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, 1998
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[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From __________ to __________
Commission File Number
----------------------
1-10290
DQE, Inc.
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-1598483
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Cherrington Corporate Center, Suite 100
500 Cherrington Parkway, Coraopolis, Pennsylvania 15108-3184
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 262-4700
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE Common Stock, no par value - 77,736,355 shares outstanding as of June 30,
1998 and 77,736,880 shares outstanding as of July 31, 1998.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
DQE
CONDENSED STATEMENT OF CONSOLIDATED INCOME
(Thousands, Except Per Share Amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------- --------
1998 1997 1998 1997
---- ---- ---- ----
Operating Revenues
Sales of Electricity $272,436 $256,811 $543,815 $529,560
Other 28,324 27,189 52,970 58,024
-------------- -------------- -------------- --------------
Total Operating Revenues 300,760 284,000 596,785 587,584
-------------- -------------- -------------- --------------
Operating Expenses
Fuel and purchased power 71,575 50,516 131,108 102,170
Other operating 71,243 76,881 148,518 158,513
Maintenance 15,669 22,551 35,952 40,300
Depreciation and amortization 57,649 58,546 114,834 113,720
Taxes other than income taxes 19,675 19,875 39,607 40,433
-------------- -------------- -------------- --------------
Total Operating Expenses 235,811 228,369 470,019 455,136
-------------- -------------- -------------- --------------
OPERATING INCOME 64,949 55,631 126,766 132,448
-------------- -------------- -------------- --------------
Other Income 28,129 42,451 59,547 60,952
-------------- -------------- -------------- --------------
Interest and Other Charges 27,313 29,029 54,931 57,709
-------------- -------------- -------------- --------------
INCOME BEFORE INCOME TAXES AND
EXTRAORDINARY ITEM 65,765 69,053 131,382 135,691
-------------- -------------- -------------- --------------
Income Taxes 25,561 22,275 46,048 43,816
-------------- -------------- -------------- --------------
INCOME Before Extraordinary Item 40,204 46,778 85,334 91,875
Extraordinary Item (Net of Tax) (82,548) -- (82,548) --
-------------- -------------- -------------- --------------
NET INCOME (LOSS) After Extraordinary Item $(42,344) $ 46,778 $ 2,786 $ 91,875
============== ============== ============== ==============
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 77,720 77,394 77,702 77,341
============== ============== ============== ==============
BASIC EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
Before Extraordinary Item $ 0.52 $ 0.61 $ 1.10 $ 1.19
============== ============== ============== ==============
Extraordinary Item $ (1.06) -- $ (1.06) --
============== ============== ============== ==============
After Extraordinary Item $ (0.54) $ 0.61 $ 0.04 $ 1.19
============== ============== ============== ==============
DILUTED EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
Before Extraordinary Item $ 0.51 $ 0.60 $ 1.08 $ 1.17
============== ============== ============== ==============
Extraordinary Item $ (1.06) -- $ (1.06) --
============== ============== ============== ==============
After Extraordinary Item $ (0.55) $ 0.60 $ 0.02 $ 1.17
============== ============== ============== ==============
DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $ 0.36 $ 0.34 $ 0.72 $ 0.68
============== ============== ============== ==============
See notes to condensed consolidated financial statements.
2
DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
June 30, December 31,
1998 1997
---- ----
ASSETS
Current assets:
Cash and temporary cash investments $ 269,214 $ 356,412
Receivables 136,145 131,711
Other current assets, principally materials and supplies 104,293 81,233
-------------------- -------------------
Total current assets 509,652 569,356
-------------------- -------------------
Long-term investments 728,815 722,786
-------------------- -------------------
Property, plant and equipment 4,701,051 4,625,128
Less: Accumulated depreciation and amortization (3,239,528) (1,962,794)
-------------------- -------------------
Property, plant and equipment - net 1,461,523 2,662,334
-------------------- -------------------
Other non-current assets:
Regulatory assets 2,272,292 680,885
Other 64,599 59,041
-------------------- -------------------
Total other non-current assets 2,336,891 739,926
-------------------- -------------------
TOTAL ASSETS $ 5,036,881 $ 4,694,402
==================== ===================
LIABILITIES AND CAPITALIZATION
Current liabilities $ 158,045 $ 281,966
-------------------- -------------------
Deferred income taxes - net 714,329 693,215
-------------------- -------------------
Deferred income 169,640 225,107
-------------------- -------------------
Beaver Valley lease liability 478,442 --
-------------------- -------------------
Other non-current liabilities 387,304 390,789
-------------------- -------------------
Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,434,607 1,376,121
-------------------- -------------------
Preferred and preference stock of subsidiaries 226,077 226,503
-------------------- -------------------
Preferred stock 22,484 1,548
-------------------- -------------------
Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
issued - 109,679,154 shares) 1,000,273 1,001,225
Retained earnings 816,582 869,749
Less treasury stock (at cost) (31,942,799 and 31,998,723
shares, respectively) (370,902) (371,821)
-------------------- -------------------
Total common shareholders' equity 1,445,953 1,499,153
-------------------- -------------------
Total capitalization 3,129,121 3,103,325
-------------------- -------------------
TOTAL LIABILITIES AND CAPITALIZATION $ 5,036,881 $ 4,694,402
==================== ===================
See notes to condensed consolidated financial statements.
3
DQE
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Six Months Ended
June 30,
--------
1998 1997
---- ----
Cash Flows From Operating Activities
Operations $ 277,992 $ 219,600
Changes in working capital other than cash (130,956) (72,802)
(Increase) decrease in ECR (19,219) 1,492
Other 7,766 2,318
--------------- ---------------
Net Cash Provided By Operating Activities 135,583 150,608
--------------- ---------------
Cash Flows From Investing Activities
Capital expenditures (97,908) (42,975)
Proceeds from the sale of equity securities -- 42,895
Long-term investments - net (26,575) (192,088)
Other 858 312
--------------- ---------------
Net Cash Used in Investing Activities (123,625) (191,856)
--------------- ---------------
Cash Flows From Financing Activities
Reductions of long term obligations - net (36,938) (12,849)
Dividends on common stock (55,953) (52,592)
Increase in notes payable 4,404 38,000
Other (10,669) 1,855
--------------- ---------------
Net Cash Used in Financing Activities (99,156) (25,586)
--------------- ---------------
Net decrease in cash and temporary cash investments (87,198) (66,834)
Cash and temporary cash investments at beginning of period 356,412 410,978
--------------- ---------------
Cash and temporary cash investments at end of period $ 269,214 $ 344,144
=============== ===============
Non-Cash Investing and Financing Activities
Preferred stock issued in conjunction with long-term investments $ 20,936 --
=============== ===============
Capital lease obligations recorded $ 4,941 $ 4,086
=============== ===============
Equity funding obligations recorded $ -- $ 17,491
=============== ===============
On May 1, 1997, DQE exchanged its shares in Chester Engineers for shares of
common stock which were subsequently sold at various dates through June 1997.
See notes to condensed consolidated financial statements.
4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting DQE, Inc. and its subsidiaries'
(the Company's) operations, markets, products, services and prices, and other
factors discussed in the Company's filings with the Securities and Exchange
Commission (SEC).
1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES
DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne); Duquesne Enterprises, Inc. (DE); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); and Montauk, Inc.
(Montauk). DQE and its subsidiaries are collectively referred to as "the
Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE acquires and develops businesses involved in energy services
and technologies, energy monitoring and controls, telecommunications, monitored
security and electronic commerce. DES is a diversified energy services company
offering a wide range of energy solutions for industrial, utility and consumer
markets worldwide. DES initiatives include energy facility development and
operation, domestic and international independent power production, and the
production and supply of innovative fuels. DQEnergy was formed to align DQE with
strategic partners to capitalize on opportunities in the energy services
industry. These alliances are intended to enhance the utilization and value of
DQE's strategic investments and capabilities while establishing DQE as a total
energy provider. Montauk is a financial services company that makes long-term
investments and provides financing for the Company's other market-driven
businesses and their customers.
As previously reported, in August 1997 the shareholders of the Company and
Allegheny Energy, Inc. (AYE), approved a proposed tax-free, stock-for-stock
merger, pursuant to which DQE would have become a wholly owned subsidiary of
AYE. On May 29, 1998, the Pennsylvania Public Utility Commission (PUC) issued
its final order (modified on July 23) approving the proposed merger, subject to
certain preconditions and stranded cost calculations. On July 28, the Company
announced its decision not to consummate the merger under the circumstances
associated with the final order. (See "Restructuring Plans and PUC Proceedings"
discussion, Note 2, page 8.)
All material intercompany balances and transactions have been eliminated in
the preparation of the condensed consolidated financial statements.
