UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 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
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Commission File Number
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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 -- 77,748,689 shares outstanding as of
September 30, 1998 AND October 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 Nine Months Ended
September 30, September 30,
--------------------------------- ----------------------------------
1998 1997 1998 1997
-------------- -------------- -------------- -------------
Operating Revenues
Sales of Electricity $ 310,596 $ 311,966 $ 854,411 $ 841,526
Other 34,424 19,998 87,394 79,122
------------ ------------ ------------ ------------
Total Operating Revenues 345,020 331,964 941,805 920,648
------------ ------------ ------------ ------------
Operating Expenses
Fuel and purchased power 85,335 63,031 216,443 165,201
Other operating 89,883 67,527 238,401 227,140
Maintenance 23,321 21,229 59,273 61,529
Depreciation and amortization 42,144 61,397 156,978 175,117
Taxes other than income taxes 21,095 21,571 60,702 62,004
------------ ------------ ------------ ------------
Total Operating Expenses 261,778 234,755 731,797 690,991
------------ ------------ ------------ ------------
OPERATING INCOME 83,242 97,209 210,008 229,657
------------ ------------ ------------ ------------
Other Income 27,073 23,828 86,620 84,780
------------ ------------ ------------ ------------
Interest and Other Charges 27,609 29,210 82,540 86,919
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INCOME Before Income Taxes And
Extraordinary Item 82,706 91,827 214,088 227,518
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Income Taxes 20,637 33,162 66,685 76,978
------------ ------------ ------------ ------------
INCOME Before Extraordinary Item 62,069 58,665 147,403 150,540
Extraordinary Item (Net of Tax) -- -- (82,548) --
------------ ------------ ------------ ------------
NET INCOME After Extraordinary Item $ 62,069 $ 58,665 $ 64,855 $ 150,540
============ ============ ============ ============
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING 77,743 77,605 77,716 77,430
============ ============ ============ ============
BASIC EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
Before Extraordinary Item $ 0.80 $ 0.75 $ 1.90 $ 1.94
============ ============ ============ ============
Extraordinary Item $ -- $ -- $ (1.06) $ --
============ ============ ============ ============
After Extraordinary Item $ 0.80 $ 0.75 $ 0.84 $ 1.94
============ ============ ============ ============
DILUTED EARNINGS (LOSS) PER
SHARE OF COMMON STOCK:
Before Extraordinary Item $ 0.78 $ 0.74 $ 1.85 $ 1.91
============ ============ ============ ============
Extraordinary Item $ -- $ -- $ (1.06) $ --
============ ============ ============ ============
After Extraordinary Item $ 0.78 $ 0.74 $ 0.79 $ 1.91
============ ============ ============ ============
DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $ 0.36 $ 0.34 $ 1.08 $ 1.02
============ ============ ============ ============
See notes to condensed consolidated financial statements.
2
DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
September 30, December 31,
ASSETS 1998 1997
------------------ -----------------
Current assets:
Cash and temporary cash investments $ 237,441 $ 356,412
Receivables 166,359 131,711
Other current assets, principally materials and supplies 89,478 81,233
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Total current assets 493,278 569,356
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Long-term investments 755,400 722,786
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Property, plant and equipment 4,705,052 4,625,128
Less: Accumulated depreciation and amortization (3,276,314) (1,962,794)
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Property, plant and equipment - net 1,428,738 2,662,334
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Other non-current assets:
Generation-related assets 2,175,616 561,867
Transmission and Distribution-related assets 111,995 119,018
Other deferred debits 90,569 59,041
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Total other non-current assets 2,378,180 739,926
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TOTAL ASSETS $ 5,055,596 $ 4,694,402
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LIABILITIES AND CAPITALIZATION
Current liabilities $ 256,711 $ 281,966
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Deferred income taxes - net 677,048 693,215
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Deferred income 157,394 225,107
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Beaver Valley lease liability 487,565 --
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Other non-current liabilities 377,614 390,789
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Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,366,440 1,376,121
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Preferred and preference stock of subsidiaries 228,118 226,503
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Preferred stock 26,604 1,548
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Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
Issued - 109,679,154 shares) 998,170 1,001,225
Retained earnings 850,675 869,749
Less treasury stock (at cost) (31,930,465 and 31,998,723
Shares, respectively) (370,743) (371,821)
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Total common shareholders' equity 1,478,102 1,499,153
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Total capitalization 3,099,264 3,103,325
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TOTAL LIABILITIES AND CAPITALIZATION $ 5,055,596 $ 4,694,402
============= =============
See notes to condensed consolidated financial statements.
3
DQE
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Nine Months Ended
September 30
---------------------------------------
1998 1997
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Cash Flows From Operating Activities
Operations $ 364,610 $ 329,281
Changes in working capital other than cash (119,450) (32,665)
Increase in ECR (19,219) (13,866)
Other 17,519 2,791
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Net Cash Provided By Operating Activities 243,460 285,541
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Cash Flows From Investing Activities
Capital expenditures (118,955) (67,875)
Long-term investments (50,862) (203,882)
Acquisition of water companies (40,961) --
Acquisition of interest in Control Solutions (21,954) --
Proceeds from the sale of property 1,063 7,723
Proceeds from the sale of equity securities -- 42,895
Other (6,786) 1,154
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Net Cash Used in Investing Activities (238,455) (219,985)
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Cash Flows From Financing Activities
Dividends on common stock (83,929) (78,996)
Reductions of long term obligations - net (36,732) (16,310)
Increase in notes payable 4,375 10,000
Other (7,690) 7,084
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Net Cash Used in Financing Activities (123,976) (78,222)
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Net decrease in cash and temporary cash investments (118,971) (12,666)
Cash and temporary cash investments at beginning of period 356,412 410,978
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Cash and temporary cash investments at end of period $ 237,441 $ 398,312
============= =============
Non-Cash Investing and Financing Activities
Preferred stock issued in conjunction with long-term investments $ 25,056 $ --
============= =============
Capital lease obligations recorded $ 5,011 $ 17,004
============= =============
Equity funding obligations recorded $ -- $ 11,897
============= =============
Equity funding obligations canceled $ -- $ 9,107
============= =============
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); AquaSource, Inc. (AquaSource); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises,
Inc. (DE); and Montauk, Inc. (Montauk). DQE and its subsidiaries are
collectively referred to as "the Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. AquaSource is a water resource management company that acquires,
develops and manages water and wastewater utilities. DES is a diversified energy
services company offering a wide range of energy solutions. DES initiatives
include energy facility development and operation, domestic and international
independent power production, and the production and supply of innovative fuels.
