<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 JUNE 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 75,619,996 SHARES OUTSTANDING AS OF JUNE 30,
1999 AND 75,303,247 SHARES OUTSTANDING AS OF JULY 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 Six Months Ended
June 30, June 30,
-------------------------------- ---------------------------------
1999 1998 1999 1998
------------ ------------- ------------ ------------
<S> <C> <C> <C> <C>
Operating Revenues
Sales of Electricity $ 254,167 $ 275,186 $ 520,922 $ 549,315
Other 72,662 28,324 131,962 52,970
------------ ------------ ------------ ------------
Total Operating Revenues 326,829 303,510 652,884 602,285
------------ ------------ ------------ ------------
Operating Expenses
Fuel and purchased power 49,669 71,575 96,580 131,108
Other operating 112,858 73,993 218,312 154,018
Maintenance 23,434 15,669 43,771 35,952
Depreciation and amortization 53,041 57,649 110,886 114,834
Taxes other than income taxes 23,246 19,675 45,920 39,607
------------ ------------ ------------ ------------
Total Operating Expenses 262,248 238,561 515,469 475,519
------------ ------------ ------------ ------------
OPERATING INCOME 64,581 64,949 137,415 126,766
------------ ------------ ------------ ------------
Other Income 37,357 28,129 73,106 59,547
------------ ------------ ------------ ------------
Interest and Other Charges 38,006 27,313 74,718 54,931
------------ ------------ ------------ ------------
INCOME BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM 63,932 65,765 135,803 131,382
------------ ------------ ------------ ------------
Income Taxes 22,326 25,561 45,732 46,048
------------ ------------ ------------ ------------
INCOME BEFORE EXTRAORDINARY ITEM 41,606 40,204 90,071 85,334
EXTRAORDINARY ITEM (NET OF TAX) -- (82,548) -- (82,548)
------------ ------------ ------------ ------------
NET INCOME (LOSS) AFTER EXTRAORDINARY ITEM $ 41,606 $ (42,344) $ 90,071 $ 2,786
============ ============ ============ ============
DIVIDENDS ON PREFERRED STOCK 336 -- 728 --
------------ ------------ ------------ ------------
EARNINGS AVAILABLE FOR
COMMON STOCK $ 41,270 $ (42,344) $ 89,343 $ 2,786
============ ============ ============ ============
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 75,776 77,720 76,493 77,702
============ ============ ============ ============
BASIC EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
BEFORE EXTRAORDINARY ITEM $ 0.55 $ 0.52 $ 1.17 $ 1.10
============ ============ ============ ============
EXTRAORDINARY ITEM $ -- $ (1.06) $ -- $ (1.06)
============ ============ ============ ============
AFTER EXTRAORDINARY ITEM $ 0.55 $ (0.54) $ 1.17 $ 0.04
============ ============ ============ ============
DILUTED EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
BEFORE EXTRAORDINARY ITEM $ 0.53 $ 0.51 $ 1.14 $ 1.08
============ ============ ============ ============
EXTRAORDINARY ITEM $ -- $ (1.04) $ -- $ (1.06)
============ ============ ============ ============
AFTER EXTRAORDINARY ITEM $ 0.53 $ (0.53) $ 1.14 $ 0.02
============ ============ ============ ============
DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $ 0.38 $ 0.36 $ 0.76 $ 0.72
============ ============ ============ ============
</TABLE>
See notes to condensed consolidated financial statements.
2
<PAGE>
DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
June 30, December 31,
ASSETS 1999 1998
------------------- -------------------
Current assets:
<S> <C> <C>
Cash and temporary cash investments $ 75,399 $ 108,790
Receivables 161,528 165,794
Other current assets, principally materials and supplies 123,590 100,168
---------------- ----------------
Total current assets 360,517 374,752
---------------- ----------------
Long-term investments 734,691 750,796
---------------- ----------------
Property, plant and equipment 4,987,197 4,884,138
Less: Accumulated depreciation and amortization (3,186,335) (3,167,328)
---------------- ----------------
Property, plant and equipment - net 1,800,862 1,716,810
---------------- ----------------
Other non-current assets:
Transition costs 2,040,473 2,132,980
Regulatory assets 62,153 64,568
Other 306,403 207,657
---------------- ----------------
Total other non-current assets 2,409,029 2,405,205
---------------- ----------------
TOTAL ASSETS $ 5,305,099 $ 5,247,563
================ ================
LIABILITIES AND CAPITALIZATION
Notes payable and current maturities $ 392,602 $ 100,822
---------------- ----------------
Other current liabilities 177,097 253,442
---------------- ----------------
Deferred income taxes - net 773,580 777,017
---------------- ----------------
Deferred income 150,347 156,579
---------------- ----------------
Beaver Valley lease liability 475,570 475,570
---------------- ----------------
Other non-current liabilities 352,804 371,653
---------------- ----------------
Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,271,213 1,364,879
---------------- ----------------
Preferred and preference stock of subsidiaries 228,940 228,282
---------------- ----------------
Preferred stock 38,802 35,274
---------------- ----------------
Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
issued - 109,679,154 shares) 994,226 994,996
Retained earnings 900,977 869,671
Less treasury stock (at cost) (33,996,458 and 32,305,726
shares, respectively) (456,703) (385,976)
Accumulated other comprehensive income 5,644 5,354
---------------- ----------------
Total common shareholders' equity 1,444,144 1,484,045
---------------- ----------------
Total capitalization 2,983,099 3,112,480
---------------- ----------------
TOTAL LIABILITIES AND CAPITALIZATION $ 5,305,099 $ 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>
Six Months Ended
June 30,
----------------------------------------
1999 1998
-------------- --------------
<S> <C> <C>
Cash Flows From Operating Activities
Operations $ 208,860 $ 277,992
Changes in working capital other than cash (45,457) (130,956)
Increase in ECR -- (19,219)
Other (41,380) 7,766
-------------- --------------
Net Cash Provided By Operating Activities 122,023 135,583
-------------- --------------
Cash Flows From Investing Activities
Acquisition of water companies (116,870) (29,203)
Capital expenditures (71,355) (68,705)
Long-term investments (17,064) (26,575)
Payment of funding obligations (14,477) --
Proceeds from the sale of investments 49,297 --
Other (8,023) 858
-------------- --------------
Net Cash Used in Investing Activities (178,492) (123,625)
-------------- --------------
Cash Flows From Financing Activities
Repurchase of common stock (70,727) --
Dividends on common stock (58,037) (55,953)
Reductions of long term obligations - net (9,097) (36,938)
Increase in notes payable 174,538 4,404
Other (13,599) (10,669)
-------------- --------------
Net Cash Used in Financing Activities 23,078 (99,156)
-------------- --------------
Net decrease in cash and temporary cash investments (33,391) (87,198)
Cash and temporary cash investments at beginning of period 108,790 356,412
-------------- --------------
Cash and temporary cash investments at end of period $ 75,399 $ 269,214
============== ==============
Non-Cash Investing and Financing Activities
Preferred stock issued in conjunction with long-term investments $ 3,528 $ 20,936
============== ==============
Capital lease obligations recorded $ 5,988 $ 4,941
============== ==============
Equity funding obligations recorded $ 1,232 $ --
============== ==============
</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 Six Months Ended
June 30, June 30,
1999 1998 1999 1998
---------- ----------- ----------- ------------
<S> <C> <C> <C> <C>
NET INCOME $ 41,606 $ (42,344) $ 90,071 $ 2,786
Other Comprehensive Income:
Unrealized holding gains (losses)
net of tax of $1,336, $(963),
$1,202 and $(745), respectively 1,885 (1,359) 1,695 (1,050)
Less: reclassification adjustment for
gains included in net income, net of
tax of $0, $0, $756 and $0, respectively -- -- (1,404) --
------------ ------------ ------------ ------------
Total Other Comprehensive Income 1,885 (1,359) 291 (1,050)
------------ ------------ ------------ ------------
Comprehensive Income $ 43,491 $ (43,703) $ 90,362 $ 1,736
============ ============ ============ =============
</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
supply of innovative fuels, investments in communications systems and electronic
commerce, and long-term investments. DQE Capital provides financing for the
expanded business lines.
The Pennsylvania Public Utility Commission (PUC) has approved the Company's
plan to divest itself of its generation assets through an auction (including an
auction of its provider of last resort service), and the pending exchange of
certain power station assets with FirstEnergy Corporation (FirstEnergy). Final
agreements governing these transactions must be approved by various regulatory
agencies. The Company currently expects these transactions to close in late 1999
or early 2000. (See "Rate Matters", Note 2, on page 7.)
All material intercompany balances and transactions have been eliminated in
the preparation of the condensed consolidated financial statements.
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 accounting presentations adopted during 1999.
These statements should be read with the financial statements and notes
included in the Annual Report on Form 10-K filed with the Securities and
Exchange Commission (SEC) for the year ended December 31, 1998. The results of
operations for the three and six months ended June 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.
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. Under-
recoveries from customers prior to May 29, 1998, were recorded on the
consolidated balance sheet as a regulatory asset. At June 30, 1999 and December
31, 1998, $42.7 million was receivable from customers. The Company expects to
recover this amount through the CTC. (See "Restructuring Plan" discussion, Note
2, on page 8.)
The Company's long-term investments include assets of nuclear
decommissioning trusts and marketable securities accounted for in accordance
with SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities. These investments are classified as available-for-sale and
6
<PAGE>
are stated at market value. The amounts of unrealized holding gains related to
marketable securities were $9.6 million ($5.6 million, net of tax) at June 30,
1999, and $8.9 million ($5.4 million, net of tax) at December 31, 1998.
2. RATE MATTERS
Competition and the Customer Choice Act
Under historical ratemaking practice, regulated electric utilities were
granted exclusive geographic franchises to sell electricity, in exchange for
making investments and incurring obligations to serve customers under the then-
existing regulatory framework. Through the ratemaking process, those prudently
incurred costs were recovered from customers, along with a return on the
investment. Additionally, certain operating costs were approved for deferral for
future recovery from customers (regulatory assets). As a result of this process,
utilities had assets recorded on their balance sheets at above-market costs,
thus creating transition and stranded costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1,
1997. The Customer Choice Act enables Pennsylvania's electric utility customers
to purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999).
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of June 30, 1999, approximately 14 percent of the Company's
customers had chosen alternative generation suppliers. Customers that have
chosen an electricity generation supplier other than the Company pay that
supplier for generation charges, and pay the Company the CTC (discussed below)
and charges for transmission and distribution. Customers that continue to buy
their generation from the Company pay for their service at current regulated
tariff rates divided into generation, transmission and distribution charges, and
the CTC. Under the Customer Choice Act, an electric distribution company, such
as Duquesne, remains a regulated utility and may only offer PUC-approved rates,
including generation rates. Also under the Customer Choice Act, electricity
delivery (including transmission, distribution and customer service) remains
regulated in substantially the same manner as under historical regulation.
In an effort to "jumpstart" competition, the Company 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, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as long as
transition costs are being recovered, with certain exceptions.
