[CONFORMED]
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 1996
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[_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From to
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Commission File Number
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1-10290
DQE, Inc.
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(Exact name of registrant as specified in its charter)
Pennsylvania 25-1598483
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(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
Cherrington Corporate Center, Suite 100
500 Cherrington Parkway, Coraopolis, Pennsylvania 15108-3184
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (412) 262-4700
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was
required to file such report), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
--- ---
Indicate the number of shares outstanding of each of the issuer's classes of
common stock as of the latest practicable date:
DQE Common Stock, no par value - 77,188,434 shares outstanding as of June 30,
1996 and 77,193,585 shares outstanding as of July 31, 1996.
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
DQE
CONDENSED STATEMENT OF CONSOLIDATED INCOME
(Thousands of Dollars, Except Per Share Amounts)
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
1996 1995 1996 1995
-------- -------- -------- --------
Operating Revenues
Sales of Electricity:
Customers - net $258,896 $251,437 $524,066 $514,581
Utilities 15,077 12,027 31,042 24,516
-------- -------- -------- --------
Total Sales of Electricity 273,973 263,464 555,108 539,097
Other 19,384 19,908 38,767 42,552
-------- -------- -------- --------
Total Operating Revenues 293,357 283,372 593,875 581,649
-------- -------- -------- --------
Operating Expenses
Fuel and purchased power 58,695 52,825 117,860 107,925
Other operating 71,744 70,851 142,175 143,947
Maintenance 18,864 21,029 39,368 39,859
Depreciation and amortization 55,827 50,427 112,808 99,201
Taxes other than income taxes 20,842 21,370 42,963 43,240
-------- -------- -------- --------
Total Operating Expenses 225,972 216,502 455,174 434,172
-------- -------- -------- --------
OPERATING INCOME 67,385 66,870 138,701 147,477
-------- -------- -------- --------
OTHER INCOME 16,817 10,706 31,640 26,335
-------- -------- -------- --------
INTEREST AND OTHER CHARGES 26,673 27,535 52,376 55,204
-------- -------- -------- --------
INCOME BEFORE INCOME TAXES 57,529 50,041 117,965 118,608
INCOME TAXES 18,557 14,356 36,688 42,022
-------- -------- -------- --------
NET INCOME $ 38,972 $ 35,685 $ 81,277 $ 76,586
======== ======== ======== ========
AVERAGE NUMBER OF COMMON
SHARES OUTSTANDING
(Thousands of Shares) 77,392 77,565 77,490 77,812
======== ======== ======== ========
EARNINGS PER SHARE OF
COMMON STOCK $.50 $.46 $1.05 $.98
======== ======== ======== ========
DIVIDENDS DECLARED PER
SHARE OF COMMON STOCK $.32 $.30 $.64 $.59
======== ======== ======== ========
See notes to condensed consolidated financial statements.
2
DQE
CONDENSED CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
(Unaudited)
June 30, December 31,
1996 1995
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ASSETS
Current assets:
Cash and temporary cash investments $ 138,554 $ 24,767
Receivables 129,868 125,768
Other current assets, principally
materials and supplies 117,532 86,851
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Total current assets 385,954 237,386
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Long-term investments 467,795 440,916
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Property, plant and equipment 4,737,240 4,746,113
Less: Accumulated depreciation and
amortization (1,729,868) (1,685,877)
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Property, plant and equipment -
net 3,007,372 3,060,236
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Other non-current assets:
Regulatory assets 650,350 671,928
Other 53,523 48,377
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Total other non-current assets 703,873 720,305
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TOTAL ASSETS $ 4,564,994 $ 4,458,843
=========== ===========
LIABILITIES AND CAPITALIZATION
Current liabilities:
Notes payable $ 39,087 $ 35,098
Current maturities and sinking fund
requirements 23,926 71,379
Accounts payable 77,059 90,941
Accrued liabilities 46,418 52,063
Dividends declared 27,168 27,825
Other 9,429 9,191
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Total current liabilities 223,087 286,497
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Deferred income taxes - net 820,397 801,631
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Deferred investment tax credits 104,645 115,760
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Capital lease obligations 31,866 34,546
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Deferred income 200,664 221,740
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Other 208,400 197,973
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Commitments and contingencies (Note 4)
Capitalization:
Long-term debt 1,416,557 1,400,993
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Preferred and preference stock of
subsidiaries:
Non-redeemable preferred stock 213,608 63,608
Non-redeemable preference stock,
Plan Series A 29,241 29,615
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Total preferred and preference
stock before deferred employee
stock ownership plan (ESOP) benefit
(involuntary liquidation values
of $242,711 and $93,086 exceed par
by $28,417 and $28,781,
respectively) 242,849 93,223
Deferred ESOP benefit (20,841) (22,257)
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Total preferred and preference
stock of subsidiaries 222,008 70,966
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Common shareholders' equity:
Common stock - no par value
(authorized - 187,500,000 shares;
issued - 109,679,154 shares) 984,665 997,461
Retained earnings 730,709 698,986
Less treasury stock (at
cost)(32,490,720 and 32,123,601
shares, respectively) (378,004) (367,710)
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Total common shareholders' equity 1,337,370 1,328,737
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Total capitalization 2,975,935 2,800,696
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TOTAL LIABILITIES AND
CAPITALIZATION $ 4,564,994 $ 4,458,843
=========== ===========
See notes to condensed consolidated financial statements.
3
DQE
CONDENSED STATEMENT OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
(Unaudited)
Six Months Ended
June 30,
---------
1996 1995
-------- ---------
Cash Flows from Operating Activities
Operations $195,457 $ 174,878
Changes in working capital other than
cash (54,726) 37,154
Other - net (9,072) 9,718
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Net Cash Provided by Operating
Activities 131,659 221,750
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Cash Flows Used in Investing Activities
Capital expenditures (34,995) (32,454)
Long-term investments - net (25,028) (55,590)
Other - net (1,728) (2,302)
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Net Cash Used in Investing
Activities (61,751) (90,346)
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Cash Flows Provided by (Used in)
Financing Activities
Increase (decrease) in notes payable 19,519 (887)
Issuance (redemption) of preferred
and preference stock 150,000 (111)
Dividends on common stock (49,555) (45,593)
Reductions of long-term obligations -
net (58,668) (60,627)
Repurchase of common stock (11,717) (21,259)
Other - net (5,700) 1,985
-------- ---------
Net Cash Provided by (Used in)
Financing Activities 43,879 (126,492)
-------- ---------
Net increase in cash and temporary cash
investments 113,787 4,912
Cash and temporary cash investments at
beginning of period 24,767 50,058
-------- ---------
Cash and temporary cash investments at
end of period $138,554 $ 54,970
======== =========
Non-Cash Investing Activities
Equity funding obligations recorded $ 16,716 $ 5,471
======== =========
See notes to condensed consolidated financial statements.
