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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 June 30, 1998
Commission File Number 1-5164
MONONGAHELA POWER COMPANY
(Exact name of registrant as specified in its charter)
Ohio 13-5229392
(State of Incorporation) (I.R.S. Employer Identification No.)
1310 Fairmont Avenue, Fairmont, West Virginia 26554
Telephone Number - 304-366-3000
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 August 14, 1998, 5,891,000 shares of the Common Stock ($50
par value) of the registrant were outstanding, all of which are
held by Allegheny Energy, Inc., the Company's parent.
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MONONGAHELA POWER COMPANY
Form 10-Q for Quarter Ended June 30, 1998
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Statement of income - Three and six months ended
June 30, 1998 and 1997 3
Balance sheet - June 30, 1998
and December 31, 1997 4
Statement of cash flows - Six months ended
June 30, 1998 and 1997 5
Notes to financial statements 6-9
Management's discussion and analysis of financial
condition and results of operations 10-18
PART II--OTHER INFORMATION 19
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MONONGAHELA POWER COMPANY
Statement of Income
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES:
<S> <C> <C> <C> <C>
Residential $ 44,244 $ 43,923 $ 96,416 $ 99,963
Commercial 29,701 27,705 59,666 57,958
Industrial 51,543 47,570 101,671 95,362
Wholesale and other, including affiliates 20,445 20,695 43,390 45,232
Bulk power transactions, net 7,841 4,185 10,903 8,366
Total Operating Revenues 153,774 144,078 312,046 306,881
OPERATING EXPENSES:
Operation:
Fuel 34,827 32,529 69,664 67,660
Purchased power and exchanges, net 23,291 24,350 48,301 50,197
Deferred power costs, net (1,269) (5,076) (7,940) (8,883)
Other 20,884 17,383 42,203 35,761
Maintenance 17,753 17,851 35,251 35,809
Depreciation 14,730 14,315 29,490 28,663
Taxes other than income taxes 10,255 9,732 21,777 20,049
Federal and state income taxes 9,216 9,293 21,855 23,444
Total Operating Expenses 129,687 120,377 260,601 252,700
Operating Income 24,087 23,701 51,445 54,181
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 106 153 358 289
Other income, net 1,543 1,695 3,081 3,353
Total Other Income and Deductions 1,649 1,848 3,439 3,642
Income Before Interest Charges 25,736 25,549 54,884 57,823
INTEREST CHARGES:
Interest on long-term debt 8,401 9,122 17,215 18,241
Other interest 817 436 1,835 1,195
Allowance for borrowed funds used during
construction (93) (183) (204) (343)
Total Interest Charges 9,125 9,375 18,846 19,093
NET INCOME $ 16,611 $ 16,174 $ 36,038 $ 38,730
</TABLE>
See accompanying notes to financial statements.
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MONONGAHELA POWER COMPANY
Balance Sheet
<TABLE>
<CAPTION>
June 30, December 31,
1998 1997
ASSETS: (Thousands of Dollars)
Property, Plant, and Equipment:
<S> <C> <C>
At original cost, including $47,593,000
and $55,588,000 under construction $ 1,977,978 $ 1,950,478
Accumulated depreciation (863,257) (840,525)
1,114,721 1,109,953
Investments:
Allegheny Generating Company - common stock at equity 44,141 53,888
Other 238 268
44,379 54,156
Current Assets:
Cash 1,464 1,686
Accounts receivable:
Electric service, net of $2,447,000 and $2,176,000
uncollectible allowance 59,955 68,143
Affiliated and other 19,107 10,917
Materials and supplies - at average cost:
Operating and construction 20,195 18,716
Fuel 19,260 15,885
Prepaid taxes 12,345 17,287
Other 10,890 3,559
143,216 136,193
Deferred Charges:
Regulatory assets 163,303 164,260
Unamortized loss on reacquired debt 18,338 14,338
Other 13,693 14,354
195,334 192,952
Total Assets $ 1,497,650 $ 1,493,254
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 294,550 $ 294,550
Other paid-in capital 2,441 2,441
Retained earnings 276,457 243,939
573,448 540,930
Preferred stock 74,000 74,000
Long-term debt and QUIDS 410,487 455,088
1,057,935 1,070,018
Current Liabilities:
Short-term debt 82,953 56,829
Long-term debt due within one year - 20,100
Notes payable to affiliates - 1,450
Accounts payable 6,250 5,910
Accounts payable to affiliates 20,195 5,804
Taxes accrued:
Federal and state income - 5,046
Other 13,658 18,935
Interest accrued 7,218 7,877
Other 8,583 13,470
138,857 135,421
Deferred Credits and Other Liabilities:
Unamortized investment credit 17,223 18,297
Deferred income taxes 248,116 235,291
Regulatory liabilities 16,252 16,973
Other 19,267 17,254
300,858 287,815
Total Capitalization and Liabilities $ 1,497,650 $ 1,493,254
</TABLE>
See accompanying notes to financial statements.
