<PAGE>
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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Quarterly Report under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For Quarter Ended September 30, 1998
Commission File Number 1-255-2
WEST PENN POWER COMPANY
(Exact name of registrant as specified in its charter)
Pennsylvania 13-5480882
(State of Incorporation) (I.R.S. Employer Identification No.)
800 Cabin Hill Drive, Greensburg, Pennsylvania 15601
Telephone Number - 724-837-3000
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 and (2) has been subject to such
filing requirements for the past 90 days.
At November 16, 1998, 24,361,586 shares of the Common Stock
(no par value) of the registrant were outstanding, all of which
are held by Allegheny Energy, Inc., the Company's parent.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Form 10-Q for Quarter Ended September 30, 1998
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Consolidated statement of income -
Three and nine months ended September 30, 1998 and 1997 3
Consolidated balance sheet - September 30, 1998
and December 31, 1997 4
Consolidated statement of cash flows -
Nine months ended September 30, 1998 and 1997 5
Notes to consolidated financial statements 6-12
Management's discussion and analysis of financial
condition and results of operations 13-22
PART II--OTHER INFORMATION 23
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Income
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
ELECTRIC OPERATING REVENUES:
<S> <C> <C> <C> <C>
Residential $ 97,845 $ 90,923 $ 283,118 $ 287,256
Commercial 59,559 57,614 168,178 165,929
Industrial 87,810 87,302 261,543 263,285
Wholesale and other, including affiliates 21,081 18,852 61,563 56,165
Bulk power transactions, net 21,977 12,055 57,596 29,372
Total Operating Revenues 288,272 266,746 831,998 802,007
OPERATING EXPENSES:
Operation:
Fuel 67,874 65,887 196,482 191,218
Purchased power and exchanges, net 31,790 26,815 90,221 88,381
Deferred power costs, net - - - 2,922
Other 34,961 40,461 111,666 113,260
Maintenance 20,576 20,608 66,747 73,161
Depreciation 27,837 29,898 86,602 90,800
Taxes other than income taxes 22,568 22,072 67,433 67,359
Federal and state income taxes 26,418 17,140 63,353 48,109
Total Operating Expenses 232,024 222,881 682,504 675,210
Operating Income 56,248 43,865 149,494 126,797
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction (430) 209 315 1,472
Other income, net 2,614 7,112 8,174 15,842
Total Other Income and Deductions 2,184 7,321 8,489 17,314
Income Before Interest Charges 58,432 51,186 157,983 144,111
INTEREST CHARGES:
Interest on long-term debt 14,634 16,248 46,570 48,742
Other interest 1,777 1,179 4,623 3,766
Allowance for borrowed funds used during
construction (814) (574) (1,354) (1,594)
Total Interest Charges 15,597 16,853 49,839 50,914
Consolidated Income Before
Extraordinary Charge 42,835 34,333 108,144 93,197
Extraordinary Charge, net (1) - - (265,446) -
CONSOLIDATED NET INCOME (LOSS) $ 42,835 $ 34,333 $(157,302) $ 93,197
</TABLE>
See accompanying notes to consolidated financial statements.
(1) See Note 6 in the notes to the consolidated financial statements.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Consolidated Balance Sheet
(Thousands of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
1998 1997
ASSETS:
Property, Plant, and Equipment:
<S> <C> <C> <C> <C>
At original cost, including $108,069
and $117,588 under construction $ 3,301,177 $ 3,293,039
Accumulated depreciation (1,305,037) (1,254,900)
1,996,140 2,038,139
Investments and Other Assets:
Allegheny Generating Company - common stock at equity 72,471 89,783
Other 653 721
73,124 90,504
Current Assets:
Cash and temporary cash investments 2,728 4,056
Accounts receivable:
Electric service, net of $14,984 and $13,326
uncollectible allowance 123,821 128,348
Affiliated and other 39,574 21,525
Materials and supplies - at average cost:
Operating and construction 33,393 34,212
Fuel 26,498 29,467
Prepaid taxes 17,047 11,738
Deferred income taxes 14,258 11,959
CTC Recovery 24,961 -
Other, including current portion of
regulatory assets 2,115 2,252
284,395 243,557
Deferred Charges:
Regulatory assets 473,029 333,235
Unamortized loss on reacquired debt 4,478 9,725
Other 31,661 31,999
509,168 374,959
Total Assets $ 2,862,827 $ 2,747,159
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 465,994 $ 465,994
Other paid-in capital 55,475 55,475
Retained earnings 238,005 475,558
759,474 997,027
Preferred stock 79,708 79,708
Long-term debt and QUIDS 837,607 802,319
1,676,789 1,879,054
Current Liabilities:
Short-term debt 42,246 52,046
Notes payable to affiliates 33,750 -
Long-term debt due within one year - 103,500
Accounts payable 68,773 73,584
Accounts payable to affiliates 35,306 16,137
Taxes accrued:
Federal and state income 6,501 1,605
Other 12,431 22,728
Interest accrued 11,276 15,817
Adverse power purchase commitments 35,380 -
Other 16,931 28,457
262,594 313,874
Deferred Credits and Other Liabilities:
Unamortized investment credit 43,271 45,206
Deferred income taxes 273,965 450,390
Regulatory liabilities 30,220 34,326
Adverse power purchase commitments 550,539 -
Other 25,449 24,309
923,444 554,231
Total Capitalization and Liabilities $ 2,862,827 $ 2,747,159
</TABLE>
See accompanying notes to consolidated financial statements.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Consolidated Statement of Cash Flows
(Thousands of Dollars)
<TABLE>
<CAPTION>
Nine Months Ended
September 30
1998 1997
CASH FLOWS FROM OPERATIONS:
<S> <C> <C> <C>
Consolidated net (loss) income $ (157,302) $ 93,197
Extraordinary charge, net of taxes 265,446 -
Consolidated income before extraordinary charge 108,144 93,197
Depreciation 86,602 90,800
Deferred investment credit and income taxes, net 3,139 15,075
