<PAGE>
Page 1 of 23
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, 1999
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 November 12, 1999, 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.
<PAGE>
- 2 -
MONONGAHELA POWER COMPANY
Form 10-Q for Quarter Ended September 30, 1999
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Statement of Income - Three and nine months ended
September 30, 1999 and 1998 3
Balance Sheet - September 30, 1999
and December 31, 1998 4
Statement of Cash Flows - Nine months ended
September 30, 1999 and 1998 5
Notes to Financial Statements 6-8
Management's Discussion and Analysis of Financial
Condition and Results of Operations 9-21
PART II--OTHER INFORMATION 22-23
<PAGE>
- 3 -
MONONGAHELA POWER COMPANY
Statement of Income
(Thousands of Dollars)
<TABLE>
<CAPTION>
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
ELECTRIC OPERATING REVENUES:
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Residential $ 59,191 $ 55,492 $ 163,633 $ 151,908
Commercial 34,229 35,458 97,560 95,124
Industrial 52,744 53,055 159,721 154,726
Wholesale and other, including affiliates 24,737 26,200 72,986 69,590
Bulk power transactions, net 7,429 7,159 15,531 18,062
Total Operating Revenues 178,330 177,364 509,431 489,410
OPERATING EXPENSES:
Operation:
Fuel 39,406 40,779 111,319 110,443
Purchased power and exchanges, net 21,323 24,563 71,247 72,864
Deferred power costs, net 7,560 1,823 11,723 (6,117)
Other 21,802 21,995 64,347 64,198
Maintenance 16,006 14,844 48,226 50,095
Depreciation 15,303 14,652 45,951 44,142
Taxes other than income taxes 10,721 11,710 32,404 33,487
Federal and state income taxes 13,614 15,111 36,196 36,966
Total Operating Expenses 145,735 145,477 421,413 406,078
Operating Income 32,595 31,887 88,018 83,332
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 389 (239) 754 119
Other income, net 1,843 1,640 4,516 4,721
Total Other Income and Deductions 2,232 1,401 5,270 4,840
Income Before Interest Charges 34,827 33,288 93,288 88,172
INTEREST CHARGES:
Interest on long-term debt 7,980 7,264 23,397 24,479
Other interest 398 1,145 2,000 2,980
Allowance for borrowed funds used during
construction (182) (365) (546) (569)
Total Interest Charges 8,196 8,044 24,851 26,890
NET INCOME $ 26,631 $ 25,244 $ 68,437 $ 61,282
</TABLE>
See accompanying notes to financial statements.
<PAGE>
- 4 -
MONONGAHELA POWER COMPANY
Balance Sheet
(Thousands of Dollars)
<TABLE>
<CAPTION>
September 30, December 31,
ASSETS: 1999 1998
Property, Plant, and Equipment:
At original cost, including $50,443
<S> <C> <C>
and $43,657 under construction $ 2,035,674 $ 2,007,876
Accumulated depreciation (916,314) (883,915)
1,119,360 1,123,961
Investments:
Allegheny Generating Company - common stock at equity 42,429 44,624
Other 193 231
42,622 44,855
Current Assets:
Cash 2,898 1,835
Accounts receivable:
Electric service 71,758 70,809
Affiliated and other 11,114 19,674
Allowance for uncollectible accounts (4,073) (2,516)
Notes receivable from affiliate 3,400 -
Notes receivable from subsidiary 54,400 -
Materials and supplies - at average cost:
Operating and construction 20,952 21,942
Fuel 14,750 16,588
Prepaid taxes 20,397 19,627
Other, including current portion of regulatory assets 8,333 9,652
203,929 157,611
Deferred Charges:
Regulatory assets 153,762 154,882
Unamortized loss on reacquired debt 17,064 17,826
Other 29,565 19,893
200,391 192,601
Total Assets $ 1,566,302 $ 1,519,028
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 294,550 $ 294,550
Other paid-in capital 2,441 2,441
Retained earnings 289,374 273,197
586,365 570,188
Preferred stock 74,000 74,000
Long-term debt and QUIDS 396,896 453,917
Funds on deposit with trustees (5,366) -
1,051,895 1,098,105
Current Liabilities:
Short-term debt - 49,000
Long-term debt due within one year 65,000 -
Accounts payable 8,101 13,080
Accounts payable to affiliates 93,685 13,958
Taxes accrued:
Federal and state income 13,589 6,277
Other 21,292 23,192
Interest accrued 9,358 7,692
Other 14,228 13,362
225,253 126,561
Deferred Credits and Other Liabilities:
Unamortized investment credit 14,544 16,155
Deferred income taxes 250,935 242,805
Regulatory liabilities 14,316 15,476
Other 9,359 19,926
289,154 294,362
Total Capitalization and Liabilities $ 1,566,302 $ 1,519,028
</TABLE>
See accompanying notes to financial statements.
