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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For The Quarterly Period Ended March 31, 1998
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[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
For The Transition Period From __________ to __________
Commission File Number
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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 - 77,685,312 shares outstanding as of March 31,
1998 and 77,728,825 shares outstanding as of April 30, 1998.
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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
DQE
CONDENSED STATEMENT OF CONSOLIDATED INCOME
(Thousands of Dollars, Except Per Share Amounts)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
------------------------------
1998 1997
------------ ------------
<S> <C> <C>
Operating Revenues
Sales of Electricity:
Customers - net $264,307 $264,018
Utilities 7,072 8,731
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Total Sales of Electricity 271,379 272,749
Other 24,646 29,335
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Total Operating Revenues 296,025 302,084
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Operating Expenses
Fuel and purchased power 59,533 51,654
Other operating 77,275 81,632
Maintenance 20,283 17,749
Depreciation and amortization 57,185 55,174
Taxes other than income taxes 19,932 20,558
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Total Operating Expenses 234,208 226,767
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OPERATING INCOME 61,817 75,317
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OTHER INCOME 31,418 20,001
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INTEREST AND OTHER CHARGES 27,618 28,680
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INCOME BEFORE INCOME TAXES 65,617 66,638
INCOME TAXES 20,487 21,541
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NET INCOME $ 45,130 $ 45,097
============== ==============
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING
(Thousands of Shares) 77,683 77,287
============== ==============
BASIC EARNINGS PER SHARE OF
COMMON STOCK $0.58 $0.58
============== ==============
DILUTED EARNINGS PER SHARE
OF COMMON STOCK $0.57 $0.57
============== ==============
DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $0.36 $0.34
============== ==============
</TABLE>
See notes to condensed consolidated financial statements.
2
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DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
March 31, December 31,
1998 1997
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ASSETS
Current assets:
<S> <C> <C>
Cash and temporary cash investments $ 253,886 $ 356,412
Receivables 122,579 131,711
Other current assets, principally materials and supplies 81,714 81,233
-------------------- -------------------
Total current assets 458,179 569,356
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Long-term investments:
Leveraged leases 360,616 349,129
Affordable housing 134,643 137,860
Gas reserves 94,093 92,645
Other leases 61,660 69,329
Nuclear decommissioning trust 51,141 47,059
Marketable securities 9,845 10,620
Other long-term investments 19,192 16,144
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Total long-term investments 731,190 722,786
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Property, plant and equipment 4,652,427 4,625,128
Less: Accumulated depreciation and amortization (1,999,797) (1,962,794)
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Property, plant and equipment - net 2,652,630 2,662,334
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Other non-current assets:
Regulatory assets 672,470 680,885
Other 78,550 59,041
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Total other non-current assets 751,020 739,926
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TOTAL ASSETS $ 4,593,019 $ 4,694,402
==================== ===================
LIABILITIES AND CAPITALIZATION
Current liabilities:
Notes payable $ 2,921 $ --
Current maturities and sinking fund requirements 62,178 97,844
Other current liabilities 131,690 184,122
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Total current liabilities 196,789 281,966
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Deferred income taxes - net 743,213 693,215
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Deferred investment tax credits 95,677 97,782
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Capital lease obligations 38,927 37,540
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Deferred income 192,285 225,107
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Other non-current liabilities 256,365 255,467
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Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,308,111 1,376,121
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Preferred and preference stock of subsidiaries:
Preferred and preference stock before deferred employee stock
ownership plan (ESOP) benefit 242,599 242,903
Deferred ESOP benefit (15,562) (16,400)
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Total preferred and preference stock of subsidiaries 227,037 226,503
-------------------- -------------------
Preferred stock 18,145 1,548
==================== ===================
Common shareholders' equity:
Common stock - no par value (authorized - 187,500,000 shares;
issued - 109,679,154 shares) 1,001,298 1,001,225
Retained earnings 886,916 869,749
Less treasury stock (at cost) (31,993,842 and 31,998,723
shares, respectively) (371,744) (371,821)
-------------------- -------------------
Total common shareholders' equity 1,516,470 1,499,153
-------------------- -------------------
Total capitalization 3,069,763 3,103,325
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TOTAL LIABILITIES AND CAPITALIZATION $ 4,593,019 $ 4,694,402
==================== ===================
</TABLE>
See notes to condensed consolidated financial statements.
3
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DQE
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
<TABLE>
<CAPTION>
Three Months Ended
March 31,
---------
1998 1997
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Cash Flows From Operating Activities
<S> <C> <C>
Operations $ 124,686 $108,101
Changes in working capital other than cash (43,781) (30,627)
(Increase) decrease in ECR (7,270) 99
Other 1,804 15,370
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Net Cash Provided By Operating Activities 75,439 92,943
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Cash Flows From Investing Activities
Capital expenditures (37,382) (17,213)
Long-term investments - net (12,495) (68,337)
Other 2,153 2,238
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Net Cash Used in Investing Activities (47,724) (83,312)
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Cash Flows From Financing Activities
Reductions of long term obligations - net (98,163) (7,780)
Dividends on common stock (27,963) (26,275)
Increase in notes payable 2,921 181
Other (7,036) 122
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Net Cash Used in Financing Activities (130,241) (33,752)
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Net decrease in cash and temporary cash investments (102,526) (24,121)
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 $ 253,886 $386,857
=============== ==============
Non-Cash Investing and Financing Activities
Preferred stock issued in conjunction with long-term investments $ 16,597 $ --
=============== ==============
Capital lease obligations recorded $ 2,552 $ 500
=============== ==============
Equity funding obligations recorded $ -- $ 2,888
=============== ==============
</TABLE>
See notes to condensed consolidated financial statements.
4
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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting DQE, Inc. and its subsidiaries'
(the Company's) operations, markets, products, services and prices, and other
factors discussed in the Company's filings with the Securities and Exchange
Commission (SEC).
1. CONSOLIDATION, RECLASSIFICATIONS AND ACCOUNTING POLICIES
DQE, Inc. (DQE) is an energy services holding company. Its subsidiaries are
Duquesne Light Company (Duquesne); Duquesne Enterprises, Inc. (DE); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); and Montauk, Inc.
(Montauk). DQE and its subsidiaries are collectively referred to as "the
Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE makes strategic investments beneficial to DQE's core energy
business. These investments are intended to enhance DQE's capabilities as an
energy provider, increase asset utilization, and act as a hedge against changing
business conditions. DES is a diversified energy services company offering a
wide range of energy solutions for industrial, utility and consumer markets
worldwide. DES initiatives include energy facility development and operation,
domestic and international independent power production, and the production and
supply of innovative fuels. DQEnergy was formed to align DQE with strategic
partners to capitalize on opportunities in the energy services industry. These
alliances are intended to enhance the utilization and value of DQE's strategic
investments and capabilities while establishing DQE as a total energy provider.
Montauk is a financial services company that makes long-term investments and
provides financing for the Company's other market-driven businesses and their
customers.
On August 7, 1997, the shareholders of the Company and Allegheny Energy,
Inc. (AYE), approved a proposed tax-free, stock-for-stock merger. Upon
consummation of the merger, DQE will be a wholly owned subsidiary of AYE.
Immediately following the merger, Duquesne, DE, DES, DQEnergy and Montauk will
remain wholly owned subsidiaries of DQE. The transaction was originally
expected to close in mid-1998, subject to approval of applicable regulatory
agencies. On April 30, 1998, the Pennsylvania Public Utility Commission (PUC)
voted to approve the proposed merger of DQE and AYE, provided that the companies
first join a fully functioning Independent System Operator (ISO) in order to
address market power concerns. An ISO is a regional electricity transmission
organization. The precondition could delay, or ultimately prevent, consummation
of the merger. (See "PUC Proceedings" discussion, Note 3, page 9.) Unless
otherwise indicated, all information presented in this Form 10-Q relates to the
Company only and does not take into account the proposed merger between the
Company and AYE.
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 months ended March
31, 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
5
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that affect the reported amounts of assets and liabilities and disclosure of
contingent assets and liabilities at the date of the financial statements. The
reported amounts of revenues and expenses during the reporting period may also
be affected by the estimates and assumptions management is required to make.
Actual results could differ from those estimates.
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters.
The Company's consolidated financial statements report regulatory assets
and liabilities in accordance with Statement of Financial Accounting Standards
(SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS
No. 71), and reflect the effects of the current ratemaking process. In
accordance with SFAS No. 71, the Company's consolidated financial statements
reflect regulatory assets and liabilities consistent with cost-based, pre-
competition ratemaking regulations. (See "Rate Matters," Note 3, on page 7.)
The Company's long-term investments include assets of nuclear
decommissioning trusts and marketable securities accounted for in accordance
with SFAS No. 115, Accounting for Certain Investments in Debt and Equity
Securities. These investments are classified as available-for-sale and are
stated at market value. The amounts of unrealized holding gains related to
marketable securities at March 31, 1998, and December 31, 1997, were $8.6
million and $8.1 million ($5.0 million and $4.7 million net of tax),
respectively.
Through the Energy Cost Rate Adjustment Clause (ECR), the Company recovers
(to the extent that such amounts are not included in base rates) nuclear fuel,
fossil fuel and purchased power expenses and, also through the ECR, passes to
its customers the profits from short-term power sales to other utilities
(collectively, ECR energy costs). Under the Company's mitigation plan approved
by the PUC in June 1996, the level of energy cost recovery is capped at 1.47
cents per kilowatt-hour (KWH) through May 2001. The rate currently being
recovered is 1.28 cents per KWH, based upon estimated 1996 costs. To the extent
that current fuel and purchased power costs, in combination with previously
deferred fuel and purchased power costs, are not projected to be recoverable
through this pricing mechanism, these costs would become transition costs
subject to recovery through a competitive transition charge (CTC). (See "Rate
Matters," Note 3, on page 7.) Nuclear fuel expense is recorded on the basis of
the quantity of electric energy generated and includes such costs as the fee
imposed by the United States Department of Energy (DOE) for future disposal and
ultimate storage and disposition of spent nuclear fuel. Fossil fuel expense
includes the costs of coal, natural gas and fuel oil used in the generation of
electricity.