4
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Except for historical information contained herein, the matters discussed in
this Quarterly Report on Form 10-Q are forward-looking statements that involve
risks and uncertainties including, but not limited to, economic, competitive,
governmental and technological factors affecting DQE 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 is an energy services holding company formed in 1989. Its subsidiaries
are Duquesne Light Company (Duquesne), Duquesne Enterprises (DE), DQE Energy
Services (DES) and Montauk. DQE and its subsidiaries are collectively referred
to as "the Company."
Duquesne is an electric utility engaged in the production, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE makes strategic investments related to DQE's core energy
business. These investments enhance DQE's capabilities as an energy provider,
increase asset utilization, and act as a hedge against changing business
conditions. DES was formed in August 1995 and is a marketing and development
company providing energy solutions for customers in domestic and international
markets. DES initiatives include energy facility development and operations,
independent power production, gas and electric energy/fuel management, utility
management services and advanced systems. Montauk is a financial services
company that makes long-term investments and provides financing for the
Company's market-driven business activities.
All material intercompany balances and transactions have been eliminated in
the preparation of the condensed consolidated financial statements of DQE.
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-period financial statements were
reclassified to conform with the 1996 presentation.
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, 1995. The results of operations for the three and six months
ended June 30, 1996, are not necessarily indicative of the results that may be
expected for the full year. The preparation of financial statements in
conformity with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of assets and
liabilities and disclosure of contingent assets and liabilities at the date of
the financial statements. The reported amounts of revenues and expenses during
the reporting period may also be affected by the estimates and assumptions
management is required to make. Actual results could differ from those
estimates.
The Company is subject to the accounting and reporting requirements of the
SEC. In addition, the Company's electric utility operations are subject to the
regulation of the Pennsylvania Public Utility Commission (PUC) and the Federal
Energy Regulatory Commission (FERC). As a result, the consolidated financial
statements contain regulatory assets and liabilities in accordance with
Statement of Financial Accounting Standards No. 71, Accounting for the Effects
of Certain
5
Types of Regulation (SFAS No. 71) and reflect the effects of the ratemaking
process. Such effects concern mainly the time at which various items enter into
the determination of net income in accordance with the principle of matching
costs and revenues. (See "Rate Matters," Note 3, below.)
The Company's long-term investments include certain investments in
marketable securities. In accordance with Statement of Financial Accounting
Standards 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 losses on investments
at June 30, 1996, and December 31, 1995, are $9.9 million and $4.4 million,
respectively. Reduced for deferred income taxes, net unrealized holding losses
on investments are $5.8 million and $2.6 million at June 30, 1996 and December
31, 1995, respectively.
2. RECEIVABLES
Components of receivables for the periods indicated are as follows:
June 30, June 30, December 31,
1996 1995 1995
(Amounts in Thousands of Dollars)
- ----------------------------------------------------------------------------
Direct customer accounts receivable $105,199 $ 93,453 $103,821
Other utility receivables 14,611 18,934 22,441
Other receivables 31,396 36,693 25,164
Less: Allowance for uncollectible
accounts (21,338) (17,212) (18,658)
- ----------------------------------------------------------------------------
Receivables less allowance for
uncollectible accounts 129,868 131,868 132,768
Less: Receivables sold - (26,000) (7,000)
- ----------------------------------------------------------------------------
Total Receivables $129,868 $105,868 $125,768
============================================================================
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
$50.0 million of accounts receivable. At June 30, 1996, the Company had no
receivables sold to the unaffiliated corporation. At December 31, 1995 and June
30, 1995, the Company had sold $7.0 million and $26.0 million of receivables to
the unaffiliated corporation, respectively. The accounts receivable sales
agreement, which was recently extended to June 1997, is one of many sources of
funds available to the Company. The Company may attempt to extend the
agreement or to replace the facility with a similar arrangement or to eliminate
it upon expiration.
3. RATE MATTERS
On May 23, 1996, the PUC approved the Company's plan for the sale of its
ownership interest in the Ft. Martin Power Station. In accordance with this PUC
order, the Company will not increase its base rates for a five-year period
through the year 2000. In addition, the Company will record a five-year annual
$5.0 million credit to the Energy Cost Rate Adjustment Clause (ECR) and cap
energy costs beginning April 1, 1997, through the remainder of the plan period.
(See "Ft. Martin Plan" discussion on page 8.)
6
Regulatory Assets
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.
The Company's electric utility operations currently satisfy the SFAS No. 71
criteria. However, a company's electric utility operations or a portion of such
operations could cease to meet these criteria for various reasons, including a
change in the PUC or the FERC regulations. Should the Company's electric utility
operations cease to meet the SFAS No. 71 criteria, the Company would be required
to write off any regulatory assets or liabilities for those operations that no
longer meet these requirements. Management will continue to evaluate significant
changes in the regulatory and competitive environment in order to assess the
Company's overall consistency with the criteria of SFAS No. 71.
The components of regulatory assets for the periods presented are as follows:
June 30, December 31,
1996 1995
(Amounts in Thousands of Dollars)
- --------------------------------------------------------------------------------
Regulatory tax receivable $407,787 $414,543
Unamortized debt costs (a) 96,013 98,776
Deferred rate synchronization costs
(see below) 42,149 51,149
Beaver Valley Unit 2 sale/leaseback
premium (b) 30,811 31,564
Deferred employee costs (c) 28,123 31,218
Extraordinary property loss 732 8,300
Deferred nuclear maintenance outage
costs 16,569 6,776
DOE decontamination and decommissioning
receivable 10,235 10,687
Deferred coal costs 12,233 12,753
Other 5,698 6,162
- ---------------------------------------------------------------------------
Total Regulatory Assets $650,350 $671,928
===========================================================================
(a) The premiums paid to reacquire debt prior to scheduled maturity dates are
deferred for amortization over the life of the debt issued to finance the
reacquisitions.
(b) The premium paid to refinance the Beaver Valley Unit 2 lease was deferred
for amortization over the life of the lease.
(c) Includes amounts for recovery of accrued compensated absences and accrued
claims for workers' compensation.
