<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported): February 3,
2000
MONONGAHELA POWER COMPANY
(Exact name of registrant as specified in its charter)
Ohio 1-5164 13-5229392
(State or other (Commission File (IRS Employer
jurisdiction of Number) Identification
incorporation) Number)
1310 Fairmont Avenue
Fairmont, WV 26554
(Address of principal executive offices)
Registrant's telephone number,
including area code: (304) 366-3000
<PAGE>
Item 7 Financial Statements and Exhibits
(c) Exhibits
Ex. 99.1 Audited Financial Statements of Monongahela
Power Company for the year ended December 31,
1999.
Ex. 99.2 Management's Discussion and Analysis of
Financial Condition and Results of Operations
for the year ended December 31, 1999.
SIGNATURES
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
Dated: March 9, 2000 By: /s/ Michael P. Morrell
Name: Michael P. Morrell
Title: Vice President
<PAGE>
EXHIBIT INDEX
Ex. 99.1 Audited Financial
Statements of Monongahela Power Company
for the year ended December 31, 1999.
Ex. 99.2 Management's Discussion and Analysis
of Financial Condition and Results of
Operations for the year ended December 31, 1999
<PAGE>
EXHIBIT 99.1
Monongahela Power Company
STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1999 1998 1997
<S> <C> <C> <C>
Electric Operating Revenues:
Residential.....................................................$210,757 $200,896 $199,931
Commercial...................................................... 130,052 126,464 118,825
Industrial...................................................... 217,792 208,613 196,716
Wholesale and other, including affiliates....................... 96,184 89,396 95,579
Bulk power transactions, net.................................... 18,550 19,753 17,260
Total Operating Revenues...................................... 673,335 645,122 628,311
Operating Expenses:
Operation:
Fuel.......................................................... 145,236 143,993 141,340
Purchased power and exchanges, net............................ 98,774 95,617 98,266
Deferred power costs, net..................................... 10,930 (8,452) (10,027)
Other......................................................... 90,625 82,637 75,908
Maintenance..................................................... 63,993 67,033 70,561
Depreciation and amortization................................... 60,905 58,610 56,593
Taxes other than income taxes................................... 43,395 44,742 38,776
Federal and state income taxes.................................. 40,440 49,456 47,519
Total Operating Expenses...................................... 554,298 533,636 518,936
Operating Income.............................................. 119,037 111,486 109,375
Other Income and Deductions:
Allowance for other than borrowed funds used during
construction.................................................. 1,059 376 570
Other income, net............................................... 6,119 6,049 8,498
Total Other Income and Deductions............................. 7,178 6,425 9,068
Income Before Interest Charges................................ 126,215 117,911 118,443
Interest Charges:
Interest on long-term debt...................................... 31,963 32,363 36,076
Other interest.................................................. 2,640 3,790 2,654
Allowance for borrowed funds used during construction........... (715) (667) (816)
Total Interest Charges........................................ 33,888 35,486 37,914
Net Income........................................................$ 92,327 $ 82,425 $ 80,529
</TABLE>
STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Balance at January 1..............................................$273,197 $243,939 $215,221
Add:
Net income...................................................... 92,327 82,425 80,529
365,524 326,364 295,750
Deduct:
Dividends on capital stock:
Preferred stock............................................... 5,037 5,037 5,037
Common stock.................................................. 78,527 48,130 46,774
Total Deductions............................................ 83,564 53,167 51,811
Balance at December 31............................................$281,960 $273,197 $243,939
</TABLE>
See accompanying notes to financial statements.
<PAGE>
Monongahela Power Company
STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
(Thousands of Dollars 1999 1998* 1997*
<S> <C> <C> <C>
Cash Flows from Operations:
Net income...................................................... $ 92,327 $ 82,425 $ 80,529
Depreciation and amortization................................... 60,905 58,610 56,593
Deferred investment credit and income taxes, net................ 4,701 14,827 18,139
Deferred power costs, net....................................... 10,930 (8,452) (10,027)
Unconsolidated subsidiaries' dividends in excess of earnings.... 2,972 9,301 988
Allowance for other than borrowed funds used during
construction.................................................. (1,059) (376) (570)
Internal restructuring liability................................ - (236) (13,761)
Write-off of generation project costs........................... 4,213 - -
Changes in certain current assets and liabilities:
Accounts receivable, net...................................... (68,344) (8,044) (5,516)
Materials and supplies........................................ 354 (3,929) 1,878
Accounts payable.............................................. 69,751 12,249 (7,260)
Prepayment.................................................... (10,000) - -
Other, net...................................................... 2,724 4,410 (3,857)
169,474 160,785 117,136
Cash Flows from Investing:
Construction expenditures (less allowance for other than
borrowed funds used during construction)...................... (81,424) (72,419) (77,569)
Acquisition of businesses....................................... (96,597) - -
(178,021) (72,419) (77,569)
Cash Flows from Financing:
Issuance of long-term debt...................................... 117,013 85,918 -
Retirement of long-term debt.................................... - (111,690) (15,500)
Funds on deposit with trustees.................................. (2,561) - -
Short-term debt, net............................................ (49,000) (7,829) 28,590
Notes payable to affiliate...................................... 28,650 (1,450) (1,450)
Dividends on capital stock:
Preferred stock............................................... (5,037) (5,037) (5,037)
Common stock.................................................. (78,527) (48,129) (46,774)
10,538 (88,217) (40,171)
Net Change in Cash ............................................... 1,991 149 (604)
Cash at January 1................................................ 1,835 1,686 2,290
Cash at December 31.............................................. $ 3,826 $ 1,835 $ 1,686
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 34,076 $ 33,041 $ 36,776
Income taxes.................................................. 42,315 33,361 28,282
</TABLE>
*Certain amounts have been reclassified for comparative purposes.
See accompanying notes to financial statements.
<PAGE>
Monongahela Power Company
BALANCE SHEET
<TABLE>
<CAPTION>
(Thousands of Dollars) DECEMBER 31
1999 1998*
ASSETS
<S> <C> <C>
Property, Plant, and Equipment:
Utility plant................................................ $2,126,482 $1,963,473
Nonutility plant............................................. 983 746
Construction work in progress................................ 46,138 43,657
2,173,603 2,007,876
Accumulated depreciation..................................... (958,867) (883,915)
1,214,736 1,123,961
Investments and Other Assets:
Allegheny Generating Company--common stock at equity......... 41,713 44,624
Excess of cost over net assets acquired...................... 26,325
Other.......................................................... 170 231
68,208 44,855
Current Assets:
Cash........................................................... 3,826 1,835
Accounts receivable:
Electric service........................................... 78,977 70,809
Affiliated and other....................................... 87,345 25,552
Allowance for uncollectible accounts....................... (4,133) (2,516)
Materials and supplies--at average cost:
Operating and construction................................. 22,127 21,942
Fuel......................................................... 16,049 16,588
Prepaid taxes................................................ 23,320 19,627
Other, including current portion of regulatory assets........ 4,708 10,153
232,219 163,990
Deferred Charges:
Regulatory assets............................................ 145,176 154,882
Unamortized loss on reacquired debt.......................... 16,810 17,826
Other.......................................................... 16,569 14,250
178,555 186,958
Total.......................................................... $1,693,718 $1,519,764
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained earnings... $ 578,951 $ 570,188
Preferred stock.............................................. 74,000 74,000
Long-term debt and QUIDS..................................... 503,741 453,917
1,156,692 1,098,105
Current Liabilities:
Short-term debt.............................................. 49,000
Notes payables to affiliate.................................. 28,650
Long-term debt due within one year........................... 65,000
Accounts payable............................................. 40,016 12,646
Accounts payable to affiliates............................... 67,312 24,931
Taxes accrued:
Federal and state income................................... 2,260 6,277
Other...................................................... 24,235 23,192
Interest accrued............................................. 5,883 7,692
Other........................................................ 11,647 9,438
245,003 133,176
Deferred Credits and Other Liabilities:
Unamortized investment credit................................ 14,007 16,155
Deferred income taxes........................................ 248,987 247,230
Regulatory liabilities....................................... 13,961 15,476
Other........................................................ 15,068 9,622
292,023 288,483
Commitments and Contingencies (Note L)
Total.......................................................... $1,693,718 $1,519,764
</TABLE>
*Certain amounts have been reclassified for comparative purposes.