<PAGE>
- 5 -
MONONGAHELA POWER COMPANY
Statement of Cash Flows
(Thousands of Dollars)
<TABLE>
<CAPTION>
Nine Months Ended
September 30
1999 1998
CASH FLOWS FROM OPERATIONS:
<S> <C> <C> <C> <C>
Net income $ 68,437 $ 61,282
Depreciation 45,951 44,142
Deferred investment credit and income taxes, net (2,769) 7,859
Deferred power costs, net 11,723 (6,117)
Unconsolidated subsidiaries' dividends in excess of earnings 2,234 10,440
Allowance for other than borrowed funds used
during construction (754) (119)
Changes in certain assets and liabilities:
Accounts receivable, net 9,168 (7,943)
Materials and supplies 2,828 (217)
Prepayments (21,198) (1,826)
Accounts payable 74,748 18,359
Taxes accrued 5,412 5,970
Interest accrued 1,666 1,074
Other, net (4,166) 1,877
193,280 134,781
CASH FLOWS FROM INVESTING:
Construction expenditures (less allowance for other
than borrowed funds used during construction) (40,856) (52,935)
CASH FLOWS FROM FINANCING:
Issuance of long-term debt 7,700 85,918
Retirement of long-term debt - (111,690)
Short-term debt, net (49,000) (26,179)
Notes payable to affiliates - (1,450)
Notes receivable from affiliates (3,400) -
Notes receivable from subsidiary (54,400) -
Dividends on capital stock:
Preferred stock (3,778) (3,778)
Common stock (48,483) (24,565)
(151,361) (81,744)
NET CHANGE IN CASH 1,063 102
Cash at January 1 1,835 1,686
Cash at September 30 $ 2,898 $ 1,788
SUPPLEMENTAL CASH FLOW INFORMATION
Cash paid during the period for:
Interest (net of amount capitalized) $22,052 $23,727
Income taxes 33,751 24,280
</TABLE>
See accompanying notes to financial statements.
<PAGE>
- 6 -
MONONGAHELA POWER COMPANY
Notes to Financial Statements
1. Monongahela Power Company (the Company) is a wholly-owned
subsidiary of Allegheny Energy, Inc. (the Parent). The
Company's Notes to Financial Statements in its Annual Report
on Form 10-K for the year ended December 31, 1998 should be
read with the accompanying financial statements and the
following notes. With the exception of the December 31, 1998
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
(which consist only of normal recurring adjustments)
necessary to present fairly the Company's financial position
as of September 30, 1999, the results of operations for the
three and nine months ended September 30, 1999 and 1998, and
cash flows for the nine months ended September 30, 1999 and
1998.
2. 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 is reported by the Company in its
financial statements using the equity method of accounting.
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.
AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and
a return on its investment under a wholesale rate schedule
approved by the Federal Energy Regulatory Commission (FERC).
AGC's rates are set by a formula filed with and previously
accepted by the FERC. The only component which changes is
the return on equity (ROE). Pursuant to a settlement
agreement filed April 4, 1996 with the FERC, AGC's ROE was
set at 11% for 1996 and will continue until the time any
affected party seeks renegotiation of the ROE.
<PAGE>
- 7 -
Following is a summary of income statement information for
AGC:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Thousands of Dollars)
Electric operating revenues $18,072 $18,303 $53,739 $56,033
Operation and maintenance
expense 1,207 888 4,122 3,383
Depreciation 4,245 4,242 12,735 12,710
Taxes other than income taxes 1,137 1,168 3,398 3,505
Federal income taxes 2,662 2,708 7,622 8,480
Interest charges 3,305 3,707 9,993 10,518
Other income, net - (35) (2) (86)
Net income $ 5,516 $ 5,625 $15,871 $17,523
The Company's share of the equity in earnings above was $1.5
million for the three months ended September 30, 1999 and
1998, and $4.3 million and $4.7 million for the nine months
ended September 30, 1999 and 1998, respectively, and was
included in other income, net, on the Company's Statement of
Income.
4. As previously reported, on October 5, 1998, DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
notified Allegheny Energy, Inc. (Allegheny Energy) that it
had unilaterally 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 lawsuit for specific performance of the
Merger Agreement or, alternatively, damages. On March 11,
1999, the United States Court of Appeals for the Third
Circuit vacated the United States District Court for the
Western District of Pennsylvania's denial of Allegheny
Energy's motion for preliminary injunction, enjoining DQE
from taking actions prohibited by the Merger Agreement. The
Circuit Court stated that if DQE breached the Merger
Agreement, Allegheny Energy may be entitled to specific
performance of the Merger Agreement. The Circuit Court also
stated that Allegheny Energy could be irreparably harmed if
DQE took actions that would prevent Allegheny Energy from
receiving the specific performance remedy. The Circuit Court
remanded the case to the District Court for further
proceedings consistent with its opinion.
The District Court denied DQE's motion for summary judgment.
The District Court has held a trial on October 18-28, 1999,
without a jury, on the issues of whether DQE's termination of
the Merger Agreement breached the agreement and whether
Allegheny Energy is entitled to specific performance. A
decision by the District Court is expected by the end of
1999. Allegheny Energy cannot predict the outcome of this
litigation. However, Allegheny Energy believes that DQE's
basis for terminating the merger is without merit.
Accordingly, Allegheny Energy continues to seek the necessary
regulatory approvals. It is not likely any agency will act
further on the merger unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.