With respect to the financial statement presentation of Statement of Financial
Accounting Standards No. 109, Accounting for Income Taxes, the Company reflects
the amortization of the regulatory tax receivable resulting from reversals of
deferred taxes as depreciation and amortization expense. Reversals of
accumulated deferred income taxes - net are included in income taxes.
Deferred Rate Synchronization Costs
In 1987, the PUC approved the Company's petition to defer initial operating
and other costs of Perry Unit 1 and Beaver Valley Unit 2 (BV Unit 2). The
Company deferred the costs incurred from the date the units went into commercial
operation until the date a rate order was issued. In its rate order, the PUC
postponed ruling on whether these costs would be recoverable from the Company's
electric utility customers. The Company is not earning a return on the deferred
costs.
7
In accordance with the recent PUC order approving the Company's plan for the
sale of its ownership interest in the Ft. Martin Power Station, the Company has
charged off $9.0 million related to the depreciation portion of deferred rate
synchronization costs. The Company's approved plan also provides for the
amortization of the remaining $42.1 million of deferred rate synchronization
costs over a ten-year period. (See "Ft. Martin Plan" discussion, below.)
Property Held for Future Use
In 1986, the PUC approved the Company's request to remove Phillips Power
Station (Phillips) and a portion of Brunot Island Power Station (BI) from
service and from rate base. The Company expects to recover its net investment in
these plants through future electricity sales. The Company believes its
investment in these plants will be necessary in order to meet future business
needs outlined in the Company's plans for optimizing generation resources. If
business opportunities do not develop as expected, the Company will consider the
sale of these assets. In the event that market demand, transmission access or
rate recovery do not support the utilization or sale of the plants, the Company
may have to write off part or all of these costs. A portion of the proceeds of
the sale of the Ft. Martin Power Station is expected to be used to finance
reliability enhancements to BI combustion turbines, allowing the re-utilization
of the facilities. The reliability enhancements are contingent upon the projects
meeting a least-cost test versus other potential sources of peaking capacity.
(See "Ft. Martin Plan" discussion, below.) At June 30, 1996, the Company's net
investment in Phillips and BI held for future use was $78.3 million and $44.9
million, respectively.
Ft. Martin Plan
On May 23, 1996, the PUC approved the sale of the Company's ownership interest
in the Ft. Martin Power Station and a plan to be financed in part by the
proceeds of the Ft. Martin transaction. Under the approved plan, the Company
will not increase its base rates for a period of five years through the year
2000. In addition, the Company will record a one-time reduction of approximately
$130.0 million in the value of the Company's nuclear plant investment. The
proceeds from the sale are expected to be used to finance reliability
enhancements to the BI combustion turbines, to retire debt and to reduce equity.
The approved plan also provides for an annual increase of $25.0 million for
three years in depreciation and amortization expense related to the Company's
nuclear investment, as well as additional annual contributions to its nuclear
plant decommissioning funds of $5.0 million, without any increase in existing
electric rates. Also, the Company will record an annual $5.0 million
credit to the ECR during the plan period to compensate the Company's electric
utility customers for the lost profits from any reduced short-term power sales
foregone by the sale of its ownership interest in the Ft. Martin Power Station.
In addition to the annual credit of $5.0 million to the ECR, the Company will
cap energy costs beginning April 1, 1997, through the remainder of the plan
period, at a historical five-year average of 1.47 cents per kilowatt hour. In
accordance with the approved plan, the Company has charged off $9.0 million
related to the depreciation portion of the $51.1 million of deferred rate
synchronization costs associated with BV Unit 2 and Perry Unit 1. Upon final
transfer of its ownership interest in the Ft. Martin Power Station, the Company
will amortize the remaining $42.1 million of deferred rate synchronization costs
over a ten-year period. Finally, the Company's approved plan also provides for
annual assistance of $0.5 million to low-income customers.
8
4. COMMITMENTS AND CONTINGENCIES
Construction
The Company estimates that it will spend, excluding Allowance for Funds Used
During Construction (AFC) and nuclear fuel, approximately $90.0 million on
electric utility construction during 1996. This estimate also excludes any
potential expenditures for the reliability enhancements to the BI combustion
turbines. (See "Ft. Martin Plan" discussion on page 8.)
Nuclear-Related Matters
The Company operates two nuclear units and has an ownership interest in a
third. 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 PUC ruled that recovery of the decommissioning
costs for Beaver Valley Unit 1 (BV Unit 1) could begin in 1977, and that
recovery for BV Unit 2 and Perry Unit 1 could begin in 1988. The Company
expects to decommission BV Unit 1, BV Unit 2 and Perry Unit 1 no earlier than
the expiration of each plant's operating license, 2016, 2027 and 2026,
respectively. BV Unit 1 will be placed in safe storage until the expiration of
the BV Unit 2 operating license, at which time the units may be decommissioned
together.
Based on site-specific studies finalized in 1992 for BV Unit 2 and in 1994
for BV Unit 1 and Perry Unit 1, the Company's share of the total estimated
decommissioning costs, including removal and decontamination costs, currently
being used to determine the Company's cost of service is $122.0 million for BV
Unit 1, $35.0 million for BV Unit 2 and $67.0 million for Perry Unit 1.
In conjunction with an August 18, 1994, PUC Accounting Order, the Company has
increased the annual contribution to its decommissioning trusts by approximately
$2.0 million, to bring the total annual funding to approximately $4.0 million
per year. On July 18, the PUC issued a Proposed Policy Statement Regarding
Nuclear Decommissioning Cost Estimation and Cost Recovery for the purpose of
obtaining comments from the public. The proposed policy includes guidelines for
a site-specific study to estimate the cost of decommissioning. These studies
need to be performed at least every five years addressing radiological and
nonradiological costs and include a contingency factor of not more than 10
percent. Under the proposed policy annual decommisioning funding levels are
based on an annuity calculation recognizing inflation in the cost estimates and
earnings on fund assets. Utilities will be permitted to update their annual
decommissioning trust fund payments through accounting petitions, a change in
base rates, or a non-earnings related change in base rates under the proposed
policy. With respect to transition to a competitive generation market, the
proposed policy recommends utilities include a plan to mitigate any shortfall in
decommissioning trust fund payments for the life of the facility with any future
decommissioning filings. The PUC recently approved the Company's plan for the
sale of its ownership interest in the Ft. Martin Power Station, which provides
for additional annual contributions to its nuclear decommissioning funds of $5.0
million without any increase in existing electric utility rates, which is
intended to achieve this mitigation objective. (See "Ft. Martin Plan"
discussion, Note 3, on page 8.)