On the Company's statement of consolidated income, these ECR revenues are
included as a component of operating revenues. For ECR purposes, the Company
defers fuel and other energy expenses for recovery, or refunding, in subsequent
years. The deferrals reflect the difference between the amount that the Company
is currently collecting from customers and its actual ECR energy costs. The PUC
annually reviews the Company's ECR energy costs for the fiscal year April
through March, compares them to previously projected ECR energy costs, and
adjusts the ECR for over- or under-recoveries and for two PUC-established coal
cost standards. This adjustment was not made during 1997, despite a projected
increase of 0.13 cents per KWH, pending the outcome of the Company's
Restructuring Plan or Stand-Alone Plan (as defined in "Rate Matters," Note 3, on
page 7).
Over- or under-recoveries from customers have been recorded in the
consolidated balance sheet as payable to, or receivable from, customers. Based
on Duquesne's Restructuring Plan and Stand-Alone Plan, the 1997 under-recoveries
were reclassified as a regulatory asset and may be recovered through a CTC. At
March 31, 1998, $30.8 million was receivable from customers. At December 31,
1997, $23.5 million was receivable from customers.
6
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2. RECEIVABLES
The components of receivables for the periods indicated are as follows:
<TABLE>
<CAPTION>
March 31, March 31, December 31,
1998 1997 1997
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Electric customer accounts receivable $ 84,323 $ 97,655 $ 90,149
Other utility receivables 19,894 16,534 23,106
Other receivables 34,684 34,465 33,472
Less: Allowance for uncollectible accounts (16,322) (19,869) (15,016)
- -------------------------------------------------------------------------------------------------------------
Total Receivables $122,579 $128,785 $131,711
=============================================================================================================
</TABLE>
The Company and an unaffiliated corporation have an agreement that entitles
the Company to sell, and the corporation to purchase, on an ongoing basis, up to
$50 million of accounts receivable. At March 31, 1998, and March 31 and
December 31, 1997, the Company had not sold any receivables to the unaffiliated
corporation. The accounts receivable sales agreement, which expires in June
1998, 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.
3. 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). For the first stage, the Company filed a pilot program with the PUC on
February 27, 1997. For the second stage, the Company filed on August 1, 1997 its
restructuring and merger plan (the Restructuring Plan) and its stand-alone
restructuring plan (the Stand-Alone Plan) with the PUC.
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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
Company pilot filing proposed unbundling transmission, distribution, generation
and competitive transition charges and offered participating customers the same
options that were to be available in a competitive generation market. The pilot
was designed to comprise approximately 5 percent of the Company's residential,
commercial and industrial demand. The 28,000 customers participating in the
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. On May 9, 1997, the PUC issued a
Preliminary Opinion and Order approving the Company's filing in part, and
requiring certain revisions. The Company and other utilities objected to several
features of the PUC's Preliminary Opinion and Order. Hearings on several key
issues were held in July. The PUC issued its final order on August 29, 1997,
approving a revised pilot program for the Company. On September 8, 1997, the
Company appealed the determination of the market price of generation set forth
in this order to the Commonwealth Court of Pennsylvania. The Company expects a
hearing to be scheduled for mid-1998. Although this appeal is pending, the
Company complied with the PUC's order to implement the pilot program that began
on November 3, 1997.
Phase-In to Competition
As set forth in the Customer Choice Act, the phase-in to competition begins
on January 1, 1999, when 33 percent of customers will have customer choice
(including customers covered by the pilot program); 66 percent of customers will
have customer choice no later than January 1, 2000; and all customers will have
customer choice no later than January 1, 2001. However, in its sole order to
date (the PECO Order), the PUC ordered the phase-in provisions of the Customer
Choice Act to require the acceleration of the second and third phases to January
2, 1999 and January 2, 2000, respectively; in addition, in its April 30, 1998
meeting the PUC voted to similarly accelerate the phase-in to competition for
the Company's customers. (See "PUC Proceedings" discussion on page 9.) As they
are phased-in, customers that have chosen an electricity generation supplier
other than the Company will pay that supplier for generation charges, and will
pay the Company a CTC (discussed below) and unbundled charges for transmission
and distribution. Customers that continue to buy their generation from the
Company will pay for their service at current regulated tariff rates divided
into unbundled generation, transmission and distribution charges. The PECO Order
concluded that under the Customer Choice Act, an electric distribution company,
such as Duquesne, is to remain a regulated utility and may only offer PUC-
approved, tariffed rates (including unbundled generation rates). Delivery of
electricity (including transmission, distribution and customer service) will
continue to be regulated in substantially the same manner as under current
regulation.
Rate Cap and Transition Cost Recovery
Before the phase-in to customer choice begins in 1999, the PUC expects
utilities to take vigorous steps to mitigate transition costs as much as
possible without increasing the rates they currently charge customers. The
Company has mitigated in excess of $350 million of transition costs during the
past three years through accelerated annual depreciation and a one-time write-
down of nuclear generating station costs, accelerated recognition of nuclear
lease costs, increased nuclear decommissioning funding, and amortization of
various regulatory assets. This relative level of transition cost reduction,
while holding rates constant, is unmatched within Pennsylvania.
The PUC will determine what portion of a utility's transition costs that
remain at January 1, 1999 will be recoverable through a CTC from customers. The
CTC recovery period could last through 2005, providing a utility a total of up
to nine years beginning January 1, 1997 to recover transition costs, unless this
period is extended as part of a utility's PUC-approved transition plan. An
overall four-and-one-half-year rate cap from January 1, 1997 will be imposed on
the transmission
8
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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. The
Company has requested recovery of transition costs of approximately $2 billion,
net of deferred taxes, beginning January 1, 1999. Of this amount, $0.5 billion
represents regulatory assets and $1.5 billion represents potentially uneconomic
plant and plant decommissioning costs. Any estimate of the ultimate level of
transition costs for the Company depends on, among other things, the extent to
which such costs are deemed recoverable by the PUC, the ongoing level of the
cost of Duquesne's operations, regional and national economic conditions, and
growth of the Company's sales. (See "Financial Exposure to Transition Cost
Recovery" discussion on page 23; "PUC Proceedings" discussion below; and
"Regulatory Assets and Emerging Issues Task Force" discussion on page 11).
Stand-Alone Plan
In the event the merger with AYE is not consummated under the filed
Restructuring Plan, the Company has sought approval for restructuring and
recovery of its own transition costs through a CTC under the Stand-Alone Plan.
The Company argued, as a fundamental premise, that any finding of market value
for the Company's generating assets to determine transition costs should be
based on market evidence and not on an administrative determination of that
value based on price forecasts (the PECO Order determined the market value of
PECO Energy Company's generation based on the price forecast sponsored by the
Pennsylvania Office of Consumer Advocate). The Company proposed a number of
alternative final market valuation methodologies that it believed would satisfy
this market-based standard. As an alternative, if the PUC finds that a
determination of market value as of December 31, 1998, is required by the
Customer Choice Act, then the Company has agreed that the PUC may order an
immediate auction of the Company's generation at that time. (A more detailed
discussion of alternative methodologies to determine transition costs based on
market evidence is set forth in the Company's Annual Report on Form 10-K for the
Year Ended December 31, 1997.)
Restructuring Plan
The Restructuring Plan incorporated the benefits of the merger with AYE,
such as anticipated savings to the Company, on a nominal basis, of $365 million
in generation-related costs over 20 years, and $9 million in transmission-
related costs and $173 million in distribution-related costs over 10 years. The
Restructuring Plan also incorporated the market-based approach to determining
transition costs proposed by the Company in its Stand-Alone Plan, however the
Company did not agree that the PUC may order an immediate auction of its
generation to determine transition costs. (A more detailed discussion of
alternative methodologies to determine transition costs based on market evidence
is set forth in the Company's Annual Report on Form 10-K for the Year Ended
December 31, 1997.) The opposing parties believe that there should be a one-
time valuation of the generation assets performed as of December 31, 1998. Any
merger-related synergies relating to generation would then be used to reduce the
Company's transition costs as of that date. These parties also believe that the
Company's proposed distribution rate decrease should be effective on January 1,
1999. The Company has requested a total CTC recovery of transition costs of
$1.899 billion in the event the PUC does not accept its proposal to determine
transition costs based on market evidence.
PUC Proceedings
On March 25, 1998, two PUC administrative law judges recommended that a
decision on the proposed merger of the Company and AYE be deferred for up to 18
months to allow the companies to address market power concerns. In two other
decisions issued at the same time, the judges recommended approval, with
modifications, of the restructuring plans of Duquesne and of AYE's utility
subsidiary, West Penn Power. On April 14, 1998, the Company filed exceptions to
the administrative law judges' recommendations. Also on April 14, the Company
and AYE jointly filed exceptions to the PUC administrative law judges'
recommendation that approval of the proposed merger be delayed.
9
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The administrative law judge did not support the Company's market-based
approach to determining the value of its generating assets (and thereby its
CTC), and recommended instead either an immediate auction of the Company's
generating assets if the proposed merger is not consummated, or an
administrative determination of the value of such assets if the proposed merger
is consummated. In its exceptions, the Company sought clarification of the
administrative law judge's recommendation and reaffirmed its fundamental premise
that market data should be used to set the value of its generating assets.
In their joint exceptions, the Company and AYE committed to mitigate the
potential market power of the new company by joining the Midwest Independent
System Operator (MISO) and by relinquishing control of the output of the
Company's 570-megawatt Cheswick Power Station (Cheswick) for a minimum of two
years or until the MISO has been approved. Both actions would occur immediately
upon completion of the proposed merger. The Company and AYE further committed
to issue a request for proposals to sell the output of Cheswick within a month
of securing all required regulatory approvals for the proposed merger. The
Company would continue to own and operate Cheswick.
On April 30, 1998, the PUC held a nonbinding vote on the recommended
decisions. Reversing the recommendation to delay a decision by up to 18 months,
the PUC voted instead to approve the merger. However, to address market power
concerns, the PUC also required membership in a fully functioning ISO prior to
consummation of the merger. The PUC recognized that joining either the MISO (as
discussed above) or the Pennsylvania-New Jersey-Maryland ISO (PJM) would be an
acceptable option. The MISO's application for approval is before the FERC, but
no date for a decision has been set. Pursuing membership in PJM would require
the Company and AYE to file an updated market power study with the PUC. The
precondition of joining a fully functioning ISO could delay, or ultimately
prevent, consummation of the merger.
With respect to the Stand-Alone Plan, the PUC voted to require the Company
to auction its generating assets in order to determine their market value and
its CTC. The Company would have to submit a divestiture plan to the PUC within
90 days of the effective date of a final order. If such a divestiture were not
completed by January 1, 1999, the Company would use an interim CTC set at the
rate approved in its pilot program. The CTC determined by the auction would be
permanent, precluding annual adjustments based on the market price of power as
originally proposed by the Company.