<PAGE>
- 8 -
The $4.4 million deferred incremental costs of the merger
process recorded by the Company through March 31, 1999 were
transferred to the Parent company in the second quarter of
1999. The accumulated merger costs will be written off by
the Parent company when the merger occurs or if it is
determined that the merger will not occur.
5. SFAS No. 131, "Disclosures about Segments of an Enterprise
and Related Information," established standards for reporting
information about operating segments in financial statements.
The Company's principal business segment is utility
operations which includes the generation, purchase,
transmission, distribution, and sale of electricity.
<PAGE>
- 9 -
MONONGAHELA POWER COMPANY
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1999
WITH THIRD QUARTER AND NINE MONTHS ENDED SEPTEMBER 30, 1998
The Notes to Financial Statements and Management's
Discussion and Analysis of Financial Condition and Results of
Operations in Monongahela Power Company's (the Company) Annual
Report on Form 10-K for the year ended December 31, 1998 should
be read 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, the proposed
merger of the Company's parent, Allegheny Energy, Inc. (Allegheny
Energy) and related litigation against DQE, Inc. (DQE), parent
company of Duquesne Light Company in Pittsburgh, Pa., Year 2000
readiness disclosure, and 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 of Allegheny Energy
with DQE; 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 1999
* Acquisition of Assets
The Company plans to purchase from UtiliCorp United,
headquartered in Kansas City, Missouri, the assets of West
Virginia Power, an electric and natural gas distribution company
located adjacent to the Company's service territory in southern
West Virginia for approximately $95 million. As part of the
transaction, the Company signed a 20-year option agreement with
UtiliCorp
<PAGE>
- 10 -
United's subsidiary, Aquila Energy, for gas supply to the
Company. Electricity will be supplied under an existing contract
with American Electric Power until December 31, 2001, and
thereafter from existing Company generation or from the market.
The proposed acquisition includes 26,000 electric and
24,000 gas customers, 1,989 miles of electric distribution lines
and 670 miles of gas pipelines, and 1,360 square miles of
electric and 500 miles of gas service territory. West Virginia
Power has approximately 120 employees. The Company has proposed
to the W.Va. PSC to generally freeze both electric and gas rates
to West Virginia Power customers for seven years except that the
fuel portion of gas rates would be allowed to fluctuate with the
gas market.
The transaction has been approved by the Boards of
Directors of UtiliCorp United and the Company. The purchase of
the assets is conditioned upon the acceptable approvals of the
Public Service Commission of West Virginia, the SEC, FERC, and
the Department of Justice/Federal Trade Commission. The Company
has made the appropriate filings and anticipates that all
required approvals will be received and the transaction completed
in the fourth quarter of 1999.
* Proposed Merger with DQE
See Note 4 to the financial statements for information
about the proposed merger of Allegheny Energy with DQE and
related litigation.
* West Virginia Fuel Review
On February 26, 1999, the Public Service Commission of
West Virginia (W.Va. PSC) entered an Order to initiate a fuel
review proceeding to establish a fuel increment in rates for the
Company to be effective July 1, 1999 through June 30, 2000. On
June 29, 1999, the W.Va. PSC approved a joint stipulation and
agreement between the Company and the intervenors. Under the
agreement, the parties are to negotiate further in an effort to
more closely align the Company's West Virginia rate schedules
with the West Virginia rate schedules of The Potomac Edison
Company, an affiliate, and to petition to reopen this case if
they are successful. Absent such agreement by October 15, 1999,
the rates were to revert to the originally proposed rates in this
case. This change would have been effective November 1, 1999 and
would have increased the Company's fuel rates by $10.9 million.
On October 15, 1999, the parties filed a "Status Report and
Agreement to Continue." The Agreement stated that the parties
had met and exchanged proposals but more time was needed to
review the matter. The parties agreed to continue discussions
until January 31, 2000. If the parties have not reached an
agreement by that date, then the rates as previously proposed
would become effective February 15, 2000 with no further approval
or action required of the W.Va. PSC. These changes, if
implemented, will have no effect on the Company's net income.
* Ohio and West Virginia Deregulation
See Electric Energy Competition on page 19 for ongoing
information regarding restructuring in Ohio and West Virginia.
<PAGE>
- 11 -
* Toxics Release Inventory (TRI)
On Earth Day 1997, President Clinton announced the
expansion of Right-to-Know TRI reporting to include electric
utilities, limited to facilities that combust coal and/or oil for
the purpose of generating power for distribution in commerce.
The purpose of TRI is to provide site-specific information on
chemical releases to the air, land, and water. On June 4, 1999,
the Allegheny Energy companies (the System) joined with other
members of the Edison Electric Institute in reporting power
station releases to the public. Packets of information about the
System's releases were provided to media in the System's area and
posted on the Parent Company's web site. The System filed its
first TRI report with the Environmental Protection Agency prior
to the July 1, 1999 deadline date, reporting 18 million pounds of
total releases for calendar year 1998.