Deferred power costs, net - 2,922
Unconsolidated subsidiaries' dividends in excess of earnings 17,381 1,772
Allowance for other than borrowed funds used
during construction (315) (1,472)
Restructuring liability - (20,912)
Changes in certain current assets and
liabilities:
Accounts receivable, net (13,522) 27,923
Materials and supplies 3,788 (7,417)
Prepaid taxes (5,309) (4,862)
Accounts payable 14,358 (14,206)
Taxes accrued (5,401) (15,244)
Interest accrued (4,541) (1,600)
Other, net (18,558) 7,319
185,766 173,295
CASH FLOWS FROM INVESTING:
Construction expenditures (less allowance for
equity funds used during construction) (62,193) (74,100)
CASH FLOWS FROM FINANCING:
Issuance of long-term debt 92,834 -
Retirement of long-term debt (161,435) -
Short-term debt, net (9,800) (6,442)
Notes payable to affiliates 33,750 750
Notes receivable from affiliates - 2,900
Dividends on capital stock:
Preferred stock (2,537) (2,573)
Common stock (77,713) (96,959)
(124,901) (102,324)
NET CHANGE IN CASH AND TEMPORARY CASH INVESTMENTS (1,328) (3,129)
Cash and Temporary Cash Investments at January 1 4,056 5,160
Cash and Temporary Cash Investments at September 30 $ 2,728 $ 2,031
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the quarter for:
Interest (net of amount capitalized) $51,960 $50,146
Income taxes 56,129 40,493
</TABLE>
See accompanying notes to consolidated financial statements.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Notes to Consolidated Financial Statements
1. West Penn Power Company (the Company) is a wholly-owned
subsidiary of Allegheny Energy, Inc. The Company's Notes to
Consolidated Financial Statements in its Annual Report on
Form 10-K for the year ended December 31, 1997 should be read
with the accompanying consolidated financial statements and
the following notes. With the exception of the December 31,
1997 consolidated balance sheet in the aforementioned Annual
Report on Form 10-K, the accompanying consolidated financial
statements appearing on pages 3 through 5 and these notes to
consolidated financial statements are unaudited. In the
opinion of the Company, such consolidated financial
statements together with these notes contain all adjustments
necessary to present fairly the Company's financial position
as of September 30, 1998, the results of operations for the
three and nine months ended September 30, 1998 and 1997, and
cash flows for the nine months ended September 30, 1998 and
1997.
2. The Consolidated Statement of Income reflects the results of
past operations and is not intended as any representation as
to future results. The Company's comprehensive income does
not differ from its consolidated net income. For purposes of
the Consolidated Balance Sheet and Consolidated Statement of
Cash Flows, temporary cash investments with original
maturities of three months or less, generally in the form of
commercial paper, certificates of deposit, and repurchase
agreements, are considered to be the equivalent of cash.
3. The Company owns 45% of the common stock of Allegheny
Generating Company (AGC), and affiliates of the Company own
the remainder. AGC owns an undivided 40% interest, 840
megawatts (MW), in the 2,100 MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.
Following is a summary of income statement information for
AGC:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Thousands of Dollars)
Electric operating revenues $18,303 $19,664 $56,033 $60,288
Operation and maintenance
expense 888 856 3,383 3,612
Depreciation 4,242 4,284 12,710 12,852
Taxes other than income taxes 1,168 1,185 3,505 3,581
Federal income taxes 2,708 3,109 8,480 9,374
Interest charges 3,707 3,888 10,518 11,765
Other income, net (35) (9,054) (86) (9,055)
Net income $ 5,625 $15,396 $17,523 $28,159
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The Company's share of the equity in earnings above was $2.5
million and $6.9 million for the three months ended September
30, 1998 and 1997, respectively, and $7.9 million and $12.7
million for the nine months ended September 30, 1998 and
1997, respectively, and was included in other income, net, on
the Consolidated Statement of Income. Dividends received
from AGC in 1998 exceeded equity in earnings by $17.3 million
which reflects an effort to reduce AGC equity to about 45% of
capital.
4. On April 7, 1997, the Company's parent, Allegheny Power
System, Inc. (now renamed Allegheny Energy, Inc.) and DQE,
Inc. (DQE), parent company of Duquesne Light Company in
Pittsburgh, Pennsylvania, announced that they had agreed to
merge in a tax-free, stock-for-stock transaction.
On March 25, 1998, the Maryland Public Service Commission
(PSC) approved a settlement agreement between Allegheny
Energy, Inc. (Allegheny Energy) and various parties, in which
the PSC indicated its approval of the merger. This action
was requested in connection with the proposed issuance of
Allegheny Energy stock to exchange for DQE stock to complete
the merger.
On July 8, 1998, the City of Pittsburgh reached a settlement
agreement with Allegheny Energy and agreed to support the
merger.
On July 16, 1998, the Public Utilities Commission of Ohio
(PUCO) found that the proposed merger would be in the public
interest. The PUCO also stated that the Midwest Independent
System Operator (ISO) is the regional transmission entity
that will best serve the interests of the Ohio customers of
Monongahela Power Company, the Company's utility affiliate,
and will best mitigate any market power issues which might
exist.
The Nuclear Regulatory Commission has approved the transfer
of control of the operating licenses for DQE's nuclear
plants. While Duquesne Light Company (Duquesne), principal
subsidiary of DQE, will continue to be the licensee, this
approval was necessary since control of Duquesne will pass
from DQE to Allegheny Energy after the merger.