7
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Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the
Company should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered
was $1,485 million, net of tax, over a seven-year period beginning January 1,
1999, as may be adjusted to account for the proceeds of the generation asset
auction. In addition, the transition costs as reflected on the consolidated
balance sheet are being amortized over the same period that the CTC revenues are
being recognized. The Company is allowed to earn an 11 percent pre-tax return on
the unrecovered, 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 has appealed the PUC's denial of recovery to the Pennsylvania
Commonwealth Court. Based upon the Customer Choice Act, which mandates recovery
of all regulatory assets, and the PUC's specific authorization for the Company
to create a regulatory asset for these costs, the Company believes that it is
probable that these costs will be recovered through retail rates. In the event
that the Company does not prevail in its appeal, these costs would be written
off as a charge against income.
Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) is expected to be recovered from ratepayers through the CTC.
Until the divestiture is complete, Duquesne has been ordered to use an interim
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).
On December 18, 1998, the PUC approved Duquesne's auction plan, including
an auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick, Elrama, Phillips and
Brunot Island power stations, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process began in April
1999, with potential buyers identified by Duquesne being asked to submit non-
binding bids. Qualified applicants have been asked to submit binding, second-
round bids, due in September 1999. Final agreements governing the transactions
must be approved by various regulatory agencies, including the PUC, the FERC,
the NRC, and the Federal Trade Commission. Duquesne currently expects the sale
to close at the end of 1999 or the beginning of 2000.
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three coal-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company
expects to sell as part of the auction of generation assets. FirstEnergy will
acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley
Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce
Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with
the power station exchange, the Company anticipates terminating the BV Unit 2
lease in December 1999. (See "Financing," discussion on page 22.) Pursuant to
the December 18, 1998, PUC order and subject to final approval, the proceeds
from the sale of the power stations received in the exchange will be used to
offset the transition costs associated with Duquesne's currently-held generation
assets and costs associated with completing the exchange. Duquesne expects this
exchange to enhance the value received from the auction, because participants
will bid
8
<PAGE>
on entire plants, rather than plants that are jointly owned and/or operated by
another entity. Additionally, the auction will include only coal-and oil-fired
plants, which are anticipated to have a higher market value than nuclear plants.
These value-enhancing features, along with a minimum level of auction proceeds
guaranteed by FirstEnergy, are expected to maximize auction proceeds, minimize
transition costs required to be recovered through the CTC (by shortening the
length of the CTC recovery period), and thus reduce customer bills as rapidly as
possible. Other benefits of this exchange include the resolution of all joint
ownership issues, and other risks and costs associated with the jointly-owned
units. 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. Certain aspects of the exchange have
yet to be approved by, among other agencies, the FERC, the NRC and, solely with
respect to reliability issues, the Public Utilities Commission of Ohio. The
power station exchange is expected to occur at the end of 1999 or in early 2000.
(See "Legal Proceedings" on page 30.)
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement with Allegheny Energy, Inc. (AYE). The Company believes that
AYE suffered a material adverse effect as a result of the PUC's final
restructuring order regarding AYE's utility subsidiary, West Penn Power Company.
AYE filed suit in the United States District Court for the Western District of
Pennsylvania, seeking to compel the Company to proceed with the merger and
seeking a temporary restraining order and preliminary injunction to prevent the
Company from certain actions pending a trial, or in the alternative seeking an
unspecified amount of money damages. The parties continue to litigate this
matter. (See "Legal Proceedings" on page 30.) 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>
June 30, June 30, December 31,
1999 1998 1998
(Amounts in Thousands of Dollars)
- ---------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 86,136 $ 87,830 $ 87,262
Water customer accounts receivable 27,606 3,610 10,591
Other utility receivables 22,154 20,907 25,412
Other receivables 86,301 40,582 51,944
Less: Allowance for uncollectible accounts (10,669) (16,784) (9,415)
- ---------------------------------------------------------------------------------------------------------------
Receivables less allowance for uncollectible accounts 211,528 136,145 165,794
Less: Receivables sold (50,000) -- --
===============================================================================================================
Total Receivables $161,528 $136,145 $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 late August 1999, 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 June 30, 1999, the Company had sold $50 million of receivables.
At June 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 auction and the power station exchange by early 2000 and, depending on the
regulatory approvals of the final agreements regarding the divestiture, expects
certain obligations related to the divested assets will be transferred to the
future owners. (See "Restructuring Plan" discussion, Note 2, on page 8.)
Construction
The Company currently estimates that during 1999 it will spend, excluding
the Allowance for Funds Used During Construction and nuclear fuel, approximately
$110 million for electric utility construction, including $30 million for
generation, and approximately $25 million for water utility construction.
Nuclear-Related Matters
The Company has an interest in three nuclear units, two of which it operates.
The operation of a nuclear facility involves special risks, potential
liabilities, and specific regulatory and safety requirements. Specific
information about risk management and potential liabilities is discussed below.
Nuclear Decommissioning. The Company expects to decommission BV Unit 1, BV
Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating
license in 2016, 2027 and 2026, respectively. At the end of its operating life,
BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be
decommissioned, at which time the units may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit 2,
and a 1997 update of the 1994 study for Perry Unit 1, the Company's approximate
share of the total estimated decommissioning costs, including removal and
decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently used to determine the Company's cost of
service related to decommissioning all three nuclear units is $224 million.
Funding for nuclear decommissioning costs is deposited in external, segregated
trust accounts and invested in a portfolio of corporate common stock and debt
securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances at
June 30, 1999, totaled approximately $69.4 million.
As part of the power station exchange, FirstEnergy has agreed to assume the
decommissioning liability for each of the nuclear plants in exchange for the
balance in the decommissioning trust funds, plus the decommissioning costs to be
collected through the CTC, as approved by the PUC.
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 weekly
indemnity of
10
<PAGE>
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. The Company would be responsible for $59 million of this total,
which includes the cost of equipment removal and replacement steam generators,
but excludes replacement power costs. The earliest that the BV Unit 1 steam
generators could be replaced during a currently scheduled refueling outage is
the spring of 2003.
The Company continues to explore all viable means of managing ODSCC, including
new repair technologies, and plans to continue to perform 100 percent tube
inspections during future refueling outages. BV Unit 1's next refueling outage
is currently scheduled to begin in the spring of 2000. BV Unit 2's next
refueling outage is currently scheduled for the fall of 2000. The Company will
continue to monitor and evaluate the condition of the BVPS steam generators.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982 established
a federal policy for handling and disposing of spent nuclear fuel and a policy
requiring the establishment of a final repository to accept spent nuclear fuel.
Electric utility companies have entered into contracts with the United States
Department of Energy (DOE) for the permanent disposal of spent nuclear fuel and
high-level radioactive waste in compliance with this legislation. The DOE has
indicated that its repository under these contracts will not be available for
acceptance of spent nuclear fuel before 2010. The DOE has not yet established an
interim or permanent storage facility, despite a ruling by the United States
Court of Appeals for the District of Columbia Circuit that the DOE was legally
obligated to begin acceptance of spent nuclear fuel for disposal by January 31,
1998. Existing on-site spent nuclear fuel storage capacities at BV Unit 1, BV
Unit 2 and Perry Unit 1 are expected to be sufficient until 2018, 2012 and 2011,
respectively.
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
11
<PAGE>
United States Supreme Court declined to review the decision. The utilities'
remaining remedies are to sue the DOE in federal court for money damages caused
by the DOE's delay in fulfilling its obligations, or to pursue an equitable
contract adjustment before the DOE contracting officer.
Uranium Enrichment Obligations. Nuclear reactor licensees in the United States
are assessed annually for the decontamination and decommissioning of DOE uranium
enrichment facilities. Assessments are based on the amount of uranium a utility
had processed for enrichment prior to enactment of the National Energy Policy
Act of 1992, and are to be paid by such utilities over a 15-year period. At June
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 June 30, 1999, the Company's share of
these guarantees was $5.4 million.
As part of the Company's investment portfolio in affordable housing, the
Company has received fees in exchange for guaranteeing a minimum defined yield
to third-party investors. A portion of the fees received has been deferred to
absorb any required payments with respect to these transactions. Based on an
evaluation of and recent experience with the underlying housing projects, the
Company believes that such deferrals are ample for this purpose.
Environmental Matters
Various federal and state authorities regulate the Company with respect to
air and water quality and other environmental matters. The Company believes it
is in current compliance with all material applicable environmental regulations.
Employees
As previously reported, in connection with the anticipated divestiture,
Duquesne has developed early retirement programs and enhanced separation
packages. To date, approximately 250 eligible employees have elected to
participate in early retirement.
Other
The Company is involved in various other legal proceedings and environmental
matters. The Company believes that such proceedings and matters, in total, will
not have a materially adverse effect on its financial position, results of
operations or cash flows.
5. BUSINESS SEGMENTS AND RELATED INFORMATION
Historically, Duquesne has been treated as a single integrated business
segment due to its regulated operating environment. The PUC authorized a
combined rate for supplying and delivering electricity to customers which was
cost-based and was designed to recover the Company's operating expenses and
investment in electric utility assets and to provide a return on the investment.
As a result of the Customer Choice Act, generation of electricity is deregulated
and charged at a separate rate from the delivery of electricity beginning in
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 six
months ended June 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
12
<PAGE>
includes the expanded business lines and Duquesne investments below the
quantitative threshold for separate disclosure. These expanded business lines
include water utilities, energy products and services, electronic commerce, and
other activities. Intercompany eliminations primarily relate to intercompany
sales of electricity, property rental, management fees and dividends. However,
as the Company was not yet collecting transition costs prior to 1999, the 1998
results are reported by the electricity delivery and electricity generation
business segments.
Financial data for business segments is provided as follows:
Business Segments for the Three Months Ended
<TABLE>
<CAPTION>
June 30, 1999 (Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------------------
Electricity Electricity All Elimina-
Delivery Generation CTC Other tions Consolidated
-----------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 81,077 $ 102,782 $ 89,380 $ 57,965 $ (4,375) $ 326,829
Operating expenses 42,101 110,294 3,933 59,679 (6,800) 209,207
Depreciation and
amortization expense 12,981 9,096 25,430 5,534 -- 53,041
- --------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 25,995 (16,608) 60,017 (7,248) 2,425 64,581
Other income 1,412 3,032 -- 38,161 (5,248) 37,357
Interest and other charges 9,157 11,814 12,007 7,258 (2,230) 38,006
- --------------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 18,250 (25,390) 48,010 23,655 (593) 63,932
Income taxes 7,192 (11,418) 19,925 6,627 -- 22,326
- --------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 11,058 $ (13,972) $ 28,085 $ 17,028 $ (593) $ 41,606
==========================================================================================================================
Assets $ 1,303,969 $ 536,680 $ 2,040,473 $ 1,423,977 $ -- $ 5,305,099
==========================================================================================================================
Capital expenditures $ 15,218 $ 9,127 $ -- $ 20,059 $ -- $ 44,404
==========================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
June 30, 1998 (Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------
Electricity Electricity All Elimina-
Delivery Generation Other tions Consolidated
--------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 76,355 $ 210,681 $ 19,477 $ (3,003) $ 303,510
Operating expenses 37,102 128,004 19,276 (3,470) 180,912
Depreciation and
Amortization expense 12,512 44,041 1,096 -- 57,649
- ----------------------------------------------------------------------------------------------------------------
Operating income 26,741 38,636 (895) 467 64,949
Other income 1,359 2,451 26,021 (1,702) 28,129
Interest and other charges 9,432 14,661 3,254 (34) 27,313
- ----------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 18,668 26,426 21,872 (1,201) 65,765
Income taxes 8,931 12,158 4,472 -- 25,561
- ----------------------------------------------------------------------------------------------------------------
Net income (loss)
before extraordinary item $ 9,737 $ 14,268 $ 17,400 $ (1,201) $ 40,204
Extraordinary item, net of tax -- (82,548) -- -- (82,548)
- ---------------------------------------------------------------------------------------------------------------
Net income
after extraordinary item $ 9,737 $ (68,280) $ 17,400 $ (1,201) $ (42,344)
================================================================================================================
Assets (1) $1,314,266 $ 2,711,533 $ 1,221,764 $ -- $ 5,247,563
================================================================================================================
Capital expenditures $ 10,173 $ 11,064 $ 4,830 $ -- $ 26,067
================================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1998.