DQEnergy intends to align DQE with strategic partners capitalizing on
opportunities in the areas of energy and communications systems. These alliances
are intended to enhance value while utilizing DQE's strategic investments and
exploiting DQE's core expertise. DE is building businesses in the energy
services and technologies and the electronic commerce industries, and in
communications. Montauk is a financial services company that makes long-term
investments and provides financing for the Company's expanded business lines and
related 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. However, on October 5, 1998, the Company unilaterally terminated the
merger agreement, and AYE filed suit in the United States District Court for the
Western District of Pennsylvania requesting enforcement of the merger agreement,
or in the alternative money damages for the termination. (See "Status of AYE
Merger" discussion, Note 2, page 10.)
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 nine months
ended September 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 Pennsylvania Public Utility Commission (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). Applying SFAS No. 121 to the non-regulated
generating assets, it has been determined that the Company's generating assets
are impaired. However, pursuant to the PUC's final restructuring order, the
Company will recover its above-market investment in generation assets through
the CTC. Under the Company's plan to auction its generating assets, the market
value utilized by the PUC in determining the value of the generating assets will
be the net after-tax proceeds received from the auction of its generating
assets. Accordingly, the amount of book value authorized to be recovered by the
PUC has been reclassified on the condensed consolidated balance sheet from
"Property, plant and equipment" to "Other non-current generation-related assets"
until the auction has been completed and all approvals for the final CTC
accounting have been granted. 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), fuel costs are expensed as incurred and impact net income.
Under-recoveries from customers prior to May 29, 1998, were recorded on the
condensed consolidated balance sheet as a regulatory asset. At September 30,
1998, $42.7 million was receivable from customers. The Company expects to
recover this amount through the CTC. (See "Restructuring Plans and Regulatory
Orders", 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
6
are stated at market value. The amounts of unrealized holding gains related to
marketable securities were $3.0 million ($1.7 million, net of tax) at September
30, 1998, and $8.1 million ($4.7 million, net of tax) at December 31, 1997.
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. On November 6, 1998, the Company withdrew its appeal.
Phase-In to Competition
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 October
31, 1998, 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 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
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
generation rates (capped at current levels so long as a CTC is being collected).
Also
7
under the Customer Choice Act, delivery of electricity (including transmission,
distribution and customer service) will continue to be regulated in
substantially the same manner as under current regulation.
In an effort to "jump start" retail competition, the Company will make 600
megawatts of power available to licensed electric generation suppliers, to be
used in supplying electricity to Duquesne's customers who have chosen other
generation suppliers. The power will be available for the first six months of
1999 at a price of 2.6 cents per kilowatt-hour (KWH). This availability will be
structured to ensure the power is used to benefit Duquesne's retail customers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997, 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 rates as long as transition costs are being
recovered, with certain exceptions.
Restructuring Plans and Regulatory Orders
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.
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. Until the
divestiture is complete, Duquesne has been ordered to use an interim system
average CTC and shopping credit based on the methodology approved in its pilot
program (approximately 2.9 cents per KWH for the CTC and approximately 3.8 cents
per KWH for the shopping credit). The PUC's order approves the auction only in
the context of the Stand-Alone Plan, not the Merger Plan.
On August 27, 1998, Duquesne filed its auction plan with the PUC. Duquesne
expects approval of the plan from the PUC by the end of 1998. The confidential
bidding process will begin in early 1999. Only companies with an established
record of owning and operating electric generating plants and with proof of
their financial ability to purchase the plants without financing will qualify to
bid. The transaction will have to be approved by various regulatory agencies,
including the PUC, the FERC, the Nuclear Regulatory Commission (NRC), the
Department of Justice and the Federal Trade Commission. Duquesne expects the
process to last approximately 12 to 18 months from the opening of bidding to the
closing of the sale.
To help facilitate the auction process, on October 14, 1998, Duquesne
entered into a non-binding agreement in principle with FirstEnergy Corp. to
exchange ownership interests in certain plants. As proposed, Duquesne would
acquire 100 percent ownership interests in three coal-fired power plants located
in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling
approximately 1,300 megawatts). In exchange, FirstEnergy Corp. would acquire
Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2
(BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield
Units 1, 2 and 3 (totaling approximately 1,400 megawatts). The Company's
investment in these plants at September 30, 1998, was $894.1 million which has
been reclassified to "Other non-current generation-related assets" on the
condensed consolidated balance sheet. The Company has requested the PUC to
authorize the investment in the acquired power plants to be accounted for in the
final auction proceeds accounting utilizing the previously authorized investment
amount of the plants transferred by the Company. Duquesne expects this exchange
to enhance the value received from the auction because participants will be
8
able to bid on plants that are wholly owned by Duquesne, rather than plants that
are jointly owned and/or operated by another entity. Additionally, the auction
will include only coal- and oil-fired plants, which are anticipated to have a
higher market value than nuclear plants. These value-enhancing features, along
with a minimum level of auction proceeds guaranteed by FirstEnergy Corp., will
maximize auction proceeds and thereby minimize transition costs required to be
recovered through the CTC and reduce customer bills as rapidly as possible.
Other benefits of this exchange for Duquesne include the resolution of all joint
ownership issues, and other risks and costs associated with the nuclear units.
Duquesne expects PUC approval of the exchange by the end of 1998. Certain
aspects of the exchange will have to be approved by the FERC, the NRC and the
Department of Justice. The closing of the exchange is expected to occur
simultaneously with the closing of the sale of Duquesne's generation through the
auction.
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 tax) to reflect the disallowance associated with
the investments in the cold reserved units and the disallowance of a portion of
the regulatory asset claim described above.
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 would require 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 merged company would be required immediately 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. The PUC would determine which 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
Company believes the Midwest ISO, as presently constituted and as approved by
the FERC, will not mitigate the PUC's concerns regarding market power.
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 Duquesne's 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 an average shopping
credit of 4.00 cents per KWH).
