million or 8.8 percent
in the third quarter of 1999 as a result of the reclassification of the interest
component of Beaver Valley lease costs to interest expense and decreased
maintenance costs.
In the third quarter of 1999, fuel and purchased power expense decreased by
$1.0 million or 1.2 percent compared to the third quarter of 1998. During the
third quarter of 1998, Duquesne's BV Units 1 and 2 were undergoing outages and
the purchased power volumes were unusually large. The anticipated reduction in
energy costs in 1999 did not occur due to power market conditions during late
July. While purchased power volumes decreased substantially, unprecedented
prices prevented a decline in costs.
Depreciation and amortization expense includes the depreciation of the
power stations' plant and equipment, accrued nuclear decommissioning costs and
the amortization of transition costs. An increase of $27.2 million or 127.4
percent in the third quarter of 1999 was primarily the result of amortization of
transition costs. In 1999, the Company began to recover transition costs through
an interim CTC. The total transition costs to be recovered was $1.49 billion,
net of tax, over a seven-year period, as may be adjusted to account for the
proceeds of the generation asset auction (see "Rate Matters" on page 25). The
Company records amortization expense for transition costs reflected on the
consolidated balance sheet over the same period as the CTC revenues are being
recognized.
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the third quarter of 1999
there was a $9.2 million or 63.2 percent increase in interest and other charges
compared third quarter of 1998. The increase reflected the reclassification of
the interest component of Beaver Valley lease costs to interest expense,
partially offset by refinancing of long-term debt at lower interest rates and
the maturity of approximately $75 million of long-term debt during 1998. (See
"Financing" discussion on page 23.)
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
In the first nine months of 1999, the electricity generation and CTC business
segments reported net income of $50.2 million compared to $53.6 million for the
first nine months of 1998, a decrease of 6.3 percent.
Operating revenues decreased by $25.2 million or 3.9 percent in the first
nine months 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 and the 1998 recognition of $23.3 million of revenues related to
deferred energy costs. Partially offsetting this decrease was a 91.7 percent
21
<PAGE>
increase in energy supplied to other utilities in the first nine months of 1999,
due to the Company's decision to make 600 MW available during the first six
months of 1999 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 and sales to other utilities:
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
KWH Supplied
-----------------------------------------------------
(In Millions)
Nine Months Ended September 30, 1999 1998 Change
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 2,368.6 2,470.1 (4.1)%
Commercial 3,381.1 4,241.0 (20.3)%
Industrial 2,527.0 2,555.9 (1.1)%
- ---------------------------------------------------------------------------------
Sales to Electric Utility Customers 8,276.7 9,267.0 (10.7)%
- ---------------------------------------------------------------------------------
Sales to Other Utilities 2,369.6 1,236.1 91.7 %
- ---------------------------------------------------------------------------------
Total Sales 10,646.3 10,503.1 1.4 %
=====================================================================================================
</TABLE>
Operating expenses decreased $45.7 million or 11.0 percent in the first
nine months of 1999 as a result of decreased energy costs and the
reclassification of the interest component of Beaver Valley lease costs to
interest expense.
In the first nine months of 1999, fuel and purchased power expense
decreased by $35.5 million or 16.4 percent compared to the first nine months of
1998, primarily as a result of decreased purchased power volumes and a favorable
power supply mix.
An increase in depreciation and amortization expense of $4.9 million or 4.5
percent in the first nine months of 1999 was the result of the amortization of
transition costs. The total of transition costs to be recovered was $1.49
billion, net of tax, over a seven-year period, as may be adjusted to account for
the proceeds of the generation asset auction (see "Rate Matters" on page 25).
The Company records amortization expense for transition costs reflected on the
consolidated balance sheet over the same period as the CTC revenues are being
recognized.
In the first nine months of 1999 there was a $26.8 million or 60.9 percent
increase in interest and other charges compared to the first nine months of
1998. The increase reflected the reclassification of the interest component of
Beaver Valley lease costs to interest expense, partially offset by the
refinancing of long-term debt at lower interest rates and the maturity of
approximately $75 million of long-term debt during 1998.
All Other
Comparison of Three Months Ended September 30, 1999, and September 30,
1998. The all other category contributed $11.0 million to net income in the
third quarter of 1999 compared to $19.2 million in the third quarter of 1998, a
decrease of 42.6 percent, as a result of decreased investment income due to the
previous disposition of certain of the Company's investments, and less income
from certain of the Company's alternative energy investments. Partially
offsetting these decreases were income from continuing water aggregation
strategy and gains on the sale of certain real estate and other investments.
Operating revenues primarily include revenues from operating activities of
the expanded business lines. Operating revenues increased in the third quarter
of 1999 by $35.2 million to more than double the level in the third quarter of
1998. This increase was primarily the result of increased revenues from
AquaSource and Control Solutions (a subsidiary of DE).
22
<PAGE>
Operating expenses include expenses from operating activities of the
expanded business lines and Duquesne investments. In the third quarter of 1999,
operating expenses increased $44.5 million to more than double the level in the
third 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 third quarter of 1999, depreciation and amortization
expense increased by $6.7 million, primarily due to the depreciation and
amortization associated with the acquisitions of water and water-related
companies by AquaSource throughout 1998 and 1999.