With respect to the Restructuring Plan, the PUC proposed calculating the
Company's transition costs based on an administrative determination of the value
of its generating assets as opposed to the Company's proposed market-based
approach. The PUC would set the Company's transition costs at approximately $1.3
billion, reflecting $152.28 million in generation-related savings resulting from
the merger. This amount would disallow certain assets the Company anticipated
including in its transition costs, including, among other things, the cold-
reserved units at Philips Power Station and at a portion of Brunot Island Power
Station. (See "Regulatory Assets and Emerging Issues Task Force" discussion on
page 11.) The PUC would permit transition cost recovery through 2005 pursuant to
a CTC initially set at an average of 2.58 cents per KWH for 1999 (resulting in a
shopping credit, or reduction from previously bundled rates, of 4.01 cents per
KWH). The PUC would also reduce the Company's distribution rates by $15 million
per year beginning January 1, 2000, to reflect merger savings. The Company has
calculated the effects of the PUC's CTC and shopping credit determination, and
estimates that, correcting for computational errors, the 1999 average CTC should
be 2.73 cents per KWH (resulting in a shopping credit of 3.49 cents per KWH).
The PUC also voted to accelerate the Company's phase-in to competition
schedule. The Customer Choice Act calls for phase-in of one-third of customers
by January 1, 1999; two-thirds by January 1, 2000; and the final third by
January 1, 2001. The PUC voted to accelerate the second third to January 2,
1999, and the final third to January 2, 2000.
Final orders with respect to the PUC's vote will be written, and a final
binding vote is currently scheduled to take place on May 21, 1998.
10
<PAGE>
The Federal Filings
In addition to the PUC filings of the Restructuring Plan and the Stand-
Alone Plan, on August 1, 1997, the Company and AYE filed their joint merger
application with the FERC (the FERC Filing). Pursuant to the FERC Filing, the
Company and AYE have committed to forming or joining an ISO that meets the
entity's requirements, including marginal cost transmission pricing, following
the merger. In April 1998, executives from the Company and AYE notified the
FERC of their intention to join the MISO, and that they would not withdraw from
the MISO without the prior approval of the FERC. In addition, the Company and
AYE have stated in the FERC Filing that following the merger the combined
entity's market share will not violate the market power conditions and
requirements set by the FERC. On January 20, 1998, the Company and AYE filed
merger applications with the Antitrust Division of the Department of Justice and
the Federal Trade Commission. These applications are currently pending.
Regulatory Assets and Emerging Issues Task Force
As a result of the application of SFAS No. 71, the Company records
regulatory assets on its consolidated balance sheet. The regulatory assets
represent probable future revenue to the Company because provisions for these
costs are currently included, or are expected to be included, in charges to
electric utility customers through the ratemaking process.
A company's electric utility operations, or a portion of such operations,
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See "Competition and the Customer Choice Act" discussion on page
7.) The Emerging Issues Task Force of the Financial Accounting Standards Board
(EITF) has determined that once a transition plan has been approved, application
of SFAS No. 71 to the generation portion of a utility must be 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).
The consensus reached by the EITF provides further guidance that the regulatory
assets and liabilities of the generation portion of a utility to which SFAS No.
101 is being applied should be 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 April 30 vote, certain of the
Company's generation-related regulatory assets may be recovered through a 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 a utility will be evaluated
including the cash flows provided by the CTC, in accordance with SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of (SFAS No. 121). Following the final PUC vote on May 21, once any
portion of the Company's electric utility operations is deemed to no longer meet
the SFAS No. 71 criteria, or is not recovered through a CTC, the Company will be
required to write off assets (to the extent their net book value exceeds fair
value), the recovery of which is uncertain, and any regulatory assets or
liabilities for those operations that no longer meet these requirements. Any
such write-off of assets could be materially adverse to the financial position,
results of operations and cash flows of the Company. (See "PUC Proceedings"
discussion on page 9.)
The Company's regulatory assets related to generation, transmission and
distribution as of March 31, 1998 were $556.1 million, $32.4 million and $84.0
million, respectively. At December 31, 1997, the Company's regulatory assets
related to generation, transmission and distribution were $561.9 million, $33.2
million and $85.8 million, respectively.
11
<PAGE>
The components of all regulatory assets for the periods presented are as
follows:
<TABLE>
<CAPTION>
- -------------------------------------------------------------------------------------
March 31, December 31,
1998 1997
(Amounts in Thousands of Dollars)
- -------------------------------------------------------------------------------------
<S> <C> <C>
Regulatory tax receivable $288,113 $301,664
Brunot Island and Phillips cold reserve units 105,693 105,693
Unamortized debt costs 93,226 87,915
Deferred energy costs 48,854 39,225
Deferred rate synchronization costs 36,177 37,231
Beaver Valley Unit 2 sale/leaseback premium 28,177 28,554
Deferred employee costs 20,109 25,130
Deferred nuclear maintenance outage costs 13,685 17,013
DOE decontamination and decommissioning receivable 8,609 8,847
Other 29,827 29,613
- -------------------------------------------------------------------------------------
Total Regulatory Assets $672,470 $680,885
- -------------------------------------------------------------------------------------
</TABLE>
4. COMMITMENTS AND CONTINGENCIES
Construction
The Company estimates that it will spend, excluding the Allowance for Funds
Used During Construction and nuclear fuel, approximately $130 million for
electric utility construction during 1998. The Company has committed to the
construction of six plants to produce E-Fuel(TM), a coal-based synthetic fuel,
in 1998. The Company estimates the cost of this construction to be
approximately $32 million, of which $8 million was spent during the first
quarter of 1998.
Nuclear-Related Matters
The Company has an ownership or leasehold interest in three nuclear units,
two of which it operates. The operation of a nuclear facility involves special
risks, potential liabilities, and specific regulatory and safety requirements.
Specific information about risk management and potential liabilities is
discussed below.
Nuclear Decommissioning. The Company expects to decommission Beaver Valley
Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and Perry Unit 1 no earlier
than the expiration of each plant's operating license in 2016, 2027 and 2026,
respectively. At the end of its operating life, BV Unit 1 may be placed in safe
storage until BV Unit 2 is ready to be decommissioned, at which time the units
may be decommissioned together.
Based on site-specific studies conducted in 1997 for BV Unit 1 and BV Unit
2, and a 1997 update of the 1994 study for Perry Unit 1, the Company's
approximate share of the total estimated decommissioning costs, including
removal and decontamination costs, is $170 million, $55 million and $90 million,
respectively. The amount currently being used to determine the Company's cost of
service related to decommissioning all three nuclear units is $224 million. The
Company is seeking recovery of any potential shortfall in decommissioning
funding as part of either its Restructuring Plan or its Stand-Alone Plan. (See
"Rate Matters," Note 3, on page 7.)
With respect to the transition to a competitive generation market, the
Customer Choice Act requires that utilities include a plan to mitigate any
shortfall in decommissioning trust fund payments for the life of the facility
with any future decommissioning filings. Consistent with this requirement, in
1997 the Company increased its annual contributions to the decommissioning
trusts by $5 million to approximately $9 million. The Company has received
approval from the IRS for tax qualification of 100 percent of additional nuclear
decommissioning trust funding for BV Unit 2 and Perry Unit 1, and 79 percent for
BV Unit 1.
12
<PAGE>
Funding for nuclear decommissioning costs is deposited in external,
segregated trust accounts and invested in a portfolio of corporate common stock
and debt securities, municipal bonds, certificates of deposit and United States
government securities. The market value of the aggregate trust fund balances at
March 31, 1998, totaled approximately $51.1 million.
Nuclear Insurance. The Price-Anderson Amendments to the Atomic Energy Act
of 1954 limit public liability from a single incident at a nuclear plant to $8.9
billion. The maximum available private primary insurance of $200 million has
been purchased by the Company. Additional protection of $8.7 billion would be
provided by an assessment of up to $79.3 million per incident on each nuclear
unit in the United States. The Company's maximum total possible assessment,
$59.4 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 21 weeks after an
accident, with no coverage thereafter. If NEIL's losses for this program ever
exceed its reserves, the Company could be assessed retrospective premiums
totaling a maximum of $2.6 million.
Beaver Valley Power Station (BVPS) Steam Generators. BVPS's two units are
equipped with steam generators designed and built by Westinghouse Electric
Corporation (Westinghouse). Similar to other Westinghouse nuclear plants,
outside diameter stress corrosion cracking (ODSCC) has occurred in the steam
generator tubes of both units. BV Unit 1, which was placed in service in 1976,
has removed approximately 17 percent of its steam generator tubes from service
through a process called "plugging." However, BV Unit 1 still has the capability
to operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called "sleeving." No tubes at
either BV Unit 1 or BV Unit 2 have been sleeved to date. BV Unit 2, which was
placed in service 11 years after BV Unit 1, has not yet exhibited the degree of
ODSCC experienced at BV Unit 1. Approximately 2 percent of BV Unit 2's tubes are
plugged; however, it is too early in the life of the unit to determine the
extent to which ODSCC may become a problem at that unit.
The Company has undertaken certain measures, such as increased inspections,
water chemistry control and tube plugging, to minimize the operational impact of
and to reduce susceptibility to ODSCC. Although the Company has taken these
steps to allay the effects of ODSCC, the inherent potential for future ODSCC in
steam generator tubes of the Westinghouse design still exists. Material
acceleration in the rate of ODSCC could lead to a loss of plant efficiency,
significant repairs or the possible replacement of the BV Unit 1 steam
generators. The total replacement cost of the BV Unit 1 steam generators is
currently estimated at $125 million. The Company would be responsible for $59
million of this total, which includes the cost of equipment removal and
replacement steam generators but excludes replacement power costs. The earliest
that the BV Unit 1 steam generators could be replaced during a currently
scheduled refueling outage is the spring of 2002.
13
<PAGE>
The Company continues to explore all viable means of managing ODSCC,
including new repair technologies, and plans to continue to perform 100 percent
tube inspections during future refueling outages. The next refueling outage for
BV Unit 1 is scheduled to begin in April 1999, and the next refueling outage for
BV Unit 2 is currently scheduled to begin in September 1998. Both outages will
include inspection of 100 percent of each unit's steam generator tubes. The
Company will continue to monitor and evaluate the condition of the BVPS steam
generators.
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review completed by the Company. BV Unit 2 went off-line December 16,
1997, to repair the emergency air supply system to the control room and has
remained off-line due to other issues identified by a technical review similar
to that performed at BV Unit 1. These technical reviews are in response to a
1997 commitment made by the Company to the Nuclear Regulatory Commission (NRC).