On July 23, 1998, the Pennsylvania Public Utility Commission
(PUC) approved the Allegheny Energy-DQE merger with
conditions acceptable to Allegheny Energy in response to a
Petition for Reconsideration filed by Allegheny Energy on
June 12, 1998. In its Petition for Reconsideration of a
previous PUC Order, Allegheny Energy reiterated its
commitment to staying in and supporting the Midwest ISO
subject to merger consummation, and also offered to
relinquish some generation in order to mitigate market power
concerns. Allegheny Energy committed to relinquishing
control of the 570 MW Cheswick, Pennsylvania, generating
station through at least June 30, 2000 and, in the event that
the Midwest ISO has not eliminated pancaked transmission
rates by June 30, 2000, Allegheny Energy could be required to
divest up to 2,500 MW of generation, if the PUC were to so
order.
In a letter to Allegheny Energy dated July 28, 1998, DQE
stated that its Board of Directors determined that DQE was
not required to proceed with the merger under present
circumstances, referring to the PUC's Orders of July 23, 1998
(regarding the PUC's approval of the merger described above),
and May 29, 1998 (regarding the restructuring plan of the
Company described in Note 5 below). DQE took the position
that the findings of both Orders constitute a material
adverse effect under the Agreement and
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Plan of Merger and invited Allegheny energy to agree promptly
to terminate the merger agreement by mutual consent. DQE
asserted that the findings in the PUC Orders will result in a
failure of the conditions to DQE's obligation to consummate
the merger. DQE indicated that if Allegheny Energy was not
amenable to a consensual termination, DQE would terminate the
agreement unilaterally not later than October 5, 1998 if
circumstances did not change sufficiently to remedy the
adverse effects DQE stated were associated with the PUC
Orders. In a letter dated July 30, 1998, Allegheny Energy
informed DQE that DQE's allegations were incorrect, that the
Orders do not constitute a material adverse effect, that
Allegheny Energy remains committed to the merger, and that if
DQE prevents completion of the merger, Allegheny Energy would
pursue all remedies available to protect the legal and
financial interests of Allegheny Energy and its shareholders.
Allegheny Energy has also notified DQE that its letter and
other actions constitute a material breach of the merger
agreement by DQE.
On September 16, 1998, the Federal Energy Regulatory
Commission (FERC) approved Allegheny Energy's merger with DQE
with conditions that were acceptable to Allegheny Energy.
The principal condition is divestiture of the Cheswick
Generating Station which enhances the proposal initially made
by Allegheny Energy and DQE to mitigate market power
concerns.
On October 5, 1998, DQE notified Allegheny Energy that it had
decided to terminate the merger. In response, Allegheny
Energy filed with the United States District Court for the
Western District of Pennsylvania on October 5, 1998, a
complaint for specific performance of the merger agreement
or, alternatively, damages and motions for a temporary
restraining order and preliminary injunction against DQE.
On October 28, 1998, the District Court denied Allegheny
Energy's motions for a temporary restraining order and
preliminary injunction. The District Court did not rule on
the merits of the complaint for specific performance or
damages. On October 30, 1998, Allegheny Energy appealed the
District Court's order to the United States Court of Appeals
for the Third Circuit. Allegheny Energy cannot predict the
outcome of the litigation between it and DQE.
All of the Company's incremental costs of the merger process
($7.6 million through September 30, 1998) are being deferred.
The accumulated merger costs will be written off by the
Company when the merger occurs, or if it is determined that
the merger will not occur.
5. In December 1996, Pennsylvania enacted the Electricity
Generation Customer Choice and Competition Act (Customer
Choice Act) to restructure the electric industry in
Pennsylvania to create retail access to a competitive
electric energy generation market. On August 1, 1997, the
Company filed with the PUC a comprehensive restructuring plan
to implement full customer choice of electric generation
suppliers as required by the Customer Choice Act. The filing
included a plan for recovery of transition costs (sometimes
referred to as stranded costs) through a Competitive
Transition Charge (CTC).
Transition costs are costs incurred under a regulated
environment, which are not expected to be recoverable in the
transition to a competitive market. The amount of transition
costs has been a key issue in the restructuring proceedings.
Since the installed costs of utility
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facilities are known, the key variable in transition cost
determinations in Pennsylvania was the projection of market
prices of electricity in future periods. The Company's
restructuring plan filing included its determination of its
transition costs based on its projection of future market
prices. West Penn's recoverable transition costs were
limited to $1.2 billion by rate caps mandated by the Customer
Choice Act.
On May 29, 1998, the PUC issued an Order authorizing the
Company recovery of approximately $525 million in transition
costs, with a return, based on alternative projections of
future market prices. On June 26, 1998, the PUC denied,
except for minor corrections, a request by the Company for
reconsideration of the May 29 Order. On that same day, the
Company filed a formal appeal in state court and an action in
federal court challenging the PUC's restructuring Order. The
Company also filed an original jurisdiction action in state
court. While pursuing its litigation, the Company has
participated in PUC-sponsored settlement discussions with
interested parties regarding issues related to the
restructuring Order.
On November 4, 1998, the PUC tentatively approved an
agreement between the Company and intervenors to settle the
restructuring proceeding. The settlement agreement includes
the following provisions:
* Agreement by the parties to withdraw all litigation related
to the Pennsylvania deregulation proceedings.
* Establishment of an average shopping credit of 3.16 cents
per kilowatt-hour in 1999 for the Company's customers who shop
for the generation portion of electricity services.
* Two-thirds of the Company's customers will have the option
of selecting a generation supplier on January 2, 1999, with all
customers able to shop on January 2, 2000.
* Provides for a 2.5 percent rate decrease (about $25 million)
throughout 1999, accomplished by an equal percentage decrease for
each rate class.
* Provides that customers will have the option of buying
electricity from the Company at capped generation rates through
2008, and that transmission and distribution rates are capped
through 2005, except that the capped rates are subject to
increases prescribed in the Public Utility Code, including
prudent increases in power purchase costs.
* Prohibits complaints challenging the Company's regulated
transmission and distribution rates through 2005.