9
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. The Company believes that as
of October 5, 1998, the relevant date under the merger agreement, AYE had
suffered a material adverse effect and, despite ample opportunity, had not
corrected it. Subsequent to the October 5, 1998 termination of the merger
agreement, the PUC tentatively approved a settlement of the West Penn
restructuring case, which settlement did not significantly increase the level of
West Penn's allowed stranded costs.
The FERC Order. The FERC issued its order regarding the proposed merger on
September 16, 1998. The order required the sale of Cheswick prior to
consummation of the merger, rejecting the proposal to relinquish control of 570
megawatts from that station in order to address market power concerns. The
Company does not believe such a divestiture could be accomplished quickly enough
to allow the proposed merger to occur within the timeframe contemplated in the
merger agreement. In addition, the FERC order does not address or alter the
financial effects on AYE of the PUC order discussed above.
Status of the AYE Merger. 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, 1998, 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.
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement. AYE promptly filed suit in the United States District Court
for the Western District of Pennsylvania, seeking to compel the Company to
proceed with the merger and seeking a temporary restraining order and
preliminary injunction to prevent the Company from certain actions pending a
trial, or in the alternative seeking an unspecified amount of money damages.
More information regarding this termination is set forth in the Company's
Current Report on Form 8-K dated October 5, 1998. A hearing was held on October
26, 1998, regarding AYE's motion for the temporary restraining order and
preliminary injunction. On October 28, 1998, the judge denied the motion. On
October 30, 1998, AYE appealed the judge's decision to the United States Court
of Appeals for the Third Circuit, asking for an injunction pending the appeal
and expedited treatment of the appeal. On November 6, 1998, the Third Circuit
denied the motion for an injunction and granted the motion to expedite the
appeal.
10
3. RECEIVABLES
The components of receivables for the periods indicated are as follows:
September 30, September 30, December 31,
1998 1997 1997
(Amounts in Thousands of Dollars)
- ----------------------------------------------------------------------------------------------------------
Electric customer accounts receivable $ 99,608 $ 94,844 $ 90,149
Other utility receivables 28,306 18,595 23,106
Other receivables 53,726 19,263 33,472
Less: Allowance for uncollectible accounts (15,281) (19,590) (15,016)
- ----------------------------------------------------------------------------------------------------------
Total Receivables $166,359 $113,112 $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 September 30, 1998, September 30, 1997
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.
4. COMMITMENTS AND CONTINGENCIES
The Company currently anticipates divesting itself of its generating assets
through the auction and the power station exchange, which will impact the
obligations related to those assets. (See "Order on the Stand-Alone Plan"
discussion, Note 2, on page 8.)
Construction
The Company currently estimates that it will spend, excluding the Allowance
for Funds Used During Construction and nuclear fuel, approximately $110 million
for electric utility construction during 1998. The Company has completed, at a
cost of approximately $40 million, the construction of six plants to produce
E-Fuel/TM/, a coal-based synthetic fuel. All of these plants are currently in
operation.
Nuclear-Related Matters
The Company has an interest in three nuclear units, two of which it
operates. The operation of a nuclear facility involves special risks, potential
liabilities, and specific regulatory and safety requirements. Specific
information about risk management and potential liabilities is discussed below.
Nuclear Decommissioning. The Company expects to decommission BV Unit 1, BV
Unit 2 and Perry Unit 1 no earlier than the expiration of each plant's operating
license in 2016, 2027 and 2026, respectively. At the end of its operating life,
BV Unit 1 may be placed in safe storage until BV Unit 2 is ready to be
decommissioned, at which time the units may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit
2, and a 1997 update of the 1994 study for Perry Unit 1, the Company's
approximate share of the total estimated decommissioning costs, including
removal and decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently 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.)
11
Funding for nuclear decommissioning costs is deposited in external,
segregated trust accounts and invested in a portfolio of corporate common stock
and debt securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances at
September 30, 1998, totaled approximately $56.2 million.
Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act
of 1954 limit public liability from a single incident at a nuclear plant to $9.9
billion. The maximum available private primary insurance of $200 million has
been purchased by the Company. Additional protection of $9.7 billion would be
provided by an assessment of up to $88.1 million per incident on each licensed
nuclear unit in the United States. The Company's maximum total possible
assessment, $66.1 million, which is based on its ownership or leasehold
interests in three nuclear generating units, would be limited to a maximum of
$7.5 million per incident per year. This assessment is subject to indexing for
inflation and may be subject to state premium taxes. If assessments from the
nuclear industry prove insufficient to pay claims, the United States Congress
could impose other revenue-raising measures on the industry.
The Company's share of insurance coverage for property damage,
decommissioning and decontamination liability is $1.2 billion. The Company would
be responsible for its share of any damages in excess of insurance coverage. In
addition, if the property damage reserves of Nuclear Electric Insurance Limited
(NEIL), an industry mutual insurance company that provides a portion of this
coverage, are inadequate to cover claims arising from an incident at any United
States nuclear site covered by that insurer, the Company could be assessed
retrospective premiums totaling a maximum of $7.3 million.
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 17 weeks after an
accident, with no coverage thereafter. If NEIL's losses for this program ever
exceed its reserves, the Company could be assessed retrospective premiums
totaling a maximum of $2.6 million.
Beaver Valley Power Station (BVPS). BVPS's two units are equipped with
steam generators designed and built by Westinghouse Electric Corporation
(Westinghouse). Similar to other Westinghouse nuclear plants, outside diameter
stress corrosion cracking (ODSCC) has occurred in the steam generator tubes of
both units. BV Unit 1, which was placed in service in 1976, has removed
approximately 17 percent of its steam generator tubes from service through a
process called "plugging." However, BV Unit 1 still has the capability to
operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called "sleeving." No tubes at
either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 3 percent of BV Unit 2's tubes are
plugged; however, it is too early in the life of the unit to determine the
extent to which ODSCC may become a problem at that unit.
The Company has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and 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.
12
The Company continues to explore all viable means of managing ODSCC,
including new repair technologies, and plans to continue to perform 100 percent
tube inspections during future refueling outages. However, the Company may be
required to perform an earlier inspection of BV Unit 1's tubes and other
equipment during a mid-cycle outage in 1999, in order to comply with NRC
requirements to conduct such inspections at BV Unit 1 at least every 20 months.