In the opinion of management, the unaudited condensed consolidated
financial statements included in this report reflect all adjustments that are
necessary for a fair presentation of the results of interim periods and are
normal, recurring adjustments. Prior periods have been reclassified to conform
with accounting presentations adopted during 1998.
These statements should be read with the financial statements and notes
included in the Annual Report on Form 10-K filed with the SEC for the year ended
December 31, 1997. The results of operations for the three and six months ended
June 30, 1998, 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.
5
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 final order regarding the Company's Stand-Alone
Plan and Merger Plan under the Customer Choice Act (see "Rate Matters", Note 2,
on page 7), the electricity generation portion of the Company's business no
longer meets the criteria of Statement of Financial Accounting Standards (SFAS)
No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, application of SFAS No. 71 to this portion of the Company's
business has been discontinued and replaced by the application of SFAS No. 101,
Regulated Enterprises Accounting for the Discontinuation of Application of FASB
Statement No. 71 (SFAS No. 101) as interpreted by EITF 97-4, Deregulation of the
Pricing of Electricity Issues Related to the Application of FASB Statements No.
71 and 101. Under SFAS No. 101, the regulatory assets and liabilities of the
generation portion of the Company are determined on the basis of the source from
which the regulated cash flows to realize such regulatory assets and settle such
liabilities will be derived. Pursuant to the PUC's final restructuring order,
certain of the Company's generation-related regulatory assets will be recovered
through a competitive transition charge (CTC) collected in connection with
providing transmission and distribution services. The Company will continue to
apply SFAS No. 71 with respect to such assets. 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 to Be Disposed
Of (SFAS No. 121). Under SFAS No. 121, all but approximately $46 million of the
Company's generating fixed assets are impaired. Pursuant to the PUC's final
restructuring order, with the exception of certain disallowances, the above-
market generation costs also will be recovered through the CTC. Accordingly,
these above-market costs have been reclassified on the condensed consolidated
balance sheet from "Property, plant and equipment" to "Regulatory assets". To
the extent that the Company is able to recover more than $46 million through the
divestiture of its generating plants, any excess recovery will be applied to
reduce the costs to be recovered through the CTC. The electricity transmission
and distribution portion of the Company's business continues to meet the SFAS
No. 71 criteria and accordingly reflects regulatory assets and liabilities
consistent with cost-based ratemaking regulations. (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 and, also through
the ECR, 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 orders regarding the Company's Merger Plan and Stand-Alone Plan (see "Rate
Matters", Note 2, on page 7), such fuel costs are no longer recoverable through
the ECR. Instead, effective May 29, 1998 (the date of the PUC's final
restructuring order), for customers with bundled rates, fuel costs are expensed
as incurred and impact net income.
Under-recoveries from customers have been recorded on the condensed
consolidated balance sheet as a regulatory asset. At May 29, 1998, $42.7 million
was receivable from customers. The Company expects to recover this amount
through the CTC. (See "Restructuring Plans and PUC Proceedings", Note 2, on page
8.) At December 31, 1997, $23.5 million was receivable from customers.
The Company's long-term investments include assets of nuclear
decommissioning trusts and marketable securities accounted for in accordance
with SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities. These investments are classified as available-for-sale and are
stated at market value. The amounts of unrealized holding gains related to
marketable securities at June 30, 1998, and December 31, 1997, were $6.3 million
and $8.1 million ($3.7 million and $4.7 million net of tax), respectively.
6
2. RATE MATTERS
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in
response to development of open transmission access and increased availability
of energy alternatives. 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 historical ratemaking process, utilities have assets recorded on their
balance sheets at above-market costs, thus creating transition or stranded
costs.
In Pennsylvania, the Customer Choice Act went into effect 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, delivery of the
electricity from the generation supplier to the customer will remain the
responsibility of the existing franchised utility. The Customer Choice Act also
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 (running through 1998) and a phase-in to competition period (beginning in
1999).
Customer Choice Pilots
The pilot period gives utilities an opportunity to examine a wide range of
technical and administrative details related to competitive markets, including
metering, billing, and cost and design of unbundled electric services. The
28,000 customers participating in the Company's pilot may choose unbundled
service, with their electricity provided by an alternative generation supplier,
and will be subject to unbundled distribution and CTC charges approved by the
PUC and unbundled transmission charges pursuant to the Company's FERC-approved
tariff. Although the pilot program was implemented, pursuant to the PUC's
order, on November 3, 1997, the Company earlier appealed the determination of
the market price of generation set forth in the PUC's order to the Commonwealth
Court of Pennsylvania. Argument has not yet been scheduled.
Phase-In to Competition
As required by the PUC in its restructuring orders (see "Restructuring
Plans and PUC Proceedings" discussion on page 8), the phase-in to competition
begins in January 1999, when 66 percent of customers will have customer choice
(including customers covered by the pilot program); all customers will have
customer choice in January 2000. As of the date of this report, approximately 41
percent of the Company's customers had elected to participate in the customer
choice program beginning in January 1999. As they are phased-in, customers that
have chosen an electricity generation supplier other than the Company will pay
that supplier for generation charges, and will pay the Company a CTC (discussed
below) and unbundled charges for transmission and distribution. Customers that
continue to buy their generation from the Company will pay for their service at
current regulated tariff rates divided into unbundled generation, transmission
and distribution charges. Under the Customer Choice Act, an electric
distribution company, such as Duquesne, is to remain a regulated utility and may
only offer PUC-approved, tariffed rates, including unbundled generation rates
(capped at current levels so long as a CTC is being collected). Delivery of
electricity (including transmission, distribution and customer service) will
continue to be regulated in substantially the same manner as under current
regulation.
7
Rate Cap and Transition Cost Recovery
An overall four-and-one-half-year rate cap from January 1, 1997, will be
imposed on the transmission and distribution charges of electric utility
companies. Additionally, electric utility companies may not increase the
generation price component of bundled rates as long as transition costs are
being recovered, with certain exceptions. The Company requested recovery of
transition costs of approximately $1.9 billion, net of deferred taxes, beginning
January 1, 1999. Of this amount, $0.4 billion represented regulatory assets and
$1.5 billion represented potentially uneconomic plant and plant decommissioning
costs. Portions of the requested transition cost recovery have been disallowed
by the PUC in its final orders (discussed below).
Restructuring Plans and PUC Proceedings
On August 1, 1997, Duquesne filed its stand-alone restructuring plan
(Stand-Alone Plan) in the event the merger of DQE and AYE is not consummated,
and DQE and AYE filed their application to merge and restructuring plan (Merger
Plan). A more detailed discussion of each of these plans is set forth in the
Annual Reports on Form 10-K for the Year Ended December 31, 1997, of Duquesne
and DQE. On May 29, 1998, the PUC issued final orders on the Stand-Alone Plan
and Merger Plan. On June 18, Duquesne submitted its compliance filing, which
would implement the PUC's final order regarding the Stand-Alone Plan or the
Merger Plan, as the case may be. The compliance filing also included Duquesne's
request that the PUC recalculate the CTC and shopping credit determination set
forth in the final orders; Duquesne estimates that, correcting for computational
errors, the 1999 average CTC should be 2.73 cents per kilowatt-hour (KWH)
(resulting in a shopping credit of 3.49 cents per KWH). Duquesne, DQE and AYE
also petitioned the PUC to reconsider its final restructuring orders. The PUC
denied Duquesne's petition to reconsider its Stand-Alone Plan final order, and
recommended that any reconsideration could be better addressed in Duquesne's
compliance filing. The PUC accepted DQE's and AYE's petition to reconsider the
Merger Plan final order. The orders and reconsideration are discussed below.
Order on the Stand-Alone Plan. With respect to stranded cost recovery, the
PUC's final order on the Stand-Alone Plan approves Duquesne's proposal to
auction its generating assets and use the proceeds to offset stranded costs. The
remaining balance of such costs (with certain exceptions described below) will
be recovered from ratepayers through a CTC, collectible through 2005. As
required, Duquesne will submit a divestiture plan to the PUC by August 27, 1998.
Duquesne has been ordered to use an interim system average CTC set at 2.9 cents
per KWH (resulting in a shopping credit of 3.75 cents per KWH), the rate
approved in its pilot program. The final CTC determined by the auction will
remain constant over the recovery period. The PUC's order approves the auction
only in the context of the Stand-Alone Plan, not the Merger Plan.
By conducting the auction, Duquesne expects to recover (through the auction
proceeds or the final CTC) or avoid the incurrence of all its stranded
generation costs, with the exception being a $65 million disallowance (net
present value, after tax) related to Duquesne's cold reserved units at the
Phillips Power Station and Brunot Island Power Station. The PUC's final order
also approves recovery of $339 million of the $357 million in regulatory assets
claimed by Duquesne. The disallowed regulatory assets relate primarily to
deferred coal costs under previously applied coal caps and deferred caretaker
costs associated with the cold reserved units.