See accompanying notes to financial statements.
<PAGE>
Monongahela Power Company
STATEMENT OF CAPITALIZATION
<TABLE>
<CAPTION>
DECEMBER 31
1999 1998 1999 1998
(Thousands of Dollars) (Capitalization Ratios)
Common Stock:
Common stock--par value $50 per share, authorized
<S> <C> <C>
8,000,000 shares, outstanding 5,891,000 shares.... $ 294,550 $ 294,550
Other paid-in capital............................... 2,441 2,441
Retained earnings................................... 281,960 273,197
Total........................................... 578,951 570,188 50.0% 51.9%
Preferred Stock:
Cumulative preferred stock--par value $100 per share,
authorized 1,500,000 shares, outstanding as follows:
December 31, 1999
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
4.40% .... 90,000 $106.50 1945 9,000 9,000
4.80% B... 40,000 105.25 1947 4,000 4,000
4.50% C... 60,000 103.50 1950 6,000 6,000
$6.28 D... 50,000 102.86 1967 5,000 5,000
$7.73 L... 500,000 100.00 1994 50,000 50,000
Total (annual dividend requirements $5,037) 74,000 74,000 6.4 6.8
Long-Term Debt and QUIDS:
First mortgage Date of Date Date
bonds: Issue Redeemable Due
5-5/8% ... 1993 2000 2000 65,000 65,000
7-3/8% ... 1992 2002 2002 25,000 25,000
7-1/4% ... 1992 2002 2007 25,000 25,000
8-5/8% ... 1991 2001 2021 50,000 50,000
8-3/8% ... 1992 2002 2022 40,000 40,000
7-5/8% ... 1995 2005 2025 70,000 70,000
December 31, 1999
Interest Rate
Quarterly Income Debt Securities
due 2025...................... 8.00% 40,000 40,000
Secured notes due 2007-2029..... 4.70%-6.875% 81,750 74,050
Unsecured notes due 2002-2012... 4.35%-5.10% 6,060 6,060
Installment purchase
obligations due 2003.......... 4.50% 19,100 19,100
Medium-term debt due 2003-2010.. 5.56%-7.36% 153,475 43,475
Unamortized debt discount and premium, net.......... (4,083) (3,768)
Total (annual interest requirements $40,018) 571,302 453,917
Less amounts on deposit with trustees............... (2,561)
Less current maturities............................. (65,000)
Total........................................... 503,741 453,917 43.6 41.3
Total Capitalization.................................. $1,156,692 $1,098,105 100.0% 100.0%
</TABLE>
See accompanying notes to financial statements.
<PAGE>
Monongahela Power Company
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Monongahela Power Company (the Company) is a wholly owned
subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a
part of the Allegheny Energy integrated electric utility system
(the System). The Company and its utility affiliates, The
Potomac Edison Company and West Penn Power Company, collectively
now doing business as Allegheny Power, are engaged in the
generation (except West Penn), purchase, transmission,
distribution, and sale of electric energy. The Company operates
as a single utility segment in the states of West Virginia and
Ohio.
Certain amounts in the December 31, 1998, balance sheets and in
the December 31, 1998, and 1997 statement of cash flows have been
reclassified for comparative purposes.
The Company is subject to regulation by the Securities and
Exchange Commission (SEC), the Public Service Commission of West
Virginia (W.Va. PSC), the Public Utilities Commission of Ohio
(Ohio PUC), and by the Federal Energy Regulatory Commission
(FERC). Significant accounting policies of the Company are
summarized below.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.
Revenues
Revenues, including amounts resulting from the application of
fuel and energy cost adjustment clauses, are recognized in the
same period in which the related electric services are provided
to customers.
Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other utilities and power marketers,
including transmission services, are deferred until they are
either recovered from or credited to customers under fuel and
energy cost-recovery procedures in West Virginia and Ohio.
Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
affiliates in the System, are stated at original cost, less
contributions in aid of construction, except for capital leases,
which are recorded at present value. Costs include direct labor
and material; allowance for funds used during construction
(AFUDC) on property for which construction work in progress is
not included in rate base; and indirect costs such as
administration, maintenance, and depreciation of transportation
and construction equipment, postretirement benefits, taxes, and
other benefits related to employees engaged in construction.
The cost of depreciable property units retired, plus removal
costs less salvage, are charged to accumulated depreciation.
<PAGE>
Monongahela Power Company
The Company capitalizes the cost of software developed for
internal use. These costs are amortized on a straight-line basis
over a five-year period beginning upon a project's completion.
Allowance for Funds Used During Construction (AFUDC)
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including
"the net cost for the period of construction of borrowed funds
used for construction purposes and a reasonable rate on other
funds when so used." AFUDC is recognized as a cost
of property, plant, and equipment. Rates used for computing
AFUDC in 1999, 1998, and 1997 were 8.26%, 6.56%, and 7.55%,
respectively. AFUDC is not included in the cost of construction
when the cost of financing the construction is being recovered
through rates.
Depreciation and Maintenance
Depreciation expense is determined generally on a straight-line
method based on estimated service lives of depreciable properties
and amounted to approximately 3.1% of average depreciable
property in each of the years 1999, 1998, and 1997. The cost of
maintenance and of certain replacements of property, plant, and
equipment is charged principally to operating expense when
incurred.
Investments
The Company records the acquisition cost in excess of net assets
acquired as an investment in goodwill. Goodwill related to the
acquisition of West Virginia Power Company in December 1999 will
be amortized over 40 years.
Temporary Cash Investments
For purposes of the 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.
Regulatory Assets and Liabilities
In accordance with the Financial Accounting Standards Board's
(FASB) Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements include certain assets and
liabilities resulting from cost-based ratemaking regulation.
Income Taxes
The Company joins with its parent and affiliates in filing a
consolidated federal income tax return. The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.
Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period. Deferred tax assets and liabilities represent
the tax effect of temporary differences between the financial
statement and tax basis of assets and liabilities computed using
the most current tax rates.
The Company has deferred the tax benefit of investment tax
credits. Investment tax credits are amortized over the estimated
service lives of the related properties.
<PAGE>
Monongahela Power Company
Postretirement Benefits
All of the employees of Allegheny Energy are employed by
Allegheny Energy Service Corporation (AESC), which performs
services at cost for the Company and its affiliates in accordance
with the Public Utility Holding Company Act of 1935 (PUHCA).
Through AESC, the Company is responsible for its proportionate
share of postretirement benefit costs. AESC provides a
noncontributory, defined benefit pension plan covering
substantially all employees, including officers. Benefits are
based on the employee's years of service and compensation. The
funding policy is to contribute annually at least the minimum
amount required under the Employee Retirement Income Security Act
and not more than can be deducted for federal income tax
purposes. Plan assets consist of equity securities, fixed income
securities, short-term investments, and insurance contracts.
AESC also provides partially contributory medical and life
insurance plans for eligible retirees and dependents. Medical
benefits, which make up the largest component of the plans, are
based upon an age and years-of-service vesting schedule and other
plan provisions. Subsidized medical coverage is not provided in
retirement to employees hired on or after January 1, 1993. The
funding policy is to contribute the maximum amount that can be
deducted for federal income tax purposes. Funding of these
benefits is made primarily into Voluntary Employee Beneficiary
Association trust funds. Medical benefits are self-insured. The
life insurance plan is paid through insurance premiums.
Comprehensive Income
SFAS No. 130, "Reporting Comprehensive Income," effective for
1998, established standards for reporting comprehensive income
and its components (revenues, expenses, gains, and losses) in the
financial statements. The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.
NOTE B: ACQUISITIONS
In December 1999, the Company acquired the assets of West
Virginia Power for approximately $95 million. The acquisition
increased property, plant, and equipment and accumulated
depreciation by $105.0 million and $35.4 million, respectively.
Also, $26.3 million was recorded as the excess of cost over net
assets acquired.