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MONONGAHELA POWER COMPANY
Statement of Cash Flows
<TABLE>
<CAPTION>
Six Months Ended
June 30
1998 1997
(Thousands of Dollars)
CASH FLOWS FROM OPERATIONS:
<S> <C> <C>
Net income $ 36,038 $ 38,730
Depreciation 29,490 28,663
Deferred investment credit and income taxes, net 8,730 9,939
Deferred power costs, net (7,940) (8,883)
Unconsolidated subsidiaries' dividends in excess of earnings 9,778 1,390
Allowance for other than borrowed funds used
during construction (358) (289)
Restructuring liability (236) (7,226)
Changes in certain current assets and
liabilities:
Accounts receivable, net (2) 2,452
Materials and supplies (4,854) (4,059)
Accounts payable 14,731 (3,274)
Taxes accrued (10,323) (7,478)
Other, net 3,834 (2,301)
78,888 47,664
CASH FLOWS FROM INVESTING:
Construction expenditures (less allowance for
equity funds used during construction) (34,764) (27,339)
CASH FLOWS FROM FINANCING:
Issuance of long-term debt 25,660 -
Retirement of long-term debt (91,160) (500)
Short-term debt, net 26,124 (13,792)
Notes payable to affiliates (1,450) -
Dividends on capital stock:
Preferred stock (2,519) (2,519)
Common stock (1,001) (5,655)
(44,346) (22,466)
NET CHANGE IN CASH (222) (2,141)
Cash at January 1 1,686 2,290
Cash at June 30 $ 1,464 $ 149
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $17,787 $18,331
Income taxes 19,750 16,540
</TABLE>
See accompanying notes to financial statements.
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MONONGAHELA POWER COMPANY
Notes to Financial Statements
1. The Company's Notes to Financial Statements in its Annual
Report on Form 10-K for the year ended December 31, 1997
should be read with the accompanying financial statements and
the following notes. With the exception of the December 31,
1997 balance sheet in the aforementioned annual report on
Form 10-K, the accompanying financial statements appearing on
pages 3 through 5 and these notes to financial statements are
unaudited. In the opinion of the Company, such financial
statements together with these notes contain all adjustments
necessary to present fairly the Company's financial position
as of June 30, 1998, the results of operations for the three
and six months ended June 30, 1998 and 1997, and cash flows
for the six months ended June 30, 1998 and 1997.
2. The Statement of Income reflects the results of past
operations and is not intended as any representation as to
future results. For purposes of the Balance Sheet and
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 27% 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 Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Thousands of Dollars)
Electric operating revenus $19,126 $20,408 $37,730 $40,624
Operation and maintenance
expense 1,542 1,471 2,495 2,756
Depreciation 4,242 4,284 8,468 8,568
Taxes other than income taxes 1,177 1,201 2,337 2,396
Federal income taxes 2,907 3,141 5,772 6,265
Interest charges 3,298 3,917 6,811 7,877
Other income, net (1) (1) (51) (1)
Net income $ 5,961 $ 6,395 $11,898 $12,763
The Company's share of the equity in earnings above was $1.6
million and $1.7 million for the three months ended June 30,
1998 and 1997, respectively, and $3.2 million and $3.4
million for the six months ended June 30, 1998 and 1997,
respectively, and was included in other income, net, on the
Statement of Income.