The Company is one of many utilities faced with similar issues, some of which
date back to the initial start-up of BVPS. Both BVPS units remain off-line for a
reaffirmation of compliance with technical specification requirements of various
plant systems. The Company is currently participating in a series of meetings
with the NRC to review its action plans. Both units are expected to remain off-
line until the action plans have been satisfactorily completed.
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
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, was not entirely in favor of the DOE or the utilities. The
court permitted the DOE to pursue alternative dispute resolution, but prohibited
it from using its lack of a spent fuel repository as a defense. While the DOE
has requested a rehearing on the matter, the utilities and states have requested
the DOE be required to submit a definitive plan to begin accepting spent nuclear
fuel. The court has not ruled on either request yet.
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 March 31, 1998 and December 31, 1997, the Company's liability
for contributions was approximately $7.2 million (subject to an inflation
adjustment). (See "Rate Matters," Note 3, on page 7.)
Fossil Decommissioning
In Pennsylvania, current ratemaking does not allow utilities to recover
future decommis-sioning costs through depreciation charges during the operating
life of fossil-fired generating stations. Based on studies conducted in 1997,
this 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
14
<PAGE>
to be decommissioned upon the cessation of the final unit's operations. The
Company has submitted these estimates to the PUC, and is seeking to recover
these costs as part of either its Restructuring Plan or its Stand-Alone Plan.
(See "Rate Matters", Note 3, 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 March 31, 1998, the Company's share of
these guarantees was $10.8 million. The prices paid for the coal by the
companies under this contract are expected to be sufficient to meet debt and
lease obligations to be satisfied in the year 2000. The minimum future payments
to be made by the Company solely in relation to these obligations are $11.7
million at March 31, 1998.
As part of the Company's investment portfolio in affordable housing, the
Company has received fees in exchange for guaranteeing a minimum defined yield
to third-party investors. A portion of the fees received has been deferred to
absorb any required payments with respect to these transactions. Based on an
evaluation of the underlying housing projects, the Company believes that such
deferrals are ample for this purpose.
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.
15
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
of Operations
Part I, Item 2 of this Quarterly Report on Form 10-Q should be read in
conjunction with DQE, Inc. and its subsidiaries' (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 15 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); Duquesne Enterprises, Inc. (DE); DQE Energy
Services, Inc. (DES); DQEnergy Partners, Inc. (DQEnergy); and Montauk, Inc.
(Montauk). DQE and its subsidiaries are collectively referred to as "the
Company."
Duquesne is an electric utility engaged in the generation, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE makes strategic investments beneficial to DQE's core energy
business. These investments are intended to enhance DQE's capabilities as an
energy provider, increase asset utilization, and act as a hedge against changing
business conditions. DES is a diversified energy services company offering a
wide range of energy solutions for industrial, utility and consumer markets
worldwide. DES initiatives include energy facility development and operation,
domestic and international independent power production, and the production and
supply of innovative fuels. DQEnergy was formed to align DQE with strategic
partners to capitalize on opportunities in the energy services industry. These
alliances are intended to enhance the utilization and value of DQE's strategic
investments and capabilities while establishing DQE as a total energy provider.
Montauk is a financial services company that makes long-term investments and
provides financing for the Company's other market-driven businesses and their
customers.
On August 7, 1997, the shareholders of the Company and Allegheny Energy,
Inc. (AYE), approved a proposed tax-free, stock-for-stock merger. Upon
consummation of the merger, DQE will be a wholly owned subsidiary of AYE.
Immediately following the merger, Duquesne, DE, DES, DQEnergy and Montauk will
remain wholly owned subsidiaries of DQE. The transaction was originally
expected to close in mid-1998, subject to approval of applicable regulatory
agencies. On April 30, 1998, the Pennsylvania Public Utility Commission (PUC)
voted to approve the proposed merger of DQE and AYE, provided that the companies
first join a fully functioning Independent System Operator (ISO) in order to
address market power concerns. An ISO is a regional electricity transmission
organization. This precondition could delay, or ultimately prevent,
consummation of the merger. (See "PUC Proceedings" discussion on page 25.)
Unless otherwise indicated, all information presented in this Form 10-Q relates
to the Company only and does not take into account the proposed merger between
the Company and AYE.
The Company's Electric Service Territory
The Company's utility operations provide electric service to customers in
Allegheny County, including the City of Pittsburgh, Beaver County and
Westmoreland County. (See "Rate Matters" discussion on page 21.) This
represents approximately 800 square miles in southwestern Pennsylvania, located
within a 500-mile radius of one-half of the population of the United States and
Canada. The population of the area served by the Company's electric utility
operations, based on 1990 census data, is approximately 1,510,000, of whom
370,000 reside in the City of Pittsburgh. In addition to serving approximately
580,000 direct customers, the Company's utility operations also sell electricity
to other utilities.
16
<PAGE>
Regulation
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to
regulation by the PUC, including regulation under the Pennsylvania Electricity
Generation Customer Choice and Competition Act (Customer Choice Act), and the
Federal Energy Regulatory Commission (FERC) under the Federal Power Act with
respect to rates for interstate sales, transmission of electric power,
accounting and other matters. (See "Rate Matters" on page 21.)
The Company's electric utility operations are also subject to regulation by
the Nuclear Regulatory Commission (NRC) under the Atomic Energy Act of 1954, as
amended, with respect to the operation of its jointly owned/leased nuclear power
plants, Beaver Valley Unit 1 (BV Unit 1), Beaver Valley Unit 2 (BV Unit 2) and
Perry Unit 1.
The Company's consolidated financial statements report regulatory assets
and liabilities in accordance with Statement of Financial Accounting Standards
(SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation (SFAS
No. 71), and reflect the effects of the current ratemaking process. In
accordance with SFAS No. 71, the Company's consolidated financial statements
reflect regulatory assets and liabilities consistent with cost-based, pre-
competition 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.
A company's electric utility operations, or a portion of such operations,
could cease to meet the SFAS No. 71 criteria for various reasons, including a
change in the FERC regulations or the competition-related changes in the PUC
regulations. (See "Rate Matters" on page 21.) The Emerging Issues Task Force of
the Financial Accounting Standards Board (EITF) has determined that once a
transition plan has been approved, application of SFAS No. 71 to the generation
portion of a utility must be 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). The consensus reached by
the EITF provides further guidance that the regulatory assets and liabilities of
the generation portion of a utility to which SFAS No. 101 is being applied
should be 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 April 30 vote, certain of the Company's
generation-related regulatory assets may 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 a
utility will be evaluated including the cash flows provided by the CTC, in
accordance with SFAS No. 121, Accounting for the Impairment of Long-Lived Assets
and for Long-Lived Assets to Be Disposed Of (SFAS No. 121). Following the final
PUC vote on May 21 regarding the Company's Restructuring Plan and Stand-Alone
Plan (as defined in "Rate Matters" on page 21), once any portion of the
Company's electric utility operations is deemed to no longer meet the SFAS No.
71 criteria, or is not recovered through a CTC, the Company will be required to
write off assets (to the extent their net book value exceeds fair value), the
recovery of which is uncertain, and any regulatory assets or liabilities for
those operations that no longer meet these requirements. Any such write-off of
assets could be materially adverse to the financial position, results of
operations and cash flows of the Company. (See "PUC Proceedings" discussion on
page 25.)
Results of Operations
- --------------------------------------------------------------------------------
The Company's future financial condition and its future operating results
are substantially dependent upon the effects of the Restructuring Plan or Stand-
Alone Plan currently before the PUC. To the extent the Company does not
ultimately recover its transition costs, a charge against earnings would be
recognized. Such charge could have a materially adverse effect on the Company's
financial position, results of operations and cash flows. (See "Rate Matters"
on page 21.)
17
<PAGE>
Earnings
The Company's earnings per share in the first quarter of 1998 and the first
quarter of 1997 were $0.58. Net income also remained constant at $45.1 million
in the first quarter of 1998 and the first quarter of 1997. In the first
quarter of 1998, Duquesne contributed $0.42 to earnings per share, a decrease
from the prior year's reported earnings per share of $0.46. Duquesne's decrease
was the result of mild first quarter 1998 temperatures and accelerated nuclear
lease recovery. This decrease was partially offset by increased other income
from an investment made in the fourth quarter of 1997. The market-driven
subsidiaries contributed $0.16 or 27.6 percent of total earnings per share in
the first quarter of 1998, up from $0.12 or 20.7 percent of total earnings per
share in the first quarter of 1997. The 33.3 percent increase is the result of
the increased level of long-term investments.
Revenues
Total operating revenues in the first quarter 1998 decreased $6.1 million
or 2.0 percent as compared to the first quarter of 1997.
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------
Increase(Decrease) in First Quarter 1998
(Revenues in Millions of Dollars) as Compared to First Quarter 1997
- ----------------------------------------------------------------------------------------
KWH Revenues
----------------------------------------
<S> <C> <C>
Residential (7.4)% $(1.0)
Commercial (7.3)% (0.5)
Industrial 4.2 % 1.8
Less: Provision for Doubtful Accounts 0.0
- ----------------------------------------------------------------------------------------
Sales to Electric Utility Customers (4.2)% 0.3
- ----------------------------------------------------------------------------------------
Sales to Other Utilities (26.3)% (1.7)
Other Revenues (4.7)
- ----------------------------------------------------------------------------------------
Total Sales (7.3)% $(6.1)
========================================================================================
</TABLE>
Sales of Electricity to Customers
Operating revenues are primarily derived from the Company's sales of
electricity. Currently the PUC authorizes rates for electricity sales which are
cost-based and are designed to recover the Company's operating expenses and
investment in electric utility assets and to provide a return on the investment.
Customer revenues fluctuate as a result of changes in sales volume and changes
in fuel and other energy costs, as these costs are generally recoverable from
customers through the Energy Cost Rate Adjustment Clause (ECR). Under current
fuel cost recovery provisions, fuel revenues generally equal fuel expense,
including the fuel component of purchased power, and do not affect net income.
As required under the Customer Choice Act, the Company has filed with the PUC
its plan addressing its proposed restructuring to operate in a competitive
environment including unbundled charges for transmission, distribution,
generation and a CTC. Although not yet approved in a final vote, the PUC has
proposed rates in connection with these filings and the phase-in to competition.
(See "PUC Proceedings" discussion on page 25.)