In December 1999, the Company agreed to acquire Mountaineer Gas
Company for $323 million, which includes the assumption of
approximately $100 million of existing debt. Completion of the
transaction is conditioned upon, among other things, certain
regulatory approvals which may be obtained by mid-2000.
<PAGE>
Monongahela Power Company
NOTE C: INCOME TAXES
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1999 1998 1997
Income taxes--current:
Federal............................. $27,391 $26,457 $21,812
State............................... 8,637 8,135 7,455
Total............................. 36,028 34,592 29,267
Income taxes--deferred, net of
amortization........................ 6,849 16,971 20,287
Amortization of deferred
investment credit................... (2,148) (2,144) (2,148)
Total income taxes................ 40,729 49,419 47,406
Income taxes--(charged) credited to
other income and deductions......... (289) 37 113
Income taxes--charged to operating
income.............................. $40,440 $49,456 $47,519
The total provision for income taxes is different from the amount
produced by applying the federal income statutory tax rate to
financial accounting income, as set forth below:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1999 1998 1997
<S> <C> <C> <C>
Income before income taxes............ $132,769 $131,881 $128,048
Amount so produced.................... $ 46,469 $ 46,158 $ 44,817
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation.......... 1,077 1,800 5,000
Plant removal costs............. (2,935) (2,600) (2,400)
State income tax, net of federal
income tax benefit................ 4,968 4,400 3,600
Amortization of deferred
investment credit................. (2,148) (2,144) (2,148)
Equity in earnings of subsidiaries.. (1,984) (2,100) (3,000)
Other, net.......................... (5,007) 3,942 1,650
Total............................. $ 40,440 $ 49,456 $ 47,519
</TABLE>
Federal income tax returns through 1995 have been examined and
substantially settled.
<PAGE>
Monongahela Power Company
At December 31, the deferred tax assets and liabilities consisted
of the following:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1999 1998
Deferred tax assets:
<S> <C> <C>
Unamortized investment tax credit............... $ 9,264 $ 10,779
Tax interest capitalized........................ 4,216 4,269
Contributions in aid of construction............ 3,069 2,810
Advances for construction....................... 2,024 2,097
Internal restructuring.......................... 1,810 1,810
Deferred power costs, net....................... 2,254
Other........................................... 16,280 14,358
38,917 36,123
Deferred tax liabilities:
Book vs. tax plant basis differences, net....... 248,801 244,432
Other........................................... 36,842 38,420
285,643 282,852
Total net deferred tax liabilities................ 246,726 246,729
Portion above included in current assets.......... 2,261 501
Total long-term net deferred tax liabilities.... $248,987 $247,230
</TABLE>
NOTE D: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $76,384,000 of the Company's retained
earnings at December 31, 1999, is not available for cash
dividends on common stock, except that a portion thereof may be
paid as cash dividends where concurrently an equivalent amount of
cash is received by the Company as a capital contribution or as
the proceeds of the issue and sale of shares of its common stock.
NOTE E: ALLEGHENY GENERATING COMPANY
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 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 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>
Monongahela Power Company
Following is a summary of financial information for AGC:
<TABLE>
<CAPTION>
December 31
(Thousands of Dollars) 1999 1998
Balance sheet information:
<S> <C> <C>
Property, plant, and equipment............... $601,717 $618,608
Current assets............................... 7,261 5,857
Deferred charges............................. 11,905 14,993
Total assets............................... $620,883 $639,458
Total capitalization......................... $303,422 $314,105
Current liabilities.......................... 65,463 75,849
Deferred credits............................. 251,998 249,504
Total capitalization and liabilities....... $620,883 $639,458
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
(Thousands of Dollars) 1999 1998 1997
Income statement information:
<S> <C> <C> <C>
Electric operating revenues......... $70,592 $73,816 $76,458
Operation and maintenance expense... 5,023 4,592 4,877
Depreciation........................ 16,980 16,949 17,000
Taxes other than income taxes....... 4,510 4,662 4,835
Federal income taxes................ 9,997 10,959 11,213
Interest charges.................... 13,261 13,987 15,391
Other income, net................... (394) (86) (9,126)
Net income........................ $21,215 $22,753 $32,268
</TABLE>
The Company's share of the equity in earnings was $5.7 million,
$6.1 million, and $8.7 million for 1999, 1998, and 1997,
respectively, and is included in other income, net, on the
Company's Statement of Income.
NOTE F: POSTRETIREMENT BENEFITS
As described in Note A, the Company is responsible for its
proportionate share of the cost of the pension plan and medical
and life insurance plans for eligible employees and dependents
provided by AESC. The Company's share of the (credits) costs of
these plans, a portion of which (approximately 35%) was credited
or charged to plant construction, is shown below:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1999 1998 1997
<S> <C> <C> <C>
Pension................................ $(1,037) $ (356) $(1,754)
Medical and life insurance............. $ 4,806 $ 5,421 $ 3,706
</TABLE>
Monongahela Power Company
NOTE G: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS
No. 71. Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered
from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers
through the ratemaking process. Regulatory assets, net of
regulatory liabilities, reflected in the Balance Sheet at
December 31 relate to:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1999 1998
Long-term assets (liabilities), net:
<S> <C> <C>
Income taxes, net.............................. $124,028 $130,878
Postretirement benefits........................ 4,937 4,937
Storm damage................................... 1,047
Other, net..................................... 2,250 2,544
Subtotal..................................... 131,215 139,406
Current assets (liabilities), net (reported in
other current assets/liabilities):
Income taxes, net.............................. 1,847 1,847
Deferred power costs, net...................... (5,021) 6,878
Subtotal..................................... (3,174) 8,725
Net Regulatory Asset...................... $128,041 $148,131
</TABLE>
Future deregulation proceedings in West Virginia and Ohio may
affect the ratemaking treatment of the net regulatory assets
related to generation in these jurisdictions. At this time, the
Company cannot determine the effect of deregulation plans in West
Virginia and Ohio.
NOTE H: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:
<TABLE>
<CAPTION>
1999 1998
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Liabilities:
<S> <C> <C> <C> <C>
Short-term debt....... $ 28,650 $ 28,650 $ 49,000 $ 49,000
Long-term debt and
QUIDS............... 575,385 547,872 457,685 483,695
</TABLE>
The carrying amount of short-term debt approximates the fair
value because of the short maturity of those instruments. The
fair value of long-term debt and QUIDS was estimated based on
actual market prices or market prices of similar issues. The
Company had no financial instruments held or issued for trading
purposes.
Monongahela Power Company
NOTE I: CAPITALIZATION
Preferred Stock
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share.
Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the
next five years are: 2000, $65,000; 2001, none; 2002, $27,060;
2003, $62,575; and 2004, none. Substantially all of the
properties of the Company are held subject to the lien securing
its first mortgage bonds. Some properties are also subject to a
second lien securing certain pollution control and solid waste
disposal notes. Certain first mortgage bonds series are not
redeemable by certain refunding until dates established in the
respective supplemental indentures.
NOTE J: SHORT-TERM DEBT
To provide interim financing and support for outstanding
commercial paper, the Company has established lines of
credit with several banks. The Company has SEC authorization for
total short-term borrowings of $106 million, including money pool
borrowings described below. The Company has fee arrangements on
all of its lines of credit and no compensating balance
requirements. In addition to bank lines of credit, an Allegheny
Energy internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated
companies have funds available. Short-term debt outstanding for
1999 and 1998 consisted of:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1999 1998
Balance and interest rate
at end of year:
<S> <C> <C>
Notes Payable to Banks............. $49,000-5.40%
Money Pool......................... $28,650-4.88%
Average amount outstanding and
interest rate during the year:
Commercial Paper................... 1,156-4.79% 12,900-5.66%
Notes Payable to Banks............. 5,636-5.05% 21,793-5.60%
Money Pool......................... 2,009-5.05% 3,764-5.46%
</TABLE>
NOTE K: RELATED PARTY TRANSACTION
All of the employees of Allegheny Energy are employed by AESC,
which performs services at cost for the Company and its
affiliates in accordance with the PUHCA. Through AESC, the
Company is responsible for its proportionate share of services
provided by AESC. The total billings by AESC (including capital)
to the Company for each of the years of 1999, 1998, and 1997 were
$115.4 million, $95.6 million, and $78.8 million, respectively. The
Company buys power from and sells power to its affiliates at tariff
rates approvd by the FERC.