13
<PAGE>
Business Segments for the Six Months Ended
<TABLE>
<CAPTION>
June 30, 1999 (Thousands of Dollars)
- --------------------------------------------------------------------------------------------------------------------------------
Electricity Electricity All
Delivery Generation CTC Other Eliminations Consolidated
-----------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating revenues $ 163,398 $ 209,413 $ 182,404 $ 106,418 $ (8,749) $ 652,884
Operating expenses 80,841 219,351 8,026 108,773 (12,408) 404,583
Depreciation and
Amortization expense 27,492 18,241 55,063 10,090 -- 110,886
- --------------------------------------------------------------------------------------------------------------------------------
Operating income (loss) 55,065 (28,179) 119,315 (12,445) 3,659 137,415
Other income 2,595 5,465 -- 72,736 (7,690) 73,106
Interest and other charges 18,043 23,522 23,715 12,282 (2,844) 74,718
- --------------------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 39,617 (46,236) 95,600 48,009 (1,187) 135,803
Income taxes 15,130 (21,035) 39,675 11,962 -- 45,732
- --------------------------------------------------------------------------------------------------------------------------------
Net income (loss) $ 24,487 $ (25,201) $ 55,925 $ 36,047 $ (1,187) $ 90,071
================================================================================================================================
Assets $ 1,303,969 $ 536,680 $ 2,040,473 $ 1,423,977 $ -- $ 5,305,099
================================================================================================================================
Capital expenditures $ 28,644 $ 12,116 $ -- $ 30,595 $ -- $ 71,355
================================================================================================================================
</TABLE>
<TABLE>
<CAPTION>
June 30, 1998 (Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------------------------
Electricity Electricity
Delivery Generation All Other Eliminations Consolidated
-------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 155,298 $ 416,895 $ 36,291 $ (6,199) $ 602,285
Operating expenses 75,650 259,202 34,186 (8,353) 360,685
Depreciation and
Amortization expense 24,857 87,824 2,153 -- 114,834
- ----------------------------------------------------------------------------------------------------------------------------
Operating income 54,791 69,869 (48) 2,154 126,766
Other income 2,828 4,878 55,870 (4,029) 59,547
Interest and other charges 19,032 29,581 6,400 (82) 54,931
- ----------------------------------------------------------------------------------------------------------------------------
Income (loss) before taxes 38,587 45,166 49,422 (1,793) 131,382
Income taxes 16,895 19,147 10,006 -- 46,048
- ----------------------------------------------------------------------------------------------------------------------------
Net income (loss)
before extraordinary item $ 21,692 $ 26,019 $ 39,416 $ (1,793) $ 85,334
Extraordinary item, net of tax -- (82,548) -- -- (82,548)
- ----------------------------------------------------------------------------------------------------------------------------
Net income
after extraordinary item $ 21,692 $ (56,529) $ 39,416 $ (1,793) $ 2,786
============================================================================================================================
Assets (1) $ 1,314,266 $ 2,711,533 $ 1,221,764 $ -- $ 5,247,563
============================================================================================================================
Capital expenditures $ 19,111 $ 15,510 $ 34,084 $ -- $ 68,705
============================================================================================================================
</TABLE>
(1) Relates to assets as of December 31, 1998.
14
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with DQE, Inc. and its subsidiaries' Annual Report on Form 10-K
filed with the Securities and Exchange Commission (SEC) for the year ended
December 31, 1998 and the condensed consolidated financial statements, which are
set forth on pages 2 through 14 in Part I, Item 1 of this Report.
General
- --------------------------------------------------------------------------------
DQE, Inc. (DQE) is a multi-utility delivery and services company. Its
subsidiaries are Duquesne Light Company (Duquesne); AquaSource, Inc.
(AquaSource); DQE Capital Corporation (DQE Capital); DQE Energy Services, Inc.
(DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises, Inc. (DE); and
Montauk, Inc. (Montauk). DQE and its subsidiaries are collectively referred to
as "the Company."
The Company's 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
supply of innovative fuels, investments in communications systems and electronic
commerce, and long-term investments. DQE Capital provides financing for the
expanded business lines.
The Pennsylvania Public Utility Commission (PUC) has approved the Company's
plan to divest itself of its generation assets through an auction (including an
auction of its provider of last resort service), and the pending exchange of
certain power station assets with FirstEnergy Corporation (FirstEnergy). Final
agreements governing these transactions must be approved by various regulatory
agencies. The Company currently expects these transactions to close in late 1999
or early 2000. (See "Rate Matters" on page 24.)
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 24.) 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 24.)
The Company's electric utility operations are also subject to regulation by
the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as
amended, with respect to the operation of its jointly owned/leased nuclear power
plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and
Perry Unit 1.
15
<PAGE>
The Company's water utility operations are subject to regulation by the
utility regulatory bodies in their respective states.
As a result of the PUC's May 29, 1998, final order regarding the Company's
restructuring plan under the Customer Choice Act (see "Rate Matters" on page
24), 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 24.)
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 stranded costs from electric utility customers.
As a result of the order, the Company recorded an extraordinary charge
(Restructuring Charge) against earnings of $82.5 million, or $1.06 per share.
The following discussion of results of operations excludes the impact of that
Restructuring Charge.
Comparison of Three Months Ended June 30, 1999, and June 30, 1998. Basic
earnings per share increased 5.8 percent in the second quarter of 1999, to
$0.55. This improvement resulted from a 2.7 percent increase in earnings
available for common stock coupled with a 1.9 million share reduction in average
shares of common stock outstanding. The net income contribution from Duquesne
decreased by $2.0 million as the result of costs related to scheduled generating
station maintenance and refueling outages. In previous periods, when the
electricity generation business segment was rate regulated, these costs were
deferred for future rate recovery. The net income contribution from the
Company's expanded business lines increased by $5.4 million, primarily as a
result of the continuing water aggregation strategy and the continuing
restructuring of the Company's investment portfolio.
Comparison of Six Months Ended June 30, 1999, and June 30, 1998. Basic
earnings per share increased 6.4 percent for the six months ended June 30, 1999,
to $1.17. This improvement resulted from a 4.7 percent increase in earnings
available for common stock coupled with a 1.2 million share reduction in average
shares of common stock outstanding. The net income increase came from results
at the Company's expanded business lines, while Duquesne's contribution was
consistent with the 1998 level.
Subsequent Events. During the latter part of July 1999, a prolonged,
wide-spread heat wave in the eastern half of the United States led to
unprecedented market prices for purchased power, record peak demands and
regional capacity constraints. This combination of factors resulted in
unexpected net purchased power costs of approximately $24 million. Because of
these unexpected costs, July's earnings will be reduced by approximately $0.18
per share of common stock. The Company did not default on any wholesale supply
commitments and did not curtail any firm retail load during July. During the
first 13 days of August, the Company has been a net seller of wholesale power.
The Company believes its purchased power price risk will be eliminated in the
future by the auction of its generating stations and provider of last resort
obligation. (See "Rate Matters" on page 24.).
As planned, the Company is continuing to restructure its unregulated
investment portfolio by divesting of non-core assets, and has negotiated the
sale of certain of these investments. The transactions, expected to close during
the third quarter of 1999, are expected to result in a gain of approximately $13
million, or approximately $0.10 per share of common stock.
The foregoing statements are forward-looking regarding the impact on
earnings of the Company's power purchases and divestiture of generation and
non-core assets, and purchased power risks. Actual results for the third quarter
could materially differ from those implied by such statements due to known and
unknown risks and uncertainties, including, but not limited to, weather
conditions, market prices and availability of power, availability of the
Company's generating stations, constraints on the regional transmission
facilities, and timing of divestiture and other investment portfolio transaction
closings.
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
16
<PAGE>
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
consolidated financial statements on page 12.)
Electricity Delivery Business Segment
Comparison of Three Months Ended June 30, 1999, and June 30, 1998. The
electricity delivery business segment contributed $11.1 million to net income in
the second quarter of 1999 compared to $9.7 million in the second quarter of
1998, an increase of 13.6 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 $4.7 million or 6.2 percent in the second
quarter of 1999 due to an increase in electricity usage by customers of 2.1
percent and to services provided to electric generation suppliers. The following
table sets forth KWH delivered to electric utility customers during the second
quarter:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
KWH Delivered
(In Millions)
-------------------------------------------------------
Three Months Ended June 30, 1999 1998 Change
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 751.8 730.9 2.9 %
Commercial 1,457.4 1,434.3 1.6 %
Industrial 872.9 853.4 2.3 %
- ------------------------------------------------------------------------------------
Sales to Electric Utility Customers 3,082.1 3,018.6 2.1 %
===================================================================================================
</TABLE>
Operating expenses for the electricity delivery business segment are
primarily made up of costs to operate and maintain the transmission and
distribution system; meter reading and billing costs; customer service;
collection; administrative expenses; and non-income taxes, such as property and
payroll taxes. Operating expenses increased $5.0 million or 13.5 percent in the
second quarter of 1999, primarily due to the timing of non-recurring charges
related to meter reading in both 1999 and 1998.
17
<PAGE>
Interest and other charges include interest on long-term debt, other
interest and preferred stock dividends of Duquesne. In the second quarter of
1999, there was $0.3 million or 2.9 percent less in interest and other charges
compared to the second 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 Six Months Ended June 30, 1999, and June 30, 1998. The
electricity delivery business segment contributed $24.5 million to net income in
the first six months of 1999 compared to $21.7 million in the first six months
of 1998, an increase of 12.9 percent.