The Company plans to request permission from the NRC to postpone these
inspections until BV Unit 1's next refueling outage, currently scheduled to
begin in the spring of 2000. The Company completed its inspection of BV Unit 2's
tubes during the recent 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 at the end of
February 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 remained
off-line due to other issues identified by a technical review similar to that
performed at BV Unit 1. These technical reviews, which were in response to a
1997 commitment made by the Company to the NRC, have been completed. The Company
was one of many utilities faced with similar issues, some of which date back to
the initial start-up of BVPS. BV Unit 1 returned to service on August 15, 1998,
and BV Unit 2 returned to service on September 28, 1998.
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 denied the relief requested by the
utilities and states and permitted the DOE to pursue alternative dispute
resolution, but prohibited the DOE from using its lack of a spent fuel
repository as a defense. The states and the DOE have both petitioned the United
States Supreme Court for review of the decision. The Supreme Court has not
decided whether it will review the case. The utilities did not join the states'
petition.
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 September 30, 1998 and December 31, 1997, the Company's
liability for contributions was approximately $7.2 million (subject to an
inflation adjustment).
13
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 September 30, 1998, the Company's share
of these guarantees was $9.9 million.
As part of the Company's investment portfolio in affordable housing, the
Company has received fees in exchange for guaranteeing a minimum defined yield
to third-party investors. A portion of the fees received has been deferred to
absorb any required payments with respect to these transactions. Based on an
evaluation of and recent experience with the underlying housing projects, the
Company believes that such deferrals are ample for this purpose.
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
- --------------------------------------------------------------------------------
DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne); AquaSource, Inc. (AquaSource); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); Duquesne Enterprises,
Inc. (DE); and Montauk, Inc. (Montauk). DQE and its subsidiaries are
collectively referred to as "the Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. AquaSource is a water resource management company that acquires,
develops and manages water and wastewater utilities. DES is a diversified energy
services company offering a wide range of energy solutions. DES initiatives
include energy facility development and operation, domestic and international
independent power production, and the production and supply of innovative fuels.
DQEnergy intends to align DQE with strategic partners capitalizing on
opportunities in the areas of energy and communications systems. These alliances
are intended to enhance value, while utilizing DQE's strategic investments and
exploiting DQE's core expertise. DE is building businesses in the energy
services and technologies and the electronic commerce industries, and in
communications. Montauk is a financial services company that makes long-term
investments and provides financing for the Company's expanded business lines and
related 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. However, on October 5, 1998, the Company unilaterally terminated the
merger agreement, and AYE filed suit in the United States District Court for the
Western District of Pennsylvania requesting enforcement of the merger agreement,
or in the alternative money damages for the termination. (See "Status of AYE
Merger" discussion on page 26.)
The Company's Service Territory
The Company's electric utility operations provide service to customers in
Allegheny County, including the City of Pittsburgh, Beaver County and
Westmoreland County. (See "Rate Matters" on page 23.) 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 electric utility operations also sell electricity to
other utilities.
The Company's water utility operations provide service to customers in
Texas, Indiana and New England, and are expanding throughout the United States.
The Company's water utility operations currently serve approximately 120,000
customers.
15
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 Pennsylvania Public Utility Commission (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 23.)
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.
The Company's water utility operations are subject to regulation by the
respective state and local public utility commissions.
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
23), 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). Applying SFAS No. 121 to the non-regulated
generating assets, it has been determined that the Company's generating assets
are impaired. However, pursuant to the PUC's final restructuring order, the
Company will recover its above-market investment in generation assets through
the CTC. Under the Company's plan to auction its generating assets, the market
value utilized by the PUC in determining the value of the generating assets will
be the net after-tax proceeds received from the auction of its generating
assets. Accordingly, the amount of book value authorized to be recovered by the
PUC has been reclassified on the condensed consolidated balance sheet from
"Property, plant and equipment" to "Other non-current generation-related assets"
until the auction has been completed and all approvals for the final CTC
accounting have been granted. 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 23.)
16
Results of Operations
- --------------------------------------------------------------------------------
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. (See "Rate Matters" on page
23.)
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: The Company's basic earnings per share in the third quarter of 1998 and
the third quarter of 1997 were $0.80 and $0.75. Net income was $62.1 million in
the third quarter of 1998 and $58.7 million in the third quarter of 1997.
During the third quarter of 1998 Duquesne increased its contribution by $0.03
per DQE share to $0.61 from $0.58 in the third quarter of 1997 primarily as a
result of decreased generating plant depreciation due to the PUC order. The
recurring operating activities of the Company's expanded business lines added
$0.21 to earnings per share in the third quarter of 1998 and $0.16 to earnings
per share in the third quarter of 1997 due to new investments entered into
during late 1997 and throughout 1998. Also in the third quarter of 1998, the
Company wrote off costs related to the proposed merger with AYE and recognized
the favorable solution of certain contingencies associated with the May 1997
sale of Chester.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Excluding the Restructuring Charge and the gain on the sale of Chester, basic
earnings per share for the nine months ended September 30, 1998 and 1997 were
$1.90 and $1.85. The Company's earnings per share for the nine months ended
September 30, 1998, and the nine months ended September 30, 1997, were $0.84 and
$1.94 after the Restructuring Charge and the gain on the sale of Chester. For
the nine months ended September 30, 1998, the Company's net income was $64.9
million and for the nine months ended September 30, 1997, the Company's net
income was $150.5 million. The decrease in earnings per share and net income
was the result of the Company's Restructuring Charge for $142.3 million ($82.5
million, net of tax) recorded in June 1998 and to the $13 million ($7 million,
net of tax) or $0.09 per share gain recognized on the sale of Chester Engineers
(Chester) in May 1997.
As a result of the Restructuring Charge, Duquesne contributed only $0.34
per DQE share in the nine months ended September 1998 as compared to $1.38 per
DQE share in the nine months ended September 1997. Excluding the Restructuring
Charge, Duquesne contributed $1.40 to DQE earnings per share for the nine months
ended September 30, 1998. Although the operating activities of the expanded
business lines recognized the gain on the sale of Chester in May 1997, the
earnings contribution dropped by only $0.06 per share in the nine months ended
September 1998 to $0.50 from $0.56 in the nine months ended September 1997. The
resulting increase of $0.03 in the contribution to earnings per share from the
expanded business lines can be attributed to new investments made late in 1997
and throughout 1998. Also in the third quarter of 1998, the Company wrote off
costs related to the proposed merger with AYE and recognized the favorable
solution of certain contingencies associated with the May 1997 sale of Chester.