Other income primarily includes long-term investment income, gains from
asset dispositions, and interest and dividend income related to the expanded
business lines and Duquesne investments. Other income in the third quarter of
1999 was $22.6 million or 126.0 percent higher than in the third quarter of
1998. Approximately $15 million of this increase was the result of the gains
recognized on the disposition of certain of the Company's real estate and other
investments.
Interest and other charges are made up of interest on long-term debt, other
interest, intercompany interest on borrowings, and preferred stock dividends of
the expanded business lines, and Duquesne investments. An increase of $6.3
million or 151.9 percent in the third quarter of 1999 was the result of higher
expense associated with higher average borrowings outstanding; approximately $3
million of the increase was intercompany interest.
Comparison of Nine Months Ended September 30, 1999, and September 30, 1998.
The all other category contributed $47.0 million to net income in the first nine
months of 1999 compared to $58.6 million in the first nine months of 1998, a
decrease of 19.7 percent.
Operating revenues increased in the first nine months of 1999 by $106.1
million or 158.4% in the first nine months of 1998. This increase was primarily
the result of increased revenues from AquaSource and Control Solutions.
In the first nine months of 1999, operating expenses increased $119.1
million or almost triple the level in the first nine months of 1998. The growth
of the expanded business lines' start-up and developmental activities and
acquisitions accounted for most of the increase.
In the first nine months of 1999, depreciation and amortization expense
increased by $14.6 million, primarily due to the depreciation and amortization
associated with the acquisitions of water and water-related companies by
AquaSource throughout 1998 and 1999.
Other income in the first nine months of 1999 was $38.7 million or 52.4
percent higher than in the first nine months of 1998. This increase was the
result of new investments made by the expanded business lines throughout 1998
and 1999 and gains recognized on the disposition of certain of the Company's
real estate and affordable housing investments.
An increase in interest and other charges of $12.2 million or 115.4 percent
in the first nine months of 1999 was the result of higher long-term debt expense
associated with higher average borrowings outstanding. In addition,
approximately $6 million of the increase was intercompany interest.
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 sale of
generation assets to Orion. To the extent that acquisition and long-term
investment opportunities prior to the generation divestiture exceed current
expectations, the Company may explore various financing alternatives. At
September 30, 1999, the Company was in compliance with all of its debt
covenants.
23
<PAGE>
Mortgage bonds in the amount of $75 million matured in July 1999, and were
retired using available cash and short term borrowings.
As discussed previously, the Company has entered into an agreement to sell
its generation assets to Orion for approximately $1.71 billion. The Company
anticipates using the net proceeds from this sale (currently estimated to be
$1.1 billion) to recapitalize the Company and for general corporate purposes.
In connection with the power station exchange with FirstEnergy, the Company
anticipates terminating the BV Unit 2 lease in the fourth quarter of 1999; the
lease liability recorded on the consolidated balance sheet would be eliminated,
however the underlying collateralized lease bonds ($370.7 million at September
30, 1999, and anticipated to be $359.2 million upon lease termination) would
become obligations of the Company and be recorded on the consolidated balance
sheet as debt. 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 27.)
In connection with customer choice, customer revenues from Duquesne's
operations will be reduced by an amount equal to the generation rate applicable
to those customers choosing alternative generation suppliers (currently
approximately 17 percent of customers). This reduction is expected to be offset
by reduced cash requirements associated with supplying energy. A further impact
is anticipated when the purchased power agreement with Orion takes effect, and
all customers will be buying generation either directly from alternative
suppliers or indirectly from Orion. An additional impact on customer revenues
is expected to occur when the CTC has been fully collected, which is currently
expected to occur in 2001 for most major rate classes. 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 timing of the receipt of sale proceeds. (See
"Restructuring Plan" on page 26.)
As of September 30, 1999, 436,902 shares of Preferred Stock, Series A
(Convertible), $100 liquidation preference per share (DQE Preferred Stock), were
outstanding, including 51,060 shares issued in the third 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
or replacing the accounts receivable sale arrangement upon its expiration,
recently extended to February 2000. At September 30, 1999, the Company had sold
$50 million of receivables.
In September 1999, DQE Capital issued $100 million of 8 3/8% medium term
notes, due in September 2039 and unconditionally guaranteed by DQE. DQE Capital
maintains a $250 million revolving credit agreement unconditionally guaranteed
by DQE, with a 364 day term, convertible at DQE Capital's option into a term
loan facility for an additional year for any amounts then outstanding upon
expiration of the revolving credit period. As guarantor, DQE is subject to
financial covenants requiring certain cash coverage and debt to capital ratios.
At September 30, 1999, $63 million was outstanding. Interest rates can, in
accordance with the option selected at the time of the borrowing, be based on
prime or Eurodollar rates. DQE Capital initiated a $250 million commercial paper
program during the fourth quarter of 1999, also unconditionally guaranteed by
DQE.
The Company also maintains a $225 million extendible revolving credit
facility which expires in September 2000. At September 30, 1999, no amounts
were outstanding. 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. Facility fees are based on the amount of the commitments. The
facility contains a two-year repayment period for any amounts outstanding at the
expiration of the revolving
24
<PAGE>
credit period. The Company also has an aggregate of $150 million in bank term
loans outstanding at September 30, 1999, with $65 million maturing in 2000 and
$85 million maturing in 2001.
At September 30, 1999, the Company had $66 million of commercial paper
borrowings outstanding. During the third quarter the maximum amount of such
borrowings was $126 million, the average daily borrowings was $87.2 million and
the weighted average daily interest rate was 5.34 percent.