The Company records decommissioning expense under the category of depreciation
and amortization and accrues a liability equal to that amount for nuclear
decommissioning expense. Such nuclear decommissioning funds are deposited in
external, segregated trust accounts. The funds are invested in a portfolio of
municipal bonds, certificates of deposit and United States government securities
having a weighted average duration of four to seven years. Trust fund earnings
increase the fund balance and the recorded liability. The market value of the
aggregate trust fund balances at June 30, 1996, totaled approximately $30.2
million. On the Company's consolidated balance sheet, the decommissioning
trusts have been reflected in long-term investments, and the related liability
has been recorded as other non-current liabilities.
9
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 $200.0 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 assessment, $59.5
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 funds prove insufficient to pay claims, the United
States Congress could impose other revenue-raising measures on the nuclear
industry.
The Company's share of property damage, decommissioning and decontamination
liability provides $1.2 billion of insurance coverage. 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 $10.9 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. The coverage provides for 100
percent of the estimated incremental costs per week during the 52-week period
starting 21 weeks after an accident and 80 percent of such estimate per week for
the following 104 weeks 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 $3.5 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 15 percent of its steam generator tubes from
service through a process called plugging. However, BV Unit 1 continues to
operate at 100 percent reactor power and has the ability to return tubes to
service by repairing them through a process called sleeving. To date, no tubes
at either BV Unit 1 or BV Unit 2 have been sleeved. BV Unit 2, which was
placed in service eleven years after BV Unit 1, has not yet exhibited the degree
of ODSCC experienced at BV Unit 1. Less than 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.
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 BV Unit 1's steam generators.
The total replacement cost of BV Unit 1's steam generators is currently
estimated at approximately $125.0 million. The Company would be responsible for
$59.0 million of this total, which includes the cost of equipment removal and
replacement, but excludes replacement power costs. The earliest that BV Unit
1's steam generators could be replaced is 1999.
BV Unit 1 completed its 11th refueling outage on May 11, 1996. The outage
lasted 49 days and was the shortest refueling outage in the history of the unit.
During the outage, various inspections of the unit's steam generators were made,
including examinations using a new "Plus Point" probe. Use of the probe found
fewer defects than expected at the top of the steam generators' tube sheets. In
addition, the Company returned to service tubes that had previously
10
been plugged. Following the refueling outage, 85 percent of the steam generator
tubes were in service, approximately 1 percent more than at the beginning of the
outage. BV Unit 2's 6th refueling outage is scheduled to begin on August 30,
1996.
The Company continues to explore all viable means of managing ODSCC,
including new repair technologies, and plans to perform 100 percent tube
inspections at each unit during future refueling outages. The Company will
continue to monitor and evaluate the condition of the BVPS steam generators.
Spent Nuclear Fuel Disposal. The Nuclear Waste Policy Act of 1982
established a policy for handling and disposing of spent nuclear fuel and a
policy requiring the established final repository to accept spent fuel.
Electric utility companies have entered into contracts with the Department of
Energy (DOE) for the permanent disposal of spent nuclear fuel and high-level
radioactive waste in compliance with this legislation. The DOE has indicated
that its repository under these contracts will not be available for acceptance
of spent fuel before 2010 at the earliest. On July 23, 1996, the U. S. Court of
Appeals for the District of Columbia Circuit, in response to a suit brought by
25 electric utilities and 18 states and state agencies, unanimously ruled that
the DOE has a legal obligation to begin taking spent fuel by January 31, 1998.
The DOE has not yet established an interim or permanent storage facility, and it
is uncertain whether the DOE will be able to accept spent nuclear fuel by
January 31, 1998. Further, Congress is considering amendments to the Nuclear
Waste Policy Act of 1982 that could give the DOE authority to proceed with the
development of a federal interim storage facility. In the event the DOE does
not begin accepting fuel, existing on-site fuel storage capacities at BV Unit 1,
BV Unit 2 and Perry Unit 1 are expected to be sufficient until 2016, 2010 and
2011, respectively.
Uranium Enrichment Decontamination and Decommissioning Fund. 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 June 30, 1996, the Company's liability for
contributions was approximately $9.9 million (subject to an inflation
adjustment). Contributions, when made, are recovered from electric utility
customers through the ECR.
Guarantees
The Company and the owners of Bruce Mansfield Power Station have guaranteed
certain debt and lease obligations related to a coal supply contract for the
Bruce Mansfield plant. At June 30, 1996, the Company's share of these guarantees
was $21.1 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 total $23.1 million at June 30,
1996.
The Company has entered into various partnerships to enhance the credit
associated with affordable housing investments made by third-party investors.
As part of the transactions, the Company has guaranteed a minimum defined yield
and the funding of certain defined operating deficits in return for a fee. 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, it is management's belief that such deferrals are ample for
this purpose.
11
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 now under
review by the DEP. Capital compliance costs of $3.0 million were incurred by
the Company in 1995 to comply with these DEP regulations; on the basis of
information currently available, an additional $2.5 million will be incurred in
1996. The expected additional capital cost of compliance through the year 2000
is estimated, based on current information, to be approximately $25.0 million.
This estimate is subject to the results of ground water assessments and DEP
final approval of compliance plans.
Other
The Company is involved in various other legal proceedings and environmental
matters. The Company believes that such proceedings and matters, in total,
will not have a materially adverse effect on its financial position, results
of operations or cash flows.
12
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 (Report) should be read in
conjunction with the Company's Annual Report on Form 10-K filed with the
Securities and Exchange Commission (SEC) for the year ended December 31, 1995
and the Company's condensed consolidated financial statements, which are set
forth on pages 2 through 12 in Part I, Item 1 of this Report.
General
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DQE is an energy services holding company formed in 1989. Its subsidiaries
are Duquesne Light Company (Duquesne), Duquesne Enterprises (DE), DQE Energy
Services (DES) and Montauk. DQE and its subsidiaries are collectively referred
to as "the Company."
Duquesne is an electric utility engaged in the production, transmission,
distribution and sale of electric energy and is the largest of DQE's
subsidiaries. DE makes strategic investments related to DQE's core energy
business. These investments enhance DQE's capabilities as an energy provider,
increase asset utilization, and act as a hedge against changing business
conditions. DES was formed in August 1995 and is a marketing and development
company providing energy solutions for customers in domestic and international
markets. DES initiatives include energy facility development and operations,
independent power production, gas and electric energy/fuel management, utility
management services and advanced systems. Montauk is a financial services
company that makes long-term investments and provides financing for the
Company's market-driven business activities.