NOTE L: COMMITMENTS AND CONTINGENCIES
Construction Program
The Company has entered into commitments for its construction
programs, for which expenditures are estimated to be $75 million
for 2000 and $72 million for 2001. In addition, in 2000, the
Company plans to purchase Mountaineer Gas Company for
approximately $323 million (which includes the assumption of
approximately $100 million in existing debt). Construction
expenditure levels
<PAGE>
Monongahela Power Company
in 2002 and beyond will depend upon, among other things, the
strategy eventually selected for complying with Phase II of the
Clean Air Act Amendments of 1990 (CAAA) and the extent to which
environmental initiatives currently being considered become
mandated. The Company estimates that its banked emission
allowances will allow it to comply with Phase II sulfur dioxide
(SO2) limits through 2005. Studies to evaluate cost-effective
options to comply with Phase II SO2 limits beyond 2005, including
those available in connection with the emission allowance trading
market, are continuing.
West Virginia and Ohio Restructuring Activities
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 W.Va. PSC on December 20,
1999, released for comment and hearings a modified version of a
proposal submitted by members of the Task Force, including the
Company and its affiliate, Potomac Edison, following the August
1999 hearings that could open full retail competition as early as
January 1, 2001. The production of power would be deregulated
and electricity rates would be frozen for four years with rates
gradually transitioning to market rates over the six years
thereafter. After hearings in January 2000, the W.Va. PSC
submitted a restructuring plan endorsed by members of the Task
Force, including the Company and Potomac Edison, to the
Legislature for approval.
On June 22, 1999, the Ohio General Assembly passed legislation to
restructure the electric utility industry. The Governor of Ohio
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 5% cut in the
generation portion of their rate. The determination of stranded
cost recovery will be handled by the Ohio PUC. On January 3,
2000, the Company filed a transition plan with the Ohio PUC,
including its claim for recovery of stranded costs of $21.3
million. The Ohio PUC is expected to hold hearings on the
Company's transition plan filing and issue a decision by October
2000.
The Ohio legislation stipulates that an entity independent of the
utilities shall own or control transmission facilities after the
start of competitive retail electric service on January 1, 2001,
but not later than December 31, 2003. 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 1997, the Emerging Issues Task Force (EITF) issued EITF No.
97-4, "Deregulation of the Pricing of Electricity-Issues Related
to the Application of FASB Statement Nos. 71 and 101." The EITF
agreed that, when a rate order that contains sufficient detail
for the enterprise to reasonably determine how the transition
plan will affect the separable portion of its business whose
pricing is being deregulated is issued, the entity should cease
to apply SFAS No. 71 to that separable portion of its business.
<PAGE>
Monongahela Power Company
At this time, the Company cannot determine the effect of
deregulation plans that may be approved in West Virginia or Ohio.
However, the approval of deregulation plans could have a material
impact on the Company regarding potential impairment of electric
generation assets and the Company's ability to recover generation-
related regulatory assets.
Environmental Matters and Litigation
The Company is subject to various laws, regulations, and
uncertainties as to environmental matters. Compliance may
require the Company to incur substantial additional costs to
modify or replace existing and proposed equipment and facilities
and may adversely affect the cost of future operations.
The Environmental Protection Agency (EPA) issued its final
regional nitrogen oxides (NOx) State Implementation Plan (SIP)
call rule on September 24, 1998. The EPA's SIP call rule found
that 22 eastern states (including Maryland, Pennsylvania, and
West Virginia) and the District of Columbia are all contributing
significantly to ozone nonattainment in downwind states. The
final rule declares that this downwind nonattainment will be
eliminated (or sufficiently mitigated) if the upwind states
reduce their NOx emissions by an amount that is precisely set by
the EPA on a state-by-state basis. The final SIP call rule
requires that all state-adopted NOx reduction measures must be
incorporated into SIPs by September 1999, and must be implemented
by May 1, 2003. However, the EPA's NOx SIP call regulation is
currently under litigation in the District of Columbia Circuit
Court of Appeals, and a decision is expected by Spring 2000. The
Company's compliance with these requirements would require the
installation of post-combustion control technologies on most, if
not all, of its power stations at a cost of approximately $99
million. The Company continues to work with other coal-burning
utilities and other affected constituencies in coal-producing
states to challenge this EPA action.
On March 4, 1994, the Company and its regulated affiliates
received notice that the EPA had identified them as potentially
responsible parties (PRPs) under the Comprehensive Environmental
Response, Compensation, and Liability Act of 1980, as amended,
with respect to a Superfund Site. There are approximately 175
other PRPs involved. A final determination has not been made for
the Company and its regulated affiliates' share of the
remediation costs based on the amount of materials sent to the
site. However, the Company and its regulated affiliates estimate
that their combined share of the cleanup liability will not
exceed $1 million, which has been accrued by the Company and its
regulated affiliates as a liability at December 31, 1999.
The Company and its regulated affiliates have also been named as
defendants, along with multiple other defendants, in pending
asbestos cases involving multiple plaintiffs. While the Company
believes that all of the cases are without merit, the Company
cannot predict the outcome of the litigation. The Company has
accrued a reserve of $2.2 million as of December 31, 1999,
related to the asbestos cases as the potential cost to settle the
cases to avoid the anticipated cost of defense.
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 of their intent to commence civil actions
against Allegheny Energy or certain of its subsidiaries alleging
violations at the Fort Martin Power Station under the federal
Clean Air Act, which requires existing power plants that make
major modifications to comply
<PAGE>
Monongahela Power Company
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 and is now jointly owned by the Company and its
affiliates, Allegheny Energy Supply Company and Potomac Edison.
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 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 effect, if any, these actions threatened by the Attorneys
General of New York and Connecticut may have on them.
In the normal course of business, the Company becomes involved in
various legal proceedings. The Company does not believe that the
ultimate outcome of these proceedings will have a material effect
on its financial position.
Leases
The Company's lease obligations as of December 31, 1999, and 1998
were not material.
<PAGE>
Monongahela Power Company
REPORT OF MANAGEMENT
The management of the Company is responsible for the information
and representations in the Company's financial statements. The
Company prepares the financial statements in accordance with
generally accepted accounting principles based upon available
facts and circumstances and management's best estimates and
judgments of known conditions.
The Company maintains an accounting system and related system of
internal controls designed to provide reasonable assurance that
the financial records are accurate and that the Company's assets
are protected. The Company's staff of internal auditors conducts
periodic reviews designed to assist management in maintaining the
effectiveness of internal control procedures.
PricewaterhouseCoopers LLP, an independent accounting firm,
audits the financial statements and expresses its opinion on
them. The independent accountants perform their audit in
accordance with generally accepted auditing standards.
The Audit Committee of the Board of Directors, which consists of
three outside Directors, meets periodically with management,
internal auditors, and PricewaterhouseCoopers LLP to review the
activities of each in discharging their responsibilities. The
internal audit staff and PricewaterhouseCoopers LLP have free
access to all of the Company's records and to the Audit
Committee.
Alan J. Noia Michael P.Morrell
Chairman and Vice President and
Chief Executive Officer Chief Financial Officer
<PAGE>
Monongahela Power Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholder
of Monongahela Power Company
In our opinion, the accompanying balance sheets, statements of
capitalization and the related statements of income, of retained
earnings and of cash flows present fairly, in all material
respects, the financial position of Monongahela Power Company (a
subsidiary of Allegheny Energy, Inc.) at December 31, 1999 and
1998, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1999, in
conformity with accounting principles generally accepted in the
United States. These financial statements are the responsibility
of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States, which
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used
and significant estimates made by management, and evaluating the
overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed
above.