The Company repurchased shares of its common stock on the open market
during the third quarter of 1999.
Investments and Acquisitions
- --------------------------------------------------------------------------------
The Company has historically made long-term investments in leases,
affordable housing, gas reserves and energy solutions. The Company continues to
restructure its investment portfolio, and is currently divesting significant
portions of its portfolio of affordable housing investments. Investing
activities during the first nine months of 1999 and 1998 totaled approximately
$26 million and $51 million, respectively.
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 $35 million for water utility construction.
During the first nine months of 1999, the Company has spent approximately $103
million on capital expenditures, which consist of approximately $58 million at
Duquesne, $26 million at AquaSource and the remaining $19 million on other.
In the first nine months of 1999 the Company issued 86,337 shares of DQE
Preferred Stock, as part of a total investment of approximately $151 million in
water companies.
During the third quarter of 1999, the Company invested approximately $7.8
million to acquire seven propane distribution businesses in Texas and
Pennsylvania. The Company expects to implement an aggregation strategy similar
to that used in acquiring the water-related companies to develop this expanded
business line.
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 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
25
<PAGE>
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
Currently 66 percent of customers are eligible to participate in customer
choice (including customers covered by the pilot program); all customers will
have customer choice in January 2000. As of September 30, 1999, approximately 17
percent of the Company's customers had chosen alternative generation suppliers,
representing approximately 22 percent of the Company's non-coincident peak load.
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 "jumpstart" competition, Duquesne had made 600 megawatts
(MW) of power available through the first six months of 1999 to licensed
electric generation suppliers, to be used to supply electricity to Duquesne's
customers who had chosen alternative generation suppliers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, was
originally imposed on the transmission and distribution charges of Pennsylvania
electric utility companies under the Customer Choice Act. As part of a
settlement regarding recovery of deferred fuel costs (discussed below), the
Company has agreed to extend this rate cap for an additional six months through
the end of 2001. 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 $1.49 billion, net of tax, of transition costs
was originally to be recovered over a seven-year period ending in 2005.
However, by applying proceeds of the generation asset auction (discussed below)
to reduce transition costs, the Company currently anticipates early termination
of the CTC collection period in 2001 for most major rate classes. 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, net
of tax balance of transition costs, as adjusted following the generation asset
auction.
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 appealed the PUC's denial of recovery to the Pennsylvania Commonwealth
Court. On October 26, 1999, the Company and the Pennsylvania Office of the
Consumer Advocate reached a settlement on this issue which would permit recovery
of the entire $42.7 million ($24.9 million, net of tax) in deferred fuel costs.
The PUC's decision on this settlement is pending.
Auction Plan. On December 18, 1998, the PUC approved Duquesne's auction
plan, including a purchased power agreement covering Duquesne's obligations for
its provider of last resort service, as well as an agreement in principle to
exchange certain generation assets with FirstEnergy. On September 24, 1999,
Duquesne and the winning auction bidder, Orion, entered into definitive
26
<PAGE>
agreements pursuant to which Orion will purchase Duquesne's wholly owned
Cheswick, Elrama, Phillips and Brunot Island power stations, and the stations to
be received from FirstEnergy in the power station exchange described below, for
approximately $1.71 billion. Under the purchased power agreement, Orion will
supply all of the electric energy requirements for Duquesne's customers who have
not chosen an alternative generation supplier (provider of last resort service).
This agreement, which expires upon Duquesne's final collection of the CTC,
effectively transfers to Orion all of the financial risks and rewards associated
with electricity supply. The purchase must be approved by various regulatory
agencies, including the PUC, the FERC, and the Federal Trade Commission.
Duquesne currently expects the sale to close in the second quarter of 2000.
Although Duquesne expects to apply the net auction proceeds to reduce transition
costs, until the divestiture is complete, Duquesne has been ordered to use an
interim CTC and price to compare for each rate class based on the methodology
approved in its pilot program (on average, approximately 2.9 cents per kilowatt
hour (KWH) for the CTC and approximately 3.8 cents per KWH for the price to
compare).
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three fossil-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company plans
to sell 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 the
fourth quarter of 1999. (See "Financing," discussion on page 23.) Pursuant to
the December 18, 1998, PUC order and subject to final approval, the proceeds
from the sale to Orion 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. Benefits of
this exchange include the resolution of all joint ownership issues, and other
ongoing risks and costs associated with the jointly-owned units. The Federal
Trade Commission approved the exchange on June 30, 1999. The PUC approved the
definitive exchange agreement on July 15, 1999, having found the exchange to be
in the public interest. On September 15, 1999, the FERC approved the exchange.
On September 30, 1999, the NRC approved the transfer of the BV Unit 1 and BV
Unit 2 operating licenses, as well as Duquesne's ownership interest in Perry, to
FirstEnergy. The Public Utilities Commission of Ohio approved the exchange
agreement on October 28, 1999. The power station exchange is expected to occur
in December 1999. (See "Legal Proceedings" on page 31.)
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. Trial was held from October 20 through 28,
1999. Post-trial pleadings were filed November 10, 1999, and closing arguments
are scheduled for November 23, 1999. The Company expects the judge's decision
prior to the scheduled closing of the power station exchange in December. (See
"Legal Proceedings" on page 31.)