Revenues
Total operating revenues in the third quarter of 1998 increased $13.1
million or 3.9 percent as compared to the third quarter of 1997. Total
operating revenues in the nine months ended September 30, 1998, increased $21.2
million or 2.3 percent as compared to the nine months ended September 30, 1997.
The following table sets forth operating revenues and KWH delivered for
residential, commercial and industrial customers who have not chosen different
generation suppliers.
17
- --------------------------------------------------------------------------------------------------------
(Revenues in Millions of Dollars) Increase(Decrease) from Prior Year
- --------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
September 30, 1998 September 30, 1998
----------------------------------------------------------
KWH Revenues KWH Revenues
----------------------------------------------------------
Residential 3.6% $ 5.2 (1.7)% $ 8.8
Commercial (2.2)% (6.0) (3.2)% 2.5
Industrial (6.1)% (5.0) (2.0)% (1.9)
Less: Provision for Doubtful Accounts 0.0 0.0
- --------------------------------------------------------------------------------------------------------
Sales to Electric Utility Customers (1.6)% (5.8) (2.5)% 9.4
- --------------------------------------------------------------------------------------------------------
Sales to Other Utilities 43.5% 4.5 (1.3)% 3.5
Other Revenues 14.4 8.3
- --------------------------------------------------------------------------------------------------------
Total 2.6% $13.1 (2.4)% $21.2
========================================================================================================
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 date of the PUC's final restructuring order),
the PUC approved separate 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, historical, 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). Beginning May 29, 1998, 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.
Customer revenues fluctuate as a result of changes in sales volume. (See "Rate
Matters" on page 23.)
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 September 30, 1998, and September 30,
1997: In the third quarter of 1998, net customer revenues reflected on the
statement of consolidated income decreased by $5.8 million or 1.9 percent to
$300.0 million from the third quarter of 1997. In 1997, $10.8 million of fuel
costs were deferred for subsequent recovery through the ECR resulting in an
increase in revenues. Excluding the deferred fuel from 1997 revenues, the net
increase in revenues can be attributed to a 3.6 percent increase in residential
sales due to warmer temperatures. Commercial and industrial sales decreased by
2.2 percent and 6.1 percent due in part to the implementation of the pilot
program in November 1997, which resulted in a reduction in electric utility
customer sales. Additionally, in response to requirements of 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. Absent the change
in categorization and the effects of the pilot program, industrial sales were
consistent with the 1997 level.
18
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Net customer revenues increased $9.4 million or 1.1 percent in the nine months
ended September 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 electric utility customer
KWH sales due primarily to the implementation of the pilot program.
Additionally, in response to requirements of 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. Absent the change in categorization
and the effects of the pilot program, industrial sales would have increased over
1997, due to 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, the Company's decision to sell 600 megawatts to licensed
generation suppliers and the Company's divestiture plan. (See "Rate Matters" on
page 23.)
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: The Company's revenues from electricity sales to other utilities in the
third quarter of 1998 were $4.5 million or 72.6 percent greater than in the
third quarter of 1997 due to increased demand from the other utilities as a
result of warmer temperatures during the third quarter of 1998 and increased
market power prices in 1998.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
In the nine months ended September 30, 1998, the Company's revenues from
electricity sales to other utilities were $3.5 million or 16.6 percent more than
in the nine months ended September 30, 1997, due to greater demand from the
other utilities as a result of warmer temperatures during the third quarter of
1998 and increased market power prices in 1998. Partially offsetting the
increases was a decrease through the first six months of 1998 due to reduced
generating station availability as a result of an increase in outage hours in
the first six months of 1998 as compared to 1997.
Other Operating Revenues
Other operating revenues include the Company's non-KWH utility revenues and
revenues from the operating activities of the expanded business lines.
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: The other operating revenues increased $14.4 million or 72.1 percent
primarily as a result of increased AquaSource revenues, and other new
investments through the operating activities of the expanded business lines.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The increase of $8.3 million or 10.5 percent in other operating revenues in the
nine months ended September 30, 1998, as compared to 1997 was primarily the
result of increased AquaSource revenues, and other new investments through the
operating activities of the expanded business lines, partially offset by the
loss of revenues from the sale of Chester in May 1997.
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 for the first
five months of 1998 or any of 1997. Beginning May 29, 1998, fuel costs for
customers
19
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 rates. (See "Rate Matters" on page 23.)
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Fuel and purchased power expense increased $22.3 million or 35.4 percent
in the third quarter of 1998 as compared to the third quarter of 1997. The
increase resulted from higher energy costs of $19.8 million or 29.8 percent due
to an unfavorable power supply mix and higher purchased power prices. The
remaining increase of $2.5 million was due to a higher volume of energy supplied
due to warmer temperatures during 1998. Reduced availability of generating
stations due to an increase in outage hours required the Company to purchase
power and generate power from the higher fuel cost fossil stations. (See
"Beaver Valley Power Station" on page 27.)
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The $51.2 million or 31.0 percent increase in fuel and purchased power expense
for the nine months ended September 30, 1998, as compared to the nine months
ended September 30, 1997, was the result of increased energy costs of $55.9
million due to an unfavorable power supply mix and higher purchased power
prices. Energy volume supplied resulted in a $4.7 million reduction in fuel and
purchased power expenses primarily due to lower sales from the pilot program.
Reduced availability of generating stations due to an increase in outage hours
required the Company to purchase power and generate power from the higher fuel
cost fossil stations. (See "Beaver Valley Power Station" on page 27.)
BV Unit 1 and BV Unit 2 continued to be off-line into the third quarter,
with BV Unit 1 returning to service on August 15, 1998, and BV Unit 2 returning
to service on September 28, 1998. These outages, combined with various fossil
station outages, 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 recent historical levels. As a result of these
higher costs and the discontinuance of the ECR, fuel costs had a negative impact
on third quarter earnings. This impact was partially mitigated by the fact that
during the second quarter of 1998 the Company entered into fixed-price firm
replacement power contracts.