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. In addition, the Customer Choice Act
has and will continue to affect bundled sales to the Company's retail customers.
The customer choice pilot that was implemented in November 1997, when 5 percent
of customers were given the right to customer choice, reduced sales to retail
customers by approximately 5 percent. It is anticipated that the net financial
impact of the Company's customers' choosing alternative generation suppliers
during the pilot period (through 1998) will be a reduction of operating revenues
of approximately $1 million per month. (See "Rate Matters" discussion on page
21.)
18
<PAGE>
In the first quarter of 1998, net customer revenues reflected on the
statement of consolidated income increased by $0.3 million to $264.3 million
from the first quarter of 1997. The variance can be attributed to an increase
in energy costs of $9.5 million offset by a 4.2 percent decrease in kilowatt-
hour (KWH) sales to electric utility customers. Residential and commercial sales
decreased 169,150 KWH when comparing the first quarter of 1998 to the first
quarter of 1997, due to the pilot program and mild 1998 temperatures. Sales to
a new customer, an industrial gas supplier, represent 82 percent of the increase
in industrial sales, while the remaining increase is due to expansion of one of
the Company's largest customers' facilities.
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 electricity sales to other utilities in the
first quarter of 1998 were $1.7 million or 19.0 percent less than in the first
quarter of 1997. The reduction was due to reduced availability of generating
capacity as a result of a 52 percent increase in outage hours as compared to the
first quarter of 1997.
Other Operating Revenues
Other operating revenues include the Company's non-KWH utility revenues and
revenues from market-based operating activities. The other operating revenues
decrease of $4.7 million or 16.0 percent when comparing the first quarter of
1998 to the first quarter of 1997 is primarily the result of the loss of
revenues from Chester Engineering, Inc., a former subsidiary which was sold
during the second quarter of 1997. Offsetting part of the decrease in revenues
was $3.5 million in revenues from the growth in market-based operating
activities.
Operating Expenses
Fuel and Purchased Power Expense
Fluctuations in fuel and purchased power expense generally result from
changes in the cost of fuel, the mix between coal and nuclear generation, the
total KWHs sold, and generating station availability. Because of the ECR,
changes in fuel and purchased power costs did not impact earnings in the first
quarter of 1998 and the first quarter of 1997. Under the Company's 1996 PUC-
approved mitigation plan, the level of energy cost recovery is capped at 1.47
cents per KWH through May 2001. Pending the final order regarding the Company's
Restructuring Plan or Stand-Alone Plan filing, the Company may freeze the ECR
and roll it into base rates. (See "Rate Matters" on page 21.)
Fuel and purchased power expense increased $7.9 million or 15.3 percent in
the first quarter of 1998 as compared to the first quarter of 1997. The
increase resulted from higher energy costs by $11.8 million or 24.8 percent
partially offset by a $3.9 million or 7.7 percent reduction in energy volume
supplied. Reduced availability of generating stations due to a 52 percent
increase in outage hours forced the Company to buy purchased power and generate
power from the higher cost fossil stations. The pilot program and mild 1998
winter temperatures resulted in a reduction of approximately 7 percent of
residential and commercial KWH sales.
Other Operating Expense
The decrease in other operating expense of $4.4 million or 5.3 percent in
the first quarter of 1998 as compared to the first quarter of 1997 can be
attributed to the reduced operating costs associated with Chester which was sold
during the second quarter of 1997 partially offset by growth of the market-based
operating activities.
19
<PAGE>
Maintenance Expense
Maintenance expense increased $2.5 million or 14.3 percent in the first
quarter of 1998 as compared to the first quarter of 1997. The increase is
primarily attributable to the timing of tree trimming and maintenance of
overhead lines expenses and to costs incurred for the Cheswick Power Station
scheduled outage that began on February 27, 1998.
Depreciation and Amortization Expense
Depreciation and amortization expense increased $2.0 million or 3.6 percent
in the first quarter of 1998 as compared to the first quarter of 1997, due to
accelerated nuclear lease recovery which began on May 1, 1997.
Other Income
The Company continues to increase investment income significantly over the
prior year levels. An $11.4 million or 57.1 percent increase in other income in
the first quarter of 1998 as compared to the first quarter of 1997 resulted from
long-term investment income. The greater long-term investment income was the
result of investments made throughout 1997. The Company invested approximately
$180 million in lease investments and $11 million in gas reserve investments
subsequent to the first quarter of 1997.
Interest and Other Charges
Interest and other charges decreased $1.1 million or 3.7 percent in the
first quarter of 1998 as compared to the first quarter of 1997. The reason for
the decrease in 1998 was primarily the result of the retirement and redemption
of mortgage bonds during the first quarter of 1998.
Income Taxes
Income taxes were lower in the first quarter of 1998 as compared to the
first quarter of 1997 by $1.1 million or 4.9 percent, primarily due to reduced
taxable income.
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 March 31, 1998, the Company was in compliance with all of its
debt covenants.
Mortgage bonds in the amount of $35 million matured in February 1998 and
were retired using available cash. In March 1998, the Company redeemed $100
million principal amount of its 8.75 percent mortgage bonds, originally due in
May 2022 at a redemption price of 106.5625 percent of the principal amount, plus
interest accrued until redemption. The redemption was partially financed with
proceeds of the February 1998 issuance of $40 million principal amount of 6.45
percent mortgage bonds, due in February 2008. In addition, in April 1998 the
Company issued $100 million principal amount of 7 3/8 percent mortgage bonds,
due in April 2038. Mortgage bonds in the amount of $35 million and $5 million
will mature in June and November 1998, respectively. The Company expects to
retire these bonds with available cash or to refinance the bonds. (See "Rate
Matters" on page 21.)
In July 1997, the Company authorized and registered 1,000,000 shares of its
Preferred Stock, Series A (Convertible) (DQE Preferred Stock), all with $100
liquidation preference, for use in connection with acquisitions by the Company
of other businesses, assets or securities. (See "Investing" discussion on page
21.) As of March 31, 1998, 181,452 shares of DQE Preferred Stock had been issued
and were outstanding. An additional 43,386 shares of DQE Preferred Stock were
issued in April 1998.
20
<PAGE>
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. This $50 million accounts receivable sale
arrangement extends through June 1998. The Company may attempt to extend the
agreement, or replace it with a similar facility, or eliminate the agreement,
upon expiration.
The Company maintains a $150 million revolving credit facility which
expires in October 1998. The Company also maintains a $125 million revolving
credit facility expiring in June 1998. No borrowings were outstanding under
either facility at March 31, 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 March 31, 1998.
Investing
- --------------------------------------------------------------------------------
The Company has made long-term investments in the following areas: leases;
affordable housing; gas reserves; energy solutions; and water companies.
Investing activities during the first three months of 1998 included
approximately $4 million in natural gas reserve partnerships and the remaining
$5 million in other investments. During the first three months of 1997, the
Company invested approximately $53 million in lease investments, $11 million in
affordable housing investments and the remaining $4 million in other
investments.
In the first quarter of 1998, the Company issued 165,972 shares of DQE
Preferred Stock, as part of an investment of approximately $23.7 million in
water companies. An additional 43,386 shares of DQE Preferred stock were issued
in April 1998, as part of an investment of approximately $7.4 million in water
companies.
In the first quarter of 1998, the Company invested $8 million for the
construction of plants to produce E-Fuel/TM/, a coal-based synthetic fuel. The
Company committed to an aggregate investment of $32 million in 1998 for such
construction.
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.
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<PAGE>
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). For the
first stage, the Company filed a pilot program with the PUC on February 27,
1997. For the second stage, the Company filed on August 1, 1997 its
restructuring and merger plan (the Restructuring Plan) and its stand-alone
restructuring plan (the Stand-Alone Plan) with the PUC.
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
Company pilot filing proposed unbundling transmission, distribution, generation
and competitive transition charges and offered participating customers the same
options that were to be available in a competitive generation market. The pilot
was designed to comprise approximately 5 percent of the Company's residential,
commercial and industrial demand. The 28,000 customers participating in the
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. On May 9, 1997, the PUC issued a
Preliminary Opinion and Order approving the Company's filing in part, and
requiring certain revisions. The Company and other utilities objected to several
features of the PUC's Preliminary Opinion and Order. Hearings on several key
issues were held in July. The PUC issued its final order on August 29, 1997,
approving a revised pilot program for the Company. On September 8, 1997, the
Company appealed the determination of the market price of generation set forth
in this order to the Commonwealth Court of Pennsylvania. The Company expects a
hearing to be scheduled for mid-1998. Although this appeal is pending, the
Company complied with the PUC's order to implement the pilot program that began
on November 3, 1997.
Financial Impact of Pilot Program Order
It is anticipated that the net financial impact of the Company's customers'
choosing alternative generation suppliers during the pilot period (through 1998)
will be a reduction of operating revenues of approximately $1 million per month.
(See "Forward-Looking Statements" discussion on page 26.) The Company is seeking
in its Restructuring Plan and its Stand-Alone Plan to maintain current rates
under Section 2804(4)(v) of the Customer Choice Act (Rate Cap Provision), which
states that in certain circumstances an electric distribution utility may roll
its energy cost rate into base rates without reducing its rates below the capped
level if the PUC determines that excess earnings are to be used for mitigation
of transition costs. The Company will reduce its accelerated nuclear lease
amortization to offset the shortfall, if any, in operating revenues between the
pilot program and the final approved rates.
Phase-In to Competition
As set forth in the Customer Choice Act, the phase-in to competition begins
on January 1, 1999, when 33 percent of customers will have customer choice
(including customers covered by the pilot program); 66 percent of customers will
have customer choice no later than January 1, 2000; and all customers will have
customer choice no later than January 1, 2001. However, in its sole order to
date (the PECO Order), the PUC ordered the phase-in provisions of the Customer
Choice Act to require the acceleration of the second and third phases to January
2, 1999 and January 2, 2000, respectively; in addition, in its April 30, 1998,
meeting the PUC voted to similarly accelerate the phase-in to competition for
the Company's customers. (See "PUC Proceedings" discussion on page 25.) As they
are phased-in, customers that have chosen an electricity generation supplier
other than the Company will pay that supplier for generation charges, and will
pay the Company a CTC (discussed below) and unbundled charges for transmission
and distribution. Customers that continue to buy their generation from the
Company will pay for their service at current regulated tariff rates divided
into unbundled generation, transmission and distribution charges. The PECO Order
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<PAGE>
concluded that under the Customer Choice Act, an electric distribution company,
such as Duquesne, is to remain a regulated utility and may only offer PUC-
approved, tariffed rates (including unbundled generation rates). Delivery of
electricity (including transmission, distribution and customer service) will
continue to be regulated in substantially the same manner as under current
regulation.