At June 30, 1998, Duquesne recorded a charge to its earnings of $142.3
million ($82.5 million net of taxes) to reflect the disallowance associated with
the investments in cold reserved units and the disallowance of a portion of the
regulatory asset claim.
8
Order on the Merger Plan. The PUC's final order on the merger (as modified
during the reconsideration process) would allow the transaction to be
consummated but requires the parties, prior to closing, to agree to certain
conditions. The conditions relate to the mitigation of market power, including
membership in an independent system operator (ISO), an entity that would operate
the transmission facilities of Duquesne, AYE and other utilities in the region.
The PUC's final order would allow DQE and AYE to maintain their current
membership in the Midwest ISO, but the PUC held that the Midwest ISO must be
"fully functional" and it must satisfy seven criteria specified by the PUC no
later than June 30, 2000. In the meantime, the merged company would be required
to relinquish control of 570 megawatts of output from Duquesne's Cheswick Power
Station (Cheswick). Divestiture of a further 2,500 megawatts would be required
if, based on a PUC evaluation in January 2000, the merged company continued to
fail certain market power tests and the Midwest ISO had not progressed
sufficiently toward a structure that fully mitigates market power. The PUC
would determine what generation assets would be divested and who would be
eligible to bid for them. DQE objects to the PUC's having authority over all
aspects of the divestiture, particularly the lack of any provision to adjust
stranded costs following the divestiture. In addition, the Midwest ISO, as
presently constituted and as proposed to the FERC, does not meet the seven
criteria specified by the PUC.
The PUC's final order regarding the Merger Plan also addressed the recovery
of stranded costs by Duquesne and AYE's wholly owned utility subsidiary West
Penn Power Company (West Penn) in the event the merger is consummated. The order
sets stranded costs at approximately $1.3 billion, using an administrative
forecast of generation market values and costs. Applied to Duquesne, and
compared to the Stand-Alone Plan, this methodology results in the disallowance
of an additional $370 million in stranded costs (net present value, pre-tax).
The PUC's final order also reduces Duquesne's recoverable stranded costs by $152
million for estimated generation-related merger synergies and reduces
distribution rates beginning January 1, 2000, by $15 million annually to reflect
estimated distribution-related merger synergies. The PUC's final order permits
transition cost recovery through 2005 pursuant to a CTC initially set at an
average of 2.58 cents per KWH for 1999 (resulting in a shopping credit, or
reduction from previously bundled rates, of 4.00 cents per KWH).
With respect to West Penn, the PUC's final order disallows recovery of
approximately $1 billion of West Penn's stranded cost claim (net present value,
pre-tax). Of the disallowed amount, approximately $830 million relates to the
impact of the administrative determination of generation market value and costs.
The other disallowances relate to regulatory assets, non-utility generation and
other transition costs. In addition, the PUC's final order reduces West Penn's
recoverable stranded costs by $71 million for generation-related merger
synergies and reduces distribution rates beginning January 1, 2000, by $9
million for distribution-related merger synergies.
DQE Announcement. On July 28, 1998, DQE's Board of Directors concluded
that it could not consummate the merger under the circumstances described above.
On that same date, DQE informed AYE of this conclusion. More information
regarding this decision is set forth in the Company's Current Report on Form 8-K
dated July 28, 1998.
On July 30, AYE informed DQE that it does not believe DQE has the right to
terminate the merger agreement under these circumstances, and that AYE will
continue to work toward consummation of the merger. AYE also stated it will
pursue all remedies available to protect the legal and financial interests of
AYE and its shareholders. With respect to the PUC's disallowance of
approximately $1 billion of stranded costs, AYE has filed an appeal in state
court and a complaint in federal court, challenging the order. In addition, a
settlement conference is scheduled for August 14 between AYE and the PUC
regarding the West Penn final order. Because various issues in West Penn's
restructuring order are related to Duquesne's Merger Plan (particularly with
respect to the recovery of stranded costs), and could impact DQE and its
shareholders, Duquesne plans to participate in the conference.
9
Regulatory Assets
As a result of the application of SFAS No. 71 to the transmission and
distribution portion of Duquesne's business, and as certain generation-related
costs will be recovered through the CTC collected in connection with the rate-
regulated portion of the business, the Company records regulatory assets on its
consolidated balance sheet. 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.
Fixed assets related to the generation portion of the Company's business
are evaluated in accordance with SFAS No. 121. Under SFAS No. 121, all but
approximately $46 million of the Company's generating fixed assets are impaired.
Pursuant to the PUC's final restructuring order, with the exception of certain
disallowances, the above-market generation costs also will be recovered through
the CTC. Accordingly, these above-market costs have been reclassified on the
condensed consolidated balance sheet from "Property, plant and equipment" to
"Regulatory assets". (See Note 1.) As a result of the PUC's final restructuring
order, the BV Unit 2 lease costs will be recovered through the CTC. The lease
has been classified on the condensed consolidated balance sheet as a liability
with a corresponding regulatory asset.
The components of all regulatory assets for the periods presented are as
follows:
- --------------------------------------------------------------------------------
June 30, December 31,
1998 1997
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------
Generation-related transition costs $2,156,626 $561,867
Transmission and distribution-related costs 115,666 119,018
- --------------------------------------------------------------------------------
Total Regulatory Assets $2,272,292 $680,885
- --------------------------------------------------------------------------------
3. RECEIVABLES
The components of receivables for the periods indicated are as follows:
June 30, June 30, December 31,
1998 1997 1997
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
Electric customer accounts receivable $ 87,830 $ 88,314 $ 90,149
Other utility receivables 20,907 15,738 23,106
Other receivables 44,192 26,324 33,472
Less: Allowance for uncollectible accounts (16,784) (20,102) (15,016)
- -------------------------------------------------------------------------------------------------------------
Total Receivables $136,145 $110,274 $131,711
=============================================================================================================
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. At June 30, 1998, and June 30 and December
31, 1997, the Company had not sold any receivables to the unaffiliated
corporation. The accounts receivable sales agreement, which expires in June
1999, is one of many sources of funds available to the Company. The Company has
not determined, but may attempt to extend the agreement or to replace the
facility with a similar arrangement or to eliminate it upon expiration.
10
4. COMMITMENTS AND CONTINGENCIES
The Company currently anticipates divesting itself of its generating assets
and related obligations. (See "Order on the Stand-Alone Plan" discussion, Note
2, on page 8.) Certain of those obligations, which currently remain with the
Company, are discussed below.
Construction
The Company estimates that it will spend, excluding the Allowance for Funds
Used During Construction and nuclear fuel, approximately $130 million for
electric utility construction during 1998. The Company has committed to the
construction of six plants to produce E-Fuel(TM), a coal-based synthetic fuel,
in 1998. The Company estimates the cost of this construction to be
approximately $40 million.
Nuclear-Related Matters
The Company has an ownership or leasehold 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 Beaver Valley
Unit 1 (BV Unit 1), Beaver Valley Unit 2 (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 being used to determine the Company's cost of
service related to decommissioning all three nuclear units is $224 million. The
Company was not permitted to recover any potential shortfall in decommissioning
funding as part of either its Merger Plan or its Stand-Alone Plan. (See "Rate
Matters," Note 2, on page 7.)
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, 1998, totaled approximately $53.9 million.
Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act
of 1954 limit public liability from a single incident at a nuclear plant to $8.9
billion (increasing to $9.9 billion effective August 20). The maximum available
private primary insurance of $200 million has been purchased by the Company.
Additional protection of $8.7 billion (increasing to $9.7 billion) would be
provided by an assessment of up to $79.3 million (increasing to $88.1 million)
per incident on each licensed nuclear unit in the United States. The Company's
maximum total possible assessment, $59.4 million (increasing to $66.1 million),
which is based on its ownership or leasehold interests in three nuclear
generating units, would be limited to a maximum of $7.5 million per incident per
year. This assessment is subject to indexing for inflation and may be subject to
state premium taxes. If assessments from the nuclear industry prove insufficient
to pay claims, the United States Congress could impose other revenue-raising
measures on the industry.
The Company's share of insurance coverage for property damage,
decommissioning and decontamination liability is $1.2 billion. The Company would
be responsible for its share of any damages in excess of insurance coverage. In
addition, if the property damage reserves of Nuclear Electric Insurance Limited
(NEIL), an industry mutual insurance company that provides a portion of this
coverage, are inadequate to cover claims arising from an incident at any United
States nuclear site covered by that insurer, the Company could be assessed
retrospective premiums totaling a maximum of $7.3 million.