In a letter dated February 24, 1999, the PUC informed the Company that the
merger application was deemed withdrawn and the docket was closed.
27
<PAGE>
Year 2000
- --------------------------------------------------------------------------------
The Company has taken aggressive and comprehensive steps to ensure a smooth
transition into the Year 2000. The transition to the Year 2000 became an issue
because 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. Since 1994, the Company has been planning for the Year 2000
with an aggressive strategy to identify information needs, replace or upgrade
equipment and coordinate resources to anticipate the new millennium. Based on
the success to date of the Year 2000 program, the Company fully expects normal
operations into the Year 2000 and beyond. The Company assembled a Year 2000
team, comprised of management representatives from all functional areas of the
Company. The goal of the Company's Year 2000 program is that all components and
services that in any material manner contribute to the operational reliability,
customer relations, safety, revenue, regulatory compliance and reputation of the
company be Year 2000 ready. Special emphasis has been focused on mission
critical systems that support the Company's ability to provide reliable services
to customers. The next priority has been on business critical systems that
support the day-to-day internal operations of the Company. The Year 2000 team
has focused on all three aspects of the Year 2000 issue: computer software and
hardware systems used to support day-to-day operations; embedded microprocessors
which are small electronic devices found in a wide range of equipment and
devices (such as plant components, substation equipment, elevators, and heating
and cooling systems); and 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.
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 inventory process involved reviewing existing
listings and subsequent verification through physical inspections and walk-
downs.
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.
Remediation, the third step in the process, addresses the activities
necessary to fix or replace those components that have Year 2000 issues that
will adversely affect the Company's operations. 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, the final step, 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.
As of June 30, 1999, Duquesne's mission critical systems that support the
generation of electricity as well as transmission and delivery of power to
customers are Year 2000 ready. As of September 30, 1999, Duquesne's business
critical systems are also Year 2000 ready.
For existing AquaSource facilities, inventory, assessment, remediation and
testing and implementation for mission critical systems were substantially
completed as of September 30, 1999. The Company's Year 2000 program is
routinely being incorporated into all new AquaSource acquisitions.
28
<PAGE>
Year 2000 readiness related to mission critical and business critical
systems at the Company's other expanded business lines was essentially complete
as of June 30, 1999.
Regulatory Review. Throughout the execution of its Year 2000 plan, the
Company has been providing and will continue to provide information on its
activities to regulatory agencies including the PUC, the Florida Public Service
Commission (PSC), the Indiana Utility Regulatory Commission (URC), the New
Jersey Board of Public Utilities (BPU), the Virginia State Corporation
Commission (SCC), the NRC and the North American Electric Reliability Council
(NERC). In addition to complying with all regulatory requirements (discussed
below), Duquesne has undergone third party audits of mission critical systems.
These independent assessments have confirmed that Duquesne's Year 2000 program
appropriately addresses Year 2000 issues related to its systems and equipment.
. Following eight months of formal proceedings by the PUC during which all
Pennsylvania utilities, including Duquesne, were required to demonstrate
that they were ready for the Year 2000, the PUC "investigation concludes
that the lights will stay on..." (Motion of PUC Chairman John M. Quain
on Docket No. I-00980076, March 31, 1999)
. Duquesne has complied with the NRC's compliance guidelines and has
verified with the NRC that all systems related to power production,
safety and security are ready for Year 2000. In addition, the NRC
conducted a Year 2000 audit of the nuclear power station safety and
operations systems in May 1999.
. NERC, which coordinates the interconnection of all utilities across the
country, has been requested by the DOE to conduct a detailed review of
the national electric power production and delivery infrastructure to
ensure a reliable power supply during the Year 2000 transition period.
The Company has provided monthly status reports to NERC. The Company's
June 30, 1999 report confirmed the Year 2000 readiness of all its
generation, transmission, and distribution systems. In addition, the
Company participated in the industry-wide NERC communication drills
conducted on April 9 and September 9, 1999. All of the Company's
communications exercised in these drills performed as expected.
. The Company's water and wastewater businesses also are being reviewed by
regulatory agencies in the various states where AquaSource has
facilities. The Company will continue to provide Year 2000 information
to these agencies as well as to any additional agencies in locations
where new facilities may be acquired.
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 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. In the event such a scenario occurs, it is not anticipated that the
Company would incur a material adverse impact on its financial position or the
consolidated results of operations.
In the normal course of business the Company has developed 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 and business critical processes. These contingency
plans incorporate numerous mitigation strategies, such as the most appropriate
allocation of staffing resources, the need for additional equipment and
facilities, and special operating procedures, including manual operations and
use of non-computer dependent back-up equipment and procedures.
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.
29
<PAGE>
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 DQE, have
been approximately $44 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 $9 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 $4 million of the amount expensed
has come from the $10 million 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 September 30, 1999 totaled approximately $69.8 million. The
amount funded into the trusts is based on estimated returns which, if not
achieved as projected, could require additional unanticipated funding
requirements.
------------------------------
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 sell 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; the loss of any significant customers; and
changes in business strategy or development plans.
30
<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 (Eastlake Litigation). 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 in the Eastlake Litigation pending the closing of the exchange.
Upon closing, the parties will enter into a settlement agreement dismissing the
Eastlake Litigation. (See "Power Station Exchange" discussion on page 27.)