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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 ISO is the
regional transmission entity that will best serve the
interests of the Ohio customers of the Company and will best
mitigate the market power issue.
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, and
also offered to relinquish some generation in order to
mitigate market power concerns. Allegheny Energy committed
to relinquishing control of the 570 megawatts (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 may be required to divest up to 2,500 MW of
generation, subject to a PUC Order.
In a letter dated July 28, 1998 to Allegheny Energy, 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's Pennsylvania affiliate, West Penn Power Company
(West Penn) described in Note 5 below). DQE took the
position that the findings of both Orders constitute a
material adverse effect under the Agreement and 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
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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 will
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.
All of the Company's incremental costs of the merger process
($3.6 million through June 30, 1998) are being deferred. The
accumulated merger costs will be written off by the Company
when the merger occurs, or when 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. The Company's
Pennsylvania affiliate, West Penn, is subject to this Act.
On August 1, 1997, West Penn 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 stranded costs through a Competitive Transition Charge
(CTC).
On May 29, 1998, West Penn received a final order from the
PUC denying full recovery of its stranded cost claim. The
Order authorized recovery of $524 million in stranded costs,
with return, over the 1999 through 2005 period, of the
approximately $1.2 billion available for recovery under the
capped rates mandated by the Customer Choice Act.
On June 26, 1998, the PUC denied a request by West Penn for
reconsideration of the May 29, 1998 PUC Order on West Penn's
restructuring plan. Under the reconsideration Order, West
Penn would be allowed to collect $525 million ($.5 million
more than the previous Order) in stranded costs, with a
return, over seven years, starting in January 1999, through
the CTC. Although in its restructuring application, West
Penn had listed $1.6 billion in stranded costs, because of
capped rates, West Penn would be limited to $1.2 billion in
stranded cost recovery under the Customer Choice Act.
Stranded costs are costs incurred under a regulated
environment, which are not expected to be recoverable in a
competitive market. Actual recovery of such costs will
depend upon the market prices for electricity in future
periods and the number of West Penn customers who choose
other generation suppliers. The PUC Order on West Penn's
restructuring plan assumed significantly higher electricity
prices in future years than Allegheny Energy believed were
appropriate.
Allegheny Energy believes that the $525 million of stranded
costs recommended for recovery is contrary to legal
requirements and does not adequately reflect the potential
effects of competition on West Penn. On June 26, 1998, West
Penn filed a formal appeal in state court and an action in
federal court challenging the PUC's restructuring Order. On
July 23, 1998, West Penn also filed in the Commonwealth Court
of Pennsylvania a petition for a stay of the two-thirds, one-
third phase-in schedule ordered by the PUC. On August 5,
1998, West Penn withdrew its petition for stay without
prejudice based on a PUC agreement to offer settlement
discussions on issues related to the PUC's restructuring
Order.
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As a result of the PUC restructuring Order, West Penn 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 of Application of SFAS
No. 71." In doing so, West Penn has also determined that
under the provisions of SFAS No. 101 an extraordinary charge
of $450.6 million ($265.4 million after taxes) is required to
reflect a write-off of disallowances in the PUC's Order. The
write-off, recorded in June 1998 by West Penn, reflects
adverse power purchase commitments and deferred costs that
are not recoverable from customers under the PUC's Order.
6. In June 1998, the Financial Accounting Standards Board 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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MONONGAHELA POWER COMPANY
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF SECOND QUARTER AND SIX MONTHS ENDED JUNE 30, 1998
WITH SECOND QUARTER AND SIX MONTHS ENDED JUNE 30, 1997
The Notes to 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 states served by the Company 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 if DQE seeks to terminate the
merger agreement; 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 Six Months of 1998
* Merger with DQE
In a letter dated July 28, 1998 to Allegheny Energy, DQE
stated that its Board of Directors determined that DQE was not
required to proceed with the merger under present circumstances,
referring to the Pennsylvania Public Utility Commission (PUC)
Orders of July 23, 1998 and May 29, 1998. See Notes 4 and 5 to
the financial statements for more information about these Orders.
DQE took the position that the findings of both Orders constitute
a material adverse effect under the Agreement and Plan of Merger,
and invited Allegheny Energy to agree promptly to terminate the
merger agreement by mutual consent.