11
In addition, the Company 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 the estimated
incremental costs during the three-year period starting 21 weeks after an
accident, with no coverage thereafter. If NEIL's losses for this program ever
exceed its reserves, the Company could be assessed retrospective premiums
totaling a maximum of $2.6 million.
Beaver Valley Power Station (BVPS). BVPS's two units are equipped with
steam generators designed and built by Westinghouse Electric Corporation
(Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter
stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of
both units. BV Unit 1, which was placed in service in 1976, has removed
approximately 17 percent of its steam generator tubes from service through a
process called "plugging." However, BV Unit 1 still has the capability to
operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called "sleeving." No tubes at
either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 2 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 to 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 fall of 2001.
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. The next refueling outage for
BV Unit 1 is currently scheduled to begin in the spring of 2000; however, the
Company may be required to perform an earlier inspection of BV Unit 1's tubes
and other equipment during a mid-cycle outage in 1999, in order to comply with
Nuclear Regulatory Commission (NRC) requirements to conduct such inspections at
BV Unit 1 at least every 20 months. The Company plans to inspect BV Unit 2's
tubes during the current forced outage in order to comply with NRC requirements
to conduct such inspections at BV Unit 2 at least every 24 months. The next
refueling outage for BV Unit 2 is currently scheduled to begin in March 1999.
The Company will continue to monitor and evaluate the condition of the BVPS
steam generators.
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review completed by the Company. BV Unit 2 went off-line December 16,
1997, to repair the emergency air supply system to the control room and has
remained off-line due to other issues identified by a technical review similar
to that performed at BV Unit 1. These technical reviews are in response to a
1997 commitment made by the Company to the NRC. The Company is one of many
utilities faced with similar issues, some of which date back to the initial
start-up of BVPS. The Company has completed a series of meetings with the NRC to
review its action plans. As of the date of this report, BV Unit 1 is in its
start-up mode and is expected to be at full power shortly. Although BV
Unit 2 is expected to remain off-line until the action plans have been
satisfactorily completed, the Company and the NRC have been discussing proposed
plans to return the unit to service during the third quarter of 1998. The
foregoing sentences contain forward-looking statements, (within the meaning of
the Private Securities Litigation Act of 1995). Actual results may differ
materially from those implied due to such risks as unforeseen mechanical
difficulties arising in
12
the normal course of starting up the units following the current outages,
additional technical specifications issues being identified, or unforeseen
difficulties arising as a consequence of the tube inspection at BV Unit 2.
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 2017, 2011 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, was not entirely in
favor of the DOE or the utilities. The court permitted the DOE to pursue
alternative dispute resolution, but prohibited it from using its lack of a spent
fuel repository as a defense.
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 (NEPA) and are to be paid by such utilities over a 15-year
period. At each of June 30, 1998 and December 31, 1997, the Company's liability
for contributions was approximately $7.2 million (subject to an inflation
adjustment). (See "Rate Matters," Note 2, on page 7.)
Fossil Decommissioning
Based on studies conducted in 1997, the amount for fossil decommissioning
is currently estimated to be $130 million for the Company's interest in 17 units
at six sites. Each unit is expected to be decommissioned upon the cessation of
the unit's final operations. The Company was not permitted to recover these
costs as part of either its Merger Plan or its Stand-Alone Plan. (See "Rate
Matters", Note 2, on page 7.)
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, 1998, the Company's share of
these guarantees was $10.8 million. The prices paid for the coal by the
companies under this contract are expected to be sufficient to meet debt and
lease obligations to be satisfied in the year 2000. The minimum future payments
to be made by the Company solely in relation to these obligations are $11.7
million at June 30, 1998.
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 the underlying housing projects, the Company believes that such
deferrals are ample for this purpose.
13
Residual Waste Management Regulations
In 1992, the Pennsylvania Department of Environmental Protection (DEP)
issued Residual Waste Management Regulations governing the generation and
management of non-hazardous residual waste, such as coal ash. The Company is
assessing the sites it utilizes and has developed compliance strategies that are
currently under review by the DEP. Based on information currently available, $8
million will be spent in 1998 to comply with these DEP regulations. The
additional capital cost of compliance through the year 2000 is estimated, based
on current information, to be $16 million. This estimate is subject to the
results of groundwater assessments and DEP final approval of compliance plans.
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.
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.
14
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' (the Company's) Annual Report
on Form 10-K filed with the Securities and Exchange Commission (SEC) for the
year ended December 31, 1997 and the Company's condensed consolidated financial
statements, which are set forth on pages 2 through 14 in Part I, Item 1 of this
Report.
General
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DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne); Duquesne Enterprises, Inc. (DE); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); and Montauk, Inc.
(Montauk). DQE and its subsidiaries are collectively referred to as "the
Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE acquires and develops businesses involved in energy services
and technologies, energy monitoring and controls, telecommunications, monitored
security and electronic commerce. DES is a diversified energy services company
offering a wide range of energy solutions for industrial, utility and consumer
markets worldwide. DES initiatives include energy facility development and
operation, domestic and international independent power production, and the
production and supply of innovative fuels. DQEnergy was formed to align DQE with
strategic partners to capitalize on opportunities in the energy services
industry. These alliances are intended to enhance the utilization and value of
DQE's strategic investments and capabilities while establishing DQE as a total
energy provider. Montauk is a financial services company that makes long-term
investments and provides financing for the Company's other market-driven
businesses and their customers.
As previously reported, in August 1997 the shareholders of the Company and
Allegheny Energy, Inc. (AYE), approved a proposed tax-free, stock-for-stock
merger, pursuant to which DQE would have become a wholly owned subsidiary of
AYE. On May 29, 1998, the Pennsylvania Public Utility Commission (PUC) issued
its final order (modified on July 23) approving the proposed merger, subject to
certain preconditions and stranded cost calculations. On July 28, the Company
announced its decision not to consummate the merger under the circumstances
associated with the final order. (See "Restructuring Plans and PUC Proceedings"
discussion on page 23.)
The Company's Electric Service Territory
The Company's utility operations provide electric service to customers in
Allegheny County, including the City of Pittsburgh, Beaver County and
Westmoreland County. (See "Rate Matters" on page 22.) This represents
approximately 800 square miles in southwestern Pennsylvania, located within a
500-mile radius of one-half of the population of the United States and Canada.
The population of the area served by the Company's electric utility operations,
based on 1990 census data, is approximately 1,510,000, of whom 370,000 reside in
the City of Pittsburgh. In addition to serving approximately 580,000 direct
customers, the Company's utility operations also sell electricity to other
utilities.
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 22.)
15
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.
As a result of the PUC's final order regarding the Company's Stand-Alone
Plan and Merger Plan under the Customer Choice Act (see "Rate Matters" on page
22), the electricity generation portion of the Company's business no longer
meets the criteria of Statement of Financial Accounting Standards (SFAS) No. 71,
Accounting for the Effects of Certain Types of Regulation (SFAS No. 71).
Accordingly, application of SFAS No. 71 to this portion of the Company's
business has been discontinued and replaced by the application of SFAS No. 101,
Regulated Enterprises--Accounting for the Discontinuation of Application of FASB
Statement No. 71 (SFAS No. 101) as interpreted by EITF 97-4, Deregulation of the
Pricing of Electricity--Issues Related to the Application of FASB Statements No.
71 and 101. Under SFAS No. 101, the regulatory assets and liabilities of the
generation portion of the Company are determined on the basis of the source from
which the regulated cash flows to realize such regulatory assets and settle such
liabilities will be derived. Pursuant to the PUC's final restructuring order,
certain of the Company's generation-related regulatory assets will be recovered
through a competitive transition charge (CTC) collected in connection with
providing transmission and distribution services. The Company will continue to
apply SFAS No. 71 with respect to such assets. 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 to Be Disposed
Of (SFAS No. 121). Under SFAS No. 121, all but approximately $46 million of the
Company's generating fixed assets are impaired. Pursuant to the PUC's final
restructuring order, with the exception of certain disallowances, the above-
market generation costs also will be recovered through the CTC. Accordingly,
these above-market costs have been reclassified on the condensed consolidated
balance sheet from "Property, plant and equipment" to "Regulatory assets". To
the extent that the Company is able to recover more than $46 million through the
divestiture of its generating plants, any excess recovery will be applied to
reduce the costs to be recovered through the CTC. The electricity transmission
and distribution portion of the Company's business continues to meet the 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 22.)
RESULTS OF OPERATIONS
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Earnings and Dividends
On May 29, 1998, the PUC issued an order related to the Company's Merger
Plan and Stand-Alone Plan. In June the Company recorded an extraordinary charge
(Restructuring Charge) against earnings for the stranded costs not considered by
the PUC's order to be recoverable from customers. The Company's future
financial condition and its future operating results are substantially dependent
upon the effects of competition. (See "Rate Matters" on page 22.)