Other Operating Expense
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Non-fuel operating expenses increased $22.4 million or 33.1 percent in
the third quarter of 1998 as compared to the third quarter of 1997. The growth
of the expanded business lines' start-up and developmental activities and
acquisitions increased expenses by approximately $15 million. Also, in the
third quarter of 1998, the Company wrote off costs related to the merger with
AYE resulting in an increase to other operating expense of $14.1 million. (See
"Rate Matters" on page 23.) Partially offsetting these increases was the
recognition of the favorable resolution of certain contingencies associated with
the May 1997 sale of Chester.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Non-fuel operating expenses increased $11.3 million or 5.0 percent when
comparing the nine months ended September 30, 1998, to the same period for 1997.
The growth of the expanded business lines' start-up and developmental activities
increased expenses by approximately $25 million. Also, in the third quarter of
1998, the Company wrote off costs related to the merger with AYE resulting in an
increase to other operating expense of $14.1 million. (See "Rate Matters" on
page 23.) As a result of the PUC's final restructuring order, the present value
of 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. Also, the May 1997 sale of Chester resulted
in reduced operating costs of $7.8 million and the recognition of the favorable
resolution of certain contingencies associated therewith.
20
Maintenance Expense
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Maintenance expense increased $2.1 million or 9.9 percent when comparing
the third quarter of 1998 to the same period in 1997. The increase is primarily
attributable to tree trimming and storm-related maintenance of overhead lines
partially offset by reduced nuclear station outage cost amortization in 1998.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
Maintenance expense decreased $2.3 million or 3.7 percent when comparing the
nine months ended September 30, 1998, to the same period in 1997. The decrease
is primarily related to the timing of the Cheswick Power Station (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. Additionally, Elrama
Power Station had higher costs in 1997 due to scrubber outages.
Depreciation and Amortization Expense
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Depreciation and amortization decreased $19.3 million or 31.4 percent
during the third quarter of 1998 as compared to the third quarter of 1997. The
decrease was primarily the result of reduced depreciation of generating plant in
connection with the PUC's final restructuring order.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The decrease in depreciation and amortization in the nine months ended September
30, 1998, as compared to the same period in 1997 was $18.1 million or 10.4
percent. The decrease was primarily the result of reduced depreciation of
generating plant in connection with the PUC's final restructuring order.
Other Income
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Comparing the third quarter of 1998 and the third quarter of 1997, an
increase of $3.2 million or 13.6 percent in other income was primarily the
result of new investments made by the expanded business lines.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The increase of $1.8 million or 2.2 percent in other income, when comparing the
nine months ended September 30, 1998, and the nine months ended September 30,
1997, was the result of new investments by the expanded business lines and at
Duquesne during the fourth quarter of 1997. Partially offsetting the increase
was a gain on the sale of Chester in May 1997.
Interest and Other Charges
Comparison of Three Months Ended September 30, 1998, and September 30,
1997: Interest and other charges decreased $1.6 million or 5.5 percent during
the third quarter of 1998 as compared to the third quarter of 1997. The
decrease was primarily the result of the refinancing of long-term debt at lower
interest rates and the retirement of long-term debt.
Comparison of Nine Months Ended September 30, 1998, and September 30, 1997:
The decrease in interest and other charges in the nine months ended September
30, 1998, as compared to the same period in 1997 was $4.4 million or 5.0
percent. The decrease was primarily the result of the refinancing of long-term
debt at lower interest rates and the maturity of approximately $120 million of
long-term debt subsequent to the nine months ended September 1997.
Income Taxes
Income taxes were lower in 1998 as compared to 1997 for the three and nine
months ended September 30 by $12.5 million and $10.3 million, respectively. The
variances were the result of lower pre-tax income in 1998 and the new investment
made at Duquesne during the fourth quarter of 1997.
21
Extraordinary 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, 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 September 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 23.)
As of September 30, 1998, 266,039 shares of Preferred Stock, Series A
(Convertible), $100 liquidation preference per share (DQE Preferred Stock), had
been issued and were outstanding. An additional 3,120 shares of DQE Preferred
Stock were issued in October 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. The accounts receivable sale arrangement
expires in 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 was
extended during the third quarter to October 1999. The Company also maintains a
$125 million revolving credit facility which expires in June 1999. No
borrowings were outstanding under either facility at September 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 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 September 30, 1998.
During the fourth quarter of 1998, the Company engaged from time to time in
repurchasing shares of its common stock on the open market.
Investing
- --------------------------------------------------------------------------------
The Company has made long-term investments in the following areas: leases;
affordable housing; gas reserves; energy solutions; and water and wastewater
utilities. Investing activities during the first nine months of 1998 included
approximately $15 million in natural gas reserve partnerships, $8 million in
funding of affordable housing commitments and the remaining $27 million in other
investments. During the first nine months of 1997, the Company invested
approximately $172 million in lease investments, $8 million in affordable
housing investments, $12 million in natural gas reserve partnerships and the
remaining $12 million in other investments.
22
In the first nine months of 1998, the Company issued 250,559 shares of DQE
Preferred Stock, as part of a total investment of approximately $66 million in
water companies. An additional 3,120 shares of DQE Preferred stock were issued
in October 1998, as part of a total investment of approximately $17 million in
water companies.
The Company has completed, at a cost of approximately $40 million, the
construction of six plants to produce E-Fuel/TM/, a coal-based synthetic fuel.
All of these plants are currently in operation.
In the third quarter of 1998, the Company invested $22 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.
Cash flows, and the corresponding level of investing and financing
activities, are expected to be impacted by several factors during 1999.
Electric utility cash flows from operations, while expected to continue to be
strong, will be reduced from current levels as a result of customer choice (the
level of customer participation, the final shopping credit, etc.).
Additionally, related to the generation divestiture, substantial one-time cash
inflows and payments may result. The Company is currently analyzing various
opportunities for utilizing the divestiture proceeds including financial
restructuring, expansion of current business lines and the introduction of new
business lines. Additionally, the Company is also studying restructuring its
current investment portfolio, including the possible divestiture of its $120
million portfolio of affordable housing investments.
Rate Matters
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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
23
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. On November 6,
1998, the Company withdrew its appeal.
Phase-In to Competition
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 October
31, 1998, 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 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
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
generation rates (capped at current levels, so long as a CTC is being
collected). Also, under the Customer Choice Act, delivery of electricity
(including transmission, distribution and customer service) will continue to be
regulated in substantially the same manner as under current regulation.