Review of Operations
EARNINGS SUMMARY
Net income for the third quarter of 1999 was $26.6
million compared with $25.2 million in the corresponding 1998
period. For the first nine months of 1999, net income was $68.4
million compared with $61.3 million for the corresponding 1998
period. The increase in net income for the third quarter of 1999
was due primarily to increased kilowatt-hour (kWh) sales to
residential customers due to summer weather that was 7% warmer
than the relatively cool summer of 1998, as measured by cooling
degree days. The increase in net income in the first nine months
of 1999 is primarily attributed to increased retail kWh sales,
including increased sales to residential customers due to winter
weather that was 21% cooler than the relatively warm winter of
1998, as measured by heating degree days, and summer weather that
was warmer than 1998, as measured by cooling degree days. The
increase is also due to reduced maintenance and interest
expenses.
SALES AND REVENUES
Percentage changes in revenues and kWh sales by major
retail customer classes were:
Change from Prior Periods
Three Months Ended Nine Months Ended
September 30 September 30
Revenues kWh Revenues kWh
Residential 6.7% 7.5% 7.7% 7.3%
Commercial (3.5) (3.3) 2.6 1.7
Industrial (.6) 2.0 3.2 2.5
Total 1.5% 2.4% 4.8% 3.6%
The changes in residential kWh sales, which are more
weather sensitive than the other classes, were due primarily to
changes in customer usage because of weather conditions, and to a
lesser extent, growth in the number of customers. Third quarter
residential kWh sales were affected by weather that was 7% warmer
than the corresponding 1998 period, as measured by
<PAGE>
- 12 -
cooling degree days. In addition, nine months ended kWh sales
were also affected by first quarter winter weather that was 21%
cooler than 1998 and 2% 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 decrease in
commercial kWh sales in the third quarter of 1999 reflects a
decrease in customer usage. The increase in commercial kWh sales
in the first nine months of 1999 primarily reflects growth in the
number of customers. The increases in industrial kWh sales in
both periods were due to increased kWh sales to iron and steel
customers and to paper and printing product customers. The
increases also reflect continued economic growth in the service
territory.
The changes in revenues from retail customers resulted
from the following:
Change from Prior Periods
Three Months Ended Nine Months Ended
September 30 September 30
(Millions of Dollars)
Fuel clauses $ .7 $ 8.5
All other 1.5 10.7
Net change in retail
revenues $2.2 $19.2
Revenues reflect not only the changes in kWh sales and
base rate changes, 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 increases in the three and nine months ended periods
for all other retail revenues was primarily due to increased kWh
sales due to customer usage which resulted from first quarter
winter weather that was cooler than the 1998 period and third
quarter summer weather that was hotter than the 1998 period.
Wholesale and other revenues were as follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Wholesale customers $ 1.1 $ 1.4 $ 3.4 $ 3.9
Affiliated companies 22.0 23.0 64.5 60.6
Street lighting and other 1.6 1.8 5.1 5.1
Total wholesale and other
revenues $24.7 $26.2 $73.0 $69.6
<PAGE>
- 13 -
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 Federal Energy
Regulatory Commission (FERC) regulation. Competition in the
wholesale market for electricity was initiated by the National
Energy Policy Act of 1992 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.
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.
Revenues from bulk power transactions include sales of
bulk power and transmission services to power marketers and other
utilities. Bulk power and transmission services revenues for the
three and nine months ended periods of 1999 and 1998 were as
follows:
Three Months Ended Nine Months Ended
September 30 September 30
1999 1998 1999 1998
(Millions of Dollars)
Revenues:
Transmission services to
nonaffiliated companies $4.5 $4.7 $ 9.6 $ 9.4
Bulk power 2.9 2.5 5.9 8.7
Total bulk power trans-
actions, net $7.4 $7.2 $15.5 $18.1
Revenues from bulk power transactions in the nine months
ended period of 1999 decreased from the same period of 1998.
Increased revenues from bulk power transactions in the first nine
months of 1998 were high due to increased sales of energy which
occurred primarily in the month of June 1998 as a result of a
heat wave which increased the demand and prices for energy. 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.
OPERATING EXPENSES
Fuel expenses for the third quarter and the first nine
months of 1999 decreased by 3.4% and increased by .8%,
respectively. The decrease in the third quarter was due to a
9.2% decrease in average fuel prices, offset in part by a 4.1%
increase in kWh's generated. The increase in kWh's generated in
the three months ended September 1999 was primarily the result of
increased sales to retail customers and to power marketers and
other utilities. 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.
<PAGE>
- 14 -
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
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
1999 1998 1999 1998
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
From PURPA generation* $13.0 $15.8 $47.9 $50.9
Other 4.1 4.6 9.4 8.2
Power exchanges, net (.8) (.7) (.7) (.4)
Affiliated transactions:
AGC capacity charges 5.0 4.9 14.6 14.1
Energy and spinning
reserve charges - - - .1
Purchased power and
exchanges, net $21.3 $24.6 $71.2 $72.9
*PURPA cost (cents per kWh) 4.9 4.9 5.2 5.1
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 these costs are reasonably assured.
The decrease in purchased power from PURPA generation for
the three months ended September 1999 was primarily due to
reduced generation at all three of the PURPA projects from which
the Company purchases generation.
Maintenance expenses in the nine months ended September
30, 1999 decreased $1.9 million. This decrease was primarily due
to $2.5 million of incremental transmission and distribution
(T&D) storm damage expenses incurred in June 1998 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 nine months ended
September 30, 1999 increased due to increased investment.