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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 will 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. Allegheny Energy believes that DQE's basis for seeking to
terminate the merger is without merit. Accordingly, Allegheny
Energy is continuing to seek the remaining regulatory approvals
from the Federal Energy Regulatory Commission (FERC), the
Department of Justice, and the Securities and Exchange
Commission. The Company cannot predict the outcome of the
requested approvals or of the differences between Allegheny
Energy and DQE.
* Pennsylvania Deregulation
On May 29, 1998, West Penn Power Company (West Penn), the
Company's Pennsylvania affiliate, received a final order from the
PUC denying full recovery of its stranded cost claim. The Order
authorized recovery of $524 million in stranded costs, with
return, over the 1999 through 2005 period, of the approximately
$1.2 billion available for recovery under the capped rates
mandated by the Customer Choice Act.
On June 26, 1998, the PUC denied a request by West Penn
for reconsideration of the May 29, 1998 PUC Order on West Penn's
restructuring plan. Under the reconsideration Order, West Penn
would be allowed to collect $525 million ($.5 million more than
the previous Order) in stranded costs, with a return over seven
years, starting in January 1999, through the Competitive
Transition Charge (CTC). Although in its restructuring
application, West Penn had listed $1.6 billion in stranded costs,
because of capped rates, West Penn would be limited to $1.2
billion in stranded cost recovery under the Customer Choice Act.
Stranded costs are costs incurred under a regulated environment
which are not expected to be recoverable in a competitive market.
Actual recovery of such costs will depend upon the market prices
for electricity in future periods and the number of West Penn
customers who choose other generation suppliers. The PUC Order
on West Penn's restructuring plan assumed significantly higher
electricity prices in future years than Allegheny Energy believed
were appropriate.
Allegheny Energy believes that the $525 million of
stranded costs recommended for recovery is contrary to legal
requirements and does not adequately reflect the potential
effects of competition on West Penn. On June 26, 1998, West Penn
filed a formal appeal in state court and an action in federal
court challenging the PUC's restructuring Order. On July 23,
1998, West Penn also filed in the Commonwealth Court of
Pennsylvania a petition for a stay of the two-thirds, one-third
phase-in schedule ordered by the PUC. On August 5, 1998, West
Penn withdrew its petition for stay without prejudice based on a
PUC agreement to offer settlement discussions on issues related
to the PUC's restructuring Order. Allegheny Energy cannot
predict the outcome of settlement discussions or the related
legal proceedings.
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* Trading Activities
In June and July 1998, certain events combined to produce
very 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 costs of purchased power and revenues from sales to
power marketers and other utilities, including transmission
services, are currently recovered from or credited to customers
under fuel and energy cost recovery procedures. The impact to
the fuel and energy cost recovery clauses, either positively or
negatively, depends on whether the Company is a net buyer or
seller of electricity during such periods. The impact of such
price volatility in June 1998 was insignificant to the Company.
Review of Operations
EARNINGS SUMMARY
Net income for the second quarter of 1998 was $16.6
million compared with $16.2 million in the corresponding 1997
period. For the first six months of 1998, net income was $36.0
million compared with $38.7 million for the corresponding 1997
period. The increase in second quarter 1998 earnings resulted
primarily from increased kilowatt-hour (kWh) sales to commercial
and industrial customers. The decrease in earnings for the first
six months of 1998 resulted primarily from a 4.2% decrease in
residential kWh sales resulting from the extremely mild winter
weather in 1998, increased allowances for uncollectible accounts,
and property insurance expense. The 1998 winter was 12% warmer
than 1997 and 19% warmer than normal as measured by heating
degree days and was the warmest in more than 100 years.
SALES AND REVENUES
Percentage changes in revenues and kWh sales by major
retail customer classes were:
Change from Prior Periods
Three Months Ended Six Months Ended
June 30 June 30
Revenues kWh Revenues kWh
Residential .7% (.7)% (3.5)% (4.2)%
Commercial 7.2 7.2 2.9 3.2
Industrial 8.4 11.9 6.6 10.2
Total 5.3% 7.8 % 1.8 % 4.7 %
The change in residential kWh sales, which are more
weather sensitive than the other classes, was due primarily to
changes in customer usage because of weather conditions. The
1998 first quarter winter weather was 12% warmer than 1997 and
19% warmer than normal as measured by heating degree days.