Rate Cap and Transition Cost Recovery
Before the phase-in to customer choice begins in 1999, the PUC expects
utilities to take vigorous steps to mitigate transition costs as much as
possible without increasing the rates they currently charge customers. The
Company has mitigated in excess of $350 million of transition costs during the
past three years through accelerated annual depreciation and a one-time write-
down of nuclear generating station costs, accelerated recognition of nuclear
lease costs, increased nuclear decommissioning funding, and amortization of
various regulatory assets. This relative level of transition cost reduction,
while holding rates constant, is unmatched within Pennsylvania.
The PUC will determine what portion of a utility's transition costs that
remain at January 1, 1999 will be recoverable through a CTC from customers. The
CTC recovery period could last through 2005, providing a utility a total of up
to nine years beginning January 1, 1997 to recover transition costs, unless this
period is extended as part of a utility's PUC-approved transition plan. 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. Following is a summary of the Company's requested transition cost
recovery, net of deferred taxes, as of January 1, 1999; the related net balances
as of December 31, 1997; and the amounts mitigated during the past three years.
(See "PUC Proceedings" discussion on page 25.)
<TABLE>
<CAPTION>
Transition Costs
- ---------------------------------------------------------------------------------------------
Mitigation Balance CTC Recovery
(Amounts in Millions of Dollars) 1/1/95 - 12/31/97 12/31/97 Requested 1/1/99
- ---------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Nuclear generation plant (a) $232 $ 968 $ 877
Fossil generation plant (a) -- 541 541
Generation-related regulatory assets (b) 103 382 357
Decommissioning costs (c) 18 133 124
- ---------------------------------------------------------------------------------------------
Total $353 $2,024 $1,899
- ---------------------------------------------------------------------------------------------
</TABLE>
(a) Nuclear and fossil generation plant represent a projection of the amount by
which the net book value, including materials and supplies inventories, and
fuel inventories, of the generating plants exceeds the market value for
these plants. "Nuclear generation plant" also includes the present value of
future above-market lease payments related to the sale/leaseback of BV Unit
2.
(b) Generation-related regulatory assets represent costs which under the
historical ratemaking process were deemed recoverable from customers through
future rates. These regulatory assets include, among other items, amounts
related to future federal income tax payments, premiums paid to reacquire
debt, initial operating costs of BV Unit 2 and Perry Unit 1, and energy
costs not recovered currently.
(c) Decommissioning costs represent the estimated present value of unfunded
fossil and nuclear generation plant decommissioning costs.
Financial Exposure to Transition Cost Recovery
Any estimate of the ultimate level of transition costs (including those set
forth in the table above) depends on, among other things, the extent to which
such costs are deemed recoverable by the PUC in its final binding vote; the
ongoing level of the Company's costs of operations; regional and national
economic conditions; and growth of the Company's sales. (See "Forward-Looking
Statements" discussion on page 26.) Indeed, the PECO Order, as modified by a
settlement on April 30, 1998, provides for recovery by PECO Energy Company
(PECO) of 100 percent of transition costs determined to be just and reasonable
by the PUC. However, in determining transition costs, the PUC found the market
value of PECO's generating units to be significantly higher than the
23
<PAGE>
estimate of market value sponsored by PECO. Thus, the total amount of transition
costs requested by PECO was significantly more than that allowed by the PUC in
the PECO Order, as the PUC-determined market value offset a larger portion of
the transition costs. The PUC-ordered recovery of PECO's transition costs
through a CTC is permitted over a twelve-year period beginning January 1, 1999.
However, PECO is only permitted to earn a return on the unamortized balance of
transition costs at a rate equal to its long-term cost of debt. In its April 30
vote, the PUC proposed that certain of the Company's transition costs cannot be
recovered through a CTC. If the PUC confirms its proposal in the final binding
vote on May 21, these costs will have to be written off. (See "Regulation" on
page 17; see also "PUC Proceedings" discussion on page 25.) On January 26, 1998,
PECO announced that it was reducing its dividend by 44 percent, and also that it
was reporting a net loss for 1997 of $1.5 billion, including an extraordinary
charge of $3.1 billion ($1.8 billion net of taxes) in the fourth quarter of 1997
to reflect the effects of the PECO Order (as effective prior to the April 30
settlement). As the Company has substantial exposure to transition costs
relative to its size, significant transition cost write-offs could have a
materially adverse effect on the Company's financial position, results of
operations and cash flows. Various financial covenants and restrictions could be
violated if substantial write-off of assets or recognition of liabilities
occurs. Under such circumstances the Company may face constraints on its ability
to pay dividends, issue new mortgage debt or maintain access to bank lines of
credit, thus negatively impacting its operations.
Stand-Alone Plan
In the event the merger with AYE is not consummated under the filed
Restructuring Plan, the Company has sought approval for restructuring and
recovery of its own transition costs through a CTC under the Stand-Alone Plan.
The Company argued, as a fundamental premise, that any finding of market value
for the Company's generating assets to determine transition costs should be
based on market evidence and not on an administrative determination of that
value based on price forecasts (the PECO Order determined the market value of
PECO's generation based on the price forecast sponsored by the Pennsylvania
Office of Consumer Advocate). The Company proposed a number of alternative
market valuation methodologies that it believed would satisfy this market-based
standard. As an alternative, if the PUC finds that a determination of market
value as of December 31, 1998 is required by the Customer Choice Act, then the
Company has agreed that the PUC may order an immediate auction of the Company's
generation at that time. (A more detailed discussion of alternative
methodologies to determine transition costs based on market evidence is set
forth in the Company's Annual Report on Form 10-K for the Year Ended December
31, 1997.)
Restructuring Plan
The Restructuring Plan incorporated the benefits of the merger with AYE,
such as anticipated savings to the Company, on a nominal basis, of $365 million
in generation-related costs over 20 years, and $9 million in transmission-
related costs and $173 million in distribution-related costs over 10 years. The
Restructuring Plan also incorporated the market-based approach to determining
stranded costs proposed by the Company in its Stand-Alone Plan, however the
Company did not agree that the PUC may order an immediate auction of its
generation to determine transition costs. (A more detailed discussion of
alternative methodologies to determine transition costs based on market evidence
is set forth in the Company's Annual Report on Form 10-K for the Year Ended
December 31, 1997.) The opposing parties believe that there should be a one-time
valuation of the generation assets performed as of December 31, 1998. Any
merger-related synergies relating to generation would then be used to reduce the
Company's transition costs as of that date. These parties also believe that the
Company's proposed distribution rate decrease should be effective on January 1,
1999. The Company has requested a total CTC recovery of transition costs of
$1.899 billion in the event the PUC does not accept its proposal to determine
transition costs based on market evidence.
24
<PAGE>
PUC Proceedings
On March 25, 1998, two PUC administrative law judges recommended that a
decision on the proposed merger of the Company and AYE be deferred for up to 18
months to allow the companies to address market power concerns. In two other
decisions issued at the same time, the judges recommended approval, with
modifications, of the restructuring plans of Duquesne and of AYE's utility
subsidiary, West Penn Power. On April 14, 1998, the Company filed exceptions to
the administrative law judges' recommendations. Also on April 14, the Company
and AYE jointly filed exceptions to the PUC administrative law judges'
recommendation that approval of the proposed merger be delayed.
The administrative law judge did not support the Company's market-based
approach to determining the value of its generating assets (and thereby its
CTC), and recommended instead either an immediate auction of the Company's
generating assets if the proposed merger is not consummated, or an
administrative determination of the value of such assets if the proposed merger
is consummated. In its exceptions, the Company sought clarification of the
administrative law judge's recommendation. Also in its exceptions, the Company
reaffirmed its fundamental premise that market data should be used to set the
value of its generating assets.
In their joint exceptions, the Company and AYE committed to mitigate the
potential market power of the new company by joining the Midwest Independent
System Operator (MISO) and by relinquishing control of the output of the
Company's 570-megawatt Cheswick Power Station (Cheswick) for a minimum of two
years or until the MISO has been approved. Both actions would occur immediately
upon completion of the proposed merger. The Company and AYE further committed
to issue a request for proposals to sell the output of Cheswick within a month
of securing all required regulatory approvals for the proposed merger. The
Company would continue to own and operate Cheswick.
On April 30, 1998, the PUC held a nonbinding vote on the recommended
decisions. Reversing the recommendation to delay a decision by up to 18 months,
the PUC voted instead to approve the merger. However, to address market power
concerns, the PUC also required membership in a fully functioning ISO prior to
consummation of the merger. The PUC recognized that joining either the MISO (as
discussed above) or the Pennsylvania-New Jersey-Maryland ISO (PJM) would be an
acceptable option. The MISO's application for approval is before the FERC, but
no date for a decision has been set. Pursuing membership in PJM would require
the Company and AYE to file an updated market power study with the PUC. The
precondition of joining a fully functioning ISO could delay, or ultimately
prevent, consummation of the merger.
With respect to the Stand-Alone Plan, the PUC voted to require the Company
to auction its generating assets in order to determine their market value and
its CTC. The Company would have to submit a divestiture plan to the PUC within
90 days of the effective date of a final order. If such a divestiture were not
completed by January 1, 1999, the Company would use an interim CTC set at the
rate approved in its pilot program. The CTC determined by the auction would be
permanent, precluding annual adjustments based on the market price of power as
originally proposed by the Company.
With respect to the Restructuring Plan, the PUC proposed calculating the
Company's transition costs based on an administrative determination of the value
of its generating assets as opposed to the Company's proposed market-based
approach. The PUC would set the Company's transition costs at approximately $1.3
billion, reflecting $152.28 million in generation-related savings resulting from
the merger. This amount would disallow certain assets the Company anticipated
including in its transition costs, including, among other things, the cold-
reserved units at Philips Power Station and at a portion of Brunot Island Power
Station. The PUC would permit transition cost recovery through 2005 pursuant to
a CTC initially set at an average of 2.58 cents per KWH for 1999 (resulting in a
shopping credit, or reduction from previously bundled rates, of 4.01 cents per
KWH). The PUC would also reduce the Company's distribution rates by $15 million
per year beginning January 1, 2000, to reflect merger savings. The Company has
calculated the effects of the PUC's CTC and shopping credit determination, and
estimates that, correcting for computational errors, the 1999 average CTC should
be 2.73 cents per KWH (resulting in a shopping credit of 3.49 cents per KWH).