Taxes other than income taxes decreased $1.1 million in
the first nine months of 1999 due primarily to an adjustment of a
prior period related to increased West Virginia Business and
Occupation Taxes.
<PAGE>
- 15 -
The decreases in federal and state income taxes in the
third quarter and first nine months of 1999 were primarily
related to the Company's share of tax savings in consolidation
related to its Parent, Allegheny Energy, Inc. The decrease in
the nine months ended period was offset in part by increased
taxes due to an increase in income before taxes.
The decrease in interest on long-term debt in the first
nine months of 1999 of $1.1 million resulted primarily 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 associated rates.
Financial Condition and Requirements
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,
1998 should be read 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 Note 4 to the Financial Statements for information about
Allegheny Energy's proposed merger with DQE.
* Market Risk
The Company supplies power in the bulk power markets. At
September 30, 1999, the marketing books for such operations
consisted primarily of fixed-priced, forward-purchase and/or sale
contracts which require settlement by 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.
* Issuance of Long-Term Debt
In April 1999, the Company issued $7.7 million of 5.50%
30-year pollution control revenue notes to Pleasants County, West
Virginia.
* Long-Term Debt Due Within One Year
The Company's long-term debt due within one year at
September 30, 1999 represents $65 million of 5-5/8% first
mortgage bonds due April 1, 2000.
<PAGE>
- 16 -
* Year 2000 Readiness Disclosure
The transition from 1999 into the Year 2000 (Y2K) has the
potential to cause serious problems to most organizations,
including the Company, related to software and various equipment
with embedded chips which may not properly recognize calendar
dates. To minimize such problems, the Company has been working
under a comprehensive Y2K program to identify and remediate the
problem areas in order to continue operations without significant
problems in 2000 and beyond. An Executive Task Force is
coordinating the efforts of 24 separate Y2K Teams, representing
all business and support units in the Company.
In May 1998, the North American Electric Reliability
Council (NERC), of which the System is a member, accepted a
request from the United States Department of Energy to coordinate
the industry's Y2K efforts. The electric utility industry and
the Company have segmented the Y2K problem into the following
components:
* Computer hardware and software;
* Embedded chips in various equipment; and
* Vendors and other organizations on which the System relies
for critical materials and services.
The industry's and the System's efforts for each of these
three components include inventory, assessment and, where
possible, remediation of the problem areas by repair, replacement
or removal, supplemented by confirmation testing and contingency
plans. Contingency plans include alternate methods of certain
operations to help avoid electric service or business
interruptions, and the review and update of restoration of
service plans to mitigate the severity and length of
interruptions in the unlikely event that any should occur.
Based on this work, the Company has determined that as of
September 30, 1999 all of its critical components and systems
related to safety and the production and distribution of
electricity are Y2K Ready, and all but one of its important
business systems are also Ready. Remediation on this one
remaining system related to customer billing has been completed
and system testing is in progress. Although the system is
expected to be Y2K Ready in November, the Company has contingency
plans to continue operations without the system if necessary.
The Company has defined Y2K Ready to mean that a determination
has been made by testing or other means that a component or
system will be able to perform its critical functions.
The Company's readiness program has been conducted in
accordance with time schedules recommended by state regulatory
commissions and by NERC. As is the case of most electric
utilities, Allegheny Energy is interconnected with neighboring
utilities, which provide added strength of supply diversity and
flexibility. But the interconnections also mean that any one
utility's Y2K readiness is related to the readiness of the group.
Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, a cascading failure of the
entire electrical system. The Company is working with the Edison
Electric Institute, the Electric Power Research Institute, the
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.
Since the Company and its neighboring utilities in the ECAR group
are all participants in the NERC Y2K effort (which had a target
completion date of June 30 for critical systems
<PAGE>
- 17 -
related to production and delivery of electricity), the Company
believes that this worst case possibility has been reduced to an
unlikely event. The Company has recently re-tested its existing
contingency plans for restoration of service even if this
unlikely event were to occur.
As part of the on-going NERC program, the Company
participated in industry-wide Y2K drills on April 9 and September
9, 1999. While the electric utility industry is aware of the
extensive Y2K programs of the major telecommunications companies,
the industry has determined that telecommunication facilities are
so important to continued operations that we must have
contingency plans just in case some of those facilities may not
be available. The drills were dry runs designed primarily to
test the ability of utilities to continue to operate with less
than normal telecommunication facilities. During the tests, the
Company was able to maintain adequate communications under
simulated failures of selected systems, and obtained valuable
information for improvement of its plans. NERC has reported that
the industry-wide tests produced similar results. On December
31, 1999, the Company will have extra staff in critical areas of
the system to implement these and other contingency plans if they
are required.
The SEC requires that each company disclose its estimate
of the "most reasonably likely worst case scenario" of a negative
Y2K event. Since the Company and the industry are working
diligently to avoid any disruption of electric service, the
Company believes its customers will not experience any
significant long-term disruptions of electric service. It is the
Company's opinion that the "most reasonably likely worst case
scenario" is a Y2K event or series of events that may cause
isolated disruptions of service. All utilities, including the
Company, have experience in the implementation of existing
restoration of service plans. As stated above the Company's Y2K
program includes a review and update of these plans to respond
quickly to any such events.