Commercial kWh sales are also affected by weather, but to a
lesser extent than residential. The increase in commercial kWh
sales in the three and six months ended periods reflects growth
in the number of customers
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as well as increased usage. The increase in industrial kWh sales
in both periods was due in part to increased kWh sales to a
customer with particularly large electricity requirements, and
also reflects continued economic growth in the service territory.
The changes in revenues from sales to residential,
commercial, and industrial customers resulted from the following:
Change from Prior Periods
Three Months Ended Six Months Ended
June 30 June 30
(Millions of Dollars)
Fuel clauses $2.8 $3.6
All other 3.5 .9
Net change in retail
revenues $6.3 $4.5
Revenues reflect not only the changes in kWh sales, but
also any changes in revenues from fuel and energy cost adjustment
clauses (fuel clauses) which have little effect on net income
because increases and decreases in fuel and purchased power costs
and sales of transmission services and bulk power are passed on
to customers by adjustment of customer bills through fuel
clauses.
All other is the net effect of kWh sales changes due to
changes in customer usage (primarily weather for residential
customers), growth in the number of customers, and changes in
pricing other than changes in general tariff and fuel clause
rates. The increase in the second quarter all other retail
revenues was primarily the result of customer usage.
Wholesale and other revenues were as follows:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Wholesale customers $ 1.2 $ 1.1 $ 2.5 $ 2.4
Affiliated companies 17.8 18.0 37.6 39.4
Street lighting and other 1.4 1.6 3.3 3.4
Total wholesale and other
revenues $20.4 $20.7 $43.4 $45.2
Wholesale customers are 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. Competition in the wholesale market for electricity was
initiated by the National Energy Policy Act of 1992 (EPACT),
which permits wholesale generators, utility-owned and otherwise,
and wholesale customers to request from owners of bulk power
transmission facilities a commitment to supply transmission
services. All of the Company's wholesale customers have signed
contracts to remain as customers until December 1, 2000.
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Revenues from affiliated companies represent sales of
energy and intercompany allocations of generating capacity,
generation spinning reserves, and transmission services pursuant
to a power supply agreement among the Company and the other
regulated utility subsidiaries of Allegheny Energy.
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 Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Revenues:
Transmission services to
nonaffiliated companies $2.6 $2.1 $ 4.7 $5.2
Bulk power 5.2 2.1 6.2 3.2
Total bulk power trans-
actions, net $7.8 $4.2 $10.9 $8.4
Revenues from bulk power sales increased in the second
quarter and in the first six months of 1998 due to increased
sales of energy which occurred primarily in the month of June as
a result of a heat wave which increased the demand and prices for
energy.
OPERATING EXPENSES
Fuel expenses for the second quarter and the first six
months of 1998 increased 7.1% and 3.0%, respectively, due
primarily to increases in kWh's generated. Fuel expenses are
primarily subject to deferred power cost accounting procedures
with the result that changes in fuel expenses have little effect
on net income.
Purchased power and exchanges, net represents power
purchases from and exchanges with nonaffiliated utilities 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 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 Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
From PURPA generation* $17.4 $17.9 $35.1 $35.9
Other 1.5 1.7 3.6 3.8
Power exchanges, net (.4) (.2) .3 .7
Affiliated transactions:
AGC capacity charges 4.7 4.9 9.2 9.7
Energy and spinning
reserve charges .1 .1 .1 .1
Purchased power and
exchanges, net $23.3 $24.4 $48.3 $50.2
*PURPA cost (cents per kWh) 5.2 5.5 5.2 5.4
<PAGE>
- 15 -
None of the Company's purchased power contracts are
capitalized since there are no minimum payment requirements
absent associated kWh generation and under a regulated
environment recovery of the costs are reasonably assured.
The increase in other operation expenses for the three
months ended June 30 was due primarily to increased provisions
for uninsured claims ($1.2 million), allowances for uncollectible
accounts ($.4 million), and rents ($.4 million). The increase in
the six-month period resulted primarily from an increase in the
allowance for uncollectible accounts ($1.2 million) and increased
property insurance expense due in part to a prior period
adjustment ($.7 million) and rents ($.8 million).