PricewaterhouseCoopers LLP
Pittsburgh, Pennsylvania
February 3, 2000
<PAGE>
Monongahela Power Company
QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)
<TABLE>
<CAPTION>
Quarter Ended
1999 1998
Dec. Sept. June March Dec. Sept. June March
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Electric operating
revenues ............. $163,904 $178,330 $160,459 $170,642 $155,712 $177,364 $153,774 $158,272
Operating income........ 31,019 32,595 25,102 30,321 28,154 31,887 24,087 27,358
Net income.............. 23,890 26,631 18,556 23,250 21,143 25,244 16,611 19,427
</TABLE>
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995 1994
<S> <C> <C> <C> <C> <C> <C>
Electric operating revenues:
Residential.......................... $210,757 $200,896 $199,931 $206,033 $209,065 $190,861
Commercial........................... 130,052 126,464 118,825 121,631 124,457 116,201
Industrial........................... 217,792 208,613 196,716 200,970 212,427 202,181
Wholesale and street lighting........ 7,138 7,656 7,600 7,513 7,255 7,142
Revenues from regular customers.... 565,739 543,629 523,072 536,147 553,204 516,385
Affiliated........................... 84,747 77,314 83,600 74,825 73,216 79,674
Other non-kWh........................ 4,299 4,426 4,379 4,136 3,722 3,535
Bulk power........................... 6,567 8,509 7,299 4,772 2,749 7,681
Transmission and other energy
services........................... 11,983 11,244 9,961 12,591 10,589 9,172
Total revenues..................... 673,335 645,122 628,311 632,471 643,480 616,447
Operation expense...................... 345,565 313,795 305,487 310,480 330,740 330,909
Maintenance............................ 63,993 67,033 70,561 74,735 73,041 69,389
Internal restructuring charges
and asset write-off.................. 24,299 5,493
Depreciation........................... 60,905 58,610 56,593 55,490 57,864 57,952
Taxes other than income................ 43,395 44,742 38,776 40,418 38,551 40,404
Taxes on income........................ 40,440 49,456 47,519 34,496 41,834 30,650
Allowance for funds used
during construction.................. (1,774) (1,043) (1,386) (672) (1,393) (2,946)
Interest charges....................... 34,603 36,153 38,730 38,604 39,872 38,156
Other income, net...................... (6,119) (6,049) (8,498) (6,831) (9,235) (8,003)
Income before cumulative effect
of accounting change................. 92,327 82,425 80,529 61,452 66,713 59,936
Cumulative effect of accounting
change, net (a)...................... 7,945
Net income............................. $ 92,327 $ 82,425 $ 80,529 $ 61,452 $ 66,713 $ 67,881
Return on average common equity (b).... 15.29% 13.62% 13.99% 11.00% 11.92% 10.66%
</TABLE>
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994
and a charge for a long dormant pumped-storage generation project
in 1999. Includes the effect of internal restructuring in 1995 and 1996.
<PAGE>
Monongahela Power Company
FINANCIAL AND OPERATING STATISTICS
<TABLE>
<CAPTION>
1999 1998 1997 1996 1995 1994
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross.............................. $2,173,603 $2,007,876 $1,950,478 $1,879,622 $1,821,613 $1,763,533
Accumulated depreciation........... (958,867) (883,915) (840,525) (790,649) (747,013) (701,271)
Net.............................. $1,214,736 $1,123,961 $1,109,953 $1,088,973 $1,074,600 $1,062,262
GROSS ADDITIONS TO PROPERTY
(Thousands):......................... $ 82,483 $ 72,795 $ 78,139 $ 72,577 $ 75,458 $ 103,975
TOTAL ASSETS at Dec. 31
(Thousands).......................... $1,693,718 $1,519,764 $1,497,756 $1,486,742 $1,480,591 $1,476,483
CAPITALIZATION at Dec. 31
(Thousands):
Common stock....................... $ 578,951 $ 570,188 $ 540,930 $ 512,212 $ 505,752 $ 495,693
Preferred stock.................... 74,000 74,000 74,000 74,000 74,000 114,000
Long-term debt and QUIDS........... 503,741 453,917 455,088 474,841 489,995 470,131
$1,156,692 $1,098,105 $1,070,018 $1,061,053 $1,069,747 $1,079,824
Ratios:
Common stock....................... 50.0% 51.9% 50.6% 48.3% 47.3% 45.9%
Preferred stock.................... 6.4 6.8 6.9 7.0 6.9 10.6
Long-term debt and QUIDS........... 43.6 41.3 42.5 44.7 45.8 43.5
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31:
Company-owned...................... 2,352,250 2,326,300 2,326,300 2,326,300 2,326,300 2,326,300
Nonutility contracts (a)........... 161,000 161,000 161,000 161,000 161,000 161,000
KILOWATT-HOURS (Thousands):
Sales Volumes:
Residential........................ 2,884,144 2,757,067 2,764,630 2,815,414 2,807,135 2,674,664
Commercial......................... 2,148,361 2,102,604 1,987,147 2,007,116 1,967,473 1,846,791
Industrial......................... 5,736,718 5,510,925 5,224,364 5,024,257 5,114,126 4,942,388
Wholesale and street lighting...... 152,476 142,797 142,827 142,198 138,456 134,351
Sales to regular customers....... 10,921,699 10,513,393 10,118,968 9,988,985 10,027,190 9,598,194
Affiliated......................... 2,746,111 1,950,803 2,080,542 1,694,722 1,596,081 1,791,099
Bulk power......................... 191,784 301,656 249,505 196,843 105,126 285,048
Transmission and other energy
services......................... 2,138,247 1,932,160 3,007,439 4,218,150 3,497,216 2,278,111
Total sales volumes............ 15,997,841 14,698,012 15,456,454 16,098,700 15,225,613 13,952,452
Output and Delivery:
Steam generation................... 12,146,537 11,251,721 10,936,469 10,678,491 10,620,003 10,743,934
Pumped-storage generation.......... 372,658 288,266 241,958 263,640 257,284 290,586
Pumped-storage input............... (481,872) (370,822) (310,565) (337,451) (330,915) (373,116)
Purchased power.................... 2,562,752 2,283,055 2,294,059 2,040,136 1,903,644 1,685,938
Transmission and other energy
services......................... 2,138,247 1,932,160 3,007,439 4,218,150 3,497,216 2,278,111
Losses and system uses............. (740,481) (686,368) (712,906) (764,266) (721,619) (673,001)
Total transactions as above.... 15,997,841 14,698,012 15,456,454 16,098,700 15,225,613 13,952,452
CUSTOMERS at Dec. 31:
Residential.......................... 312,180 309,760 307,920 305,579 303,568 300,465
Commercial........................... 38,654 37,929 37,168 36,323 35,793 35,268
Industrial........................... 8,014 7,992 7,996 8,019 8,085 8,029
Other................................ 176 218 199 182 170 171
Total customers.................... 359,024 355,899 353,283 350,103 347,616 343,933
RESIDENTIAL SERVICE:
Average use-
kWh per customer................... 9,283 8,938 9,023 9,256 9,306 8,957
Average revenue-
dollars per customer............... 678.38 651.29 652.53 677.37 693.11 639.16
Average rate-
cents per kWh...................... 7.31 7.29 7.23 7.32 7.45 7.14
</TABLE>
(a) Capability available through contractual arrangements with nonutility
generator.
<PAGE>
EXHIBIT 99.2
1999 Annual Report
Monongahela Power Company
<PAGE>
Monongahela Power Company
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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 Monongahela Power Company
(the Company), 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 ongoing state and federal activities; developments in
the legislative and regulatory environments in which the Company
operates, including regulatory proceedings affecting rates
charged by the Company; environmental, legislative, and
regulatory changes; future economic conditions; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power and fuel for electric generation, unscheduled maintenance
or repair requirements, weather, and compliance with laws and
regulations.
Business Strategy
A component of the deregulation plans sponsored by the Company in
West Virginia and Ohio is the authority to transfer electric
generation assets at net book value to an unregulated affiliate.
Subject to the approval of the deregulation plans by the West
Virginia legislature and the Public Utilities Commission of Ohio
(Ohio PUC), the Company plans to transfer its generation assets
to Allegheny Energy Supply Company, LLC (Allegheny Energy
Supply). Allegheny Energy Supply is a subsidiary of Allegheny
Energy, Inc. (Allegheny Energy), the Company's Parent.