The Company is aware of the importance of electricity to
its customers and is using its best efforts to avoid any serious
Y2K problems. Despite the Company'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 of any such event.
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 Y2K work has been significant, it primarily represents
a labor-intensive effort of remediation, component testing,
multiple systems testing, documentation, and contingency
planning. While outside contractors and equipment vendors have
been employed for some of the work, the Company has used its own
employees for most of the effort because of their experience with
the Company's systems and equipment. The Company currently
estimates that its total incremental expenditures for the Y2K
effort since it began identification of Y2K costs will be up to
about $5 million of which $4 million has been incurred through
September 30, 1999. These expenditures are financed by internal
sources and primarily result from the purchase of external expert
assistance by the Generation and Information Services
departments. The expenditures have not required a material
reduction in the normal budgets and work efforts of these
departments.
<PAGE>
- 18 -
The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act. Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995. There can be
no assurance that actual results will not materially differ from
expectations.
* Electric Energy Competition
The electricity supply segment of the electric utility
industry in the United States is becoming increasingly
competitive. The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems. Since 1992, the wholesale
electricity market has become more competitive as companies began
to engage in nationwide power trading. In addition, an
increasing number of states have taken active steps toward
allowing retail customers the right to choose their electricity
supplier. The Company has been an advocate of federal
legislation to create competition in the retail electricity
markets to avoid regional dislocations and ensure level playing
fields. Legislation before the U.S. Congress to restructure the
nation's electric utility industry cleared an important hurdle on
October 28, 1999 when a House Commerce Committee subcommittee
gave its approval to the bill. The bill will now move on to the
full Commerce Committee where it will be considered next year.
In the absence of federal legislation, state-by-state
implementation has begun. All of the states the operating
subsidiaries serve are at various stages of implementation or
investigation of programs that allow customers to choose their
electric supplier. Pennsylvania is furthest along with a retail
program in place, while Maryland, Virginia, and Ohio passed
legislation this year to implement retail choice. West Virginia
continues to actively study this issue. West Penn, an affiliate,
is currently implementing a settlement agreement to create
competition for electricity supply in Pennsylvania. Potomac
Edison, an affiliate, filed a settlement agreement to introduce
generation competition with the Maryland PSC on September 23,
1999. Maryland PSC approval is expected before the end of 1999.
Activities at the Federal Level
The Company continues to seek enactment of federal
legislation to bring choice to all retail electric customers,
deregulate the generation and sale of electricity on a national
level, and create a more liquid, free market for electric power.
Fully meeting challenges in the emerging competitive environment
will be difficult for the Company unless certain outmoded and
anti-competitive laws, specifically the Public Utility Holding
Company Act of 1935 (PUHCA) and Section 210 of the Public Utility
Regulatory Policies Act of 1978 (PURPA), are repealed or
significantly revised. The Company continues to advocate the
repeal of PUHCA and PURPA on the grounds that they are obsolete
and anti-competitive and that PURPA results in utility customers
paying above-market prices for power. H.R. 2944, which was
sponsored by Representative Joe Barton, was favorably reported
out of the House Commerce Subcommittee on Energy and Power.
While the bill does not mandate a date certain for customer
choice, several key provisions favored by the Company are
included in the legislation, including an amendment that allows
existing state restructuring plans and agreements to remain in
effect. Other provisions address important
<PAGE>
- 19 -
Company priorities by repealing the PUHCA and the mandatory
purchase provisions of the PURPA. Consensus remains elusive with
significant hurdles remaining in both houses of Congress. It is
too early to tell whether momentum on the issue will result in
legislation in the current Congress.
Ohio
The Ohio General Assembly ended five years of debate on
June 22, 1999 when it passed legislation to restructure the
electric utility industry. Governor Taft added his signature
soon thereafter, and all of the state's customers will be able to
choose their electricity supplier starting January 1, 2001,
beginning a five-year transition to market rates. Total electric
rates will be frozen over that period, and residential customers
are guaranteed a five percent cut in the generation portion of
their rate. The determination of stranded cost recovery will be
handled by The Public Utilities Commission of Ohio. The bill
stipulates that no entity shall own or control transmission
facilities after the start of competitive retail electric
service. Customer protections were kept intact with a low-income
assistance plan and a one-time forgiveness of past debts for low-
income and handicapped customers. In regard to renewable energy,
the bill requires that electric generators purchase excess
electricity from small businesses and homes using renewable
energy sources. In addition, a customer's bill will list what
fuel was expended to produce the electricity and what emissions
were created.
West Virginia
In March 1998, legislation was passed by the West
Virginia Legislature that directed the W.Va. PSC to meet with all
interested parties to develop a restructuring plan which would
meet the dictates and goals of the legislation. Interested
parties formed a Task Force that met during 1998, but the Task
Force was unable to reach a consensus on a model for
restructuring. The W.Va. PSC held hearings in August 1999 that
addressed certification, licensing, bonding, reliability,
universal service, consumer protection, code of conduct,
subsidies, and stranded costs. The August hearings have
concluded and the W.Va. PSC has stated that it would issue an
order after November 1, 1999. The Order will have a
determination as to whether deregulation is in the best interest
of West Virginia, and if so, a plan may be issued with it.