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: The
Company's earnings (loss) per share in the second quarter of 1998 and the second
quarter of 1997 were ($0.54) and $0.61. In the second quarter of 1998 the
Company recognized a net loss of ($42.3) million due to the Restructuring
Charge recorded in June 1998 for $142.3 million ($82.5 million, net of tax) or a
$1.06 reduction to earnings per share. Net income was $46.8 million in the
second quarter of 1997, of which approximately $7 million and a $0.09 increase
to earnings per share can be attributed to the gain on the sale of Chester
Engineers (Chester) in May 1997.
16
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The
Company's earnings per share for the six months ended June 30, 1998, and the six
months ended June 30, 1997, were $0.04 and $1.19. For the six months ended June
30, 1998, the Company's net income was $2.8 million and for the six months ended
June 30, 1997, the Company's net income was $91.9 million. The reduction in net
income can also be attributed to the Restructuring Charge and the gain
recognized on the sale of Chester in May 1997.
Excluding the Restructuring Charge and the gain on the sale of Chester,
1998 earnings per share for both the three and six months ended June 30 were the
same as for the comparable periods in 1997.
As a result of the Restructuring Charge in June 1998, Duquesne lost $0.68
per DQE share in the second quarter of 1998 and $0.26 per DQE share in the six
months ended June 30, 1998, a decrease from the prior year reported earnings per
share of $0.34 in the second quarter of 1997 and $0.80 in the six months ended
June 30, 1997. Due to the May 1997 gain on the sale of Chester, the market-
based operating activities earnings contribution dropped to $0.14 per share in
the second quarter of 1998, down from $0.27 of total earnings per share in the
second quarter of 1997. The contribution to earnings per share for the six
months ended June 30, 1998, and June 30, 1997 was $0.30 and $0.39, respectively,
for the market-based operating activities.
Revenues
Total operating revenues in the second quarter of 1998 increased $16.8
million or 5.9 percent as compared to the second quarter of 1997. Total
operating revenues in the six months ended June 30, 1998, increased $9.2 million
or 1.6 percent as compared to the six months ended June 30, 1997.
------------------------------------------------------------
(Revenues in Millions of Dollars) Increase(Decrease) from Prior Year
------------------------------------------------------------
Three Months Ended Six Months Ended
June 30, 1998 June 30, 1998
------------------------------------------------------------
Bundled Bundled
KWH Revenues KWH Revenues
------------------------------------------------------------
Residential (1.4)% $ 4.6 (4.8)% $ 3.6
Commercial (0.2)% 8.9 (3.8)% 8.4
Industrial (4.0)% 1.4 0.1 % 3.2
Less: Provision for Doubtful Accounts 0.0 0.0
- --------------------------------------------------------------------------------------------------------
Sales to Electric Utility Customers (1.6)% 14.9 (3.0)% 15.2
- --------------------------------------------------------------------------------------------------------
Sales to Other Utilities (9.2)% 0.7 (19.0)% (0.9)
Other Revenues 1.2 (5.1)
- --------------------------------------------------------------------------------------------------------
Total Sales (2.5)% $16.8 (5.0)% $ 9.2
========================================================================================================
Sales of Electricity to Customers
Operating revenues are primarily derived from the Company's sales of
electricity. Previously, the PUC authorized rates for electricity sales that
were cost-based and were designed to recover the Company's operating expenses
and investment in electric utility assets and to provide a return on the
investment. On May 29, 1998, the PUC unbundled charges for transmission,
distribution, generation and a CTC for customers who are eligible to choose
their generation supplier. Transmission and distribution rates are subject to a
rate cap through June 2001. Under the PUC's final order regarding the Stand-
Alone Plan, Duquesne's CTC will be adjusted to reflect the proceeds from the
divestiture of its generating assets. Generation rates are unregulated and will
fluctuate based upon competitive factors. For customers who are not yet
eligible to choose their generation supplier, fully-bundled, cost-based rates
will continue to be charged. Under prior fuel cost recovery provisions, fuel
revenues generally equaled fuel expense as the costs were recoverable from
customers through the Energy Cost Rate Adjustment Clause (ECR), including the
fuel component of
17
purchased power, and did not affect net income. Beginning May 29, 1998, for
customers with bundled rates, fuel costs are expensed as incurred and will now
have an impact on net income to the extent fuel costs exceed recovery amounts
included in Duquesne's previously authorized rates. Beginning May 29, 1998,
customer revenues fluctuate as a result of changes in sales volume. (See "Rate
Matters" on page 22.)
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.
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: In the
second quarter of 1998, net customer revenues reflected on the statement of
consolidated income increased by $14.9 million to $265.5 million from the second
quarter of 1997. The variance can be attributed to an increase in energy costs,
prior to the May 29, 1998 restructuring order, partially offset by a 1.6 percent
decrease in kilowatt-hour (KWH) sales to bundled electric utility customers.
Residential and commercial bundled sales decreased 13,223 KWH or 0.6 percent
when comparing the second quarter of 1998 and the second quarter of 1997. Due
to the implementation of the pilot program in November 1997, a reduction in
bundled electric utility customer sales resulted. Additionally, in response to
requirements of the retail customer choice, Duquesne completed a review of its
customer categorization during the second quarter of 1998. As a result,
approximately 400 customers were moved from the "industrial" to the "commercial"
category based upon historical maximum billed demand and Standard Industrial
Classification Codes. The change in categorization represents the reason for
the fluctuation in industrial sales.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: Net
customer revenues increased $15.2 million or 3.0 percent in the six months ended
June 30, 1998, as compared to the same period in 1997. The variance can be
attributed primarily to increased energy costs, prior to the May 29, 1998
restructuring order, partially offset by decreased bundled electric utility
customer KWH sales due to the implementation of the pilot program.
Additionally, in response to requirements of the retail customer choice,
Duquesne completed a review of its customer categorization during the second
quarter of 1998. As a result, approximately 400 customers were moved from the
"industrial" to the "commercial" category based upon historical maximum billed
demand and Standard Industrial Classification Codes. The change in
categorization represents the reason for the decrease in industrial sales that
was offset by sales to a new customer, an industrial gas supplier.
Sales to Other Utilities
Short-term sales to other utilities are regulated by the FERC and 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 and the Company's divestiture plan.
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: The
Company's electricity sales to other utilities in the second quarter of 1998
were $0.7 million or 10.8 percent greater than in the second quarter of 1997 due
to increased power market prices. This increase was offset by lower sales
volume due to reduced generating station availability as a result of an increase
in outage hours in 1998.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: In the
six months ended June 30, 1998, the Company's electricity sales to other
utilities were $0.9 million or 6.5 percent less than in the six months ended
June 30, 1997, due to reduced generating station availability as a result of a
24.8 percent increase in outage hours in 1998. Partially offsetting this
decrease were increases due to power market prices in 1998.
18
Other Operating Revenues
Other operating revenues include the Company's non-KWH utility revenues and
revenues from market-based operating activities.
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: The
other operating revenue increase of $1.2 million or 4.2 percent when comparing
the second quarter of 1998 to the second quarter of 1997 was primarily the
result of increased AquaSource, Inc. (AquaSource) revenues, and was partially
offset by the loss of revenues from the sale of Chester in May 1997. AquaSource
was formed by DQEnergy in 1997 to purchase small and mid-sized water companies.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The
decrease of $5.1 million or 8.7 percent in other operating revenues in the six
months ended June 30, 1998, as compared to 1997 was primarily due to the loss of
revenues from the sale of Chester in May 1997, and was partially offset by
AquaSource revenues.
Operating Expenses
Fuel and Purchased Power Expense
Fluctuations in fuel and purchased power expense generally result from
changes in the cost of fuel, the mix between coal and nuclear generation, the
total KWHs sold, and generating station availability. Because of the ECR,
changes in fuel and purchased power costs did not impact earnings in April or
May of 1998 or the second quarter of 1997. Beginning May 29, 1998, fuel costs
for bundled customers are being expensed as incurred and will now have an impact
on net income to the extent fuel costs exceed recovery amounts included in
Duquesne's previously authorized bundled rates. (See "Rate Matters" on page 22.)
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: Fuel
and purchased power expense increased $21.1 million or 41.7 percent in the
second quarter of 1998 as compared to the second quarter of 1997. The increase
resulted from higher energy costs of $23.5 million or 48.8 percent due to an
unfavorable power supply mix and higher purchased power prices. The increase
was partially offset by a $2.4 million decrease in energy volume supplied
primarily due to lower sales from the pilot program. Reduced availability of
generating stations due to an increase in outage hours forced the Company to
purchase power and generate power from the higher fuel cost fossil stations.