The settlement agreement in Pennsylvania permitted the Company's
affiliate, West Penn Power Company (West Penn), to transfer 3,778
megawatts (MW) of generating capacity at net book value to
Allegheny Energy Supply in 1999.
The recent settlement in Maryland will allow approximately 1,300
MW of additional generating capacity to be transferred at net
book value in 2000. Allegheny Energy is seeking to transfer the
remaining generating assets in Ohio, Virginia, and West Virginia
to its unregulated subsidiary at book value in deregulation
proceedings in these jurisdictions. The unregulated electric
supply is being sold in both the wholesale and retail competitive
marketplaces, allowing greater earnings growth potential, subject
to market risk, while allowing Allegheny Energy to capitalize on
its strengths in the generation business.
Following the transfer of generation assets to Allegheny Energy
Supply, the Company will be part of Allegheny Energy's delivery
business (wires and pipes). The delivery business will remain an
important part of Allegheny Energy's business which Allegheny
Energy plans to expand.
<PAGE>
Monongahela Power Company
SIGNIFICANT EVENTS IN 1999, 1998, AND 1997
Acquisitions
In December 1999, the Company purchased from UtiliCorp United
Inc. 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 United's subsidiary, Aquila Energy, for gas supply to
the Company. Electricity is being supplied under an existing
contract with American Electric Power until December 31, 2001,
and thereafter will be supplied from the existing generation of
Allegheny Energy or from the market. Consumers will benefit from a
six-year freeze of natural gas base rates and a three-year freeze
of electric rates, with a reduction in electric rates in 2003 to
rates now offered by the Company. The acquisition included
26,000 electric and 24,000 natural gas customers, 1,989 miles of
electric distribution lines, 670 miles of gas pipelines, and
1,360 square miles of electric and 500 square miles of gas
service territory. West Virginia Power had approximately 120
employees.
In conjunction with the acquisition of West Virginia Power's
assets, Allegheny Energy purchased for $2.1 million the assets of
a heating, ventilation, and air conditioning business with
approximately 10,000 customers and 52 employees.
The Company also plans to purchase Mountaineer Gas Company, a
natural gas sales, transportation, and distribution company
serving southern West Virginia and the northern and eastern
panhandles of West Virginia, from Energy Corporation of America
for $323 million (which includes the assumption of approximately
$100 million in existing debt). The planned acquisition also
includes the assets of Mountaineer Gas Services, which operates
natural gas-producing properties, natural gas-gathering
facilities, and intrastate transmission pipelines. Mountaineer
Gas has 490 employees, approximately 200,000 residential,
commercial, and industrial gas customers, 3,926 miles of gas
pipeline, and 11.7 billion cubic feet of gas storage. The
completion of the transaction is conditioned upon, among other
things, the approvals of the Public Service Commission of West
Virginia (W.VA. PSC) and the Securities and Exchange Commission
(SEC). The companies anticipate that regulatory approval could
be received by mid-2000.
PURPA Power Project Termination
In 1999, the Company settled for $2.3 million litigation by a
developer alleging failure by the Company to comply with the
Public Utility Regulatory Policies Act of 1978 (PURPA) regulations.
Electric Industry Restructuring
See Electric Energy Competition on page 8 for ongoing information
regarding electric industry restructuring.
<PAGE>
Monongahela Power Company
REVIEW OF OPERATIONS
Earnings Summary
(Millions of Dollars) 1999 1998 1997
Net Income............................... $92.3 $82.4 $80.5
The increase in 1999 earnings resulted, in part, from increased
retail kilowatt-hour (kWh) sales, including increased sales to
residential customers due to winter weather that was cooler than
the relatively warm winter of 1998, as measured by heating degree
days. The increase is also due to a 1999
decrease in federal and state income taxes of $9.0 million
primarily due to the Company's share of tax savings in
consolidation related to its parent, Allegheny Energy, and to a
net change in income tax provisions related to prior years. The
1998 increase in earnings resulted from increased kWh sales to
commercial and industrial customers and from reduced power
station operations and maintenance spending.
Sales and Revenues
Percentage changes in revenues and kWh sales in 1999 and 1998 by
major retail customer classes were:
1999 vs. 1998 1998 vs. 1997
Revenues kWh Revenues kWh
Residential................. 4.9% 4.6% 0.5% (0.3)%
Commercial.................. 2.8 2.2 6.4 5.8
Industrial.................. 4.4 4.1 6.0 5.5
Total..................... 4.2% 3.8% 4.0% 4.0 %
The 1999 increase 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, and to a
lesser extent, growth in the number of customers. Colder winter
weather in 1999 led to the increased residential KWh sales and
revenues. The growth in the number of residential customers was
.8% and .6% in 1999 and 1998, respectively.
Commercial kWh sales are also affected by weather, but to a
lesser extent than residential. The 2.2% and 5.8% increases in
1999 and 1998, respectively, reflect growth in the number of
customers and increased usage. The increase in industrial kWh
sales in 1999 was due to increased kWh sales to iron and steel
customers and to paper and printing product customers. The
increase in industrial kWh sales in 1998 was primarily due to
increased sales to one of the Company's customers who switched an
additional portion of their load requirements to the Company in
September 1997.
On February 26, 1999, the W.Va. PSC entered an order to initiate
a fuel review proceeding to establish a fuel increment in rates
for the Company and its affiliate, The Potomac Edison Company, to
be effective July 1, 1999, through June 30, 2000. The parties
have exchanged proposals which continue to be discussed. If an
agreement is not reached, the proposed fuel rates which would
increase the Company's fuel rates by $10.9 million will become
effective March 15, 2000.
<PAGE>
Monongahela Power Company
Changes in revenues from retail customers resulted from the
following:
Changes from Prior Year
(Millions of Dollars) 1999 vs. 1998 1998 vs. 1997
Fuel clauses............................... $ 9.4 $11.8
All other.................................. 13.2 8.7
Net change in retail revenues............ $22.6 $20.5
Revenues reflect not only 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 customers'
bills through fuel clauses. The Company expects that the fuel
clause rates in Ohio and West Virginia will cease as these states
implement customer choice. The Company will then assume the
risks and benefits of changes in fuel and purchased power costs
and sales of transmission services and bulk power.
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 1999 and 1998 all other retail revenues were
primarily the result of increased customer usage and growth in
the number of customers.
Wholesale and other revenues were as follows:
(Millions of Dollars) 1999 1998 1997
Wholesale customers...................... $ 4.6 $ 5.2 $ 4.9
Affiliated companies..................... 84.7 77.3 83.6
Street lighting and other................ 6.9 6.9 7.1
Total wholesale and other revenues..... $96.2 $89.4 $95.6
Wholesale customers are cooperatives and municipalities that own
their 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. All of the Company's wholesale customers
have signed contracts to remain as customers until November 30,
2003.
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. The 1999 increase of $7.4 million in
affiliated revenues was due to increased energy sales to
affiliates. As a result of increased generation at one of the
Company's power stations in 1999, the Company had more generation
available for sale after meeting the needs of its regular
customers. Some of this excess generation was sold to affiliates
to meet their needs. The affiliated
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Monongahela Power Company
revenue decrease in 1998 resulted primarily from decreased
generating capacity sales.
Bulk power transactions include sales of bulk power and
transmission and other energy services to power marketers and
other utilities. Bulk power and transmission and other energy
services sales for 1999, 1998, and 1997 were as follows:
1999 1998 1997
KWh Transactions (in billions):
Bulk power............................... .2 .3 .3
Transmission and other energy services
to nonaffiliated companies............. 2.1 1.9 3.0
Total................................ 2.3 2.2 3.3
Revenues (in millions):
Bulk power............................... $ 6.6 $ 8.5 $ 7.3
Transmission and other energy services
to nonaffiliated companies............. 12.0 11.3 10.0
Total................................ $18.6 $19.8 $17.3
Revenues from bulk power transactions decreased in 1999 due to
decreased sales to power marketers and other utilities. The 1998
increase in revenues from bulk power was due to increased sales
that occurred primarily in the second quarter as a result of warm
weather which increased the demand and price for energy.
Revenues from transmission and other energy services in 1999 and
1998 increased $.7 million and $1.3 million, respectively.