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, 1998, 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, originally scheduled
to terminate on September 16, 1999, was extended by mutual agreement for the
duration of the trial. On March 25, 1999, the Company petitioned the Third
Circuit for rehearing; this petition was denied on June 14, 1999. On June 1,
1999, AYE informed the PUC that, given the procedural posture of the merger
litigation, it would seek a Federal court order enjoining the closing of the
power station exchange with FirstEnergy because, in its view, such a closing
would prevent the merger from qualifying for "pooling of interests" accounting.
31
<PAGE>
The Company's motion for summary judgment, originally filed December 18,
1998, was denied on October 19, 1999. 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. Trial was held from October 20 through 28, 1999. Post-trial pleadings
were filed November 10, 1999, and closing arguments are scheduled for November
23, 1999. The Company expects the judge's decision prior to the scheduled
closing of the power station exchange in December.
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 10.1 - Severance Agreement and Release between James D. Mitchell
and DQE.
EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividend Requirements.
EXHIBIT 27.1 - Financial Data Schedule
b. A report on Form 8-K was filed September 29, 1999, to report the execution
of agreements to sell Duquesne's power plants and provider of last resort
service. No financial statements were field with this report.
-----------------------------
32
<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 November 15, 1999 /s/ Gary L. Schwass
--------------------- --------------------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer
Date November 15, 1999 /s/ James E. Wilson
--------------------- -----------------------------------------
(Signature)
James E. Wilson
Controller
(Principal Accounting Officer)
33
<PAGE>
Exhibit 10.1
CONFIDENTIAL SEVERANCE AGREEMENT AND RELEASE
--------------------------------------------
This Confidential Severance Agreement and Release ("Agreement"), dated as
of August 23, 1999, is made between James D. Mitchell ("Employee"), the
undersigned employee, and DQE, Inc. ("the Company") for the purpose of forever
releasing the Company and all "Released Parties" as defined herein from any and
all possible liability to Employee. The parties, intending to be legally bound
hereby, enter into this Agreement as follows:
1. Employee has voluntarily elected to resign from employment with the
Company and its subsidiaries and affiliates and from all officer, board and
committee positions at the Company and its subsidiaries and affiliates,
including without limitation the positions set forth in Exhibit A, in exchange
for the benefits provided herein. The Company's employment records will reflect
that Employee's employment with the Company will end effective August 23, 1999
(the "Termination Date").
2. The Company, on its behalf, and on behalf of the Released Parties as
defined herein, has agreed to provide to Employee, and Employee has expressly
agreed to accept, the following, in full settlement, release and discharge of
all possible claims, known or unknown, which Employee might have or might have
claimed for any reason:
a. As soon as practicable after the Termination Date, Employee shall
receive a lump sum cash payment of his accrued vacation pay and the unpaid
amount of sold vacation time.
b. Employee shall be entitled to receive all benefits accrued by
him as of the Termination Date under all qualified and nonqualified
pension and 401(k)
<PAGE>
plans of the Company and its affiliates in such manner and at such time as
are provided under the terms of such plans.
c. On the next regularly scheduled payday following the later of
(i) the Termination Date or the (ii) the execution of this Agreement, the
Company will pay to Employee the first of twenty-four (24) semi-monthly
payments, less standard deductions and tax withholdings, the total of all
being an amount equal to twelve (12) months of base salary at Employee's
most recent rate of pay. By signing this Agreement, Employee acknowledges
that his resignation would not ordinarily entitle him to this separation
allowance, that this separation allowance is intended by the parties to
constitute separation pay and not actual continuation of salary and that
he is being awarded this allowance in consideration for signing this
Agreement.
d. Health, dental, long-term disability and accidental death and
dismemberment insurance benefits will be provided to Employee for the
length of his salary continuance of the same kind and at the same cost to
Employee as if still employed by the Company. If Employee becomes employed
during the period of time he is on salary continuance, he must notify the
Company by contacting in writing Victor A. Roque, Executive Vice President
and General Counsel of the Company at 411 Seventh Avenue - 16/th/ Floor,
Pittsburgh, Pennsylvania 15219. The benefits Employee is receiving from
the Company will then cease if he is eligible to receive from his new
employer benefits that the Company reasonably determines to be comparable
to the benefits Employee is receiving from the Company. Severance pay
will, however, continue to be paid.
2
<PAGE>
e. For the length of Employee's salary continuance, the Company
shall pay the cost, in an aggregate amount not to exceed $15,000, for
outplacement services to be provided to Employee by the Bizet Group.
f. As soon as practicable after the Termination Date, Employee will
receive a lump sum amount equal to the actuarial equivalent of the
additional benefits Employee would have accrued under the Retirement Plan,
the Supplemental Plan and the Pension Service Supplement Plan (PSSP) if
Employee had continued to be employed by the Company for the period of his
salary continuance under this Agreement and if his covered compensation
for such period had continued at as rate equal to his rate of covered
compensation for the twelve (12) full calendar months immediately
preceding the calendar month in which the Termination Date occurred (for
purposes of the foregoing, actuarial equivalence shall be determined in
accordance with the terms of the Retirement Plan, the Supplemental Plan
and the Pension Service Supplement Plan (PSSP), as applicable.