Operating revenues increased by $8.1 million or 5.2 percent in the first
six months of 1999 due to a 2.0 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 decreased primarily due to a reduction in electricity
consumption by steel manufacturers, which experienced a decline in demand. The
following table sets forth KWH delivered to electric utility customers during
the first six months of 1999 and 1998:
<TABLE>
<CAPTION>
- ---------------------------------------------------------------------------------------------------
KWH Delivered
-------------------------------------------------------
(In Millions)
-------------------------------------------------------
Six Months Ended June 30, 1999 1998 Change
- ---------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 1,668.4 1,599.3 4.3 %
Commercial 2,897.6 2,814.0 3.0 %
Industrial 1,723.7 1,754.3 (1.7)%
- ---------------------------------------------------------------------------------
Sales to Electric Utility Customers 6,289.7 6,167.6 2.0 %
===================================================================================================
</TABLE>
Operating expenses for the electricity delivery business segment increased
$5.2 million or 6.9 percent in the first six 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 $2.6 million or 10.6
percent in the first six months of 1999 due to additions to the plant and
equipment.
Other income is primarily comprised of interest and dividend income. A
decrease of $0.2 million or 8.2 percent was the result of lower interest income
from a smaller amount of cash available for investing in the first six months of
1999.
In the first six months of 1999, there was $1.0 million or 5.2 percent less
in interest and other charges compared to the first six 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 June 30, 1999, and June 30, 1998. In the
second quarter of 1999, the electricity generation and CTC business segments
reported net income of $14.1 million compared to $14.3 million for the second
quarter of 1998, a decrease of 1.1 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 June 30, 1999, approximately 14
percent of the Company's customers are purchasing electricity from alternative
generation suppliers.
18
<PAGE>
For the electricity generation and CTC business segments, operating
revenues are primarily derived from the Company's supply of electricity for
delivery to retail customers, the supply of electricity to wholesale customers
and, beginning in 1999, the collection of generation-related transition costs
from electricity delivery customers. Under fuel cost recovery provisions
effective 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 24.)
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 24.)
Operating revenues decreased by $18.5 million or 8.8 percent in the second
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. As of June 30, 1999, 13.6 percent of residential non-coincident
peak load, 29.4 percent of commercial load, and 5.8 percent of industrial load
have selected alternative generation suppliers. Partially offsetting this
decrease was a 127.3 percent increase in energy supplied to other utilities in
the second quarter of 1999, due to the Company's decision to sell 600 MW to
licensed generation suppliers to stimulate competition, and increased capacity
available to sell as a result of participation in customer choice. The following
table sets forth KWH supplied for customers who have not chosen an alternative
generation supplier.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
KWH Supplied
---------------------------------------------------------
(In Millions)
Three Months Ended June 30, 1999 1998 Change
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 633.9 687.3 (7.8)%
Commercial 987.0 1,355.1 (27.2)%
Industrial 837.5 840.0 (0.3)%
- ----------------------------------------------------------------------------------
Sales to Electric Utility Customers 2,458.4 2,882.4 (14.7)%
- ----------------------------------------------------------------------------------
Sales to Other Utilities 787.9 346.6 127.3%
- ----------------------------------------------------------------------------------
Total Sales 3,246.3 3,229.0 0.5%
=====================================================================================================
</TABLE>
Operating expenses for the electricity generation and CTC business segments
are primarily made up of energy costs; costs to operate and maintain the power
stations; administrative expenses; and non-income taxes, such as property and
payroll taxes.
Fluctuations in energy costs generally result from changes in the cost of
fuel, the mix between coal and nuclear generation, total KWH supplied, and
generating station availability. Because of the ECR, changes in fuel and
purchased power costs did not impact earnings for the first five months of 1998.
19
<PAGE>
Operating and maintenance expenses decreased $13.8 million or 10.8 percent
in the second quarter of 1999 as a result of decreased energy costs and the
reclassification of the interest component of Beaver Valley lease costs to
interest expense. Partially offsetting these reductions were an increase in
costs recognized currently as expense related to generating station outages.
In the second quarter of 1999, fuel and purchased power expense decreased
by $21.9 million or 30.6 percent compared to the second quarter of 1998. This
decrease was the result of decreased energy costs due to a favorable power
supply mix. During the second quarter of 1998, reduced availability of nuclear
generating stations due to an increase in outage hours required the Company to
purchase power and generate power from the higher fuel cost fossil stations.
Depreciation and amortization expense includes the depreciation of the
power stations' plant and equipment, accrued nuclear decommissioning costs and
the amortization of transition costs. A decrease of $9.5 million or 21.6 percent
in the second quarter of 1999 was the result of accelerated transition cost
reduction efforts during that period in 1998. In 1999, the Company began to
recover transition costs through an interim CTC. The total of transition costs
to be recovered was $1,485 million, net of tax, over a seven-year period, as may
be adjusted to account for the proceeds of the generation asset auction. 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 second quarter of
1999 there was a $9.2 million or 62.5 percent increase in interest and other
charges compared second 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 22.)
Comparison of Six Months Ended June 30, 1999, and June 30, 1998. In the
first six months of 1999, the electricity generation and CTC business segments
reported net income of $30.7 million compared to $26.0 million for the first six
months of 1998, an increase of 18.1 percent.
Operating revenues decreased by $25.1 million or 6.0 percent in the first
six 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. Partially offsetting this decrease was a 99.8 percent increase
in energy supplied to other utilities in the first six months of 1999, due to
the Company's decision to sell 600 MW to licensed generation suppliers to
stimulate competition, and increased capacity available to sell as a result of
participation in customer choice. The following table sets forth KWH supplied
for customers who have not chosen an alternative generation supplier.
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------
KWH Supplied
---------------------------------------------------------
(In Millions)
Six Months Ended June 30, 1999 1998 Change
- -----------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Residential 1,456.6 1,513.6 (3.8)%
Commercial 2,139.4 2,665.6 (19.7)%
Industrial 1,660.2 1,728.9 (4.0)%
- --------------------------------------------------------------------------------
Sales to Electric Utility Customers 5,256.2 5,908.1 (11.0)%
- --------------------------------------------------------------------------------
Sales to Other Utilities 1,450.4 726.0 99.8%
- --------------------------------------------------------------------------------
Total Sales 6,706.6 6,634.1 1.1%
=====================================================================================================
</TABLE>
20
<PAGE>
Operating expenses decreased $31.8 million or 12.3 percent in the first six
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.
Partially offsetting these reductions was an increase in costs recognized
currently as expense related to generating station outages, as opposed to prior
accounting which deferred the expense for recovery over the subsequent 18
months.
In the first six months of 1999, fuel and purchased power expense decreased
by $34.5 million or 26.3 percent compared to the first six months of 1998. This
decrease was the result of decreased energy costs due to a favorable power
supply mix. During the first six months of 1998, reduced availability of nuclear
generating stations due to an increase in outage hours required the Company to
purchase power and generate power from the higher fuel cost fossil stations.
A decrease in depreciation and amortization expense of $14.5 million or
16.5 percent in the first six months of 1999 was the result of accelerated
transition cost reduction efforts during that period. In 1999, the Company began
to recover transition costs through an interim CTC. The total of transition
costs to be recovered was $1,485 million, net of tax, over a seven-year period,
as may be adjusted to account for the proceeds of the generation asset auction.
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 six months of 1999 there was a $17.7 million or 59.7 percent
increase in interest and other charges compared to the first six 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 June 30, 1999, and June 30, 1998. The all
other category contributed $17.0 million to net income in the second quarter of
1999 compared to $17.4 million in the second quarter of 1998, a decrease of 2.1
percent.
Operating revenues primarily include revenues from operating activities of
the expanded business lines. Operating revenues increased in the second quarter
of 1999 by $38.5 million to almost triple the level in the second quarter of
1998. This increase was primarily the result of increased revenues from
AquaSource and Control Solutions (a subsidiary of DE).
Operating expenses include expenses from operating activities of the
expanded business lines and Duquesne investments. In the second quarter of 1999,
operating expenses increased $40.4 million or more than triple the level in the
second 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 second quarter of 1999, depreciation and
amortization expense increased by $4.4 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 second quarter of
1999 was $12.1 million or 46.7 percent higher than in the second quarter of
1998. $8.9 million of this increase was the result of the disposition of
certain of the Company's affordable housing 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 $4.0
million or 123.0 percent in the second quarter of 1999 was the result of higher
expense associated with higher average borrowings outstanding; $2.2 million of
the increase was intercompany interest.
21
<PAGE>
Comparison of Six Months Ended June 30, 1999, and June 30, 1998. The all
other category contributed $36.0 million to net income in the first six months
of 1999 compared to $39.4 million in the first six months of 1998, a decrease of
8.5 percent.
Operating revenues increased in the first six months of 1999 by $70.1
million to almost triple the level in the first six months of 1998. This
increase was primarily the result of increased revenues from AquaSource and
Control Solutions.
In the first six months of 1999, operating expenses increased $74.6 million
or more than triple the level in the first six 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 six months of 1999, depreciation and amortization expense
increased by $7.9 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 six months of 1999 was $16.9 million or 30.2
percent higher than in the first six months of 1998. This increase was the
result of new investments made by the expanded business lines throughout 1998
and 1999.
An increase in interest and other charges of $5.9 million or 91.9 percent
in the first six months of 1999 was the result of higher long-term debt expense
associated with higher average borrowings outstanding.
Liquidity and Capital Resources
- -------------------------------------------------------------------------------
Financing
The Company expects to meet its current obligations and debt maturities
through the year 2003 with funds generated from operations, through new
financings and short-term borrowings, and through the proceeds from the auction
of generation assets. To the extent that acquisition and long-term investment
opportunities prior to the generation divestiture exceed current expectations,
the Company may explore various financing alternatives. At June 30, 1999, the
Company was in compliance with all of its debt covenants.
Mortgage bonds in the amount of $75 million matured in July 1999, and were
retired using available cash and short term borrowings.
In connection with the power station exchange with FirstEnergy, the Company
anticipates terminating the BV Unit 2 lease in December 1999, in which case the
lease liability recorded on the consolidated balance sheet would no longer be an
obligation of the Company. The underlying collateralized lease bonds ($370.7
million at June 30, 1999) would become obligations of the Company and be
recorded on the consolidated balance sheet. The Company anticipates redeeming
the bonds on December 1, 2002 (the first redemption date), using funds generated
from operations, the generation asset auction proceeds, the CTC, and/or through
new financings. The Company would also pay approximately $230 million in
termination costs, which the Company expects to recover through the proceeds of
the generation asset auction and the CTC. (See "Power Station Exchange"
discussion on page 25.)
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 14 percent of customers). This reduction is expected to be offset
by reduced cash requirements associated with supplying energy. A further
impact is anticipated to occur when, as part of the divestiture, Duquesne
auctions its provider of last resort service and all customers will be buying
generation, either directly from alternative suppliers or indirectly from the
provider of last resort. An additional impact on customer revenues is expected
to occur when the CTC has been fully collected. The length of the CTC
collection period will depend on the level of auction proceeds and future retail
sales The foregoing statements are forward-looking regarding the impact on cash
flows of customer choice and Duquesne's divestiture. Actual results
22
<PAGE>
could materially differ from those implied by such statements due to known and
unknown risks and uncertainties, including, but not limited to, the amount and
timing of the receipt of auction proceeds. (See "Restructuring Plan" on page
25.)