Revenues from transmission and other energy services increased in
1999 due primarily to increased megawatt-hours (MWh) transmitted.
The increase in 1998 revenues, despite decreased transmission
services activity, was due to transmission services' reservation
charges paid to the Company by others for the right to transmit
energy. Transmission services activity was affected as a result
of some of the reservations to transmit energy not being used. In
1998, revenues from transmission and other energy services were
affected by a revenue refund resulting from a reduction in the
Company's standard transmission rate and rates for ancillary
services which were approved by the FERC. A provision
of $1.7 million for these rate reductions was recorded in 1998,
with revenues refunded to customers in the first quarter of 1999.
In June and July 1999 and June and July 1998, certain events
combined to produce significant volatility in the spot prices for
electricity at the wholesale level. These events included
extremely hot weather, generation unit outages, and transmission
constraints. Wholesale prices for electricity rose from a normal
range of $25 to $40 per MWh to as high as $3,500 to $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 may be positive or
negative, depending on whether the Company is a net buyer or
seller of electricity during such periods. The effect of such
price volatility in June and July of 1999 and 1998 was
insignificant to the Company because changes are passed through
to customers through operation of fuel clauses. The Company
expects that the fuel clause rates in Ohio and West Virginia will
cease
<PAGE>
Monongahela Power Company
as these states implement customer choice. The company will then
assume the risks and benefits of changes in fuel and purchased
power costs and sales of transmission services and bulk power.
Operating Expenses
Fuel expenses increased .9% in 1999 due to an 8.9% increase
related to kWhs generated, offset in part by an 8% decrease in
average fuel prices. The increase in kWhs generated was to meet
retail customer requirements and increased sales to affiliates.
The decrease in average fuel prices was due to renegotiated fuel
contracts. The 1.9% increase in fuel expenses in 1998 was due
primarily to an increase in kWhs generated.
Purchased power and exchanges, net, represents power purchases
from and exchanges with other companies and purchases from
qualified facilities under the PURPA, capacity charges paid to
Allegheny Generating Company (AGC), and other transactions with
affiliates made pursuant to a power supply agreement whereby each
company uses the most economical generation available in the
System at any given time, and consists of the following items:
(Millions of Dollars) 1999 1998 1997
Nonaffiliated transactions:
Purchased power:
From PURPA generation*................ $65.1 $65.5 $69.8
Other................................. 15.1 11.6 9.6
Power exchanges, net.................... (.6) (.2) .1
Affiliated transactions:
AGC capacity charges.................... 19.1 18.4 18.5
Energy and spinning reserve charges..... .1 .3 .3
Purchased power and exchanges, net.... $98.8 $95.6 $98.3
*PURPA cost (cents per kWh) .052 .051 .053
The decrease in purchased power from PURPA generation in 1998 was
due primarily to reduced generation at hydroelectric plants due
to reduced river flow. The increase in other purchased power in
1999 resulted primarily from
increased purchases for sales. An increase in price caused by
volatility in the spot prices for electricity at the wholesale
level in the second and third quarters of 1998 contributed to the
1998 increase in other purchased power costs.
The increase in other operation expenses of $8.0 million in 1999
resulted primarily from a write-off of $4.2 million of costs
related to a pumped-storage generation project no longer
considered useful, $2.3 million of costs associated with settling
litigation concerning a PURPA project, and increases in salaries
and wages costs. The increase in other operations expenses in
1998 resulted primarily from increases in salaries and wages and
employee benefits, increased property insurance expense, and an
increase in expense related to Year 2000 readiness.
Maintenance expenses decreased in 1999 by $3.0 million due to
decreases in transmission and distribution maintenance expenses,
offset in part by increases in general plant maintenance which
includes renovations of office facilities. The decrease in
maintenance expenses in 1998 was due primarily to
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Monongahela Power Company
a management program to postpone such expenses for the year in response to
limited sales growth in the first quarter due to the warm winter
weather. The Company postponed these expenses primarily by
extending the time between maintenance outages and experienced no
measurable effect on system performance.
Maintenance expenses represent costs incurred to maintain the
power stations, the transmission and distribution (T&D) system
and general plant, and to 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 1999 and 1998 increased $2.3 million and
$2.0 million, respectively, due to increased investment.
Taxes other than income taxes decreased $1.3 million in 1999 due
primarily to a 1998 adjustment to West Virginia Business and
Occupation Taxes for a prior period. Taxes other than income
taxes increased $6.0 million in 1998 due primarily to West
Virginia Business and Occupation Taxes.
The decrease in federal and state income taxes of $9.0 million
was primarily due to the Company's share of tax savings in
consolidation related to its parent, Allegheny Energy, and to a
net change in income tax provisions related to prior years. The
1998 increase in federal and state income taxes was primarily due
to increased taxable income. Note C to the financial statements
provides a further analysis of income tax expenses.
Other Income and Deductions
The decrease in other income, net, of $2.4 million in 1998 was
primarily due to a 1997 interest refund on a tax-related contract
settlement ($2.2 million after taxes) received by AGC, which is
partly owned by the Company.
Interest Charges
The decrease in interest on long-term debt in 1998 of $3.7
million resulted from reduced long-term debt and lower interest
rates. Other interest expense reflects changes in the levels of
short-term debt maintained by the Company throughout the year, as
well as the associated interest rates.
FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the
sale of common and preferred stock, debt instruments, installment
loans, and lease arrangements. The timing and amount of external
financings depend primarily upon economic and financial market
conditions, the Company's cash needs, and capitalization ratio
objectives.
The availability and cost of external financings depend upon the
financial health of the companies seeking those funds and market
conditions.
<PAGE>
Monongahela Power Company
Construction expenditures in 1999 were $82 million and, for 2000 and
2001, are estimated at $75 million and $72 million, respectively. In
addition, in 1999 the Company acquired the assets of West
Virginia Power for approximately $95 million, and in 2000 the
Company also plans to purchase Mountaineer Gas
Company for approximately $323 million (which includes the
acquisition of approximately $100 million in existing debt). The
2000 and 2001 estimated expenditures include $27 million and $34
million, respectively, for construction of environmental control
technology. It is the Company's goal to constrain future
construction spending to the approximate level of depreciation
currently in rates. As described under Environmental Issues
starting on page 11, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues. Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues. The Company also has additional
capital requirements for debt maturities (see Note I to the
financial statements). The Company anticipates issuing new debt
to replace the $65 million of long-term debt maturing in 2000.
Internal Cash Flow
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $86 million in 1999,
compared with $108 million in 1998. The decrease in 1999 cash
flows resulted from an increase in the level of common stock
dividends payable to its Parent, Allegheny Energy. Current
rate levels and reduced levels of construction expenditures
permitted the Company to finance all of its construction
expenditures in 1999 and 1998 with internal cash flow.
Financing
Short-term debt is used to meet temporary cash needs. Short-term
debt, including notes payable to affiliates under the money pool,
decreased $20.3 million to $28.7 million in 1999. At December
31, 1999, the Company had Securities and Exchange Commission
(SEC) authorization to issue up to $106 million of short-term
debt. The Company and its regulated affiliates use an Allegheny
Energy internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that
certain of the companies have funds available. The Company
anticipates meeting its 2000 cash needs through internal cash
generation, cash on hand, short-term borrowings as necessary,
and by issuing debt to refinance maturing first mortgage bonds.
In April 1999, the Company issued $7.7 million of 5.50% 30-year
pollution control revenue notes to Pleasants County, West
Virginia. In December 1999, the Company issued $110 million of
7.36% unsecured medium-term notes due in January 2010, in part to
finance the purchase of West Virginia Power.
The Company's long-term debt due within one year at December 31,
1999 was $65 million of 5-5/8% first mortgage bonds due April 1,
2000.
SIGNIFICANT CONTINUING ISSUES
Electric Energy Competition
The electricity supply segment of the electric utility industry
in the United States is becoming increasingly competitive. The
national Energy Policy Act of
<PAGE>
Monongahela Power Company
1992 deregulated 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 are engaging 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 and its parent, Allegheny Energy, have been
advocates 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 a bill. The bill will
now move on to the full Commerce Committee, where it will be
considered in 2000.