g. On July 22, 1997, Employee was granted a stock option (the "1997
Three-Year Option") in respect of an aggregate of 22,500 shares of the
Company's Common Stock pursuant to the 1997 three-year stock option
program under the terms of the Company's Long-Term Incentive Plan. In
1997, the first tranche of the 1997 Three-Year Option, in respect of 6,750
shares, was awarded to Employee by the Compensation Committee (the
"Committee") of the Company's Board of Directors. In July 1999, the
Committee awarded a second tranche of the 1997 Three-Year Option, in
respect of 6,750 shares. The third and final tranche,
3
<PAGE>
in respect of 9,000 shares, has not yet been awarded. The parties agree
that the second and third tranches of the 1997 Three-Year Option, as well
as the 1999 annual stock option in respect of an aggregate of 18,129
shares of Company Common Stock granted to Employee as of December 18, 1998
but not yet awarded, shall be forfeited by Employee as of the Termination
Date and shall not be exercisable by Employee or any other person on or
after the Termination Date. All other stock options granted to Employee
prior to the Termination Date under the terms of the Company's Long-Term
Incentive Plan and not heretofore exercised by Employee, as described in
Exhibit B hereto, shall, upon execution of this Agreement, remain
exercisable in accordance with their respective terms for one year after
the Termination Date at which time any unexercised portion of such options
shall expire and no longer be exercisable. Employee acknowledges and
agrees that his resignation would not ordinarily entitle him to the
continued ability to exercise such stock options and that he is being
given this ability in consideration for signing this Agreement.
h. For the length of his salary continuance, Employee shall have the
right, at the Company's expense, to continue to use the financial planning
and counseling services offered to Company executives by AYCO in
accordance with the guidelines established by the Company for such
services.
Except as expressly provided above, Employee waives any compensation,
benefits or rights that may have accrued in his capacity as an employee or
otherwise prior to the date of this Agreement and shall not be entitled to
receive any salary or benefits or participate in any compensation plans,
programs or arrangements of the Company and its affiliates after the
4
<PAGE>
Termination Date.
3. In consideration for the payments and benefits that Employee shall be
provided under this Agreement, Employee on behalf of himself and his dependents,
heirs, administrators, representatives, executors, successors, assigns and any
other person or entity, including any government agency seeking to assert a
claim on his behalf, hereby releases and forever discharges the Company and its
agents, servants, officers, directors, employees, parents, subsidiaries,
divisions, affiliates, predecessors, successors and assigns, all its employee
benefit plans and their administrators, trustees and other fiduciaries
(severally and collectively called "the Released Parties") from any and all
injuries, causes of actions, claims and demands whatsoever, and from all debts
and liabilities whatsoever, whether known or unknown, asserted or unasserted or
any that Employee or any person or entity acting for Employee now have or
hereafter may have against any of the Released Parties for any acts, practices
or events up to and including the effective date of this Agreement and the
continuing effects thereof, it being Employee's intention to effect a general
release of all claims. This release includes, without in any way limiting the
generality of the foregoing, any claims for attorneys' fees, any claims for
costs arising out of or relating to Employee's employment by the Company, and
any claims arising from any alleged violation by any of the Released Parties of
any federal, state or local statute, ordinance, rule, Executive Order or
regulation, including, but not limited to, Title VII of the Civil Rights Act of
1964, as amended, the Rehabilitation Act of 1973, the Pennsylvania Worker's
Compensation Act, the Americans with Disabilities Act, the Employee Retirement
Income Security Act of 1974, as amended, the Pennsylvania Human Relations Act,
the Civil Rights Act of 1991, the Americans with Disabilities Act and the Age
Discrimination in Employment Act, as amended; provided, however, that the
foregoing release shall not adversely
5
<PAGE>
affect Employee's COBRA rights or his rights to benefits under the Company's
401(k) Plan for Management Employees or its tax-qualified Retirement Plan and
Supplemental Retirement Plan.
4. Nothing in this Release is intended as a waiver of, or to interfere
with, Employee's right to file a charge under, or to testify, assist or
participate in any manner in any investigation, hearing or proceeding under any
statute over which the Equal Employment Opportunity Commission has jurisdiction;
provided, however, that Employee agrees that the waiver and release in Paragraph
3 bars him from receiving any personal financial recovery or other personal
remedy as a result of, or in connection with, any such charge, investigation,
hearing or proceeding.
5. The Company and Employee agree to refrain from making any disparaging
remarks about each other or otherwise acting or commenting in a way which
reflects adversely upon the Company's business or personnel or Employee's work
performance.
6. The terms of this Agreement shall remain strictly confidential.
Employee agrees that he will not, unless compelled by law or judicial process to
do so, disclose or discuss, directly or indirectly, its terms with anyone other
than his spouse, attorney, financial advisors, and prospective employers who
have specifically requested a copy hereof.
7. Notwithstanding the foregoing, all of the confidentiality, non-
competition and other obligations of Employee under that certain Employee Non-
Competition and Confidentiality Agreement between Employee and the Company dated
December 13, 1996 (the "Non-Competition Agreement"), which is incorporated
herein by reference, shall remain in full force and effect as set forth in the
Non-Competition Agreement, but the provisions of the Non-Competition Agreement
regarding severance pay shall be deemed terminated and of no force or effect.