* Provides about $16 million of the Company's funding for the
development and use of renewable energy and clean energy
technologies, energy conservation, energy efficiency, etc.
* Permits recovery of $670 million in transition costs over 10
years beginning in January 1999 for the Company. In the event
that the merger of Allegheny Energy, Inc. and DQE, Inc. is
consummated, the transition costs will be adjusted to $630
million plus a regulated return to provide a sharing of merger
synergy savings with customers.
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* Allows for income recognition of transition cost recovery in
the earlier years of the transition period to reflect the PUC's
projections that electricity market prices are lower in the
earlier years.
* Grants the Company's application to issue bonds to
"securitize" up to $670 million (or $630 million in the event of
the merger) in transition costs and to provide 75 percent of the
associated savings to customers with 25 percent to shareholders.
* Authorizes the transfer of the Company's generating assets
to a non-regulated corporate entity at book value and the
unregulated business received authorization, subject to a code of
conduct, to sell generating capacity and energy in unregulated
markets.
* If the Company is forced to divest some generating assets or
chooses to divest all of its generation before 2002, the CTC will
be adjusted, either up or down, based on the results of such
divestiture.
Pursuant to PUC orders, including the tentatively approved
settlement agreement, starting in 1999 the Company will
unbundle its rates to reflect separate prices for the
generation charge, the CTC, and transmission and distribution
charges. While generation will be open to competition, the
Company will continue to provide regulated transmission and
distribution services to customers in its service area at PUC
and FERC regulated rates, and will be the electricity
provider of last resort (PLR) for those customers who decide
not to choose another electricity supplier.
As stated above, the Company made its filing concerning its
transition cost requirements based on its early 1997
projection of market prices. The PUC issued its May 29, 1998
Order to the Company, as well as its 1998 orders to all other
Pennsylvania electric utilities, based on alternative
projections. Current prices, which the Company believes are
being influenced, among other things, by price volatility in
the summer of 1998, are equal to and in some cases slightly
higher than the projections adopted by the PUC in its
deregulation orders issued to the Company and other utilities
in Pennsylvania. If the PUC's projections are correct, the
Company believes that the transition costs provided will be
sufficient to permit it to recover its embedded costs, with a
return, during the transition from regulation to deregulation
of electricity generation.
The terms of the settlement will require a charge to earnings
in the fourth quarter of about $55-60 million ($33-36 million
after tax) for the 1999 one-year rate decrease of about $25
million, the funding of renewable energy, etc., of about $15
million and an adjustment of about $15-20 million to the
amount of the extraordinary charge recorded in the second
quarter of 1998.
The Company anticipates the PUC tentative approval of the
settlement agreement will become final and nonappealable
before the end of 1998.
6. As a result of the PUC Order described in Note 5 above, the
Company has determined that it is required to discontinue the
application of Statement of Financial Accounting Standards
(SFAS) No. 71 for electric generation operations and to adopt
SFAS No. 101, "Accounting for the Discontinuation
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of Application of SFAS No. 71." In doing so, the Company
determined that under the provisions of SFAS No. 101 an
extraordinary charge of $450.6 million ($265.4 million after
taxes) was required to reflect a write-off of certain
disallowances in the PUC's Order. The write-off, recorded in
June 1998, reflects adverse power purchase commitments and
deferred costs that are not recoverable from customers under
the PUC's Order as follows:
(Millions of Dollars)
AES Beaver Valley nonutility generation contract $201.4
AGC pumped-storage capacity contract 177.2
Other 72.0
Total $450.6
In 1985, the Company entered into a contract with AES
Corporation for the purchase of energy from AES's Beaver
Valley generating plant in Pennsylvania pursuant to the
requirements of the Public Utility Regulatory Policies Act of
1978 (PURPA) at prices then determined under the Act.
The Company owns 45% of AGC, which owns an undivided 40%
interest in the 2,100 MW pumped-storage hydroelectric station
in Bath County, Virginia. The Company buys AGC's capacity in
the station priced under a cost of service formula wholesale
rate schedule approved by the FERC.
Under both of these contracts, the Company has purchase
commitments at costs in excess of the market value of energy
from the plants. Because of utility restructuring under the
Customer Choice Act, these commitments have been determined
to be adverse purchase commitments requiring accrual as loss
contingencies pursuant to SFAS No. 5, "Accounting for
Contingencies." The extraordinary charge for these contracts
is the net result of such excess cost accruals (recorded in
June as adverse power purchase commitments) less estimated
revenue recoveries authorized in the PUC Order (recorded in
June 1998 as regulatory assets) as follows:
AES AGC
Beaver Valley Bath County
(Millions of Dollars)
Projected costs in excess of market value
of energy $351.5 $234.4
Estimated recovery 150.1 57.2
Net unrecoverable extraordinary charge $201.4 $177.2
The other $72.0 million of extraordinary charges represents
$55.0 million of deferred unrecovered expenditures for
previous PURPA buyouts, $15.4 million for an abandoned
generating plant, and $1.6 million of other generation-
related regulatory assets.
As described in Note 5 above, the PUC issued a tentative
Order on November 4, 1998, tentatively approving a settlement
agreement between the Company and parties to its
restructuring proceedings in Pennsylvania. As a result, the
Company in the fourth quarter expects to increase the amount
of the write-off by about $15-20 million to reflect the
agreement provision that future recoveries should be
allocated first to return and then to cost recovery,
resulting in a decrease to regulatory assets recorded in June
1998.
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The Consolidated Balance Sheet includes the amounts listed
below for generation assets not subject to SFAS 71.
September December
1998 1997
(Thousands of Dollars)
Property, plant and equipment at
original cost $1,744,436 $1,775,661
Amounts under construction included above 39,618 51,715
Accumulated depreciation (806,707) (786,545)
7. In June 1997, the Financial Accounting standards Board (FASB)
issued SFAS No. 131, "Disclosures about Segments of an
Enterprise and Related Information," to establish standards
for reporting information about operating segments in
financial statements. The Company continues to review this
standard for further potential effect on the Company's
financial statement disclosures.