Maintenance expenses decreased slightly for the second
quarter and first six months due primarily to reduced expenses
achieved through restructuring efforts and other cost controls.
Both 1998 periods include $2.5 million of incremental
transmission and distribution (T&D) storm damage expenses
incurred in June for an unusually strong thunderstorm 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 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 in the three and six months ended
June 1998 increased primarily due to additions to electric plant.
Taxes other than income taxes increased $1.7 million in
the first six months due primarily to increased West Virginia
Business and Occupation Taxes resulting from a prior period
adjustment.
The net decrease in federal and state income taxes in the
first six months resulted primarily from a decrease in income
before taxes.
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 and 5 to the Financial Statements for information
about merger activities and the Pennsylvania Customer Choice Act.
<PAGE>
- 16 -
* Risk Management
The Company and its affiliates manage the risk exposure
associated with contracts they write for the purchase and/or sale
of electricity for receipt or delivery at future dates. Such
management is done in accordance with a formal risk management
policy adopted by the Board of Directors and monitored by an
Exposure Management Committee of senior management. The policy
requires continuous monitoring, reporting, and stress testing of
all open positions for conformity to policies which limit value
at risk and market risk associated with the credit standing of
trading counterparties. Such credit standings must be investment
grade or better, or be guaranteed by a parent company with such a
credit standing for all over-the-counter instruments.
At June 30, 1998, the trading books of the Company and
its affiliates consisted primarily of physical contracts with
fixed pricing. Most contracts were fixed-priced, forward-
purchase and/or sale contracts which require settlement by
physical delivery of electricity. During 1998, the Company and
its affiliates also entered into option contracts which, if
exercised, were settled with physical delivery of electricity.
These transactions result in market risk which occurs when the
market price of a particular obligation or entitlement varies
from the contract price. As the Company continues to develop its
power marketing and trading business, its exposure to volatility
in the price of electricity and other energy commodities may
increase within approved policy limits.
* Year 2000 Readiness
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 21 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.
<PAGE>
- 17 -
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,
remediation initiated as needs are identified, 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 at 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.
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 non-compliant 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 $4 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.
<PAGE>
- 18 -
* Environmental Issues
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 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. Although several
restructuring bills were introduced in the House and Senate in
1998, Congress is not expected to move legislation on
restructuring this year.
The West Virginia Legislature passed a House Bill on
March 14, 1998 which sets the stage for the restructuring of the
electric utility industry in West Virginia. The House Bill
directed the West Virginia Public Service Commission (West
Virginia PSC) to determine if deregulation is in the best
interests of the state and, if so, to develop a transition plan.
It also set up a task force of all interested parties to
participate in the plan development. The West Virginia PSC has
been conducting meetings of the Task Force on Restructuring over
the summer to examine if competition is in the best interest of
the state and, if so, to develop a transition plan. All
interested parties have participated in the process which is
nearing the end of its official schedule with little apparent
progress concerning a defined plan for restructuring. The
deadline to file a consensus workshop report and comments
regarding the Commission's public interest determination is
August 26, 1998. The Commission also announced a series of five
public hearings in August and September to allow for broader
public input into the process. Evidentiary hearings are
scheduled for September 29, 1998, to address utility unbundling
and stranded cost filings.
In late March, bills to start competition in Ohio were
introduced in both houses of the General Assembly. In their
current form, the bills would allow residential customers to
choose their electric provider beginning July 1, 1999, for
service beginning January 1, 2000. However, the bills have not
been fully supported by legislative bodies or by the utilities in
the state. A new version of the bills is being developed.
<PAGE>
- 19 -
MONONGAHELA POWER COMPANY
Part II - Other Information to Form 10-Q
for Quarter Ended June 30, 1998
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(27) Financial Data Schedule
(b) No reports on Form 8-K were filed on behalf of the
Company for the quarter ended June 30, 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.
MONONGAHELA POWER COMPANY
/s/ T. J. KLOC
T. J. Kloc, Controller
(Chief Accounting Officer)
August 14, 1998
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