(See "Beaver Valley Power Station" on page 25.)
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The $28.9
million or 28.3 percent increase in fuel and purchased power expense for the six
months ended June 30, 1998, as compared to the six months ended June 30, 1997,
was the result of increased energy costs of $35.3 million or 36.9 percent due to
an unfavorable power supply mix and higher purchased power prices. Energy
volume supplied resulted in a $6.4 million reduction in fuel and purchased power
expenses primarily due to lower sales from the pilot program. Reduced
availability of generating stations due to a 24.8 percent increase in outage
hours forced the Company to purchase power and generate power from the higher
fuel cost fossil stations. (See "Beaver Valley Power Station" on page 25.)
BV Unit 1 and BV Unit 2 have continued to be off-line into the third
quarter. These outages, combined with various fossil station outages, have
caused the Company to continue to purchase larger than normal quantities of
electricity. Additionally, the market price for purchased power continues to be
higher than traditional levels. As a result of these higher costs and the
discontinuance of the ECR, fuel costs are expected to have a negative impact on
third quarter earnings. This impact has been partially mitigated by the fact
that during the second quarter of 1998 the Company entered into fixed-price firm
replacement power contracts.
19
Other Operating Expense
Comparison of Three Months Ended June 30, 1998, and June 30, 1997: Other
operating expenses decreased $5.6 million or 7.3 percent in the second quarter
of 1998 as compared to the second quarter of 1997. As a result of the PUC's
final restructuring order, the BV Unit 2 lease costs will be recovered through
the CTC. The lease has been classified on the condensed consolidated balance
sheet as a liability with a corresponding regulatory asset. Due to this
recharacterization, certain BV Unit 2 lease costs are reflected as amortization
expense, resulting in reduced levels of other operating expenses. The growth of
market-driven start-up and developmental activities increased expenses by
approximately $6 million.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: Other
operating expenses decreased $10.0 million or 6.3 percent when comparing the six
months ended June 30, 1998, to the same period for 1997. As a result of the
PUC's final restructuring order, the BV Unit 2 lease costs will be recovered
through the CTC. The lease has been classified on the condensed consolidated
balance sheet as a liability with a corresponding regulatory asset. Due to this
recharacterization, certain BV Unit 2 lease costs are reflected as amortization
expense, resulting in reduced levels of other operating expenses. The growth of
market-driven start-up and development activities increased expenses by
approximately $10 million. Reduced operating costs of $7.8 million can be
attributed to the May 1997 sale of Chester.
Maintenance Expense
Comparison of Three Months Ended June 30, 1998, and June 30, 1997:
Maintenance expense decreased $6.9 million or 30.5 percent when comparing the
second quarter of 1998 to the same period in 1997. The decrease is primarily
attributable to the timing of the Cheswick Power Station (Cheswick) maintenance
outage costs. Additionally, Elrama Power Station (Elrama) costs for scrubber
outages in 1997 were approximately $1.0 million. Partially offsetting the 1998
decreases were higher costs for tree trimming and storm-related maintenance of
overhead lines of $1.5 million.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997:
Maintenance expense decreased $4.3 million or 10.8 percent when comparing the
six months ended June 30, 1998, to the same period in 1997. The decrease is
primarily attributable to the timing of the Cheswick maintenance outage costs
and reduced nuclear station outage cost amortization in 1998. Partially
offsetting the 1998 decreases were higher costs for tree trimming and storm-
related maintenance of overhead lines of $3.3 million. Additionally Elrama had
higher costs in 1997 due to scrubber outages for approximately $1.0 million.
Other Income
Comparison of Three Months Ended June 30, 1998, and June 30, 1997:
Comparing the second quarter of 1998 and the second quarter of 1997, a decrease
of $14.3 million in other income was primarily the result of the sale of Chester
in May 1997. A gain of approximately $13 million ($7 million net of tax) net of
costs of the sale and reserves for contingencies was realized on the sale in the
second quarter of 1997. The remaining decrease was the result of additional
interest income recognized in 1997 from a higher level of short-term
investments, partially offset by increased income from long-term investments
made during the fourth quarter of 1997.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The
decrease of $1.4 million or 2.3 percent in other income, when comparing the six
months ended June 30, 1998, and the six months ended June 30, 1997, was the
result of the sale of Chester in May 1997 and additional interest income
recognized in 1997 from a higher level of short-term investments, partially
offset by additional income recognized from long-term investments made in late
1997.
20
Interest and Other Charges
Comparison of Three Months Ended June 30, 1998, and June 30, 1997:
Interest and other charges decreased $1.7 million or 5.9 percent during the
second quarter of 1998 as compared to the second quarter of 1997. The decrease
was primarily the result of the refinancing of long-term debt at lower interest
rates and the maturity of approximately $100 million of long-term debt
subsequent to the second quarter of 1997.
Comparison of Six Months Ended June 30, 1998, and June 30, 1997: The
decrease in interest and other charges in the six months ended June 30, 1998, as
compared to the same period in 1997 was $2.8 million or 4.8 percent. The
decrease was primarily the result of the refinancing of long-term debt at lower
interest rates and the maturity of approximately $100 million of long-term debt
subsequent to the six months ended June 1997.
Income Taxes
Income taxes were higher in 1998 as compared to 1997 for both the three and
six months ended June 30 by $3.3 million and $2.2 million, respectively. The
variances were the result of higher pre-tax income in 1998.
Restructuring Charge
On May 29, 1998, the PUC issued its final order related to the Company's
Merger Plan and Stand-Alone Plan. In June the Company recorded the
Restructuring Charge against earnings for the stranded costs not considered by
the PUC's Order to be recoverable from customers. The Restructuring Charge
included Phillips Power Station, Brunot Island Power Station (BI), deferred
caretaker costs related to the two stations and deferred coal costs for a total
of $142.3 million ($82.5 million net of tax).
Liquidity and Capital Resources
- --------------------------------------------------------------------------------
Financing
The Company expects to meet its current obligations and debt maturities
through the year 2002 with funds generated from operations and through new
financings. At June 30, 1998, the Company was in compliance with all of its
debt covenants.
During 1998, $70 million of mortgage bonds matured and were retired and
$100 million of 8.75 percent mortgage bonds due in May 2022 were redeemed. The
retirement and redemption were financed using available cash, the proceeds of
the $40 million of 6.45 percent mortgage bonds due in February 2008 and the
proceeds of the $100 million of 7 3/8 percent mortgage bonds due in April 2038
issued by Duquesne. Mortgage bonds in the amount of $5 million will mature in
November 1998. The Company expects to retire these bonds with available cash or
to refinance the bonds. (See "Rate Matters" on page 22.)
As of June 30, 1998, 224,838 shares of Preferred Stock, Series A
(Convertible) (DQE Preferred Stock) had been issued and were outstanding. An
additional 15,200 shares of DQE Preferred Stock were issued in July 1998.
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. During the second quarter, the $50 million
accounts receivable sale arrangement was extended through June 1999. The
Company may attempt to extend the agreement, or replace it with a similar
facility, or eliminate the agreement, upon expiration.
The Company maintains a $150 million revolving credit facility which
expires in October 1998. The Company also maintains a $125 million revolving
credit facility which, during the second quarter, was extended to June 1999. No
borrowings were outstanding under either facility at June 30, 1998. With
respect to each of these revolving credit facilities, interest rates can, in
accordance with the option selected at the time of the borrowing, be based on
prime, Eurodollar or certificate of
21
deposit rates. Commitment fees are based on the unborrowed amount of the
commitments. Each revolving credit facility contains a two-year repayment period
for any amounts outstanding at the expiration of the revolving credit period.
The Company also maintains an aggregate of $150 million in bank term loans
outstanding at June 30, 1998.
Investing
- --------------------------------------------------------------------------------
The Company has made long-term investments in the following areas: leases;
affordable housing; gas reserves; energy solutions; and water companies.
Investing activities during the first six months of 1998 included approximately
$10 million in natural gas reserve partnerships and the remaining $10 million in
other investments. During the first six months of 1997, the Company invested
approximately $168 million in lease investments, $11 million in affordable
housing investments, $3 million in natural gas reserve partnerships and the
remaining $14 million in other investments.
In the first six months of 1998, the Company issued 209,358 shares of DQE
Preferred Stock, as part of an investment of approximately $55 million in water
companies. An additional 15,200 shares of DQE Preferred stock were issued in
July 1998, as part of an investment of approximately $2 million in water
companies.
In the first six months of 1998, the Company increased to approximately $40
million its commitment for investment in the construction of plants to produce
E-Fuel(TM), a coal-based synthetic fuel.