The Company's Electric Operations
The Company's utility operations provide electric service to customers in
Allegheny County, including the City of Pittsburgh and Beaver County. This
represents approximately 800 square miles in southwestern Pennsylvania, located
within a 500-mile radius of one-half of the population of the United States and
Canada. The population of the area served by the Company's electric utility
operations, based on 1990 census data, is approximately 1,510,000, of whom
370,000 reside in the City of Pittsburgh. In addition to serving approximately
580,000 direct customers, the Company's utility operations also sell electricity
to other utilities.
Regulation
The Company's electric utility operations are subject to regulation by the
Pennsylvania Public Utility Commission (PUC), as well as to regulation by 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 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 is also subject to the accounting and reporting
requirements of the SEC.
13
The Company's consolidated financial statements report regulatory assets and
liabilities in accordance with Statement of Financial Accounting Standards No.
71, Accounting for the Effects of Certain Types of Regulation (SFAS No. 71), and
reflect the effects of the ratemaking process. In accordance with SFAS No. 71,
the Company's consolidated financial statements reflect regulatory assets and
liabilities based on current cost-based ratemaking regulations. The regulatory
assets represent probable future revenue to the Company because provisions for
these costs are currently included, or are expected to be included, in charges
to electric utility customers through the ratemaking process.
The Company's electric utility operations currently satisfy the SFAS No. 71
criteria. However, a company's utility operations or a portion of such
operations could cease to meet these criteria for various reasons, including a
change in the PUC or the FERC regulations. (See "Competition" discussion on
page 18.) Should the Company's electric utility operations cease to meet the
SFAS No. 71 criteria, the Company would be required to write off any regulatory
assets or liabilities for those operations that no longer meet these
requirements. Management will continue to evaluate significant changes in the
regulatory and competitive environment in order to assess the Company's overall
consistency with the criteria of SFAS No. 71.
Results of Operations
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Seasonality
The quarterly results are not necessarily indicative of full-year operations
because of seasonal fluctuations. Sales of electricity to customers by the
Company's electric utility operations tend to increase during the warmer summer
and colder winter seasons because of greater customer use of electricity for
cooling and heating, respectively.
In the near term, weather conditions and the overall level of business
activity in the Company's electric utility geographic area are expected to
continue to be the primary factors affecting sales of electricity to customers.
In the long-term, the Company's electric sales may also be affected by increased
competition in the electric utility industry. (See "Competition" discussion on
page 18.)
Operating Revenues
Total operating revenues increased $10.0 million during the second quarter
of 1996 as compared to the second quarter of 1995, due to higher sales of
electricity. Warmer May 1996 temperatures, compared to 1995, resulted in higher
direct customer revenues from residential and commercial customers of 6.1
percent and 2.9 percent, respectively. May 1996 temperatures also resulted in
greater demand for electricity from other utilities. Revenue from sales of
electricity to other utilities increased $3.1 million in the second quarter of
1996 when compared to the corresponding quarter of 1995. Total operating
revenues increased $12.2 million during the first six months of 1996 as compared
to the first six months of 1995, also due to greater sales of electricity.
Direct customer revenues from residential and commercial customers during the
first six months of 1996 were 4.4 percent and 1.3 percent higher than for the
same period of 1995 due to colder winter and warmer May temperatures. Revenues
from sales of electricity to other utilities increased $6.5 million for the
first six months of 1996 as compared to the same period in 1995. Scheduled
outages at BV Unit 2 and Elrama Power Station, as well as a forced outage at
Ft. Martin
14
Power Station, reduced generation available for sales to other utilities during
the first six months of 1995.
Other operating revenues declined $0.5 million when comparing the second
quarter of 1996 and 1995 and declined $3.8 million when comparing the first six
months of 1996 and 1995. The reduction in 1996 other operating revenues reflects
the shorter Beaver Valley Power Station refueling outage activity when compared
to the first two quarters of 1995. The record 49-day outage at BV Unit 1 and the
absence of a BV Unit 2 outage during 1996 resulted in lower billings to the
other joint owners for administrative and general costs during the first six
months of the current year. The comparative decrease for the first six months of
1996 also reflects the restructuring of Chester Engineers (Chester), a
subsidiary of DE.
Operating Expenses
Total operating expenses increased $9.5 million and $21.0 million during the
second quarter of 1996 and the first six months of 1996 as compared to the same
periods in 1995, respectively.
Fuel and purchased power expense was $5.9 million greater in the second
quarter of 1996 when compared to the second quarter of 1995 and $9.9 million
greater in the first six months of 1996 when compared to the first six months of
1995. These increases in fuel and purchased power expense are consistent with
the 1996 increase in electric sales volume.
Other operating expenses increased for the second quarter of 1996 by $0.9
million compared to the second quarter of 1995. The increase is the result of
costs associated with DES, which was formed in August 1995. During the first six
months of 1996, other operating expenses decreased $1.8 million compared to the
first six months of 1995. The net decrease includes the restructuring of Chester
offset by costs associated with DES. Also, the scheduled refueling outage at
Perry Unit 1 resulted in a $1.4 million shift from other operating expense to
maintenance expense as labor resources normally applied to operations were
shifted to plant maintenance during the first quarter of 1996.
Maintenance expenses decreased $2.2 million when comparing the second
quarter of 1996 and 1995 due to fewer fossil station outages in 1996.
Maintenance expense incurred during the first six months of 1996 were comparable
to the first six months of 1995.
Depreciation and amortization expense increased $5.4 million and $13.6
million for the second quarter of 1996 and the first six months of 1996, as
compared to the same periods in 1995, respectively. The Company charged off $9.0
million for the first six months of 1996 depreciation related to deferred rate
synchronization costs in conjunction with the sale of its ownership interest in
the Ft. Martin Power Station. Accelerated depreciation of fixed assets also
contributed to the 1996 period increases in depreciation and amortization. (See
"Ft. Martin Plan" discussion on page 17.)
Taxes other than income taxes for both periods, the second quarter of 1996
and the first six months of 1996, were comparable to the second quarter of 1995
and the first six months of 1995, respectively.
15
Other Income
Other income increased $6.1 million and $5.3 million in the second quarter
of 1996 and the first six months of 1996, respectively, largely because of
increased long-term investments made since the second quarter of 1995. During
the first quarter of 1995 a pre-tax gain of approximately $7.2 million was
recorded related to the acquisition of International Power Machines (IPM) (in
which the Company had a $2.8 million equity investment) by Exide Electronics
Group (Exide).