In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," to establish
accounting and reporting standards for derivatives. The new
standard requires recognizing all derivatives as either
assets or liabilities on the balance sheet at their fair
value and specifies the accounting for changes in fair value
depending upon the intended use of the derivative. The new
standard is effective for fiscal years beginning after June
15, 1999. The Company expects to adopt SFAS No. 133 in the
first quarter of 2000. The Company is in the process of
evaluating the impact of SFAS No. 133.
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WEST PENN POWER COMPANY AND SUBSIDIARIES
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1998
WITH THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1997
The Notes to Consolidated Financial Statements and
Management's Discussion and Analysis of Financial Condition and
Results of Operations in the Company's Annual Report on Form 10-K
for the year ended December 31, 1997 should be read in
conjunction with the following management's discussion and
analysis information.
Factors That May Affect Future Results
This Management's Discussion and Analysis of Financial
Condition and Results of Operations contains forecast information
items that are "forward-looking statements" as defined in the
Private Securities Litigation Reform Act of 1995. These include
statements with respect to deregulation activities and movements
toward competition in Pennsylvania and the DQE, Inc. (DQE) merger
as well as results of operations. All such forward-looking
information is necessarily only estimated. There can be no
assurance that actual results will not materially differ from
expectations. Actual results have varied materially and
unpredictably from past expectations.
Factors that could cause actual results to differ
materially include, among other matters, electric utility
restructuring, including the ongoing state and federal
activities; potential Year 2000 operation problems; developments
in the legislative, regulatory, and competitive environments in
which the Company operates, including regulatory proceedings
affecting rates charged by the Company; environmental legislative
and regulatory changes; future economic conditions; developments
relating to the proposed merger with DQE, including expenses that
may be incurred in litigation; and other circumstances that could
affect anticipated revenues and costs such as significant
volatility in the market price of wholesale power, unscheduled
maintenance or repair requirements, weather, and compliance with
laws and regulations.
Significant Events in the First Nine Months of 1998
* Merger with DQE
In a letter to Allegheny Energy dated October 5, 1998,
DQE stated that it had decided to terminate the merger. In
response, Allegheny Energy filed with the United States District
Court for the Western District of Pennsylvania on October 5, 1998
a complaint for specific performance of the merger agreement, or
in the alternative, damages, and also filed a request for a
temporary restraining order and preliminary injunction against
DQE. See Note 4 to the Consolidated Financial Statements for
more information about the merger. Allegheny Energy believes
that DQE's basis for seeking to terminate the merger is without
merit. Accordingly, Allegheny Energy continues to seek
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the remaining regulatory approvals from the Department of Justice
and the Securities and Exchange Commission. It is not likely
either agency will act on the requests unless Allegheny Energy
obtains judicial relief requiring DQE to move forward. Allegheny
Energy cannot predict the outcome of the litigation between it
and DQE.
* Pennsylvania Deregulation
On November 4, 1998, the Pennsylvania Public Utility
Commission (PUC) tentatively approved an agreement between the
Company and intervenors to settle the restructuring proceeding
related to legislation in Pennsylvania to provide customer choice
of electric supplier and deregulate electricity generation. See
Notes 5 and 6 to the Consolidated Financial Statements for
details of the settlement agreement and other information about
the deregulation process.
Under the deregulation legislation, all utilities were
provided an opportunity to recover their transition (or stranded)
costs, as further described in Note 5. As also further described
in Note 5, the determination of transition costs relied heavily
on projections of future market prices of electricity. The
Company's transition cost recovery claim of $1.2 billion was the
subject of significant disagreement and debate, as were the
transition cost claims of the other Pennsylvania utilities.
Under the tentatively approved settlement agreement, the
Company has been authorized to recover $670 million of transition
costs ($630 million if the DQE merger is consummated, see Note
5), plus a return, and to record the income therefrom in the
earlier years of the transition period when electricity market
prices are assumed to be lowest. Additionally, as described in
Note 6, the Company will have written off as an extraordinary
item in 1998 about $465-470 million of costs which it deemed not
recoverable under the deregulation process. $451 million of this
amount was recorded in the second quarter.
Under the terms of the settlement agreement, two-thirds
of the Company's customers will be permitted to choose an
alternate generation supplier beginning in January 1999. All of
the Company's customers can do so beginning in January 2000.
They can also choose to remain as a West Penn customer at the
Company's capped generation rates, or to alternate back and
forth. Under the law, all electric utilities, including the
Company, retain the responsibility of electricity provider of
last resort (PLR) to all customers in their respective franchise
territories that do not choose an alternate supplier.
Beginning in 1999, in Pennsylvania, electricity supply
and electricity delivery will be two separate businesses. The
transmission and distribution "wires" business will be under
traditional regulated rate making, and the electricity generation
business will be deregulated with pricing determined by the
market place. The "wires" business will have the PLR
responsibility and will generally obtain its electricity supply
from the market primarily by competitive bidding, including bids
from an affiliated generation business. The generation business
will be free to sell, subject to a code of conduct, the Company's
generation capacity and energy in the open wholesale and retail
markets, except that it is not permitted to sell at retail in the
Company's franchise territory through the year 2003.
<PAGE>
- 15 -
The settlement agreement permits the transfer of the
Company's generation assets to the unregulated generation
business at the Company's embedded cost book values.
Current electricity supply prices are below the level
required to produce results of operations equal to that obtained
in the regulated environment primarily because, in the Company's
opinion, of abundant generation from other states, as well as in
Pennsylvania, to supply the limited market of Pennsylvania. The
Company believes that the utilities in states that are not yet
deregulated are now selling and will continue to sell electricity
into Pennsylvania at marginal cost while their fixed costs are
recovered from franchise customers in their home state
territories.