Informal negotiations with all of the parties will continue
beyond the November 1 Commission-imposed deadline to seek
consensus on a restructuring plan, although no agreements have
been reached to date.
The status of electric energy competition in Virginia, Maryland,
and Pennsylvania in which affiliates of the Company serve are as
follows:
Virginia
The Virginia Electric Utility Restructuring Act (the
"Restructuring Act") was passed by the Virginia General Assembly
on March 25, 1999 and was signed by the Governor of Virginia on
March 29, 1999. The Legislative Transition Task Force on
Electric Utility Restructuring, which was established by the
Restructuring Act, held hearings this summer on a number of
issues concerning the implementation of retail competition in
Virginia. Working groups continued to meet with State
Corporation Commission staff, comments were filed, and Commission
hearings were held to discuss the nature of and the rules
governing the proposed retail pilot programs of other utilities
in the state.
<PAGE>
- 20 -
Maryland
On April 8, 1999, Maryland Governor Glendening signed the
legislation that will bring competition to Maryland's electric
generation market. The Maryland PSC is in the process of
implementing the new law. Final Electric Restructuring
Roundtable reports were filed with the Commission in May and
legislative-style hearings were held this summer on the
Roundtable reports. The Commission is expected to issue
decisions on those aspects of restructuring by the end of the
year.
On September 23, the Company filed a Settlement Agreement
(covering the Company's stranded cost quantification mechanism,
price protection mechanism, and unbundled rates) with the
Maryland PSC. The Agreement was signed by all parties active in
the case except Eastalco, who stated although they did not sign
the agreement, they would not oppose it. The settlement
agreement, which is subject to Commission approval, includes the
following provisions:
* The ability for nearly all of our 208,000 Maryland customers
to have the option of choosing an electric generation supplier
starting July 1, 2000.
* The authorization to transfer generating assets to a non-
regulated corporate entity at book value on July 1, 2000.
* A reduction in base rates of 7% for residential customers
from 2002 through 2008 ($10.4 million each year, totaling $72.8
million). A reduction in base rates of one-half a percent for
the majority of commercial and industrial customers from 2002
through 2008 ($1.5 million each year, totaling $10.5 million).
* Standard Offer Service (provider of last resort) will be
provided to residential customers during a transition period from
July 1, 2000 to December 31, 2008 and to all other customers
during a transition period of July 1, 2000 to December 31, 2004.
* A cap on generation rates for residential customers from
2002 through 2008. Generation rates for non-residential
customers are capped from 2002 through 2004.
* A cap on transmission and distribution rates for all
customers from 2002 through 2004.
* Unless the Company is subject to significant changes that
would materially affect the Company's financial condition, the
parties agree not to seek a reduction in rates which would be
effective prior to January 1, 2005.
* The recovery of all purchased power costs incurred as a
result of our contract to buy generation from the AES Warrior Run
PURPA cogeneration contract.
* The establishment of a fund for the development and use of
energy-efficient technologies.
<PAGE>
- 21 -
On October 4, the Company filed unbundled rates covering
the period 2000-2008. The Commission held public hearings
regarding the settlement agreement on October 14 and October 18.
A final Commission decision is expected before the end of 1999.
Pennsylvania
As previously disclosed, beginning in January 1999, two-
thirds of the customers of the Company's Pennsylvania affiliate,
West Penn Power Company, were permitted to choose an alternate
electricity supplier. Remaining customers can do so in January
2000.
Accounting for the Effects of Price Deregulation
In July 1997, the Emerging Issues Task Force (EITF) of
the Financial Accounting Standards Board (FASB) released Issue
No. 97-4, "Deregulation of the Pricing of Electricity - Issues
Related to the Application of FASB Statement Nos. 71 and 101,"
which concluded that utilities should discontinue application of
Statement of Financial Accounting Standards (SFAS) No. 71 for the
generation portion of their business when a deregulation plan is
in place and its terms are known. Because Ohio has passed
legislation for a deregulation plan, the Company has determined
that it will be required to discontinue use of SFAS No. 71 for
the generation portion of its business (the Ohio portion) on an
uncertain future date. West Virginia has not yet developed a
restructuring plan. One of the conclusions of the EITF is that
after discontinuing SFAS No. 71, utilities should continue to
carry on their books the assets and liabilities recorded under
SFAS No. 71 if the regulatory cash flows to settle them will be
derived from the continuing regulated transmission and
distribution business. Additionally, continuing costs and
obligations of the deregulated generation business which are
similarly covered by the cash flows from the continuing regulated
business will meet the criteria as regulatory assets and
liabilities. The Ohio legislation establishes definitive
processes for transition to deregulation and market-based pricing
for electric generation. Until relevant regulatory proceedings
are complete and final orders are received, the Company is unable
to predict the effect of discontinuing SFAS No. 71, but it may be
required to write off unrecoverable regulatory assets, impaired
assets, and uneconomic commitments.