Interest and Other Charges
As the result of retirement and refinancing of long-term debt, interest and
other charges were $0.9 million and $2.8 million lower for the second quarter of
1996 and the first six months of 1996 when compared to the same periods in 1995,
respectively.
Income Taxes
Income taxes were $4.2 million greater in the second quarter of 1996
compared to the second quarter of 1995. The increase in income taxes in the
second quarter of 1996 is partially attributable to additional taxable income.
Income taxes in the second quarter of 1995 were reduced by the amortization of
deferred taxes associated with the Company's accelerated depreciation of fixed
assets and the effect of a retroactive one-time reduction in the Pennsylvania
corporate income tax rate. Income taxes for the six months period ended June 30,
1996, when compared to the same period in 1995 decreased $5.3 million due to
the amortization of deferred investment tax credits in the first quarter of
1995.
Liquidity and Capital Resources
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Financing
The Company expects to meet its current obligations and debt maturities
through the year 2000 with funds generated from operations and through new
financings. At June 30, 1996, the Company was in compliance with all of its
debt covenants.
All of the Company's First Collateral Trust Bonds have been issued under a
mortgage indenture established in April 1992 (the 1992 Indenture). All First
Collateral Trust Bonds became first mortgage bonds when the Company's 1947 first
mortgage bond indenture was retired in the third quarter of 1995 following the
maturity of the last bond series issued under the indenture.
The Company entered into a five-year bank term loan on June 24, 1996, for
$10.0 million at 7.5 percent. On July 24, 1996, the Company entered into an
additional five-year bank term loan for $50.0 million at 7.3 percent. Both term
loans pay interest semi-annually.
On June 24, 1996, the Company extended one of its revolving credit
agreements to June 23, 1997, and increased the facility from $100.0 million to
$125.0 million. Interest rates can, in accordance with the option selected at
the time of each borrowing, be based on prime, Eurodollar or certificate of
deposit rates. Commitment fees are based on the unborrowed amount of the
commitment. The credit facility contains a two-year repayment period for any
amounts outstanding at the expiration of the revolving credit period. In
addition, a $50.0 million accounts receivable sale arrangement was extended to
June 25, 1997, during the second quarter. 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 $50.0 million of accounts
receivable. The Company may attempt to extend the agreement or to replace the
facility with a similar one or to eliminate it upon expiration.
16
On May 14, 1996, Duquesne Capital L.P., a Delaware special-purpose limited
partnership whose sole general partner is Duquesne, issued in aggregate $150.0
million, principal amount of 8-3/8% Cumulative Monthly Income Preferred
Securities, Series A, with a stated liquidation value of $25. A portion of the
proceeds was used to retire $50.0 million of long-term debt maturing May 15,
1996. The Company intends to apply the remaining proceeds to the purchase or
redemption of outstanding securities and for general corporate purposes.
Investing
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The Company's market-driven long-term investments focus in five principal
areas: affordable housing, natural gas reserves, lease and leasehold
investments, environmental services and energy solution investments.
Investments in leveraged leases for the six months ended June 30, 1996, were
$38.0 million. The Company invested $8.6 million and $13.9 million in
affordable housing funds during the six months ended June 30, 1996 and 1995,
respectively. The Company also invested $5.4 million in natural gas reserve
partnerships during the six months ended June 30, 1996.
On February 8, 1995, IPM was acquired by Exide. As a result of this merger,
the Company acquired 526,250 shares of Exide common stock, a 6.8 percent
interest. Since the merger, the Company has acquired an additional 532,500
shares of Exide for $9.8 million. At June 30, 1996, the Company held a 10.6
percent interest in Exide. Other long-term investments at June 30, 1996,
included a $10.1 million investment in Exide common stock.
Outlook
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Ft. Martin Plan
On May 23, 1996, the PUC approved the sale of the Company's ownership
interest in the Ft. Martin Power Station and a plan to be financed in part by
the proceeds of the Ft. Martin transaction. Under the approved plan, the Company
will not increase its base rates for a period of five years through the year
2000. In addition, the Company will record a one-time reduction of approximately
$130.0 million in the value of the Company's nuclear plant investment. The
proceeds from the sale are expected to be used to finance reliability
enhancements to the Brunot Island Power Station (BI) combustion turbines, to
retire debt and to reduce equity. The approved plan also provides for an annual
increase of $25.0 million for three years in depreciation and amortization
expense related to the Company's nuclear investment, as well as additional
annual contributions to its nuclear plant decommissioning funds of $5.0 million,
without any increase in existing electric rates. Also, the Company will record
an annual $5.0 million credit to the Energy Cost Rate Adjustment Clause (ECR)
during the plan period to compensate the Company's electric utility customers
for the lost profits from any reduced short-term power sales foregone by the
sale of its ownership interest in the Ft. Martin Power Station. In addition to
the annual credit of $5.0 million to the ECR, the Company will cap energy costs
beginning April 1, 1997, through the remainder of the plan period, at a
historical five-year average of 1.47 cents per kilowatt hour. In accordance with
the approved plan, the Company has charged off $9.0 million related to the
depreciation portion of the $51.1 million of deferred rate synchronization costs
associated with BV Unit 2 and Perry Unit 1. Upon final transfer of its ownership
interest in the Ft. Martin Power Station, the Company will amortize the
remaining $42.1 million of deferred rate synchronization costs over a ten-year
period. Finally, the Company's approved plan also provides for annual assistance
of $0.5 million to low-income customers.
The Company's regulatory assets include deferred coal costs of $12.2 million
and $12.7 million at June 30, 1996 and 1995, respectively. The Company believes
these deferred costs
17
continue to represent probable future revenues recoverable under all existing
energy caps. The Company will continue to monitor significant changes in the
regulatory and competitive climate that would affect its ability to recover
these costs from electric utility customers. (See "Regulation" discussion on
page 13.)
Competition
The electric utility industry is undergoing fundamental change in response
to the open transmission access and increased availability of energy
alternatives fostered by the National Energy Policy Act of 1992 (NEPA), which
has served to increase competition in the industry. These competitive pressures
require utilities to offer competitive pricing and terms to retain customers and
to develop new markets for the optimal utilization of their generation capacity.