The PUC's projections of electricity market prices
recognized this possibility, among others, and accordingly
assumed depressed prices in the earlier years of the transition
process from regulation to deregulation. The projections further
assumed that prices would increase in later years due to
increasing demand from deregulation in other states and normal
increases in customer demand, particularly because of
competition.
The forward-looking statements above are provided to
describe the Company's plans and its reasoning for actions taken.
Of necessity, its plans are based on assessments of future
events. There can be no assurance that actual results will not
materially differ from expectations.
Review of Operations
EARNINGS SUMMARY
Consolidated net income for the third quarter of 1998 was
$42.8 million compared with $34.3 million in the corresponding
1997 period. For the first nine months of 1998, consolidated
income before the extraordinary charge was $108.1 million
compared with $93.2 million for the corresponding 1997 period.
The increase in consolidated net income in the third quarter was
primarily due to increased kilowatt-hour (kWh) sales to retail
customers and increased bulk power transactions. The increase in
consolidated income before the extraordinary charge in the first
nine months of 1998 was primarily due to increased bulk power
transactions, a reduction in the Company's depreciation expense
reflecting a change in the retirement dates for the Mitchell
Power Station and the Pleasants Power Station scrubbers, and
continuing efforts to reduce operations and maintenance (O&M)
expense. See Note 6 to the Consolidated Financial Statements for
information about the extraordinary charge.
<PAGE>
- 16 -
SALES AND REVENUES
Total operating revenues for the third quarter and first
nine months of 1998 and 1997 were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Operating revenues:
Bundled retail sales $242.4 $237.4 $707.8 $721.6
Unbundled retail sales 4.6 - 10.5 -
Wholesale and other* 19.3 17.2 56.1 51.0
Bulk power and transmission
services sales 22.0 12.1 57.6 29.4
Total operating revenues $288.3 $266.7 $832.0 $802.0
*Excludes street lighting sales
which are included in bundled
retail sales $1.8 $1.7 $5.5 $5.2
The increase in bundled retail sales (full service sales
to retail customers) for the third quarter is primarily due to
increased kWh sales to retail customers which was a result of
third quarter summer weather which was 55% warmer than 1997 and
8% warmer than normal as measured in cooling degree days. Retail
sales include sales to residential, commercial, industrial and
street lighting customers. The decrease in bundled retail sales
for the nine months ended September 30, 1998 is due in part to
reduced kWh sales to residential customers due to the mild first
quarter winter weather. The 1998 first quarter winter weather
was 15% warmer than 1997 and 22% warmer than normal as measured
in heating degree days. The decrease in bundled retail sales
revenues was also due in part to the Customer Choice Act in
Pennsylvania. As part of the Customer Choice Act, all utilities
in Pennsylvania were required to administer retail access pilot
programs under which customers representing 5% of the load of
each rate class would choose a generation supplier other than
their own local franchise utility. As a result, 5% of previously
fully bundled customers chose to participate in the Pennsylvania
pilot program and were required to buy energy from another
supplier of their choice. The pilot program began on November 1,
1997 and will continue through December 31, 1998. Unbundled
retail sales revenues represent transmission and distribution
revenues from Pennsylvania pilot customers who chose another
supplier to provide their energy needs.
To assure participation in the pilot program, pilot
participants are receiving an energy credit from their local
utility and a price for energy pursuant to an agreement with an
alternate supplier. The credit established by the PUC is
artificially high, with the result that the Company could suffer
a revenue loss of up to $10 million in 1998 for the pilot. The
PUC has approved the Company's pilot compliance filing and thus
has indicated its intent to treat the revenue losses as a
regulatory asset. Wholesale and other revenues include an
accrual of such revenue losses, as well as sales to wholesale
customers (cooperatives and municipalities that own their own
distribution systems and buy all or part of their bulk power
needs from the Company under regulation by the FERC) and non-kWh
revenues. The increase in
<PAGE>
- 17 -
wholesale and other revenues was due primarily to $2.5 million
and $5.8 million for the three and nine months ended September
30, 1998, respectively, of deferred net revenue losses recorded
as a regulatory asset to offset revenue losses suffered as a
result of the pilot.
Bulk power transactions consist of sales of power to
power marketers and other utilities. Revenues from bulk power
transactions consist of the following items:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Revenues:
Transmission services sales
to nonaffiliated companies $ 8.0 $ 4.4 $16.1 $13.7
Bulk power 14.0 7.7 41.5 15.7
Total bulk power trans-
actions, net $22.0 $12.1 $57.6 $29.4
The increase in revenues from bulk power was due to
increased sales which occurred primarily in the month of June as
a result of warm weather which increased the demand and price for
energy. The increase in revenues from transmission services was
due to an increase in price.
In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level. These events included extremely hot weather and
Midwest generation unit outages and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The potential exists for such volatility to significantly
affect the Company's operating results. The impact on such
results, either positively or negatively, depends on whether the
Company is a net buyer or seller of electricity during such
periods.
OPERATING EXPENSES
Fuel expenses for both the three and nine months ended
September 30, 1998, increased 3% primarily due to a 1% and 4%
increase in kWhs generated, respectively. Prior to May 1, 1997,
the Company's fuel expenses were primarily subject to deferred
power cost accounting procedures to match fuel and energy cost
adjustment clause revenues, with the result that changes in fuel
expenses until then had little effect on consolidated net income.
After May 1, 1997, the Company assumed the risks and benefits of
changes in fuel and purchased power costs and sales of
transmission and bulk power.