As of June 30, 1999, 387,360 shares of Preferred Stock, Series A
(Convertible), $100 liquidation preference per share (DQE Preferred Stock), were
outstanding, including 1,200 shares issued in the second quarter of 1999. An
additional 51,060 shares were issued in July 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 in
late August 1999. At June 30, 1999, the Company had sold $50 million of
receivables.
DQE Capital was formed in the second quarter of 1999 to provide financing for
the expanded business lines. On June 10, 1999, DQE Capital filed a shelf
registration statement for the periodic sale of up to $250 million of unsecured
debt securities, unconditionally guaranteed by DQE. On June 11, 1999, DQE
Capital entered into 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. This facility replaced a $125
million revolving credit facility. As guarantor, DQE is subject to financial
covenants requiring certain cash coverage and debt to capital ratios. At June
30, 1999, $149 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.
The Company also maintains a $150 million extendable revolving credit
facility which expires in October 1999. At June 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. Commitment fees are based on the unborrowed amount of the commitments.
The facility contains a two-year repayment period for any amounts outstanding at
the expiration of the revolving credit period. The Company also has an
aggregate of $150 million in bank term loans outstanding at June 30, 1999, with
$65 million maturing in 2000 and $85 million maturing in 2001.
At June 30, 1999, the Company had $19.5 million of commercial paper
borrowings outstanding. During the second quarter the maximum amount of such
borrowings was $40 million, the average daily borrowings was $25.6 million and
the weighted average daily interest rate was 5.13 percent.
The Company repurchased shares of its common stock on the open market
during the second 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 its portfolio
of affordable housing investments. Investing activities during the first six
months of 1999 and 1998 totaled approximately $17 million and $27 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 $25 million for water utility construction.
During the first six months of 1999, the Company has spent approximately $71
million on capital expenditures, which consist of approximately $41 million at
Duquesne, $18 million at AquaSource and the remaining $12 million on other.
In the first six months of 1999 the Company issued 35,277 shares of DQE
Preferred Stock, as part of a total investment of approximately $120 million in
water companies.
23
<PAGE>
During the second quarter of 1999, the Company invested approximately $12
million to acquire four propane distribution businesses in Texas. 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 and stranded costs.
In Pennsylvania, the Customer Choice Act went into effect on January 1,
1997. The Customer Choice Act enables Pennsylvania's electric utility customers
to purchase electricity at market prices from a variety of electric generation
suppliers (customer choice). Although the Customer Choice Act will give
customers their choice of electric generation suppliers, the existing,
franchised local distribution utility is still responsible for delivering
electricity from the generation supplier to the customer. The local distribution
utility is also required to serve as the provider of last resort for all
customers in its service territory, unless other arrangements are approved by
the PUC. The provider of last resort must provide electricity for any customer
who cannot or does not choose an alternative electric generation supplier, or
whose supplier fails to deliver. The Customer Choice Act provides that the
existing franchised utility may recover, through a CTC, an amount of transition
costs that are determined by the PUC to be just and reasonable. Pennsylvania's
electric utility restructuring is being accomplished through a two-stage process
consisting of an initial customer choice pilot period (which ended in December
1998) and a phase-in to competition period (which began in January 1999).
Phase-In to Competition
The phase-in to competition began in January 1999, when 66 percent of
customers became eligible to participate in customer choice (including customers
covered by the pilot program); all customers will have customer choice in
January 2000. As of June 30, 1999, approximately 14 percent of the Company's
customers had chosen alternative generation suppliers. Customers that have
chosen an electricity generation supplier other than the Company pay that
supplier for generation charges, and pay the Company the CTC (discussed below)
and charges for transmission and distribution. Customers that continue to buy
their generation from the Company pay for their service at current regulated
tariff rates divided into generation, transmission and distribution charges, and
the CTC. Under the Customer Choice Act, an electric distribution company, such
as Duquesne, remains a regulated utility and may only offer PUC-approved rates,
including generation rates. Also under the Customer Choice Act, electricity
delivery (including transmission, distribution and customer service) remains
regulated in substantially the same manner as under historical regulation.
In an effort to "jumpstart" competition, the Company 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, has been
imposed on the transmission and distribution charges of Pennsylvania electric
utility companies under the Customer Choice Act. Additionally, electric utility
companies may not increase the generation price component of rates as long as
transition costs are being recovered, with certain exceptions.
24
<PAGE>
Restructuring Plan
In its May 29, 1998, final restructuring order, the PUC determined that the
Company should recover most of the above-market costs of the generation assets,
including plant and regulatory assets through the collection of the CTC from
electric utility customers. The total of the transition costs to be recovered
was $1,485 million, net of tax, over a seven-year period beginning January 1,
1999, as may be adjusted to account for the proceeds of the generation asset
auction. In addition, the transition costs as reflected on the consolidated
balance sheet are being amortized over the same period that the CTC revenues are
being recognized. The Company is allowed to earn an 11 percent pre-tax return on
the unrecovered, 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 has appealed the PUC's denial of recovery to the Pennsylvania
Commonwealth Court. Based upon the Customer Choice Act, which mandates recovery
of all regulatory assets, and the PUC's specific authorization for the Company
to create a regulatory asset for these costs, the Company believes that it is
probable that these costs will be recovered through retail rates. In the event
that the Company does not prevail in its appeal, these costs would be written
off as a charge against income.
Restructuring Plan and Auction Plan. With respect to transition cost
recovery, the PUC's final order on the restructuring plan approved Duquesne's
proposal to auction its generation assets and use the proceeds to offset
transition costs. The remaining balance of such costs (with certain exceptions
described below) is expected to be recovered from ratepayers through the CTC.
Until the divestiture is complete, Duquesne has been ordered to use an interim
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 KWH for the CTC
and approximately 3.8 cents per KWH for the price to compare).
On December 18, 1998, the PUC approved Duquesne's auction plan, including
an auction of its provider of last resort service, as well as an agreement in
principle to exchange certain generation assets with FirstEnergy. The assets to
be auctioned will include Duquesne's wholly owned Cheswick, Elrama, Phillips and
Brunot Island power stations, as well as the stations to be received from
FirstEnergy in the power station exchange described below. The auction plan
calls for a two-phase, sealed bid process similar to that used in other power
plant divestitures. The initial confidential bidding process began in April
1999, with potential buyers identified by Duquesne being asked to submit non-
binding bids. Qualified applicants have been asked to submit binding, second-
round bids, due in September 1999. Final agreements governing the transactions
must be approved by various regulatory agencies, including the PUC, the FERC,
the NRC, and the Federal Trade Commission. Duquesne currently expects the sale
to close at the end of 1999 or the beginning of 2000.
Power Station Exchange. Pursuant to the definitive agreements entered into
on March 25, 1999, Duquesne and FirstEnergy will exchange ownership interests in
certain power stations. Duquesne will receive 100 percent ownership rights in
three coal-fired power plants located in Avon Lake and Niles, Ohio and New
Castle, Pennsylvania (totaling approximately 1,300 MW), which the Company
expects to sell as part of the auction of generation assets. FirstEnergy will
acquire Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley
Unit 2 (BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce
Mansfield Units 1, 2 and 3 (totaling approximately 1,400 MW). In connection with
the power station exchange, the Company anticipates terminating the BV Unit 2
lease in December 1999. (See "Financing," discussion on page 22) Pursuant to the
December 18, 1998, PUC order and subject to final approval, the proceeds from
the sale of the power stations received in the exchange will be used to offset
the transition costs associated with Duquesne's currently-held generation assets
and costs associated with completing the exchange. Duquesne expects this
exchange to enhance the value received from the auction, because participants
will bid
25
<PAGE>
on entire plants, rather than plants that are jointly owned and/or
operated by another entity. Additionally, the auction will include only coal-
and oil-fired plants, which are anticipated to have a higher market value than
nuclear plants. These value-enhancing features, along with a minimum level of
auction proceeds guaranteed by FirstEnergy, are expected to maximize auction
proceeds, minimize transition costs required to be recovered through the CTC (by
shortening the length of the CTC recovery period), and thus reduce customer
bills as rapidly as possible. Other benefits of this exchange include the
resolution of all joint ownership issues, and other risks and costs associated
with the jointly-owned units. 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. Certain
aspects of the exchange have yet to be approved by, among other agencies, the
FERC, the NRC and, solely with respect to reliability issues, the Public
Utilities Commission of Ohio. The power station exchange is expected to occur at
the end of 1999 or in early 2000. (See "Legal Proceedings" on page 30.)
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement between the Company and Allegheny Energy, Inc. (AYE). The
Company believes that AYE suffered a material adverse effect as a result of the
PUC's final restructuring order regarding AYE's utility subsidiary, West Penn
Power Company. AYE filed suit in the United States District Court for the
Western District of Pennsylvania, seeking to compel the Company to proceed with
the merger and seeking a temporary restraining order and preliminary injunction
to prevent the Company from certain actions pending a trial, or in the
alternative seeking an unspecified amount of money damages. The parties continue
to litigate this matter. (See "Legal Proceedings" on page 30.) In a letter
dated February 24, 1999, the PUC informed the Company that the merger
application was deemed withdrawn and the docket was closed.
Year 2000
- ---------
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
26
<PAGE>
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 well, many of Duquesne's business critical
systems are ready as of June 30, 1999. The remainder are expected to be
completed by September 30, 1999.
For existing AquaSource facilities, completion of inventory and assessment
for mission critical systems is scheduled for August 31, 1999. Full remediation
and testing and implementation for these systems will be substantially completed
by September 30, 1999. The Company's Year 2000 program is routinely being
incorporated into all new AquaSource acquisitions.
Year 2000 readiness related to mission critical and business critical systems
at the Company's other expanded business lines were 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).
. 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
27
<PAGE>
its generation, transmission, and distribution systems. In addition,
the Company participated in the industry-wide NERC communication drill
that was conducted on April 9, 1999. All of the Company's
communications systems exercised in this drill performed as expected.
The Company will also be participating in the NERC Year 2000 readiness
drill to be conducted on September 9, 1999.
. The Company'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.
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 $39 million. Of this amount, approximately $35 million are
capital costs attributable to the licensing and installation of new software for
total system replacements. The remaining $4 million has been expensed as
incurred. Funds for the Company's Year 2000 plan have come from the Company's
operating and capital budgets. Approximately $10 million has been budgeted for
1999 to address Year 2000 issues. The Company does not anticipate that Year 2000
issues and related costs will be material to the Company's operations, financial
condition and results of operations.
The foregoing paragraphs contain forward-looking statements regarding the
timetable, effectiveness and ultimate cost of the Company's Year 2000 strategy.
Actual results could materially differ from those implied by such statements due
to known and unknown risks and uncertainties, including, but not limited to, the
possibility that changes and upgrades are not timely completed, that corrections
to the systems of other companies on which the Company's systems rely may not be
timely completed, and that such changes and upgrades may be incompatible with
the Company's systems; the availability and cost of trained personnel; and the
ability to locate and correct all relevant computer code and microprocessors.