At the national level, on April 24, 1996, the FERC issued two related final
rules that address the terms on which electric utilities will be required to
provide wholesale suppliers of electric energy with non-discriminatory access to
the utility's wholesale transmission system. The first rule, Order No. 888,
addresses both open access and stranded cost issues. Each public utility that
owns, controls or operates interstate transmission facilities was required to
file, no later than July 9, 1996, a tariff that offers unbundled transmission
services containing non-rate terms that conform to the FERC's Order No. 888 pro
forma tariff and to propose rates for these services. The Company's tariff was
timely filed. Order No. 888 also provides for full recovery of those costs that
were prudently incurred to serve wholesale (and retail-turned wholesale)
customers that subsequently leave a utility's system. These costs will be
recovered from the departing customers. However, the FERC will not be the
forum for recovery of stranded costs arising when retail customers leave a
utility's system, even if their new suppliers rely on FERC-jurisdiction
transmission services, unless state regulators lack authority under state law
to provide for recovery. The rule indicates FERC's willingness to defer to
state regulators with respect to retail access, recovery of retail stranded
costs and the scope of state regulatory jurisdiction.
The second rule, Order No. 889, is the Open Access Same Time Information rule
(OASIS). This rule prohibits transmission owners and their affiliates from
gaining preferential access to information concerning transmission and
establishes a code of conduct to ensure the complete separation of a utility's
wholesale power marketing and transmission operation functions.
Finally, the FERC simultaneously issued a new Notice of Proposed Rulemaking
(NOPR) on Capacity Reservation Open Access Transmission Tariffs (CRT), which
would require all market participants to reserve firm capacity rights between
designated receipt and delivery points. If adopted, the CRT would replace the
open access pro forma tariff implemented in Order No. 888. On July 12, 1996,
the Company filed with the FERC a request for acceptance of a CRT to replace the
FERC pro forma tariff filed on July 9, 1996. (See "Transmission Access"
discussion on page 20.)
In Pennsylvania, the PUC has completed its investigation concerning
regulatory reform and has issued a report recommending to the governor and the
Pennsylvania General Assembly that retail choice be adopted by the electric
utility industry. The PUC plan calls for electric utility restructuring to be
accomplished through a two-stage process consisting of a transition period
(1996 to 2001) and a phase-in period (2001 to 2005). The transition period,
which could be reduced to three years if successful, would afford the industry
an opportunity to restructure itself for retail choice. It would include retail
access pilot programs, milestone reviews and provisions for stranded cost
recovery. Utilities are expected to submit restructuring plans by April 1, 1997.
Competitive retail access pilot programs, which will include all classes of
customers, could begin as early as April 1997. Periodic milestone reviews would
be used to ensure that the move to retail choice is conducted in a careful and
appropriate manner. After a successful transition, the phase-in period would
provide an incremental move to full retail competition. The PUC report proposes
the following phase-in schedule: during the year 2001, no less than 10 percent
load; during the year 2002, no less than 25 percent load; during the year 2003,
no less than 50 percent load; and by January 1, 2005, all customers will have
the option to receive direct retail access. Milestone reviews would be used to
monitor activities related to the implementation.
Under the PUC plan, utilities are to be afforded an opportunity, but not a
guarantee, to recover stranded costs. Utilities will be expected to mitigate
stranded investments through various means, such as selling assets, accelerating
depreciation and buying out uneconomic contracts. These activities, however,
are not to result in any increase in current rates paid by customers. After the
transition period, the PUC will determine the eligibility for recovery of
remaining stranded costs through a Competitive Transition Charge, which would be
paid by consumers who choose alternative generation suppliers. Performance Based
Rates, which reward or penalize a utility through incentives that more closely
resemble those available in a market-driven industry, are expected to replace
the existing method of setting rates, according to the plan. The PUC plan also
encourages utilities to employ flexible pricing and other innovative proposals,
such as real-time pricing, interruptible buy-through options and commodity index
pricing, for all customer classes. In addition, legislation related to retail
customer choice has been introduced in the Pennsylvania state legislature. The
Company cannot predict what legislation, if any, may ultimately be enacted.
18
The Company is aware of the foregoing state and federal regulatory and
business uncertainties, and is attempting to position itself to operate in a
more competitive environment. Because of the Company's current electric
generating configuration, some of its baseload capacity is used less than
optimally. The Company is currently considering ways to align its generating
capabilities more closely with customer demand. Its current rate structure
allows some flexibility in setting rates to retain its customer base and attract
new business. In addition, despite the fact that sales to wholesale customers do
not account for a significant portion of the Company's revenues, open access
transmission offers the Company the opportunity to sell power on a market basis
to customers outside of its geographic area.
Open access transmission requirements implicitly create the potential for
stranded costs. The Company continues to implement, and to further evaluate,
the accelerated depreciation of its generating assets as one method to guard
against the competitive risks of stranded investments. The PUC recently
approved the Company's plan for the sale of its ownership interest in the Ft.
Martin Power Station. The Company's approved plan provides for an annual
increase of $25.0 million for three years in depreciation and amortization
expense related to the Company's nuclear investment and a one-time write-down
in the value of the Company's nuclear plant investment of approximately $130.0
million. In addition, the Company's plan recognizes an immediate charge off
of $9.0 million of deferred rate synchronization costs and, upon final
transfer of the Company's ownership interest in the Ft. Martin Power Station,
the remaining $42.1 million balance will be amortized over a ten-year period.
(See "Ft. Martin Plan" discussion on page 17.) These current and proposed
accelerated investment cost recovery measures will be absorbed by the Company
without an increase in base rates. Although the Company believes the
initiatives will enable it to mitigate these issues, the Company could face the
risk of reduced rates of return if unforeseen costs arise and if revenues from
sales or if sources of other income prove inadequate to fund those costs.
The Company believes that these and similar strategies will strengthen its
position to succeed in a more competitive environment by eliminating the need to
charge its electric utility customers in the future for these currently
recognized expenses. At this time, however, there is no assurance as to the
extent to which Company initiatives can or will ultimately eliminate regulatory
and other uncertainties associated with increased competition.
19
Transmission Access
In March 1994, the Company submitted, pursuant to the Federal Power Act, two
separate "good faith" requests for transmission service with Allegheny Power
System (APS) and the Pennsylvania-New Jersey-Maryland Interconnection
Association (PJM Companies), respectively. Each request is based on 20-year
firm service with flexible delivery points for 300 megawatts of transfer
capability over the APS and PJM Companies transmission networks, which together
extend from western Pennsylvania to the East Coast. Because of a lack of
progress on pricing and other issues, on August 5 and September 16, 1994, the
Company filed with the FERC applications for transmission service from the PJM
Companies and APS, respectively. The applications are authorized under Section
211 of the Federal Power Act, which requires electric utilities to provide firm
wholesale transmission service. In May 1995, the FERC issued proposed orders
instructing APS and the PJM Companies to provide transmission service to the
Company and directing the parties to negotiate specific rates, terms and
conditions. The Company was unable to agree to terms for transmission service
with either APS or the PJM Companies. Briefs were filed with the FERC outlining
the areas of disagreement among the companies. The matter is now pending before
the FERC.