In the second quarter of 1998, the Company acquired an interest in
BroadPoint Communications, Inc. BroadPoint Communications has introduced a new
long-distance telephone service (the FreeWay(TM) Service) in which customers
earn free long-distance service in exchange for listening to short, targeted
audio advertisements. In July, the Company increased its investment to an
aggregate of approximately $3 million.
In July 1998, the Company invested $25 million to acquire a 50 percent
interest in, and to finance the future growth of, Control Solutions LLC, a
commercial and industrial HVAC service and energy controls company.
Rate Matters
- --------------------------------------------------------------------------------
Competition and the Customer Choice Act
The electric utility industry continues to undergo fundamental change in
response to development of open transmission access and increased availability
of energy alternatives. 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 historical ratemaking process, utilities have assets recorded on their
balance sheets at above-market costs, thus creating transition or stranded
costs.
In Pennsylvania, the Customer Choice Act went into effect 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, delivery of the
electricity from the generation supplier to the customer will remain the
responsibility of the existing franchised utility. The Customer Choice Act also
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 (running through 1998) and a phase-in to competition period (beginning in
1999).
Customer Choice Pilots
The pilot period gives utilities an opportunity to examine a wide range of
technical and administrative details related to competitive markets, including
metering, billing, and cost and design of unbundled electric services. The
28,000 customers participating in the Company's pilot may choose
22
unbundled service, with their electricity provided by an alternative generation
supplier, and will be subject to unbundled distribution and CTC charges approved
by the PUC and unbundled transmission charges pursuant to the Company's FERC-
approved tariff. Although the pilot program was implemented, pursuant to the
PUC's order, on November 3, 1997, the Company earlier appealed the determination
of the market price of generation set forth in the PUC's order to the
Commonwealth Court of Pennsylvania. Argument has not yet been scheduled.
Financial Impact of Pilot Program Order
During the first six months of 1998, the net financial impact of the
Company's customers' choosing alternative generation suppliers was a reduction
of operating revenues of approximately $12 million. It is anticipated that the
level during the remainder of the year should be consistent with that level.
The net income impact has been a reduction of $6 million for the first six
months of 1998.
Phase-In to Competition
As required by the PUC in its restructuring orders (see "Restructuring
Plans and PUC Proceedings" discussion below), the phase-in to competition begins
in January 1999, when 66 percent of customers will have customer choice
(including customers covered by the pilot program); all customers will have
customer choice in January 2000. As of the date of this report, approximately 41
percent of the Company's customers had elected to participate in the customer
choice program beginning in January 1999. As they are phased-in, customers that
have chosen an electricity generation supplier other than the Company will pay
that supplier for generation charges, and will pay the Company a CTC (discussed
below) and unbundled charges for transmission and distribution. Customers that
continue to buy their generation from the Company will pay for their service at
current regulated tariff rates divided into unbundled generation, transmission
and distribution charges. Under the Customer Choice Act, an electric
distribution company, such as Duquesne, is to remain a regulated utility and may
only offer PUC-approved, tariffed rates, including unbundled generation rates
(capped at current levels, so long as a CTC is being collected). Delivery of
electricity (including transmission, distribution and customer service) will
continue to be regulated in substantially the same manner as under current
regulation.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997 will be
imposed on the transmission and distribution charges of electric utility
companies. Additionally, electric utility companies may not increase the
generation price component of bundled rates as long as transition costs are
being recovered, with certain exceptions.
Restructuring Plans and PUC Proceedings
On August 1, 1997, Duquesne filed its stand-alone restructuring plan
(Stand-Alone Plan) in the event the merger of DQE and AYE is not consummated,
and DQE and AYE filed their application to merge and restructuring plan (Merger
Plan). A more detailed discussion of each of these plans is set forth in the
Annual Reports on Form 10-K for the Year Ended December 31, 1997, of Duquesne
and DQE. On May 29, 1998, the PUC issued final orders on the Stand-Alone Plan
and Merger Plan. On June 18, Duquesne submitted its compliance filing, which
would implement the PUC's final order regarding the Stand-Alone Plan or the
Merger Plan, as the case may be. The compliance filing also included Duquesne's
request that the PUC recalculate the CTC and shopping credit determination set
forth in the final orders; Duquesne estimates that, correcting for computational
errors, the 1999 average CTC should be 2.73 cents per kilowatt-hour (KWH)
(resulting in a shopping credit of 3.49 cents per KWH). Duquesne, DQE and AYE
also petitioned the PUC to reconsider its final restructuring orders. The PUC
denied Duquesne's petition to reconsider its Stand-Alone Plan final order, and
recommended that any reconsideration could be better addressed in Duquesne's
compliance filing. The PUC accepted DQE's and AYE's petition to reconsider the
Merger Plan final order. The orders and reconsideration are discussed below.
23
Order on the Stand-Alone Plan. With respect to stranded cost recovery, the
PUC's final order on the Stand-Alone Plan approves Duquesne's proposal to
auction its generating assets and use the proceeds to offset stranded costs. The
remaining balance of such costs (with certain exceptions described below) will
be recovered from ratepayers through a CTC, collectible through 2005. As
required, Duquesne will submit a divestiture plan to the PUC by August 27, 1998.
Duquesne has been ordered to use an interim system average CTC set at 2.9 cents
per KWH (resulting in a shopping credit of 3.75 cents per KWH), the rate
approved in its pilot program. The final CTC determined by the auction will
remain constant over the recovery period. The PUC's order approves the auction
only in the context of the Stand-Alone Plan, not the Merger Plan.
By conducting the auction, Duquesne expects to recover (through the auction
proceeds or the final CTC) or avoid the incurrence of all its stranded
generation costs, with the exception being a $65 million disallowance (net
present value, after tax) related to Duquesne's cold reserved units at the
Phillips Power Station and Brunot Island Power Station. The PUC's final order
also approves recovery of $339 million of the $357 million in regulatory assets
claimed by Duquesne. The disallowed regulatory assets relate primarily to
deferred coal costs under previously applied coal caps and deferred caretaker
costs associated with the cold reserved units.
At June 30, 1998, Duquesne recorded a charge to its earnings of $142.3
million ($82.5 million net of taxes) to reflect the disallowance associated with
the investments in cold reserved units and the disallowance of a portion of the
regulatory asset claim.
Order on the Merger Plan. The PUC's final order on the merger (as modified
during the reconsideration process) would allow the transaction to be
consummated but requires the parties, prior to closing, to agree to certain
conditions. The conditions relate to the mitigation of market power, including
membership in an independent system operator (ISO), an entity that would operate
the transmission facilities of Duquesne, AYE and other utilities in the region.
The PUC's final order would allow DQE and AYE to maintain their current
membership in the Midwest ISO, but the PUC held that the Midwest ISO must be
"fully functional" and it must satisfy seven criteria specified by the PUC no
later than June 30, 2000. In the meantime, the merged company would be required
to relinquish control of 570 megawatts of output from Duquesne's Cheswick Power
Station (Cheswick). Divestiture of a further 2,500 megawatts would be required
if, based on a PUC evaluation in January 2000, the merged company continued to
fail certain market power tests and the Midwest ISO had not progressed
sufficiently toward a structure that fully mitigates market power. The PUC
would determine what generation assets would be divested and who would be
eligible to bid for them. DQE objects to the PUC's having authority over all
aspects of the divestiture, particularly the lack of any provision to adjust
stranded costs following the divestiture. In addition, the Midwest ISO, as
presently constituted and as proposed to the FERC, does not meet the seven
criteria specified by the PUC.
The PUC's final order regarding the Merger Plan also addressed the recovery
of stranded costs by Duquesne and AYE's wholly owned utility subsidiary West
Penn Power Company (West Penn) in the event the merger is consummated. The order
sets stranded costs at approximately $1.3 billion, using an administrative
forecast of generation market values and costs. Applied to Duquesne, and
compared to the Stand-Alone Plan, this methodology results in the disallowance
of an additional $370 million in stranded costs (net present value, pre-tax).
The PUC's final order also reduces Duquesne's recoverable stranded costs by $152
million for estimated generation-related merger synergies and reduces
distribution rates beginning January 1, 2000, by $15 million annually to reflect
estimated distribution-related merger synergies. The PUC's final order permits
transition cost recovery through 2005 pursuant to a CTC initially set at an
average of 2.58 cents per KWH for 1999 (resulting in a shopping credit, or
reduction from previously bundled rates, of 4.00 cents per KWH).
24
With respect to West Penn, the PUC's final order disallows recovery of
approximately $1 billion of West Penn's stranded cost claim (net present value,
pre-tax). Of the disallowed amount, approximately $830 million relates to the
impact of the administrative determination of generation market value and costs.
The other disallowances relate to regulatory assets, non-utility generation and
other transition costs. In addition, the PUC's final order reduces West Penn's
recoverable stranded costs by $71 million for generation-related merger
synergies and reduces distribution rates beginning January 1, 2000, by $9
million for distribution-related merger synergies.