28
<PAGE>
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 June 30, 1999 totaled approximately $69.4 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 auction its
generating assets; the power station exchange; general and economic and business
conditions; industry capacity; changes in technology; changes in political,
social and economic conditions; pending regulatory decisions regarding industry
restructuring in Pennsylvania; the loss of any significant customers; and
changes in business strategy or development plans.
29
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, the Company commenced arbitration against The Cleveland
Electric Illuminating Company (CEI), seeking damages, termination of the
operating agreement for Eastlake Unit 5 (Eastlake) and partition of the parties'
interests in Eastlake through a sale and division of the proceeds. The
arbitration demand alleged, among other things, the improper allocation by CEI
of fuel and related costs; the mismanagement of the administration of the
Saginaw coal contract in connection with the closing of the Saginaw mine, which
historically supplied coal to Eastlake; and the concealment by CEI of material
information. CEI also seeks monetary damages from the Company for alleged unpaid
joint costs in connection with the operation of Eastlake. The Company removed
the action to the United States District Court for the Northern District of
Ohio, Eastern Division, where it is now pending. Pursuant to the agreement
regarding the power station exchange between Duquesne and FirstEnergy, the
parties have jointly sought and received a court order staying all proceedings
pending the closing of the exchange. (See "Power Station Exchange" discussion on
page 25.)
Termination of the AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement with AYE. More information regarding this termination is set
forth in the Company's Current Report on Form 8-K dated October 5, 1998. AYE
promptly filed suit in the United States District Court for the Western District
of Pennsylvania, seeking to compel the Company to proceed with the merger and
seeking a temporary restraining order and preliminary injunction to prevent the
Company from certain actions pending a trial, or in the alternative seeking an
unspecified amount of money damages. On October 28, 1998, the judge denied AYE's
motion for the temporary restraining order and preliminary injunction. AYE
appealed to the United States Court of Appeals for the Third Circuit, asking for
an injunction pending the appeal and expedited treatment of the appeal. On
November 6, 1998, the Third Circuit denied the motion for an injunction and
granted the motion to expedite the appeal.
On March 11, 1999, the Third Circuit vacated the October 28 denial of a
preliminary injunction. The Third Circuit remanded the case to the District
Court for further proceedings to address certain issues, including whether AYE
could demonstrate a reasonable likelihood of success on the merits, before
determining whether any injunctive relief is warranted. On March 12, 1999, AYE
filed a motion for a temporary restraining order with the district court, and a
hearing was held that same day. On March 16, 1999, AYE and DQE entered into a
consent agreement, which was approved by the district court on March 18.
Pursuant to the consent agreement, AYE and DQE have agreed, among other things,
that pending the consolidated hearing on AYE's application for a preliminary
injunction and/or an expedited trial on the merits, both parties will give each
other 10 business days' notice before taking or omitting to take any action
which would prevent the merger from qualifying for "pooling of interests"
accounting treatment. This would not prevent either party from entering into any
agreement, but would require the 10 business days' notice prior to closing any
transaction which prevents pooling. The consent agreement shall terminate on
September 16, 1999, unless earlier terminated or extended by mutual agreement or
an order of the district court. On March 25, 1999, the Company petitioned the
Third Circuit for rehearing; 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.
The Company continues to believe that AYE's claim is entirely without merit
in light of the $1 billion disallowance of its stranded costs, which constituted
a material adverse effect under the merger agreement and entitled the Company to
terminate it as of October 5, 1998. The Company will continue to defend itself
vigorously against AYE's claims and intends to pursue a prompt resolution of the
litigation. The ultimate outcome of this suit cannot be determined at this time.
The Company's motion for summary judgment, originally filed December 18, 1998,
remains pending.
30
<PAGE>
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 3.1 - Bylaws of DQE, as amended through June 29, 1999, and
currently in effect.
EXHIBIT 4.1 - Form of Indenture from DQE Capital Corporation and DQE, Inc.
to The First National Bank of Chicago, as Trustee, filed as
Exhibit 4.1 to Registration Statement on Form S-3
(Registration Nos. 333-80377 and 333-80377-01) and
incorporated herein by reference.
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. No reports on Form 8-K were filed during the fiscal quarter ended June 30,
1999.
A report on Form 8-K was filed July 29, 1999, which included the DQE
Earnings Release for the quarter ended June 30, 1999.
_____________________________
31
<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 August 13, 1999 /s/ Gary L. Schwass
--------------- -------------------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer
Date August 13, 1999 /s/ James E. Wilson
--------------- -------------------------------------
(Signature)
James E. Wilson
Controller
(Principal Accounting Officer)
32
<PAGE>
Exhibit 3.1
-----------
DQE
BY-LAWS
EFFECTIVE June 29, 1999
ARTICLE I
STOCKHOLDERS
SECTION 1. Annual Meeting. The Corporation shall hold an annual
---------------
stockholders' meeting for election of Directors at a date, location (within or
outside Pennsylvania) and time set by the Board of Directors.
SECTION 2. Notice of Business to be Presented at the Annual Meeting.
--------------------------------------------------------
(a) The proposal of business to be considered by the stockholders at
an annual meeting of stockholders may be made (i) pursuant to the Corporation's
notice of meeting, (ii) by or at the direction of the Board of Directors or
(iii) by any stockholder of the Corporation who was a stockholder of record at
the time of giving of notice provided for in this Section, who is entitled to
vote at the meeting and who has complied with the notice procedures set forth in
this Section. For business to be properly brought before an annual meeting by a
stockholder pursuant to clause (iii) of the preceding sentence, such business
must be a proper matter for stockholder action, the stockholder must have given
timely notice thereof in writing to the Secretary of the Corporation and such
notice must comply with the following requirements.
<PAGE>
(1) To be timely, a stockholder's notice given pursuant to this
Section must be received at the principal executive offices of the
Corporation, addressed to the Secretary, not less than 120 calendar days
before the anniversary date of the Corporation's proxy statement released
to stockholders in connection with the previous year's annual meeting or,
if none, its most recent previous annual meeting. Notwithstanding the
preceding sentence, if the date of the annual meeting at which such
business is to be presented has been changed by more than 30 days from the
date of the most recent previous annual meeting, a stockholder's notice
shall be considered timely if so received by the Corporation (i) on or
before the later of (x) 150 calendar days before the date of the annual
meeting at which such business is to be presented or (y) 30 days following
the first public announcement by the Corporation of the date of such annual
meeting and (ii) not later than 15 calendar days prior to the scheduled
mailing date of the Corporation's proxy material for such annual meeting.
In no event shall the public announcement of an adjournment of an annual
meeting commence a new time period for the giving of a stockholder's notice
as described above.
(2) A stockholder's notice given pursuant to this Section shall set
forth (A) the name and address of the stockholder who intends to make the
proposal and the classes and numbers of shares of the Corporation's
2
<PAGE>
stock beneficially owned by such stockholder; (B) a representation that the
stockholder is and will at the time of the annual meeting be a holder of
record of stock of the Corporation entitled to vote at such meeting on the
proposal(s) specified in the notice and intends to appear in person or by
proxy at the meeting to present such proposal(s), (C) a description of the
business the stockholder intends to bring before the meeting, including the
text of any proposal or proposals to be presented for action by the
stockholders, (D) the name and address of any beneficial owner(s) of the
Corporation's stock on whose behalf such business is to be presented and
the class and number of shares beneficially owned by each such beneficial
owner and (E) the reasons for conducting such business at the meeting and
any material interest in such business of such stockholder or any such
beneficial owner.
(b) General. (i) Only such business shall be conducted at a meeting of
stockholders as shall have been brought before the meeting in accordance with
the procedures set forth in this Section. The Chairman of the Meeting shall have
the power and the duty to determine whether any business proposed to be brought
before a meeting was proposed in accordance with the procedures set forth in
this Section and, if any business is not in compliance with this Section, to
declare that such defective proposal shall be disregarded.
3
<PAGE>
(ii) For purposes of this Section, (A) "public announcement" shall
mean disclosure in a press release reported by the PR Newswire, the Dow Jones
News Service, Associated Press or comparable national news service or in a
document publicly filed by the Corporation with the Securities and Exchange
Commission pursuant to Section 13, 14 or 15(d) of the Securities Exchange Act of
1934 (the "Exchange Act") and (B) "beneficial ownership" shall be determined in
accordance with Rule 13d-3 under the Exchange Act or any successor rule.
(iii) Notwithstanding the foregoing provisions of this Section, a
stockholder shall also comply with all applicable requirements of the Exchange
Act and the rules and regulations thereunder with respect to the matters set
forth in this Section. Nothing in this Section shall be deemed to affect any
rights of a stockholder to request inclusion of a proposal in the Corporation's
proxy statement pursuant to Rule 14a-8 under the Exchange Act, or any successor
rule, or to present for action at an annual meeting any proposal so included.
SECTION 3. Special Meetings. Special meetings of the stockholders
-----------------
may be called at any time by the Chairman of the Board or President or by the
Board of Directors. Only such business shall be conducted at a special meeting
of stockholders as shall have been brought before the meeting pursuant to the
Corporation's notice of meeting.
4
<PAGE>
SECTION 4. Notice of Meetings. Written notice of every meeting of
-------------------
the stockholders shall be given to each stockholder entitled to vote at such
meeting, at least five days (or such other period as required by statute) before
the meeting, by the Chairman of the Board or Secretary. Failure to give notice
of any annual meeting or irregularity in the notice shall not affect the
validity of any proceedings at such meeting (other than proceedings of which
special notice is required by law, the Articles or these By-Laws).
SECTION 5. Quorum. At all meetings of stockholders, a majority of
-------
the voting power of the outstanding shares entitled to vote, represented by
stockholders in person or by proxy, shall constitute a quorum.
SECTION 6. Judges of Election. Three judges of election shall be
-------------------
appointed by the Board of Directors for any meeting of stockholders. The judges
of election shall act as tellers of any ballot vote taken at the meeting and
certify the result.
SECTION 7. Voting and Proxies. The holders of Series A Preferred
-------------------
Stock will be entitled to vote on all matters submitted to a vote of the holders
of Common Stock, voting together with the holders of Common Stock as one class.
Each share of Common Stock will be entitled to one vote. Each share of Series A
Preferred Stock will be entitled to three votes per share, subject to certain
adjustments. At meetings for the
5
<PAGE>
election of Directors, each stockholder entitled to vote shall be entitled to
votes equal to the number of shares held multiplied by the number of Directors
to be elected, and each stockholder may cast all votes for a single candidate or
distribute them among any two or more candidates.
Any stockholder entitled to vote at any meeting of stockholders may
vote either in person or by proxy, but no proxy which is dated more than three
years prior to the meeting at which it is offered shall confer the right to
vote. Every proxy shall be in writing, signed by a stockholder or duly
authorized attorney in fact.
SECTION 8. Order of Business. At all meetings of stockholders, the
------------------
order of business shall be, as far as applicable and practicable, as follows:
(1) Organization.