On July 12, 1996, the Company filed with the FERC a request for acceptance
of a capacity reservation tariff to replace the FERC pro forma tariff filed on
July 9, 1996 (previously discussed in "Competition" on page 19). The tariff is
intended to provide for the transition to retail customer choice in
Pennsylvania. The Company's tariff proposes to adopt marginal cost pricing for
transmission service on the Company transmission system. Marginal cost pricing
of transmission service will ensure that generators delivering energy to the
Company system will compete on the basis of their relative marginal costs. The
tariff is now pending before the FERC.
The Company is currently evaluating the impact of FERC regulatory actions
on these proceedings. The Company cannot predict the final outcome of these
proceedings.
Generation Resource Optimization
The Company's plans for optimizing generation resources are designed to
reduce underutilized generating capacity, promote competition in the wholesale
marketplace, maintain stable prices and meet customer-specified levels of
service reliability. The Company is committed to exploring firm energy sales to
wholesale customers, system power sales, system power sales with specific unit
back-up, unit power sales, generating asset sales and any other approach to
efficiently managing capacity and energy.
The sale of the Company's ownership interest in the Ft. Martin Power Station
demonstrates the Company's ongoing efforts to optimize the utilization of
generation resources. (See "Ft. Martin Plan" discussion on page 17.) The sale
is expected to reduce power production costs by employing a cost-effective
source of peaking capacity through enhanced reliability of the BI combustion
turbines. The reliability enhancements are contingent upon the projects meeting
a least-cost test versus other potential sources of peaking capacity.
Implementation of the plan will better align the Company's generating
capabilities with its native load requirements.
20
Customer Service Guarantees
The Company's commitment to provide reliable, quality service to its
electric utility customers is characterized by its customer service guarantees.
On March 6, 1995, Duquesne became the first Pennsylvania regulated utility, and
the third in the United States, to offer its residential customers guarantees of
its commitment to courteous, reliable and efficient service. The Company offers
a $25 credit to a customer's account if the Company fails to provide accurate
billings; to meet punctual service appointments; to extend prompt, courteous and
professional service; or to connect new services within one day of the date
requested by the customer.
Customer Advanced Reliability System
In January 1996, the Company announced its Customer Advanced Reliability
System, a new communications service that will provide its electric utility
customers with superior levels of service reliability, security and convenience.
The Company has signed a long-term, full service contract with Itron, Inc.
(Itron), a leading supplier of energy information and communication solutions to
the electric utility industry. Itron will install, operate and maintain a
communications network that will provide the Company with an electronic link to
its 580,000 customers.
The Customer Advanced Reliability System is designed to respond to customer
needs on the basis of immediate information about the status of power delivery
and offer customer choices for new services. This electronic communications
service is another major element in the Company's multi-step plan to make the
Company's electric utility operations more competitive and efficient.
------------------------------
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 the Company's operations,
markets, products, services and prices, and other factors discussed in the
Company's filings with the Securities and Exchange Commission.
21
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In September 1995, the Company commenced arbitration against Cleveland
Electric Illuminating Company (CEI), seeking damages, a declaratory
judgment, termination of the Operating Agreement for Eastlake Power Station
Unit 5 (Unit), the appointment of a special operations advisor to oversee
CEI's operation of the Unit, partition of the parties' interests in the
Unit through a sale and division of the proceeds, and other equitable
relief. The arbitration demand alleged, among other things, the improper
allocation by CEI of fuel and related costs; the mismanagement of the
closing of the Saginaw mine, which historically supplied coal to the Unit;
and the concealment by CEI of material information, particularly with
regard to costs relating to the closing of the Powhattan No. 6 mine, which
currently supplies coal to the Unit.
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, through arbitration or otherwise,
on the basis of a waiver of partition contained in the deed to the land
underlying the Unit. CEI also seeks monetary damages from the Company for
alleged unpaid joint costs in connection with the operation of the Unit. It
is the Company's position that the deed covenant is unenforceable by CEI
due to CEI's bad faith conduct toward the Company, as described in the
arbitration demand, and because it is indefinite in duration, being tied to
the useful life of the Unit. The Company removed the action to the United
States District Court for the Northern District of Ohio, Eastern Division,
where it is now pending, and the parties have agreed to litigate all of
their disputes in federal court and to waive arbitration. The Company
asserted counterclaims in the action identical to the claims made in its
arbitration demand and joined CEI's parent, Centerior Energy Corporation,
in the claims. Several motions have been made by both parties, among them
being motions to dismiss, motions for summary judgment and a motion by the
Company for the appointment of a special operations advisor. The court has
not ruled on any of the motions.
Subject to these proceedings, the Company is currently soliciting offers
for its ownership interest in the Unit, located near Cleveland, Ohio and
operated by Centerior Energy Corporation. The Company's 31.2 percent
ownership interest represents 186 megawatts of the Unit's output capacity.
Item 5. Other Information
Effective August 9, 1996, Wesley W. von Schack resigned as Chairman,
President, CEO and Director of DQE, as well as Chairman, CEO and Director
of Duquesne to accept the position of Chairman, President, CEO and Director
of New York State Electric and Gas Corporation. The Company's Board of
Directors elected David D. Marshall, who had been serving as President
and Chief Operating Officer of Duquesne and Executive Vice President of
DQE, to serve as interim CEO of both DQE and Duquesne. The Board of
Directors has undertaken a search for a replacement for Mr. von Schack that
will include both internal and external candidates.
Item 6. Exhibits and Reports on Form 8-K
a. Exhibits:
EXHIBIT 27.1 - Financial Data Schedule
b. No Current Report on Form 8-K was filed during the three months ended
June 30, 1996.
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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
-----------------
(Registrant)
Date August 14, 1996 /s/ Gary L. Schwass
----------------- ------------------------------------
(Signature)
Gary L. Schwass
Executive Vice President, Treasurer
and Principal Financial Officer
Date August 14, 1996 /s/ Morgan K. O'Brien
----------------- ------------------------------------
(Signature)
Morgan K. O'Brien
Controller and
Principal Accounting Officer
23