Purchased power and exchanges, net, represents power
purchases from and exchanges with other companies and purchases
from qualified facilities under the Public Utility Regulatory
Policies Act of 1978 (PURPA), capacity charges paid to Allegheny
Generating Company (AGC), an affiliate partially owned by the
Company, and other transactions with affiliates made pursuant to
<PAGE>
- 18 -
a power supply agreement whereby each company uses the most
economical generation available in the Allegheny Energy System at
any given time, and consists of the following items:
Three Months Ended Nine Months Ended
September 30 September 30
1998 1997 1998 1997
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
From PURPA generation* $14.7 $14.9 $47.5 $48.8
Other 9.7 4.4 16.7 11.6
Power exchanges, net (1.4) (1.2) (.7) .1
Affiliated transactions:
AGC capacity charges 7.7 7.9 23.9 25.5
Energy and spinning reserve
charges 1.1 .8 2.8 2.4
Purchased power and
exchanges, net $31.8 $26.8 $90.2 $88.4
*PURPA cost (cents per kWh) 5.8 5.8 5.8 6.0
The increases in other purchased power resulted primarily
from increased purchases for sales. As described earlier, an
increase in price caused by volatility in the spot prices for
electricity at the wholesale level in June as well as in the
third quarter of 1998 also contributed to the increases.
The decrease in other operation expense for the three
months ended September 30, 1998 was due primarily to decreased
provisions for uninsured claims ($2.1 million) resulting from a
reevaluation of existing claims, litigation expenses related to a
PURPA project which were incurred in the corresponding period
ended September 30, 1997 ($1.5 million), and a decrease in
transmission services purchased from affiliated companies ($.9
million). The decrease for the nine months ended September 30,
1998 was due primarily to litigation expenses related to a PURPA
project which were incurred in the corresponding period ended
September 30, 1997 ($2.8 million) and a $2 million decrease to
expense related to a reversal of a portion of the remaining
restructuring liability. The decrease in the nine months ended
September 30, 1998, was offset in part by increased expenses
related to the Pennsylvania pilot and competition ($1.4 million)
and increases in salaries and wages. The Company expects to
incur increased advertising and other sales-related expenditures
to enhance nonutility energy sales.
Maintenance expenses decreased $6.4 million for the nine
months ended September 30, 1998 because of a management program
to postpone such expenses for the year in response to limited
sales growth in the first quarter due to the warm winter weather.
The Company is postponing these expenses primarily by extending
the time between maintenance outages. The nine months ended
September 30, 1998 period includes approximately $1.7 million of
incremental transmission and distribution (T&D) expenses
primarily incurred in the second quarter for two unusually strong
thunderstorms in the Company's service territory. Maintenance
expenses represent costs incurred to maintain the power stations,
the T&D system, and general plant, and reflect routine
maintenance of equipment and rights-of-way as well as planned
major repairs and unplanned expenditures, primarily from forced
outages at the power
<PAGE>
- 19 -
stations and periodic storm damage on the T&D system. Variations
in maintenance expense result primarily from unplanned events and
planned major projects, which vary in timing and magnitude
depending upon the length of time equipment has been in service
without a major overhaul and the amount of work found necessary
when the equipment is dismantled.
Depreciation expense decreased $2.1 million and $4.2
million in the third quarter and first nine months of 1998,
respectively, reflecting a change in the retirement dates for the
Mitchell Power Station and the Pleasants Power Station scrubbers.
The increases in federal and state income taxes for the
three and nine months ended September 30, 1998 were primarily due
to increases in income before taxes, exclusive of other income
which is reported net of taxes.
The decreases in allowance for other than borrowed funds
used during construction of $.6 million and $1.2 million for the
three and nine months ended September 30, 1998, respectively,
reflect a shift in the rate calculated under the Federal Energy
Regulatory Commission formula to lower cost short-term debt
financing. The allowance for borrowed funds used during
construction component of the formula receives greater weighting
when short-term debt increases. The decreases also reflect
adjustments of prior periods.
The decreases in other income, net, of $4.5 million and
$7.7 million for the three and nine months ended September 30,
1998, respectively, were primarily due to an interest refund on a
tax-related contract settlement in the three and nine months
ended September 30, 1997, received by the Company's subsidiary,
AGC. The nine months ended September 30, 1997 period also
reflected a sale of land and timber by West Virginia Power and
Transmission Company, a subsidiary of West Penn.
The decreases in interest on long-term debt of $1.6
million and $2.2 million for the three and nine months ended
September 30, 1998, respectively, result from reduced long-term
debt and lower interest rates.
Other interest expense reflects changes in the levels of
short-term debt maintained by the Company throughout the year, as
well as the associated rates.
Financial Condition
The Company's discussion on Financial Condition,
Requirements, and Resources and Significant Continuing Issues in
its Annual Report on Form 10-K for the year ended December 31,
1997 should be read in conjunction with the following
information.
In the normal course of business, the Company is subject
to various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.
See Notes 4, 5, and 6 to the Consolidated Financial Statements
for information about merger activities and the Pennsylvania
Customer Choice Act.
<PAGE>
- 20 -
* Year 2000 Readiness Disclosure
As the year 2000 approaches, most organizations,
including the Company, could experience serious problems related
to software and various equipment with embedded chips which may
not properly recognize calendar dates. To minimize such
problems, the Company and its affiliates in the Allegheny Energy
System (the System) are proceeding with a comprehensive effort to
continue operations without significant problems in the Year 2000
(Y2K) and beyond. An Executive Task Force is coordinating the
efforts of 23 separate Y2K Teams, representing all business and
support units in the System.
The System has segmented the Y2K problem into the
following components:
* Computer software
* Embedded chips in various equipment
* Vendors and other organizations on which the System relies
for critical materials and services.
The System's effort for each of these three components
includes assessment of the problem areas, remediation, testing
and contingency plans for critical functions for which
remediation and testing are not possible or which do not provide
reasonable assurance.
The Company has expended significant time and money over
the past several years on upgrading and replacing its large and
complex computer systems and software to achieve greater
efficiency as well as Y2K readiness. As a result, the Company
expects these systems to achieve a state of Y2K readiness on or
about March 31, 1999, subject to continuing review and testing.