25
<PAGE>
The PUC voted to accelerate the Company's phase-in to competition schedule.
The Customer Choice Act calls for phase-in of one-third of customers by January
1, 1999; two-thirds by January 1, 2000; and the final third by January 1, 2001.
The PUC voted to accelerate the second third to January 2, 1999, and the final
third to January 2, 2000.
Final orders with respect to the PUC's vote will be written, and a final
binding vote is currently scheduled to take place on May 21, 1998.
The Federal Filings
In addition to the PUC filings of the Restructuring Plan and the Stand-
Alone Plan, on August 1, 1997, the Company and AYE filed their joint merger
application with the FERC (the FERC Filing). Pursuant to the FERC Filing, the
Company and AYE have committed to forming or joining an ISO that meets the
entity's requirements, including marginal cost transmission pricing, following
the merger. In April 1998, executives from the Company and AYE notified the
FERC of their intention to join the MISO, and that they would not withdraw from
the MISO without the prior approval of the FERC. In addition, the Company and
AYE have stated in the FERC Filing that following the merger the combined
entity's market share will not violate the market power conditions and
requirements set by the FERC. On January 20, 1998, the Company and AYE filed
merger applications with the Antitrust Division of the Department of Justice and
the Federal Trade Commission. These applications are currently pending.
Forward-Looking Statements
The foregoing paragraphs contain forward-looking statements (within the
meaning of the Private Securities Litigation Reform Act of 1995) regarding the
financial impact, consequences and benefits of the Customer Choice Act, the
pilot program, the Stand-Alone Plan, the Restructuring Plan and the merger with
AYE. Such forward-looking statements involve known and unknown risks and
uncertainties that may cause the actual results and benefits to materially
differ from those implied by such statements. Such risks and uncertainties
include, but are not limited to, the final binding vote of PUC approvals
regarding the Stand-Alone Plan or the Restructuring Plan, general economic and
business conditions, industry capacity, changes in technology, integration of
the operations of AYE and the Company, regulatory conditions to the merger, the
loss of any significant customers, and changes in business strategy or
development plans.
Beaver Valley Power Station (BVPS)
BV Unit 1 went off-line January 30, 1998, due to an issue identified in a
technical review completed by the Company. BV Unit 2 went off-line December 16,
1997, to repair the emergency air supply system to the control room and has
remained off-line due to other issues identified by a technical review similar
to that performed at BV Unit 1. These technical reviews are in response to a
1997 commitment made by the Company to the NRC. The Company is one of many
utilities faced with similar issues, some of which date back to the initial
start-up of BVPS. Both BVPS units remain off-line for a reaffirmation of
compliance with technical specification requirements of various plant systems.
The Company is currently participating in a series of meetings with the NRC to
review its action plans. Both units are expected to remain off-line until the
action plans have been satisfactorily completed.
BVPS's two units are equipped with steam generators designed and built by
Westinghouse Electric Corporation (Westinghouse). Similar to other Westinghouse
nuclear plants, outside diameter stress corrosion cracking (ODSCC) has occurred
in the steam generator tubes of both units. The units still have the capability
to operate at 100 percent reactor power, although approximately 17 percent of BV
Unit 1 and 2 percent of BV Unit 2 steam generator tubes have been removed from
service. Material acceleration in the rate of ODSCC could lead to a loss in
plant efficiency and significant repairs or replacement of BV Unit 1 steam
generators. The total replacement cost of the BV Unit 1 steam generators is
estimated at $125 million, $59 million of which would be the Company's
responsibility. The earliest that the BV Unit 1 steam generators could be
replaced during a currently scheduled refueling outage is the spring of 2002.
26
<PAGE>
Year 2000
Many existing computer programs use only two digits to identify a year (for
example, "98" is used to represent "1998"). Such programs read "00" as the year
1900, and thus may not recognize dates beginning with the year 2000, or may
otherwise produce erroneous results or cease processing when dates after 1999
are encountered. Such failures could cause disruptions in normal business
operations. The Company continues to implement its strategy, formulated in
1995, to address required computer software changes and upgrades relating to
such operations, and currently believes that implementation of its plan will
minimize its Year 2000 issues relating to these systems. The Company's Year
2000 team, comprised of management representatives from all functional areas of
the Company, also continues to explore and assess the Company's exposure to Year
2000-related problems in devices and equipment containing embedded
microprocessors that may not correctly identify the year, as well as potential
problems that may originate with third parties outside the Company's control.
The Company has authorized the retention of a Year 2000 consultant to assist the
Year 2000 team in its assessments.
Given the fact that the Company's assessment, as noted above, is currently
in progress, the Company cannot currently estimate the exact extent of any
outstanding Year 2000 systems and equipment issues, the specific time frame in
which any required corrections would need to be made and the costs to the
Company in correcting any possible related outstanding matters. Until the
Company's assessment is completed, it cannot determine whether Year 2000 issues
and related costs will be material to the Company's operations, financial
condition and results of operations.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Funding for nuclear decommissioning costs is deposited by the Company in
external, segregated trust accounts and invested in a portfolio of corporate
common stock and debt securities, municipal bonds, certificates of deposit and
United States government securities. The market value of the aggregate trust
fund balances at March 31, 1998 totaled approximately $51.1 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: 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; regulatory
conditions applicable to the pending merger; the loss of any significant
customers; and changes in business strategy or development plans.
27
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
Eastlake Unit 5
In September 1995, the Company commenced arbitration against Cleveland
Electric Illuminating Company (CEI), seeking damages, termination of the
Operating Agreement for Eastlake Unit 5 (Eastlake) and partition of the parties'
interests in Eastlake through a sale and division of the proceeds. The
arbitration demand alleged, among other things, the improper allocation by CEI
of fuel and related costs; the mismanagement of the administration of the
Saginaw coal contract in connection with the closing of the Saginaw mine, which
historically supplied coal to Eastlake, and the concealment by CEI of material
information. In October 1995, CEI commenced an action against the Company in
the Court of Common Pleas, Lake County, Ohio seeking to enjoin the Company from
taking any action to effect a partition on the basis of a waiver of partition
covenant contained in the deed to the land underlying Eastlake. CEI also seeks
monetary damages from the Company for alleged unpaid joint costs in connection
with the operation of Eastlake. The Company removed the action to the United
States District Court for the Northern District of Ohio, Eastern Division, where
it is now pending. The Company anticipates that a trial will commence late in
1998.
Proposed Merger
In September 1997 the City of Pittsburgh filed a federal antitrust suit
seeking to prevent the merger and asking for monetary damages. Although the
United States District Court for the District of Western Pennsylvania dismissed
the suit in January 1998, the City filed an appeal and asked for expedited
review. The Company anticipates a decision on whether the appeal has been
granted during the second quarter of 1998. Unless otherwise indicated, all
information presented in this report relates to the Company only and does not
take into account the proposed merger between the Company and AYE.
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 10.1 - Duquesne Light Company/DQE Charitable Giving Program, as
amended to date.
EXHIBIT 12.1 - Calculation of Ratio of Earnings to Fixed Charges and
Preferred and Preference Stock Dividend Requirements.
EXHIBIT 27.1 - Financial Data Schedule
b. A Current Report on Form 8-K was filed April 8, 1998, to report the March
25, 1998, recommended decision regarding the proposed merger and the
restructuring plans issued by administrative law judges to the PUC. No
financial statements were filed with this report.
A Current Report on Form 8-K was filed April 16, 1998, to report the filing
of the Company's exceptions to the recommended decisions. No financial
statements were filed with this report.
_____________________________
28
<PAGE>
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant identified below has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
DQE, Inc.
-----------------------------------
(Registrant)
Date May 13, 1998 /s/ Gary L. Schwass
------------------------------ -----------------------------------
(Signature)
Gary L. Schwass
Executive Vice President
and Chief Financial Officer
Date May 13, 1998 /s/ Morgan K. O'Brien
------------------------------ -----------------------------------
(Signature)
Morgan K. O'Brien
Vice President and Controller
(Principal Accounting Officer)
29
<PAGE>
Exhibit 10.1
Duquesne Light/DQE
Charitable Giving Program
PLAN DOCUMENT
1. PURPOSE OF THE PROGRAM
The Duquesne Light/DQE Charitable Giving Program (the "Program") allows each
eligible Director of Duquesne Light/DQE (the "Corporation") to recommend that
the Corporation make a donation of $500,000 to the eligible (as defined in
Section 5) tax-exempt organization(s) (the "Donee(s)") selected by the
Director, with the donation to be made, in the joint names of the Director
and the Corporation, in ten equal annual installments, with the first
installment to be made as soon as is practicable after the Director's death.
The purpose of the Program is to recognize the interest of the Corporation
and its Directors in supporting worthy educational institutions and other
charitable organizations.
2. ELIGIBILITY
All Directors of the Corporation who were serving as Directors on April 24,
1990 shall be eligible to participate in the Program. All Directors who join
the Corporation's Board of Directors (the "Board") after that date shall be
eligible to participate in the Program upon election to the Board.
3. RECOMMENDATION OF DONATION
When a Director becomes eligible to participate in the Program, he or she
shall make a written recommendation to the Corporate Secretary, on a form
approved by the Corporation for this purpose, designating the Donee(s) which
he or she intends to be the recipient(s) of the Corporation's donation to be
made on his or her behalf. A Director can revise his or her recommendation
of a beneficiary by filing a new Beneficiary Recommendation Form with the
Corporate Secretary. The Employment and Community Relations Committee of the
Board (the "Employment and Community Relations Committee") must review and
approve all new Donee(s) submitted by Directors who have not been previously
approved as an eligible beneficiary. In addition, the Corporation reserves
the right to select a different beneficiary if the recommended organization
ceases to
<PAGE>
qualify as an eligible beneficiary, and if the Director does not file a new
form recommending a qualifying organization before his or her death.
If the Director recommends more than one organization and one ceases to
qualify, the entire donation will be made to the other selected
organization(s), but only if the Corporation can do so and still achieve the
objective of the Program to have at least $300,000 (or 60% of the vested
donation amount, if less) of the donation amount pass to institutions located
within Allegheny and/or Beaver Counties. Otherwise, donations will be made
to the other selected organization(s) to the extent possible within the
objectives of the Program, with the balance of the donation amount to be
donated, in the joint names of the Director and the Corporation, to
organizations selected by the Employment and Community Relations Committee
and reviewed at a meeting of the Board of Directors. In order for a
recommendation or change of recommendation to be final, the Director must
receive an acknowledged copy of the Beneficiary Recommendation Form from the
Corporate Secretary.