Without limiting the scope of his obligations under the Non-Competition
Agreement,
6
<PAGE>
Employee acknowledges and agrees that the Company's confidential and proprietary
information includes, but is not limited to, all proprietary information and
trade secrets of the Company and its affiliates, such as all information
disclosed to Employee or known by him about (1) any matters relating to the
participation of the Company and/or an affiliate in certain lease transactions
wherein the Company and/or an affiliate acquired interests in certain portfolios
of equipment and a power facility (collectively the "Assets") and the ongoing
administration of such property interests including, without limitation, any
agreements or arrangements relating to the sale or release of any of the Assets;
(2) any agreements or arrangements between the Company and/or an affiliate and
Computer Leasing Inc. or any affiliate thereof including, without limitation,
any remarketing arrangements and any matters relating to the acquisition by the
Company and/or an affiliate of beneficial ownership of certain equipment trusts
that participated in the leasehold transactions referenced in (1) above; (3) any
matters relating to the participation of the Company and/or an affiliate in
domestic sale/leaseback transactions; (4) any matters relating to the
participation of the Company and/or an affiliate in certain offshore
lease/leaseback transactions; (5) any matters relating to the participation of
the Company and/or an affiliate in investments in landfill gas recovery
operations, as well as investments in limited partnership holding oil and gas
well investments; and (6) any matters relating to the participation of the
Company and/or an affiliate in investments in limited partnerships which invest
in affordable housing projects. It will be presumed that information supplied to
the Company and/or any affiliate from outside sources is confidential
information unless and until it is designated otherwise. Before making any
legally required disclosure of the Company's confidential or proprietary
information, Employee shall give the Company as much advance written notice as
possible.
7
<PAGE>
8. Employee agrees to deliver to the Company on or before the
Termination Date, all confidential or proprietary information, equipment,
documents, files, lists or other written, graphic or electronic records relating
to the Company's business, and all copies of such materials, which are or have
been in Employee's possession, or under his control.
9. In addition to any other remedy herein set forth or available to the
Company at law or in equity, in the event that Employee breaches or otherwise
fails to observe any and all of the covenants, agreements or duties herein set
forth above, as determined by a court or other body of competent jurisdiction,
the Company may, in its discretion, terminate this Agreement and shall
thereafter be released from performing under any other arrangement set forth
herein.
10. It is expressly understood and agreed that by entering into this
Agreement, the Company does not admit in any way that it has treated Employee
unlawfully or wrongfully. To the contrary, the Company expressly denies that it
has violated any of Employee rights or harmed him in any way.
11. Employee acknowledges that he has carefully read and fully
understands all the provisions and effects of this Agreement; that he has had
the opportunity to consult and thoroughly discuss all aspects of it with an
attorney; that he is voluntarily entering into this Agreement; and that neither
the Company nor its agents or attorneys made any representations or promises
concerning the terms or effects of this Agreement other than those contained
herein. Employee understands and acknowledges that he is bound by the terms of
the Non-Competition Agreement, the terms and conditions of which are
incorporated herein by reference.
12. Employee acknowledges that he has been given no less than twenty-one
days to consider this Agreement before executing it. Employee acknowledges that
he has been
8
<PAGE>
advised orally and by this writing to consult with an Attorney prior to signing
this Agreement. He further acknowledges that he may revoke this Agreement for a
period of seven (7) days from the date he executes it (the "Revocation Period"),
by notifying in writing, Victor A. Roque, Executive Vice President and General
Counsel of the Company at 411 Seventh Avenue, 16th Floor, Pittsburgh,
Pennsylvania 15219.
13. This Agreement shall be construed under the laws of the United States
and of the Commonwealth of Pennsylvania. The provisions hereof are severable,
except the provisions of Paragraph 3 are not severable from the consideration
provided in Paragraph 2. If any term, condition, clause or provision of this
Agreement shall be deemed unenforceable, it shall have no effect on the
enforceability of the other provisions hereof.
14. Nothing in this Agreement is intended to, nor shall it be deemed to,
constitute a waiver or release of any claim under the Age Discrimination in
Employment Act which arises after this Agreement is executed by the parties.
15. This Agreement and the Non-Competition Agreement (as modified in
Section 7 hereof) represent the entire agreement of the parties and any
amendments hereto shall not be effective unless they are in writing signed by
all parties and/or their duly authorized representatives. Without limiting the
generality of the foregoing, the Severance Agreement, dated as of April 4, 1997,
between Employee and the Company is deemed terminated in its entirety and shall
be of no further force or effect.
16. By signing this Agreement, Employee has made the following
representation: "I HAVE READ THIS AGREEMENT, AND HAVE HAD AN OPPORTUNITY TO
CONSULT WITH AN ATTORNEY OF MY CHOOSING ABOUT IT. I HAVE BEEN GIVEN THE
NECESSARY TIME TO CONSIDER ITS CONTENTS AND I
9
<PAGE>
FULLY UNDERSTAND ALL OF ITS TERMS. I AM SIGNING THIS AGREEMENT VOLUNTARILY."
This Agreement is made this 3/rd/ day of October, 1999 effective as of the
Termination Date.
/s/ Sharon A. Mitchell /s/ James D. Mitchell
- ----------------------------------- ----------------------------------
Witness James D. Mitchell
Attest: DQE, INC.
/s/ Amy M. Parker By: /s/ Victor A. Roque
- ----------------------------------- ----------------------------------
Victor A. Roque
/s/ Diane S. Eismont Executive Vice President
- ----------------------------------- and General Counsel
10
<PAGE>
EXHIBIT A
---------
BOARD POSITIONS:
Allegheny Development Corp. Duquesne Enterprises, Inc.