<PAGE>
- 22 -
MONONGAHELA POWER COMPANY
Part II - Other Information to Form 10-Q
for Quarter Ended September 30, 1999
ITEM 1. LEGAL PROCEEDINGS
The MidAtlantic case, previously reported as an ongoing
litigation matter, has been settled and an Order was entered on
July 9, 1999 dismissing the case with prejudice.
As of September 30, 1999, the Company has been named as a
defendant, along with multiple other defendants in a total of
approximately 8,626 asbestos cases. The Potomac Edison Company
and West Penn Power Company, affiliates of the Company, were
named as defendants along with multiple other defendants in
approximately one-half of those cases. As of September 30, 1999,
a total of 878 cases have been settled and/or dismissed against
the Company, The Potomac Edison Company, and West Penn Power
Company for reasonable settlement amounts. While the Company,
The Potomac Edison Company, and West Penn Power Company believe
that all of the cases are without merit, they cannot predict the
outcome nor are they able to determine whether additional cases
will be filed.
As previously reported, on October 5, 1998, DQE, Inc.
(DQE), parent company of Duquesne Light Company in Pittsburgh,
Pa., notified the Company's parent, Allegheny Energy, Inc.
(Allegheny Energy) that it had unilaterally 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 lawsuit for specific performance of the Merger
Agreement or, alternatively, damages. On March 11, 1999, the
United States Court of Appeals for the Third Circuit vacated the
United States District Court for the Western District of
Pennsylvania's denial of Allegheny Energy's motion for
preliminary injunction, enjoining DQE from taking actions
prohibited by the Merger Agreement. The Circuit Court stated
that if DQE breached the Merger Agreement, Allegheny Energy may
be entitled to specific performance of the Merger Agreement. The
Circuit Court also stated that Allegheny Energy could be
irreparably harmed if DQE took actions that would prevent
Allegheny Energy from receiving the specific performance remedy.
The Circuit Court remanded the case to the District Court for
further proceedings consistent with its opinion.
The District Court denied DQE's motion for summary
judgment. The District Court has held a trial on October 18-28,
1999, without a jury, on the issues of whether DQE's termination
of the Merger Agreement breached the agreement and whether
Allegheny Energy is entitled to specific performance. A decision
by the District Court is expected by the end of 1999. Allegheny
Energy cannot predict the outcome of this litigation. However,
Allegheny Energy believes that DQE's basis for terminating the
merger is without merit. Accordingly, Allegheny Energy continues
to seek the necessary regulatory approvals. It is not likely any
agency will act further on the merger unless Allegheny Energy
obtains judicial relief requiring DQE to move forward.
<PAGE>
- 23 -
ITEM 5. OTHER EVENTS
The Attorney General of the State of New York and the
Attorney General of the State of Connecticut in their letters
dated September 15, 1999 and November 3, 1999, respectively,
notified Allegheny Energy, Inc. (Allegheny Energy) of their
intent to commence civil actions against Allegheny Energy or its
subsidiaries (West Penn Power Company, Monongahela Power Company,
The Potomac Edison Company, and AYP Energy, Inc.) alleging
violations at the Fort Martin power station under the Federal
Clean Air Act, which requires power plants that make major
modifications to comply with the same emission standards
applicable to new power plants. Similar actions may be commenced
by other governmental authorities in the future. Fort Martin is a
station located in West Virginia jointly owned by West Penn Power
Company, Monongahela Power Company, The Potomac Edison Company,
and AYP Energy, Inc. Both Attorneys General stated their intent
to seek injunctive relief and penalties.
In addition, the Attorney General of the State of New York
in his letter indicated that he may assert claims under the State
common law of public nuisance seeking to recover, among other
things, compensation for alleged environmental damage caused in
New York by the operation of Fort Martin power station.
At this time, Allegheny Energy and its subsidiaries are
not able to determine what impact, if any, these actions taken by
the Attorneys General of New York and Connecticut may have on
them.
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 September 30, 1999.
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)
November 15, 1999
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1998
<PERIOD-START> JUL-01-1999
<PERIOD-END> SEP-30-1999
<EXCHANGE-RATE> 1
<CASH> 2,898
<SECURITIES> 0
<RECEIVABLES> 82,872
<ALLOWANCES> (4,073)
<INVENTORY> 35,702
<CURRENT-ASSETS> 203,929
<PP&E> 2,035,674
<DEPRECIATION> (916,314)
<TOTAL-ASSETS> 1,566,302
<CURRENT-LIABILITIES> 225,253
<BONDS> 391,530<F1>
0
74,000
<COMMON> 294,550
<OTHER-SE> 291,815
<TOTAL-LIABILITY-AND-EQUITY> 1,566,302
<SALES> 178,330
<TOTAL-REVENUES> 178,330
<CGS> 106,097
<TOTAL-COSTS> 132,121
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 8,196
<INCOME-PRETAX> 40,245
<INCOME-TAX> 13,614
<INCOME-CONTINUING> 26,631
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 26,631
<EPS-BASIC> 0.00<F2>
<EPS-DILUTED> 0.00<F2>
<FN>
<F1> Includes $5,366 for funds on deposit with trustees.
<F2> All common stock is owned by parent, no EPS required.
</FN>
</TABLE>