(2) Proof of giving of the notice of meeting or of waivers thereof.
(3) Submission by the Secretary, or by the judges of election, of a
list of stockholders entitled to vote, present in person or by
proxy.
(4) If an annual meeting, presentation of unapproved minutes of
preceding meetings and action thereon.
6
<PAGE>
(5) Matters to be voted upon as specified in the notice of meeting.
(6) Reports.
(7) Unfinished business.
(8) New business.
(9) Adjournment.
ARTICLE II
BOARD OF DIRECTORS
SECTION 1. Election and Powers. The business and affairs of the
--------------------
Corporation shall be managed by its Board of Directors. The Board may exercise
all the powers of the Corporation except such as are by statute, the Articles or
these By-Laws conferred upon or reserved to the stockholders. At each annual
meeting the stockholders shall elect directors of the class whose term then
expires, to hold office until the third succeeding annual meeting. Except as
otherwise expressly provided in the Articles, each director shall hold office
until a successor is elected and qualified, or until such director's earlier
death, resignation or removal in the manner provided in
7
<PAGE>
Section 11 of this Article II. The number of directors which shall constitute
the full Board of Directors shall be not less than one as fixed by the Board of
Directors in the manner provided in the Articles.
SECTION 2. Eligibility for Election. No person who is an employee of
------------------------
the Company, except the Chairman of the Board or President, shall be eligible to
serve as a Director of the Company after retiring as an employee. The mandatory
retirement age for directors is 70 except for directors completing a current
term of office.
SECTION 3. Regular Meetings. After each meeting of stockholders at
-----------------
which Directors shall have been elected, the Board of Directors shall meet as
soon as practicable for the purpose of organization and the transaction of other
business. Additional regular meetings shall be held as fixed by the Board of
Directors.
SECTION 4. Special Meetings. Special meetings of the Board of
-----------------
Directors shall be held whenever called by the Chairman of the Board, the
President or a majority of the Board of Directors.
SECTION 5. Place of Meetings. The Board of Directors may hold its
------------------
regular and special meetings at such places as it designates.
8
<PAGE>
SECTION 6. Notice of Meetings. No notice of regular meetings of the
-------------------
Board of Directors need be given. Notice of the place, day and hour of every
special meeting shall be given to each director at least one day before the
meeting, by personal delivery, by telephone or by facsimile or electronic
communication , at the director's residence or usual place of business or in the
alternative, by mailing the notice at least three days before the meeting to the
director's last known mailing address. The failure to give notice shall not
affect the validity of any meeting as to any director who attends the meeting or
waives notice in writing. No notice of adjourned meetings of the Board of
Directors need be given. All regular and special meetings of the Board of
Directors shall be general meetings open for the transaction of any business
without special notice of such business.
SECTION 7. Quorum. At all meetings of the Board of Directors, a
-------
majority of the directors shall constitute a quorum for the transaction of
business. Except in cases in which it is by law, the Articles or these By-Laws
otherwise provided, a majority of the quorum shall decide any questions.
SECTION 8. Vacancies. Vacancies on the Board of Directors shall be
----------
filled as provided in the Articles.
SECTION 9. Compensation. The directors may be compensated for their
-------------
services on a periodic basis and/or receive a fixed sum for attendance at each
regular, special or Committee
9
<PAGE>
meeting and every adjournment thereof. The amount shall be fixed by resolution
of the Board of Directors. The directors shall be reimbursed for all reasonable
traveling expenses incurred in attending meetings. Directors who are employees
of the Corporation shall not be paid for their services as directors.
SECTION 10. Removal. Any Director, any class of Directors or the
--------
entire Board of Directors may be removed as provided in the Articles.
SECTION 11. Indemnification of Directors and Officers.
------------------------------------------
(a) Right of Indemnification. Except as prohibited by law, every
-------------------------
Director and officer of the Corporation shall be entitled as of right to be
indemnified by the Corporation against reasonable expense and any liability paid
or incurred by such person in connection with any actual or threatened claim,
action, suit or proceeding, civil, criminal, administrative, investigative or
other, whether brought by or in the right of the Corporation or otherwise, by
reason of such person being or having been a Director or officer of the
Corporation or by reason of the fact that such person is or was serving at the
request of the Corporation as a director, officer, employee, fiduciary or other
representative of another corporation, partnership, joint venture, trust,
employee benefit plan or other entity (such claim, action, suit or proceeding
hereinafter being referred to as "action"); provided, however, that no such
right of indemnification shall exist with respect to an action brought by a
Director or officer against the Corporation (other than a suit
10
<PAGE>
for indemnification as provided in paragraph (b)). Such indemnification shall
include the right to have expenses incurred by such person in connection with an
action paid in advance by the Corporation prior to final disposition of such
action, subject to such conditions as may be prescribed by law. Persons who are
not Directors or officers of the Corporation may be similarly indemnified in
respect of service to the Corporation or to another such entity at the request
of the Corporation to the extent the Board of Directors at any time denominates
such person as entitled to the benefits of this Section. As used herein,
"expense" shall include fees and expenses of counsel selected by such person;
and "liability" shall include amounts of judgments, excise taxes, fines and
penalties, and amounts paid in settlement.
(b) Right of Claimant to Bring Suit. If a claim under paragraph (a)
--------------------------------
of this Section is not paid in full by the Corporation within thirty days after
a written claim has been received by the Corporation, the claimant may at any
time thereafter bring suit against the Corporation to recover the unpaid amount
of the claim, and, if successful in whole or in part, the claimant shall also be
entitled to be paid the expense of prosecuting such claim. It shall be a
defense to any such action that the conduct of the claimant was such that under
Pennsylvania law the Corporation would be prohibited from indemnifying the
claimant for the amount claimed, but the burden of proving such defense shall be
on the Corporation. Neither the failure of the Corporation (including its Board
of Directors, independent legal counsel and its stockholders) to have made a
11
<PAGE>
determination prior to the commencement of such action that indemnification of
the claimant is proper in the circumstances because the conduct of the claimant
was not such that indemnification would be prohibited by law, nor an actual
determination by the Corporation (including its Board of Directors, independent
legal counsel or its stockholders) that the conduct of the claimant was such
that indemnification would be prohibited by law, shall be a defense to the
action or create a presumption that the conduct of the claimant was such that
indemnification would be prohibited by law.
(c) Insurance and Funding. The Corporation may purchase and maintain
----------------------
insurance to protect itself and any person eligible to be indemnified hereunder
against any liability or expense asserted or incurred by such person in
connection with any action, whether or not the Corporation would have the power
to indemnify such person against such liability or expense by law or under the
provisions of this Section 11. The Corporation may create a trust fund, grant a
security interest, cause a letter of credit to be issued or use other means
(whether or not similar to the foregoing) to ensure the payment of such sums as
may become necessary to effect indemnification as provided herein.
(d) Non-Exclusivity; Nature and Extent of Rights. The right of
---------------------------------------------
indemnification provided for herein (1) shall not be exclusive of any other
rights, whether existing now or later, to which those seeking indemnification
may be entitled under any agreement, by-law or charter provision, vote of
stockholders or Directors or otherwise, (2) shall be deemed to create
contractual rights in favor of persons entitled to indemnification, (3) shall
12
<PAGE>
continue as to persons who have ceased to have the status pursuant to which they
were entitled or were denominated as entitled to indemnification and shall inure
to the benefit of the heirs and legal representatives of persons entitled to
indemnification hereunder and (4) shall be applicable to actions, suits or
proceedings commenced after adoption, whether arising from acts or omissions
occurring before or after the adoption hereof. The right of indemnification may
not be amended, modified or repealed so as to limit the indemnification provided
herein with respect to any acts or omissions occurring prior to the adoption of
any such amendment or repeal.
SECTION 12. Personal Liability of Directors.
--------------------------------
(a) To the fullest extent that the laws of the Commonwealth of
Pennsylvania, as in effect on January 27, 1987 or as thereafter amended, permit
elimination or limitation of the liability of directors, no Director of the
Corporation shall be personally liable for monetary damages as such for any
action taken, or any failure to take any action, as a Director.
(b) This Section 12 shall not apply to any action filed prior
to January 27, 1987, nor to any breach of performance or failure of performance
of duty by a Director occurring prior to January 27, 1987. Any amendment or
repeal of this Section 13 which has the effect of increasing Director liability
shall operate prospectively only, and shall not affect action taken, or any
failure to act, prior to its adoption.
13
<PAGE>
SECTION 13. Applicable Law. Pennsylvania Business Corporation Law of
---------------
1988, as amended, Title 15, Part II, Subpart B, Article C, Chapter 25,
Subchapters G through J, shall not apply to the Corporation.
ARTICLE III
COMMITTEES
Committees. The Board of Directors may by resolution designate and
-----------
discontinue such standing or special committees, including an Executive
Committee, as it deems desirable. Each committee shall have such powers and
perform such duties, not inconsistent with law, as may be assigned by the Board
of Directors.
ARTICLE IV
OFFICERS
SECTION 1. Executive Officers. The executive officers of the
-------------------
Corporation shall be a Chairman of the Board, a President, one or more Vice
Presidents, a Secretary, a Treasurer and a Controller. The Chairman of the
Board and the President shall be chosen from among the Directors. The executive
officers shall be elected annually by the Board of Directors at its first
meeting following the annual meeting, and each such officer shall hold
14
<PAGE>
office until the corresponding meeting in the next year and until a successor
has been duly chosen and qualified, or until such officer's earlier death,
resignation or removal. Any vacancy in the above offices may be filled for the
unexpired portion of the term by the Board of Directors, at any regular or
special meeting.
SECTION 2. Chairman of the Board. The Chairman of the Board shall
----------------------
preside at any meeting of the stockholders or of the Board of Directors and
shall have all the powers and authority vested in a presiding officer by law or
practice to conduct an orderly meeting. In addition to any specific powers
conferred by these By-Laws, the Chairman of the Board shall have the powers and
duties assigned by the Board of Directors.
SECTION 3. President. In addition to any specific powers conferred
----------
by these By-Laws, the President shall have the powers and duties assigned by the
Board of Directors. At the request or in the absence or disability of the
Chairman of the Board, the President shall preside at any meeting of the
stockholders or of the Board of Directors.
SECTION 4. Chief Executive Officer. The Board of Directors shall
------------------------
designate the Chairman of the Board or President or the person holding both of
such offices to perform the functions of the Chief Executive Officer. The Chief
Executive Officer shall carry out the policies approved by the Board of
Directors. In addition to any specific powers conferred by these
15
<PAGE>
By-Laws, the Chief Executive Officer shall have supervision over, and shall
exercise general executive powers concerning, all the operations and business of
the Corporation. The Chief Executive Officer shall also have and exercise such
powers and duties as assigned by the Board of Directors and may delegate
executive and other powers and duties to any other officer.
SECTION 5. Vice Presidents. At the request of the President, or in
----------------
the absence or disability of the President, any Vice President shall perform the
duties of the President, and when so acting shall have the powers of the
President, unless otherwise determined by the Board of Directors. Each Vice
President shall also have and exercise such powers and duties as assigned by the
Board of Directors or the Chief Executive Officer.