AquaSource, Inc. Duquesne Light Company
Bushton Company EnviroGas Recovery, Inc.
Diemen-Flevo Co. Monongahela Light and Power Co.
DQE Capital Corporation Montauk, Inc.
DQE Communications, Inc. Monticello Corporation
DQE Energy Services, Inc. Property Ventures, Ltd.
DQEnergy Partners, Inc.
OFFICER POSITIONS:
Company Name Title
------------ -----
Bushton Company President
DQE Capital Corporation Vice President
DQE, Inc. Vice President - Finance
Montauk, Inc. President
Waste Energy Technology, LLC Manager
<PAGE>
EXHIBIT B
OF CONFIDENTIAL
SEVERANCE
AGREEMENT
AND RELEASE
LONG TERM INCENTIVE PLAN SUMMARY
NAME: JAMES D. MITCHELL DATE: AUGUST 23, 1999
<TABLE>
<CAPTION>
Shares
Option Shares Exercise Shares Unexercisable
Date Awarded Price SAR's DEA's Exercisable Until 11/12/99
---- ------- ----- ----- ----- ----------- --------------
<S> <C> <C> <C> <C> <C> <C>
11/11/96 1015 $29.9375 YES YES 1015 0
05/08/97 2396 28.5625 YES YES 2396 0
07/22/97 3159 30.9375 NO YES 3159 0
11/10/97 2954 30.7188 YES YES 2954 0
11/10/97 2962 30.7188 YES YES 2962 0
01/26/98 11774 33.1250 YES NO 11774 0
08/04/98 3268 35.0625 YES YES 3268 0
11/11/98 1219 40.5625 YES YES 1219 0
11/11/98 2096 40.5625 YES YES 2096 0
02/08/99 1619 39.5938 YES YES 1619 0
05/11/99 682 41.0000 YES YES 0 682
05/11/99 3193 41.0000 YES YES 0 3193
</TABLE>
Memo: All options expire one (1) year after date of termination.
2
<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>
Year Ended December 31,
Nine Months Ended ----------------------------------------------------------------
September 30, 1999 1998 1997 1996 1995 1994
------------------ -------- -------- --------- --------- --------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 53,970 $ 81,076 $ 87,420 $ 88,478 $ 95,391 $101,027
Other interest 21,259 14,556 13,823 10,926 7,033 4,050
Portion of lease payments representing
an interest factor 35,755 44,146 44,208 44,357 44,386 44,839
Dividend requirement 12,173 15,612 21,649 14,385 7,374 9,355
----------- ------------ ---------- ---------- ----------- ---------
Total Fixed Charges $123,157 $155,390 $167,100 $158,146 $154,184 $159,271
----------- ------------ ---------- ---------- ----------- ---------
EARNINGS:
Income from continuing operations $139,288 $196,688 $199,101 $179,138 $170,563 $156,816
Income taxes 71,909* 100,982* 95,805* 87,388* 96,661* 92,973
Fixed Charges as above 123,157 155,390 167,100 158,146 154,184 159,271
----------- ------------ ---------- ---------- ----------- ---------
Total Earnings $334,354 $453,060 $462,006 $424,672 $421,408 $409,060
----------- ------------ ---------- ---------- ----------- ---------
RATIO OF EARNINGS TO FIXED CHARGES 2.71 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 $1.8 million for the nine months ended
September 30, 1999, has been excluded from the ratio.
*Earnings related to income taxes reflect a $3.0 million decrease for the nine
months ended September 30, 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 a 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 2.74 for the nine months ended September 30, 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> 9-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> SEP-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,424,216
<OTHER-PROPERTY-AND-INVEST> 1,063,948
<TOTAL-CURRENT-ASSETS> 419,312
<TOTAL-DEFERRED-CHARGES> 2,389,629
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 5,297,105
<COMMON> 73,119
<CAPITAL-SURPLUS-PAID-IN> 927,197
<RETAINED-EARNINGS> 921,156
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,452,081<F1>
4,500
268,523<F2>
<LONG-TERM-DEBT-NET> 1,367,072
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 134,100
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 145,435
0
<CAPITAL-LEASE-OBLIGATIONS> 16,937
<LEASES-CURRENT> 664
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,907,793
<TOT-CAPITALIZATION-AND-LIAB> 5,297,105
<GROSS-OPERATING-REVENUE> 1,051,901
<INCOME-TAX-EXPENSE> 71,908<F3>
<OTHER-OPERATING-EXPENSES> 834,476
<TOTAL-OPERATING-EXPENSES> 834,476
<OPERATING-INCOME-LOSS> 217,425
<OTHER-INCOME-NET> 109,015
<INCOME-BEFORE-INTEREST-EXPEN> 326,440
<TOTAL-INTEREST-EXPENSE> 115,244<F4>
<NET-INCOME> 139,288
1,153
<EARNINGS-AVAILABLE-FOR-COMM> 138,135
<COMMON-STOCK-DIVIDENDS> 86,650
<TOTAL-INTEREST-ON-BONDS> 55,878
<CASH-FLOW-OPERATIONS> 281,732
<EPS-BASIC> 1.81
<EPS-DILUTED> 1.77
<FN>
<F1>Includes $(469,391) of Treasury Stock at cost.
<F2>Includes $14,129 of Preference Stock.
<F3>Non-operating expense.
<F4>Includes $12,510 of Preferred and Preference stock dividends.
</FN>
</TABLE>