4. AMOUNT AND TIMING OF DONATION
Subject to the vesting provisions set forth in Section 6, each eligible
Director may choose one organization to receive a corporate donation of
$500,000, or two or more organizations to receive donations aggregating
$500,000. Each recommended organization must be designated to receive a
donation of at least $50,000. The donation will be made by the Corporation
in ten equal annual installments, with the first installment to be made as
soon as is practicable after the Director's death. If a Director recommends
more than one organization to receive a donation, each will receive a
prorated portion of each annual installment. Each annual installment payment
will be divided among the recommended organizations in the same proportions
as the total donation amount has been allocated among the organizations by
the Director.
5. ELIGIBLE DONEES
At least $300,000 (or 60% of the vested donation amount, if less) of the
donation must be made to charities or educational institutions located within
Allegheny and/or Beaver Counties in Pennsylvania. Donations to institutions
located outside these counties are limited to U.S. colleges and universities
or to U.S. entities organized to receive donations on behalf of foreign
colleges and universities.
-2-
<PAGE>
Each designated charitable organization and each designated educational
institution which is not a college or university must: (1) be located within
Allegheny and/or Beaver Counties in Pennsylvania; (2) be recognized by the
Internal Revenue Service as an organization to which deductible charitable
contributions may be made; (3) be approved by the Employment and Community
Relations Committee; and (4) be reviewed at a meeting of the Board of
Directors.
Each designated college or university must: (1) be either listed in the most
recent issue of the Higher Education Directory published by the U.S.
Department of Education or a U.S. entity organized to receive donations on
behalf of and make grants to a foreign college or university; (2) be
recognized by the Internal Revenue Service as an organization to which
deductible charitable contributions may be made; (3) offer at least a two-
year program of college level studies; (4) be approved by the Employment and
Community Relations Committee; and (5) be reviewed at a meeting of the Board
of Directors.
6. VESTING
A Director will be vested in the Program when he or she completes five years
of Board service, or (a) in the event he or she dies while serving as a
Director, or (b) as set forth in Section 10. For persons serving as
Directors of the Corporation on April 24, 1990, service on that date and
prior will count as vesting service. If a Director terminates Board service
(other than due to death) before becoming vested, a reduced donation will be
made on his or her behalf. The following vesting schedule will apply to
determine the donation amount for which each Director is eligible:
<TABLE>
<CAPTION>
Service as a Director Donation Amount
- --------------------------- ------------------------------
<S> <C>
Less than 12 months $100,000
12-35 months 200,000
36-47 months 300,000
48-59 months 400,000
60 or more months 500,000
</TABLE>
-3-
<PAGE>
7. FUNDING AND PROGRAM ASSETS
The Corporation may fund the Program or it may choose not to fund the
Program. If the Corporation elects to fund the Program in any manner,
neither the Directors nor their recommended Donee(s) shall have any rights or
interests in any assets of the Corporation identified for such purpose.
Nothing contained in the Program shall create, or be deemed to create, a
trust, actual or constructive, for the benefit of a Director or any Donee
recommended by a Director to receive a donation, or shall give, or be deemed
to give, any Director or recommended Donee any interest in any assets of the
Program or the Corporation. If the Corporation elects to fund the Program
through life insurance policies, a participating Director agrees to cooperate
and fulfill the enrollment requirements necessary to obtain insurance on his
or her life.
8. AMENDMENT OR TERMINATION
The Board of Directors of the Corporation may, at any time, without the
consent of the Directors participating in the Program, amend, suspend, or
terminate the Program. However, once a Director becomes vested in the
Program, the Program may not be amended, suspended or terminated with respect
to such Director's vested rights without his or her consent.
9. ADMINISTRATION
The Program shall be administered by the Compensation Committee of the Board
of Directors (the "Compensation Committee"). The Compensation Committee
shall have plenary authority in its discretion, but subject to the provisions
of the Program, to prescribe, amend, and rescind rules, regulations and
procedures relating to the Program. The determinations of the Compensation
Committee on the foregoing matters shall be conclusive and binding on all
interested parties.
-4-
<PAGE>
10. CHANGE OF CONTROL
If there is a Change of Control of the Corporation and the Program is not
adopted on substantially equivalent terms by the new company, all
participants serving as Directors at the time of the Change of Control shall
become immediately vested in the Program, and, notwithstanding the provisions
of Section 8, the Program shall not thereafter be amended or terminated by
the company, or any successor thereto with respect to any person
participating in the Program at the time of the Change of Control. For the
purpose of the Program, a Change of Control shall mean the date upon which
any of the following events occur: the stockholders of the Company approve
an agreement or plan (a "Reorganization Agreement") providing for the Company
to be merged, consolidated or otherwise combined with, or for all or
substantially all its assets or stock to be acquired by, another corporation.
11. GOVERNING LAW
The Program shall be construed and enforced according to the laws of the
Commonwealth of Pennsylvania, without regard to the conflict of laws and
provisions thereof, and shall be administered according to the laws of said
Commonwealth.
12. EFFECTIVE DATE
The effective date of this amendment and restatement of the Program is July
29, 1997. The recommendation of a Director will not be effective until he or
she completes the Program enrollment requirements.
13. BINDING EFFECT
This Program shall be binding upon and inure to the benefit of the
Corporation and eligible directors and their respective successors,
assignors, heirs and legal representatives.
-5-
<PAGE>
ATTEST: DUQUESNE LIGHT COMPANY:
/s/Diane S. Eismont BY: /s/David D. Marshall
- ---------------------------------- ------------------------------
(Corporate Seal) Secretary Title: President and Chief
Executive Officer
ATTEST: DQE:
/s/Diane S. Eismont BY: /s/David D. Marshall
- ---------------------------------- ------------------------------
(Corporate Seal) Secretary Title: President and Chief
Executive Officer
Originally effective: April 24, 1990
Amended: July 29, 1997
-6-
<PAGE>
J
Exhibit 12.1
DQE, Inc. and Subsidiaries
Calculation of Ratio of Earnings to Combined Fixed Charges
and Preferred and Preference Stock Dividend Requirements
(Thousands of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
Three Months Ended ----------------------------------------------------------------
March 31, 1998 1997 1996 1995 1994 1993
------------------ ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
FIXED CHARGES:
Interest on long-term debt 20,816 $ 87,420 $ 88,478 $ 95,391 $101,027 $108,479
Other interest 3,177 13,823 10,926 7,033 4,050 2,718
Portion of lease payments representing
an interest factor 11,294 44,208 44,357 44,386 44,839 45,925
Dividend requirement 3,788 21,649 14,385 7,374 9,355 14,368
-------- -------- -------- -------- -------- --------
Total Fixed Charges 39,075 $167,100 $158,146 $154,184 $159,271 $171,490
-------- -------- -------- -------- -------- --------
EARNINGS:
Income from continuing operations 45,130 $199,101 $179,138 $170,563 $156,816 $141,407
Income taxes 20,487* 95,805* 87,388* 96,661* 92,973* 79,822*
Fixed Charges as above 39,075 167,100 158,146 154,184 159,271 171,490
-------- -------- -------- -------- -------- --------
Total Earnings 104,692 $462,006 $424,672 $421,408 $409,060 $392,719
-------- -------- -------- -------- -------- --------
RATIO OF EARNINGS TO FIXED CHARGES 2.68 2.76 2.69 2.73 2.57 2.29
======== ======== ======== ======== ======== ========
</TABLE>
The Company's share of the fixed charges of an unaffiliated coal supplier,
which amounted to approximately $0.7 million for the three months ended March
31, 1998, has been excluded from the ratio.
* Earnings related to income taxes reflect a $4.5 million decrease for the three
months ended March 31, 1998, a $17 million, $12 million, $13.5 million, $13.5
million and $10.4 million decrease for the twelve months ended December 31,
1997, 1996, 1995, 1994 and 1993, respectively, due to financial statement
reclassification related to Statement of Financial Accounting Standards No. 109,
Accounting for Income Taxes. The ratio of earnings to fixed charges, absent this
reclassification, equals 2.79 for the three months ended March 31, 1998, and
2.87, 2.76, 2.82, 2.65, and 2.35 for the twelve months ended December 31, 1997,
1996, 1995, 1994 and 1993, respectively.
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JAN-01-1998
<PERIOD-END> MAR-31-1998
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 2,525,490
<OTHER-PROPERTY-AND-INVEST> 858,330
<TOTAL-CURRENT-ASSETS> 458,179
<TOTAL-DEFERRED-CHARGES> 751,020
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,593,019
<COMMON> 73,119
<CAPITAL-SURPLUS-PAID-IN> 928,179
<RETAINED-EARNINGS> 886,916
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,516,470<F1>
4,000
241,182<F2>
<LONG-TERM-DEBT-NET> 1,308,111
<SHORT-TERM-NOTES> 0
<LONG-TERM-NOTES-PAYABLE> 2,921
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 40,322
0
<CAPITAL-LEASE-OBLIGATIONS> 38,927
<LEASES-CURRENT> 21,856
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,419,230
<TOT-CAPITALIZATION-AND-LIAB> 4,593,019
<GROSS-OPERATING-REVENUE> 296,025
<INCOME-TAX-EXPENSE> 20,487<F3>
<OTHER-OPERATING-EXPENSES> 234,208
<TOTAL-OPERATING-EXPENSES> 234,208
<OPERATING-INCOME-LOSS> 61,817
<OTHER-INCOME-NET> 31,418
<INCOME-BEFORE-INTEREST-EXPEN> 93,235
<TOTAL-INTEREST-EXPENSE> 27,618<F4>
<NET-INCOME> 45,130
0
<EARNINGS-AVAILABLE-FOR-COMM> 45,130
<COMMON-STOCK-DIVIDENDS> 27,964
<TOTAL-INTEREST-ON-BONDS> 20,816
<CASH-FLOW-OPERATIONS> 75,439
<EPS-PRIMARY> 0.58
<EPS-DILUTED> 0.57
<FN>
<F1>INCLUDES $(371,744) OF TREASURY STOCK AT COST
<F2>INCLUDES $12,428 OF PREFERENCE STOCK
<F3>NON-OPERATING EXPENSE
<F4>INCLUDES $4,265 OF PREFERRED AND PREFERENCE STOCK DIVIDENDS
</FN>
</TABLE>