DQE Announcement. On July 29, 1998, DQE's Board of Directors concluded
that it could not consummate the merger under the circumstances described above.
On that same date, DQE informed AYE of this conclusion. More information
regarding this decision is set forth in the Company's Current Report on Form 8-K
dated July 28, 1998.
On July 30, AYE informed DQE that it does not believe DQE has the right to
terminate the merger agreement under these circumstances, and that AYE will
continue to work toward consummation of the merger. AYE also stated it will
pursue all remedies available to protect the legal and financial interests of
AYE and its shareholders. With respect to the PUC's disallowance of
approximately $1 billion of stranded costs, AYE has filed an appeal in state
court and a complaint in federal court, challenging the order. In addition, a
settlement conference is scheduled for August 14 between AYE and the PUC
regarding the West Penn final order. Because various issues in West Penn's
restructuring order are related to Duquesne's Merger Plan (particularly with
respect to the recovery of stranded costs), and could impact DQE and its
shareholders, Duquesne plans to participate in the conference.
Beaver Valley Power Station (BVPS)
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review completed by the Company. BV Unit 2 went off-line December 16,
1997, to repair the emergency air supply system to the control room and has
remained off-line due to other issues identified by a technical review similar
to that performed at BV Unit 1. These technical reviews are in response to a
1997 commitment made by the Company to the NRC. The Company is one of many
utilities faced with similar issues, some of which date back to the initial
start-up of BVPS. The Company has completed a series of meetings with the NRC to
review its action plans. As of the date of this report, BV Unit 1 is in its
start-up mode and is expected to be at full power shortly. Although BV Unit 2 is
expected to remain off-line until the action plans have been satisfactorily
completed, the Company and the NRC have been discussing proposed plans to return
the unit to service during the third quarter of 1998. The foregoing sentences
contain forward-looking statements (within the meaning of the Private Securities
Litigation Act of 1995). Actual results may differ materially from those implied
due to such risks as unforeseen mechanical difficulties arising in the normal
course of starting up the units following the current outages, additional
technical specifications issues being identified, or unforeseen difficulties
arising as a consequence of the tube inspection at BV Unit 2.
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. The units still have the capability
to operate at 100 percent reactor power, although approximately 17 percent of BV
Unit 1 and 2 percent of BV Unit 2 steam generator tubes have been removed from
service. Material acceleration in the rate of ODSCC could lead to a loss in
plant efficiency and significant repairs or replacement of BV Unit 1 steam
generators. The total replacement cost of the BV Unit 1 steam generators is
estimated at $125 million, $59 million of which would be the Company's
responsibility. The earliest that the BV Unit 1 steam generators could be
replaced during a currently scheduled refueling outage is the fall of 2001.
25
Year 2000
Many existing computer programs and embedded microprocessors use only two
digits to identify a year (for example, "98" is used to represent "1998"). 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. Such failures could cause
disruptions in normal business operations such as, among other things,
communicating with customers and vendors, calculating and processing bills and
payments, reading meters, managing and operating generating stations, operating
substations and distribution circuits, and maintaining internal financial and
accounting systems.
In 1994, the Company began reviewing its critical information systems that
impact operations and financial reporting in order to develop a strategy to
address required computer software and system changes and upgrades. The Company
has since assembled a Year 2000 team, comprised of management representatives
from all functional areas of the Company, which continues to explore the
exposure to Year 2000-related problems in computer software and devices and
equipment containing embedded microprocessors that may not correctly identify
the year, as well as potential problems that may originate with third parties
outside the Company's control. In general, the Company's overall strategy to
address the Year 2000 issue is comprised of four components, which may overlap
and be conducted simultaneously: inventory, assessment, remediation and testing
and implementation. Inventory consists of identifying the various systems,
components, equipment and third parties used in the Company's operations which
may be faced with Year 2000 issues. The Company has been performing the
inventory since the plan's inception, and expects to complete this portion
during the fourth quarter of 1998. Assessment consists of evaluating the
inventoried items for Year 2000 compliance by, among other things, contacting
vendors (the Company has already submitted questionnaires to its vendors),
inspecting software code and data, and testing high priority items. Assessment
is expected to be complete during the fourth quarter of 1998. During
remediation, the Company will apply the solution selected for an item (e.g.,
whether to replace a product, employ a software upgrade, or revise existing
software code). The Company expects to complete remediation during the first
quarter of 1999. Testing and implementation will consist of placing the
renovated processes, systems, equipment and other items into use within the
Company's operations. The Company expects this portion to take place during the
first two quarters of 1999.
The Company currently believes that implementation of its plan will
minimize the Year 2000 issues relating to its systems and equipment. Duquesne
has not yet identified the need for contingency plans in the event any part of
its overall strategy should fail adequately to address the Year 2000 problem.
However, Duquesne believes that the methodology and timetables incorporated into
its strategy will ensure that should contingency plans become necessary, they
will be developed on a timely basis. Through Duquesne, the Company has retained
a Year 2000 consultant to assist the Year 2000 team in the planning,
organization and management of its efforts. The Company also participates in
the Electric Power Research Institutes project to share information about
technical issues regarding the Year 2000 problem with other entities in the
electric utility industry.
The costs to date of the Company's plan, primarily incurred as a result of
software and system changes and upgrades by Duquesne, have been approximately
$35 million, of which approximately $31 million will be capitalized since those
costs are attributable to the purchase of new software for total system
replacements (i.e., the Year 2000 solution comprises only a portion of the
benefit resulting from such replacements). Given the fact that the various
aspects of the Company's strategy, as noted above, are currently in progress,
the Company cannot estimate the exact extent of any outstanding Year 2000
systems and equipment issues or the ultimate costs to the Company in correcting
any possible related outstanding matters. Until the Company's assessment is
completed, it cannot determine whether Year 2000 issues and related costs will
be material to the Company's operations, financial condition and results of
operations.
26
The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
timetable and effectiveness 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. Such risks and uncertainties include, but are
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. There can be no guarantee that such risks
would not have a material adverse impact on the Company. The costs associated
with this potential impact are speculative and not currently quantifiable.
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, 1998 totaled approximately $53.9 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 a
number of risks and uncertainties, and actual results may differ materially.
Such forward-looking statements 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. Such factors include, among others, the following: the Company's
decision not to consummate the merger with AYE under the current circumstances;
Duquesne's upcoming plan to auction its generating assets; 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.
27
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, the Company commenced arbitration against 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. In October 1995, CEI commenced an action against the Company in
the Court of Common Pleas, Lake County, Ohio seeking to enjoin the Company from
taking any action to effect a partition on the basis of a waiver of partition
covenant contained in the deed to the land underlying Eastlake. 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
trial is currently scheduled to begin February 1, 1999.
Proposed Merger
In September 1997, the City of Pittsburgh filed a federal antitrust suit
seeking to prevent the merger and asking for monetary damages. Although the
United States District Court for the District of Western Pennsylvania dismissed
the suit in January 1998, the City filed an appeal, which was dismissed by the
U.S. Court of Appeals for the Third Circuit on June 12, 1998. The City
petitioned for a rehearing, but on July 8 entered into a settlement agreement
with AYE, pursuant to which the City has dropped its suit and withdrawn its
objections to the proposed merger.
Item 5. Other Information
DQE previously reported that its 1998 Annual Meeting of Stockholders was
tentatively scheduled to occur in October. DQE has now scheduled its 1998
Annual Meeting of Stockholders to be held on Tuesday, November 24, at 11:00 a.m.
The record date for holders of both DQE Common Stock and DQE Preferred Stock,
Series A (Convertible) is September 23, 1998. Stockholder proposals to be
included in DQE's proxy materials for the meeting must be received by August 21.
Notice of stockholder proposals that will be solicited independently also must
be received by that date. Such proposals and notices should be in writing and
directed to the Corporate Secretary of DQE, Box 68, Pittsburgh, PA 15230-0068.
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividend Requirements.
EXHIBIT 27.1 - Financial Data Schedule
b. A Current Report on Form 8-K was filed June 12, 1998, to report the PUC's
final orders regarding the proposed merger and the restructuring plans. No
financial statements were filed with this report.
A Current Report on Form 8-K was filed July 29, 1998, to report a letter
from David D. Marshall to Alan J. Noia, and included the DQE Earnings
Release for the quarter ended June 30, 1998.
_____________________________
28
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 14, 1998 /s/ Gary L. Schwass
--------------- ------------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer
Date August 14, 1998 /s/ Morgan K. O'Brien
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(Signature)
Morgan K. O'Brien
Vice President and Controller
(Principal Accounting Officer)
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