SECTION 6. Secretary. The Secretary shall perform all duties
----------
incident to the office of a secretary of a corporation, and such other duties as
assigned by the Board of Directors or the Chief Executive Officer.
SECTION 7. Treasurer. The Treasurer shall perform all the duties
----------
incident to the office of a treasurer of a corporation, and such other duties as
assigned by the Board of Directors or the Chief Executive Officer.
16
<PAGE>
SECTION 8. Controller. The Controller shall perform all duties
-----------
incident to the office of a controller of a corporation, and such other duties
as assigned by the Board of Directors or the Chief Executive Officer.
SECTION 9. Assistant Officers. The Board of Directors may elect one
-------------------
or more Assistant Vice Presidents, Assistant Secretaries and Assistant
Treasurers. Each assistant officer shall hold office for such period and shall
have such authority and perform such duties as the Board of Directors or the
Chief Executive Officer may prescribe.
SECTION 10. Certain Powers of Officers. Except in cases in which the
--------------------------
signing and execution shall have been expressly delegated by the Board of
Directors to some other officer, employee or agent of the Corporation, the
Chairman of the Board or President or a Vice President may sign and execute in
the name of the Corporation all authorized deeds, mortgages, bonds, contracts or
other instruments; provided, however, that a Vice President may delegate to any
General Manager or Manager reporting to such officer authority to sign and
execute in the name of the Corporation all authorized contracts and similar
instruments pursuant to a policy approved by the Board of Directors.
SECTION 11. Compensation. The Board of Directors shall have the
-------------
power to fix the compensation of the Chairman of the Board, President and any
Vice President of the Corporation.
17
<PAGE>
The Chief Executive Officer shall have the power to fix the compensation of the
Secretary, the Treasurer, the Controller and assistant officers.
ARTICLE V
STOCK
SECTION 1. Certificates. Every stockholder shall be entitled to a
-------------
certificate or certificates of stock of the Corporation in a form prescribed by
the Board of Directors, duly numbered and sealed with the corporate seal of the
Corporation, and setting forth the number and kind of shares represented
thereby; provided however, that the Board of Directors shall have the power to
provide for uncertificated shares of any class or series of stock or any part
thereof. The certificates shall be signed, by facsimile or otherwise, by the
Chairman of the Board, the President or a Vice President and by the Treasurer or
the Secretary and shall bear the corporate seal, which may be a facsimile,
engraved or printed. The Board of Directors may also appoint one or more
Transfer Agents and/or Registrars for its stock of any class and may require
stock certificates to be countersigned, by facsimile or otherwise, and/or
registered by one or more of such Transfer Agents and/or Registrars. In case any
officer, Transfer Agent or Registrar who has signed or whose facsimile signature
or authentication has been placed upon any share certificate shall have ceased
to be such officer, Transfer
18
<PAGE>
Agent or Registrar because of death, resignation or otherwise, before the
certificate is issued, the certificate may be issued with the same effect as if
the officer, Transfer Agent or Registrar had not ceased to be such at the date
of its issue.
SECTION 2. Transfer of Shares. The Board of Directors shall have
-------------------
power and authority to make all rules and regulations concerning the issue,
transfer, and registration of certificates of stock.
SECTION 3. Record Dates. The Board of Directors shall have the
-------------
authority to fix in advance a date, not exceeding ninety (90) days preceding any
meeting of stockholders, or the date for payment of any dividend, or the date
for the allotment of rights, or the date when any change, conversion, or
exchange of capital stock shall go into effect (each a "stockholder event"), as
a record date, in connection with such stockholder event, and in such case only
such stockholders as shall be stockholders of record on the date so fixed shall
be entitled to participate in such stockholder event, notwithstanding any
transfer of any stock on the books of the Corporation after any such record
date.
SECTION 4. Mutilated, Lost or Destroyed Certificates.
-----------------------------------------
The holder of any certificate representing shares of stock of the Corporation
shall immediately notify the Corporation of any mutilation, loss or destruction
thereof, and the Board of Directors may, in its discretion, cause one or more
new certificates, for the same number of shares in the aggregate, to
19
<PAGE>
be issued to such holder upon the surrender of the mutilated certificate, or in
case of loss or destruction of the certificate, upon satisfactory proof of such
loss or destruction and the deposit of indemnity by way of bond or otherwise, in
such form and amount and with such sureties or security as the Board of
Directors may require to indemnify the Corporation against loss or liability by
reason of the issuance of such new certificate or certificates, and the failure
of such holder to comply with such requirements shall constitute a waiver by
such holder of any right to receive such new certificate or certificates.
ARTICLE VI
DIVIDENDS AND FINANCE
SECTION 1. Dividends. Subject to the provisions of the Articles, the
----------
Board of Directors, or an authorized Committee may, in its discretion, declare
what, if any, dividends shall be paid upon the stock of the Corporation. Except
as otherwise provided by the Articles, dividends shall be payable upon such
dates as the Board of Directors may designate. Before payment of any dividend
there may be set aside out of any funds of the Corporation available for
dividends such sum or sums as the Directors, in their absolute discretion, think
proper as a reserve fund to meet contingencies, for equalizing dividends, or for
repairing or maintaining any property of the Corporation, or
20
<PAGE>
for such other purposes as the Directors shall think conducive to the interests
of the Corporation, and the Directors may abolish any such reserve in the manner
in which it is created.
SECTION 2. Checks, Drafts, Etc. Unless otherwise provided by
--------------------
resolution of the Board of Directors, all checks, drafts, or orders for the
payment of money, notes, and other evidences of indebtedness, issued in the name
of the Corporation, shall be signed by the Treasurer or an Assistant Treasurer
and countersigned by the Chairman of the Board, the President or a Vice
President.
SECTION 3. Fiscal Year. The fiscal year of the Corporation shall be
------------
the calendar year, unless otherwise provided by the Board of Directors.
ARTICLE VII
SUNDRY PROVISIONS
SECTION 1. Seal. The Corporate Seal of the Corporation shall contain
-----
within a circle the words "DQE", and in an inner circle the word "SEAL".
SECTION 2. Inspection of Books and Records. The Board of Directors
--------------------------------
may determine whether and, if allowed, when and under what conditions and
regulations, the books and records of
21
<PAGE>
the Corporation shall be open to the inspection of stock-holders, and the rights
of stockholders in this respect are and shall be limited accordingly, except as
otherwise provided by statute. No stockholder has the right to inspect any book
or record or receive any statement for an improper purpose.
SECTION 3. Bonds. The Board of Directors may require any officers,
------
agents, or employees of the Corporation to give a bond to the Corporation,
conditioned upon the faithful discharge of their duties, with one or more
sureties and in such amount as may be satisfactory to the Board of Directors.
SECTION 4. Voting Upon Stock in Other Corporations. Any stock in
----------------------------------------
other corporations, which may be held by the Corporation, may be represented and
voted at any meeting of stockholders of such other corporations by the Chairman
of the Board, the President or a Vice President of the Corporation or by proxy
executed in the name of the Corporation by the Chairman of the Board, the
President or a Vice President.
SECTION 5. Amendments. Except as provided by the Articles or by
-----------
statute, the authority to adopt, amend and repeal the By-Laws is exclusively
vested in the Board of Directors.
SECTION 6. Participation in Meeting by Telephone. One or more
--------------------------------------
Directors may participate in a meeting of the Board of Directors or a committee
of the Board of Directors by means of
22
<PAGE>
a conference telephone or similar communications equipment by means of which all
persons participating in the meeting can communicate with each other.
SECTION 7. Informal Action by Directors or Committees.
-------------------------------------------
Any action which may be taken at a meeting of the Board of Directors or a
committee of the Board of Directors may be taken without a meeting if a consent
or consents in writing setting forth the action so taken shall be signed by all
of the Directors or the members of the committee and shall be filed with the
Secretary of the Corporation.
23
<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>
Six-Months
Ended Year Ended December 31,
June 30, -----------------------------------------------------------------
1999 1998 1997 1996 1995 1994
---------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt $ 37,849 $ 81,076 $ 87,420 $ 88,478 $ 95,391 $101,027
Other interest 10,472 14,556 13,823 10,926 7,033 4,050
Portion of lease payments
representing an interest factor 20,942 44,146 44,208 44,357 44,386 44,839
Dividend requirement 8,084 15,612 21,649 14,385 7,374 9,355
-------- -------- -------- -------- -------- --------
Total Fixed Charges $ 77,348 $155,390 $167,100 $158,146 $154,184 $159,271
-------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations $ 90,071 $196,688 $199,101 $179,138 $170,563 $156,816
Income taxes 43,856* 100,982* 95,805* 87,388* 96,661* 92,973*
Fixed Charges as above 77,348 155,390 167,100 158,146 154,184 159,271
-------- -------- -------- -------- -------- --------
Total Earnings $211,275 $453,060 $462,006 $424,672 $421,408 $409,060
-------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.73 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 $1.2 million for the six months ended
June 30, 1999, has been excluded from the ratio.
*Earnings related to income taxes reflect a $2.0 million decrease for the six
months ended June 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 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 2.76 for the six months ended June 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.
1
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> JUN-30-1999
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,455,491
<OTHER-PROPERTY-AND-INVEST> 1,080,062
<TOTAL-CURRENT-ASSETS> 360,516
<TOTAL-DEFERRED-CHARGES> 2,409,030
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 5,305,099
<COMMON> 73,119
<CAPITAL-SURPLUS-PAID-IN> 926,751
<RETAINED-EARNINGS> 900,977
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,444,144<F1>
4,500
263,242<F2>
<LONG-TERM-DEBT-NET> 1,271,213
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 173,951
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 178,635
0
<CAPITAL-LEASE-OBLIGATIONS> 14,992
<LEASES-CURRENT> 40,016
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,914,406
<TOT-CAPITALIZATION-AND-LIAB> 5,305,099
<GROSS-OPERATING-REVENUE> 652,884
<INCOME-TAX-EXPENSE> 45,732<F3>
<OTHER-OPERATING-EXPENSES> 515,469
<TOTAL-OPERATING-EXPENSES> 515,469
<OPERATING-INCOME-LOSS> 137,415
<OTHER-INCOME-NET> 73,106
<INCOME-BEFORE-INTEREST-EXPEN> 210,521
<TOTAL-INTEREST-EXPENSE> 74,718<F4>
<NET-INCOME> 90,071
728
<EARNINGS-AVAILABLE-FOR-COMM> 89,343
<COMMON-STOCK-DIVIDENDS> 58,037
<TOTAL-INTEREST-ON-BONDS> 37,849
<CASH-FLOW-OPERATIONS> 122,023
<EPS-BASIC> 1.17
<EPS-DILUTED> 1.14
<FN>
<F1>Includes $(456,703) of Treasury Stock at cost.
<F2>Includes $13,832 of Preference Stock.
<F3>Non-Operating Expense.
<F4>Includes $8,311 of Preferred and Preference Stock Dividends.
</FN>
</TABLE>