Various equipment used by the System includes thousands
of embedded chips. Most are not date sensitive, but identifying
those which are, and which are critical to operations, is a labor
intensive task. Identification, remediation, and testing in many
cases require the assistance of the original equipment
manufacturers. Even they frequently cannot state with certainty
if the chips they used are date sensitive. The System's review
calls for the inventory and assessment of suspect embedded chips
in critical systems to be completed by December 31, 1998, with
remediation initiated as needs are identified, and with 1999 to
complete remediation and testing.
Integrated electric utilities are uniquely reliant on
each other to avoid, in a worst case situation, cascading failure
of the entire electrical system. The System is working with the
Edison Electric Institute (EEI), the Electric Power Research
Institute (EPRI), the North American Electric Reliability Council
(NERC), and the East Central Area Reliability Agreement group
(ECAR) to capitalize on industry-wide experiences and to
participate in industry-wide testing and contingency planning.
The effort with regard to vendors and other organizations is to
obtain reasonable assurance of their readiness to conduct
operations in the year 2000 and beyond and, where reasonable
assurance is questionable, to develop contingency plans. Of
particular concern are telecommunications systems which are
integral to the System's electricity production and distribution
operations. While the System will develop contingency plans for
critical telecommunication needs, there can be no assurance that
the contingency plans could cope with a significant failure of
major telecommunication systems.
<PAGE>
- 21 -
The Company is aware of the importance of electricity to
its service territory and its customers and is using its best
efforts to avoid any serious Y2K problems. Despite the System's
best efforts, including working with internal resources, external
vendors, and industry associations, the Company cannot guarantee
that it will be able to conduct all of its operations without Y2K
interruptions. To the extent that any Y2K problem may be
encountered, the Company is committed to resolution as
expeditiously as possible to minimize the effect.
Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents an internal labor intensive effort of assessment,
remediation, and component testing for noncompliant embedded
chips in equipment, and a substantial labor intensive effort of
multiple systems testing, documentation, and working with other
parties. While outside contractors and equipment vendors will be
employed for some of the work, the Company believes it must rely
on System employees for most of the effort because of their
experience with systems and equipment. The Company currently
estimates that its incremental expenditures for the remaining Y2K
effort will not exceed $7 million.
The descriptions herein of the elements of the Company's
Y2K effort are forward-looking statements as defined in the
Private Securities Litigation Reform Act of 1995. Of necessity,
this effort is based on estimates of assessment, remediation,
testing and contingency planning activities and dates for
perceived problems not yet identified. There can be no assurance
that actual results will not materially differ from expectations.
* Environmental Issues
The Environmental Protection Agency (EPA) issued its
final regional NOx State Implementation Plan (SIP) call rule on
September 24, 1998. EPA's SIP call rule finds that 22 eastern
states (including Maryland, Pennsylvania, and West Virginia) and
the District of Columbia are all contributing significantly to
ozone nonattainment in downwind states. The final rule declares
that this downwind nonattainment will be eliminated (or
sufficiently mitigated) if the upwind states reduce their NOx
emissions by an amount that is precisely set by EPA on a state-by-
state basis. The final SIP call rule requires that all state-
adopted NOx reduction measures must be incorporated into SIPs by
September 24, 1999 and must be implemented by May 1, 2003. The
Company's compliance with these requirements would require the
installation of post-combustion control technologies on most, if
not all, of its power stations at a cost of approximately $145
million. The Company continues to work with other coal-burning
utilities and other affected constituencies in coal-producing
states to challenge this EPA action.
The Company previously reported that the EPA had
identified the Company and its regulated affiliates and
approximately 875 others as potentially responsible parties in a
Superfund site subject to cleanup. A final determination has not
been made for the Company's share of the remediation costs based
on the amount of materials sent to the site. The Company has
also been named as a defendant along with multiple other
affiliated and nonaffiliated defendants in pending asbestos cases
involving
<PAGE>
- 22 -
one or more plaintiffs. The Company believes that provisions for
liabilities and insurance recoveries are such that final
resolution of these claims will not have a material effect on its
financial position.
* Electric Energy Competition
Allegheny Energy is working actively within its states to
advance customer choice. However, Allegheny Energy believes that
federal legislation is necessary to ensure that electric
restructuring is implemented consistently across state and
regional boundaries so that all electric customers have an equal
opportunity to benefit from competition and customer choice by a
date certain. Federal legislation is also needed to remove
barriers to competition, including the repeal of both the Public
Utility Holding Company Act of 1935 and PURPA. Allegheny Energy
has been working with Congress to advance these goals.
<PAGE>
- 23 -
WEST PENN POWER COMPANY AND SUBSIDIARIES
Part II - Other Information to Form 10-Q
for Quarter Ended September 30, 1998
ITEM 1. LEGAL PROCEEDINGS
On October 5, 1998, Allegheny Energy, Inc. (Allegheny
Energy), filed a lawsuit in the United States District Court for
the Western District of Pennsylvania against DQE, Inc. (DQE) for
specific performance of the Agreement and Plan of Merger among
DQE, Allegheny Power System, Inc., and AYP Sub, Inc., dated as of
April 5, 1997 (the "Merger Agreement"), or for damages.
Allegheny Energy also filed motions for a temporary restraining
order and preliminary injunction against DQE. On October 28,
1998, the court denied Allegheny Energy's motions for a temporary
restraining order and preliminary injunction. On October 30,
1998, Allegheny Energy appealed the order to the Third Circuit
Court of Appeals. Allegheny Energy cannot predict the outcome of
the litigation between it and DQE.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(27) Financial Data Schedule
(b) The Company filed 8-K's on July 27, 1998, October 8, 1998,
and November 6, 1998.
Signature
Pursuant to the requirements of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly
authorized.
WEST PENN POWER COMPANY
/s/ T. J. KLOC
T. J. Kloc, Controller
(Chief Accounting Officer)
November 16, 1998
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