In an effort to "jump start" retail competition, the Company will make 600
megawatts of power available to licensed electric generation suppliers, to be
used in supplying electricity to Duquesne's customers who have chosen other
generation suppliers. The power will be available for the first six months of
1999 at a price of 2.6 cents per kilowatt-hour (KWH). This availability will be
structured to ensure the power is used to benefit Duquesne's retail customers.
Rate Cap
An overall four-and-one-half-year rate cap from January 1, 1997 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 rates as long as transition costs are being
recovered, with certain exceptions.
Restructuring Plans and Regulatory Orders
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.
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. Until the
divestiture is complete, Duquesne has been ordered to use an interim system
average CTC and shopping credit based on the methodology approved in its pilot
program (approximately 2.9 cents per KWH for the CTC and approximately 3.8 cents
per KWH for the shopping credit). The PUC's order approves the auction only in
the context of the Stand-Alone Plan, not the Merger Plan.
On August 27, 1998, Duquesne filed its auction plan with the PUC. Duquesne
expects approval of the plan from the PUC by the end of 1998. The confidential
bidding process will begin in early 1999. Only companies with an established
record of owning and operating electric generating plants and with proof of
their financial ability to purchase the plants without financing will qualify to
24
bid. The transaction will have to be approved by various regulatory agencies
including the PUC, the FERC, the Nuclear Regulatory Commission (NRC), the
Department of Justice and the Federal Trade Commission. Duquesne expects the
process to last approximately 12 to 18 months from the opening of bidding to the
closing of the sale.
To help facilitate the auction process, on October 14, 1998, Duquesne
entered into a non-binding agreement in principle with FirstEnergy Corp. to
exchange ownership interests in certain plants. As proposed, Duquesne would
acquire 100 percent ownership interests in three coal-fired power plants located
in Avon Lake and Niles, Ohio and New Castle, Pennsylvania (totaling
approximately 1,300 megawatts). In exchange, FirstEnergy Corp. would acquire
Duquesne's interests in Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2
(BV Unit 2), Perry Unit 1, Sammis Unit 7, Eastlake Unit 5 and Bruce Mansfield
Units 1, 2 and 3 (totaling approximately 1,400 megawatts). The Company's
investment in these plants at September 30, 1998, was $894.1 million which has
been reclassified to "Other non-current generation-related assets" on the
condensed consolidated balance sheet. The Company has requested the PUC to
authorize the investment in the acquired power plants to be accounted for in the
final auction proceeds accounting utilizing the previously authorized investment
amount of the plants transferred by the Company. Duquesne expects this exchange
to enhance the value received from the auction because participants will be able
to bid on plants that are wholly owned by Duquesne, rather than plants that are
jointly owned and/or operated by another entity. Additionally, the auction will
include only coal- and oil-fired plants, which are anticipated to have a higher
market value than nuclear plants. These value-enhancing features, along with a
minimum level of auction proceeds guaranteed by FirstEnergy Corp., will maximize
auction proceeds and thereby minimize transition costs required to be recovered
through the CTC and reduce customer bills as rapidly as possible. Other
benefits of this exchange for Duquesne include the resolution of all joint
ownership issues, and other risks and costs associated with the nuclear units.
Duquesne expects PUC approval of the exchange by the end of 1998. Certain
aspects of the exchange will have to be approved by the FERC, the NRC and the
Department of Justice. The closing of the exchange is expected to occur
simultaneously with the closing of the sale of Duquesne's generation through the
auction.
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 tax) to reflect the disallowance associated with
the investments in the cold reserved units and the disallowance of a portion of
the regulatory asset claim described above.
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 would require 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 merged company would be required immediately to relinquish control of 570
megawatts of output from 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. The PUC would determine
which 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 Company believes the Midwest ISO, as
presently constituted and as approved by the FERC, will not mitigate the PUC's
concerns regarding market power.
25
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 Duquesne's 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 an average shopping
credit 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. The Company believes that as
of October 5, 1998, the relevant date under the merger agreement, AYE had
suffered a material adverse effect and, despite ample opportunity, had not
corrected it. Subsequent to the October 5, 1998, termination of the merger
agreement, the PUC tentatively approved a settlement of the West Penn
restructuring case, which settlement did not significantly increase the level of
West Penn's allowed stranded costs.
The FERC Order. The FERC issued its order regarding the proposed merger on
September 16, 1998. The order required the sale of Cheswick prior to
consummation of the merger, rejecting the proposal to relinquish control of 570
megawatts from that station in order to address market power concerns. The
Company does not believe such a divestiture could be accomplished quickly enough
to allow the proposed merger to occur within the timeframe contemplated in the
merger agreement. In addition, the FERC order does not address or alter the
financial effects on AYE of the PUC order discussed above.
Status of the AYE Merger. 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, 1998, 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.
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement. AYE promptly filed suit in the United States District Court
for the Western District of Pennsylvania, seeking to compel the Company to
proceed with the merger and seeking a temporary restraining order and
preliminary injunction to prevent the Company from certain actions pending a
trial, or in the alternative seeking an unspecified amount of money damages.
More information regarding this termination is set forth in the Company's
Current Report on Form 8-K dated October 5, 1998. A hearing was held on October
26, 1998, regarding AYE's motion for the temporary restraining order and
preliminary injunction. On October 28, 1998, the judge denied the motion. On
October 30, 1998, AYE appealed the judge's decision to the United States Court
of Appeals for the Third Circuit, asking for an injunction pending the appeal
and expedited treatment of the appeal. On November 6, 1998, the Third Circuit
denied the motion for an injunction and granted the motion to expedite the
appeal.
26
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 remained
off-line due to other issues identified by a technical review similar to that
performed at BV Unit 1. These technical reviews, which were in response to a
1997 commitment made by the Company to the NRC, have been completed. The Company
was one of many utilities faced with similar issues, some of which date back to
the initial start-up of BVPS. BV Unit 1 returned to service on August 15, 1998,
and BV Unit 2 returned to service on September 28, 1998.
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 3 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.
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.
Year 2000 Plan. In 1994, the Company began reviewing its critical
information systems that impact operations and financial reporting in order to
develop a strategy to address required computer software and system changes and
upgrades. The Company has since assembled a Year 2000 team, comprised of
management representatives from all functional areas of the Company, which
continues to explore the exposure to Year 2000-related issues in computer
software and in devices and equipment (such as plant components, elevators, and
heating and cooling systems) containing embedded microprocessors that may not
correctly identify the year. The team is also exploring potential related
issues that may originate with third parties with whom the Company does
business. To support the planning, organization and management of its efforts,
the team has retained Year 2000 consultants.
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 completed it during the fourth quarter
of 1998. Assessment consists of evaluating the inventoried items for Year 2000
compliance by, among other things, contacting vendors and inspecting software
code and data. As of the date of this report, the Company has completed
substantially all of its assessment. The Company is involved in ongoing
discussions with its critical vendors, and will continue working with them
throughout their transition to Year 2000 readiness. The remediation and testing
and implementation components will concentrate first on those systems,
components and equipment that substantially impact the Company's ability to
perform its essential business functions ("mission critical"). During
remediation, the Company will apply the solution selected for an item (e.g.,
whether to replace a product or vendor, employ a software upgrade, or revise
existing software code). The Company has completed approximately 25% of the
remediation it currently deems
27
necessary. This remediation is in addition to previously planned improvements to
the Company's systems with benefits beyond Year 2000 solutions, such as the
total system replacements discussed below. 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 remediation and
testing and implementation to take place during the first quarter of 1999, with
mission critical systems being compliant or appropriate contingency plans, if
necessary, being developed by that time.
Throughout the execution of its Year 2000 plan, the Company has been
providing and will continue to provide information on its activities to the PUC,
the NRC and the North American Electric Reliability Counsel (NERC), which
coordinates the network of interconnected utilities across the nation. The
Company's plan is in accordance with NRC guidelines, and the Company is working
with the NRC to certify that its nuclear power station safety and operations
systems, and issues related to suppliers, will be ready for the Year 2000. NERC
has been requested by the DOE to review the national electric power production
and delivery infrastructure to ensure a reliable power supply during the Year
2000 transition period. The Company is working with NERC to address these
issues. The Company also participates in the Electric Power Research
Institute's project to share information about technical issues regarding Year
2000 with other entities in the electric utility industry.
Risks and Contingency Plans. The Company currently believes that
implementation of its plan will minimize the Year 2000 issues relating to its
systems and equipment. The Company's goal is to ensure that all components and
services that in any material manner contribute to operational reliability,
customer relations, safety, revenue, regulatory compliance and the Company's
reputation will fully satisfy criteria regarding date-recognition and general
integrity of such components and services, or be suitable for continued use with
appropriate work-arounds or contingency plans. The Company currently is
assessing its operations to determine the most likely worst-case scenario it
could face as a result of the Year 2000 problem. Similarly, the Company
currently is developing contingency plans in the event any part of its overall
strategy should fail adequately to address the Year 2000 problem.
Costs. The estimated total cost of implementing the Company's Year 2000
plan is approximately $45 million, which includes costs related to total system
replacements (i.e., the Year 2000 solution comprises only a portion of the
benefit resulting from such replacements). These costs to date, primarily
incurred as a result of software and system changes and upgrades by Duquesne,
have been approximately $35 million. Of this amount, approximately $31 million
are capital costs attributable to the licensing and installation of new software
for total system replacements. The remaining $4 million has been expensed as
incurred. Funds for the Company's Year 2000 plan have come from the Company's
operating and capital budgets. Approximately $10 million has been budgeted for
1999 to address Year 2000 issues. Until the Company's remediation 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.
The foregoing paragraphs contain forward-looking statements regarding the
timetable, effectiveness and ultimate cost of the Company's Year 2000 strategy.
Actual results could materially differ from those implied by such statements due
to known and unknown risks and uncertainties, including, but not limited to, the
possibility that changes and upgrades are not timely completed, that corrections
to the systems of other companies on which the Company's systems rely may not be
timely completed, and that such changes and upgrades may be incompatible with
the Company's systems; the availability and cost of trained personnel; and the
ability to locate and correct all relevant computer code and microprocessors.
28
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Funding for nuclear decommissioning costs is deposited by the Company in
external, segregated trust accounts and invested in a portfolio of corporate
common stock and debt securities, municipal bonds, certificates of deposit and
United States government securities. The market value of the aggregate trust
fund balances at September 30, 1998 totaled approximately $56.2 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; 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.
29
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, the Company commenced arbitration against Cleveland
Electric Illuminating Company (CEI), a subsidiary of FirstEnergy Corp.
(FirstEnergy) 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. Pursuant to the agreement
in principle between Duquesne and FirstEnergy to exchange interests in certain
power stations (see "Restructuring Plans and Regulatory Orders" discussion
above), the parties jointly sought, and on October 26, 1998, received, a court
order staying all proceedings in the Eastlake litigation pending complete
execution of the exchange-related agreements.
AYE Merger
On October 5, 1998, the Company announced its unilateral termination of the
merger agreement. AYE promptly filed suit in the United States District Court
for the Western District of Pennsylvania, seeking to compel the Company to
proceed with the merger and seeking a temporary restraining order and
preliminary injunction to prevent the Company from certain actions pending a
trial, or in the alternative seeking an unspecified amount of money damages.
More information regarding this termination is set forth in the Company's
Current Report on Form 8-K dated October 5, 1998. A hearing was held on October
26, 1998, regarding AYE's motion for the temporary restraining order and
preliminary injunction. On October 28, 1998, the judge denied the motion. On
October 30, 1998, AYE appealed the judge's decision to the United States Court
of Appeals for the Third Circuit, asking for an injunction pending the appeal
and expedited treatment of the appeal. On November 6, 1998, the Third Circuit
denied the motion for an injunction and granted the motion to expedite the
appeal.
Item 5. Other Information
DQE previously reported that its 1998 Annual Meeting of Stockholders will
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) was
September 23, 1998.
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
30
b. A Current Report on Form 8-K was filed October 5, 1998, to report the
Company's termination of the merger agreement with AYE. No financial
statements were filed with this report.
A Current Report on Form 8-K was filed October 15, 1998, to report the
execution by Duquesne and FirstEnergy Corp. of an agreement in principle to
exchange interests in certain power stations. No financial statements were
filed with this report.
_____________________________
31
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
DQE, Inc.
----------------------------------------
(Registrant)
Date November 16, 1998 /s/ Gary L. Schwass
----------------- -----------------------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer
Date November 16, 1998 /s/ Morgan K. O'Brien
----------------- -----------------------------------------
(Signature)
Morgan K. O'Brien
Vice President, Treasurer and Controller
(Principal Accounting Officer)
32