In the absence of federal legislation, state-by-state
implementation of deregulation of electric generation is under
way. The Company has franchised customers in the states of West
Virginia and Ohio. The five states in which the Company and its
affiliates serve customers 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, Ohio, and
Virginia passed legislation in 1999 to implement retail
choice. West Virginia continues to actively study this issue. On
December 23, 1999, the Maryland PSC approved a settlement agreement
for one of the Company's affiliates, The Potomac Edison Company, to
implement generation competition in Maryland.
At this time, the Company cannot determine the effect of
deregulation plans that may be approved in West Virginia and
Ohio. However, the approval of deregulation plans could have a
material impact on the Company regarding potential impairment of
electric generation assets and the Company's ability to recover
generation-related regulatory assets.
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 (Mandatory Purchase
Provisions) of PURPA, are repealed or significantly revised. The
Company continues to advocate the repeal of PUHCA and Section 210
of 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
U.S. 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 Company priorities by repealing the
PUHCA and the mandatory purchase provisions of 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 2000.
<PAGE>
Monongahela Power Company
Ohio Activities
On June 22, 1999, the Ohio General Assembly passed legislation to
restructure the electric utility industry. The Governor of Ohio
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 5% cut in the generation portion of their rate. The
determination of stranded cost recovery will be handled by the
Ohio PUC. On January 3, 2000, the Company filed a transition plan
with the Ohio PUC, including its claim for recovery of stranded
costs of $21.3 million. The Ohio PUC is expected to hold hearings
on the Company's transition plan filing and issue a decision by
October 2000.
The Ohio legislation stipulates that an entity independent of the
utilities shall own or control transmission facilities after the
start of competitive retail electric service on January 1, 2001,
but not later than December 31, 2003. 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.
West Virginia Activities
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 W.Va. PSC on
December 20, 1999, released for comment and hearings a modified
version of a proposal submitted by members of the Task Force,
including the Company and its affiliate, Potomac Edison,
following the August 1999 hearings that could open full retail
competition as early as January 1, 2001. The production of power
would be deregulated and electricity rates would be frozen for
four years with rates gradually transitioning to market rates
over the six years thereafter. After hearings in January 2000,
the W.Va. PSC submitted a restructuring plan endorsed by members
of the Task Force, including the Company and Potomac Edison, to
the Legislature for approval.
The status of electric energy competition in Virginia, Maryland,
and Pennsylvania in which affiliates of the Company serve are as
follows:
Virginia Activities
On March 25, 1999, Governor Gilmore signed the Virginia Electric
Utility Restructuring Act (Restructuring Act) passed by the
Virginia General Assembly. All utilities must submit a
restructuring plan by January 1, 2001, to be effective on January
1, 2002. Customer choice will be phased in beginning on January
1, 2002, with full customer choice by January 1, 2004. The
Legislative Transition Task Force on Electric Utility
Restructuring, which was established by the Restructuring Act to
oversee the implementation of customer choice, held hearings in
the summer and fall of 1999 on a number of issues concerning the
implementation of retail competition in Virginia. Parties have
also been
<PAGE>
Monongahela Power Company
working with the Virginia SCC staff to develop the rules
governing the proposed retail pilot programs of other utilities in the state.
Maryland Activities
On April 8, 1999, Maryland Governor Glendening signed the
legislation that will bring competition to Maryland's electric
generation market beginning July 1, 2000. The Maryland PSC is in
the process of implementing the new law. Final Electric
Restructuring Roundtable reports were filed with the Maryland PSC
on May 3, 1999, and legislative-style hearings were held last
summer on the reports. The Company's affiliate, Potomac Edison,
filed testimony in Maryland's investigation into transition
costs, price protection, and unbundled rates, and a consensus
settlement agreement was achieved with no protest by any of the
parties participating in the negotiations. The agreement was
filed on September 23, 1999, and a hearing before the Commission
was held on October 14, 1999. On December 23, 1999, the Maryland
PSC issued an order approving the settlement. Potomac Edison
filed an application on December 15, 1999, to transfer its
Maryland generation assets at book value to an affiliate under
Section 7-508 of the Electric Customer Choice and Competition Act
of 1999. A Maryland PSC decision approving the transfer of the
generating assets is due by July 1, 2000.
Pennsylvania Activities
In December 1996, Pennsylvania enacted the Electricity Generation
Customer Choice and Competition Act to restructure the electric
industry to create retail access to a competitive electric energy
supply market. On May 29, 1998
(as amended on November 19, 1998), the Pennsylvania Public
Utility Commission granted final approval to West Penn's
restructuring plan. As of January 2, 2000, all electricity
customers in Pennsylvania had the right to choose their electric
suppliers. Two-thirds of all retail customers had a choice
throughout 1999, the first year of retail choice following a
pilot program. The number of customers who have switched
suppliers and the amount of electrical load transferred in
Pennsylvania far exceed that of any other state so far. However,
for West Penn, only 12,700 of its Pennsylvania customers
eligible to shop in 1999 have chosen an alternate energy
supplier. West Penn has retained about 98% of its Pennsylvania
customers through December 31, 1999. More than 100 electric
generation suppliers have been licensed to sell to retail
customers in Pennsylvania.
Environmental Issues
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.
The significant costs of complying with Title IV (acid rain)
provisions of Phase I of the Clean Air Act Amendments of 1990
(CAAA) have been incurred and are included in the cost of the
related generation facilities. The Company estimates that its
banked emission allowances will allow it to comply with Phase II
sulfur dioxide (SO2) limits through 2005. Studies to evaluate
cost-effective options to comply with Phase II emission limits
beyond 2005, including those available in connection with the
emission allowance trading market, are continuing.
<PAGE>
Monongahela Power Company
Title I of the CAAA established an Ozone Transport Commission to
ascertain additional nitrogen oxides (NOx) reductions to allow
the Ozone Transport Region (OTR) to meet the ozone National
Ambient Air Quality Standards (NAAQS). Under terms of a
Memorandum of Understanding (MOU) among the OTR states, the
Company's generating station located in Pennsylvania was required
to reduce NOx emissions by approximately 55% from the 1990
baseline emissions, with a compliance date of May 1999. Further
reductions of 75% from the 1990 baseline may be required by May
2003 under Phase III of the MOU. However, this reduction will
most likely be superceded by the proposed NOx State
Implementation Plan (SIP) call rule discussed below. If
reductions of 75% are required, installation of post-combustion
control technologies would be very expensive. Pennsylvania and
Maryland promulgated regulations to implement Phase II of the MOU
in November 1997 and May 1998, respectively. However, as a result
of litigation, the Maryland regulation was revised to postpone
compliance to May 2000.
The Ozone Transport Assessment Group issued its final report in
June 1997 and recommended that the Environmental Protection
Agency (EPA) consider a range of NOx controls between existing
CAAA Title IV controls and the less stringent of an 85% reduction
from the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated
the regulatory process to adopt the recommendations and issued
its final NOx SIP call rule on September 24, 1998. The EPA's SIP
call rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone nonattainment in downwind
states. The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis. The final SIP call rule
requires that all state-adopted NOx reduction measures must be
incorporated into SIPs by
September 24, 1999, and must be implemented by May 1, 2003. The
Company's compliance with these requirements would require the
installation of post-combustion control technologies on most, if
not all, of its power stations. The Company continues to work
with other coal-burning utilities and other affected
constituencies in coal-producing states to challenge this EPA
action. While the SIP call is being litigated, the Company is
making preliminary plans to comply by applying NOx reduction
facilities to existing units at various power stations.
In August 1997, eight northeastern states filed Section 126
petitions with the EPA requesting the immediate imposition of up
to an 85% NOx reduction from utilities located in the Midwest and
Southeast (West Virginia included). The petitions claim NOx
emissions from these upwind sources are preventing their
attainment with the ozone standard. In December 1997, the
petitioning states and the EPA signed a Memorandum of Agreement
to address these petitions in conjunction with the related SIP
call. In May 1999, the EPA issued a technical approval of the
petition and, in December 1999, granted final approval of four of
the petitions. The Section 126 petition rulemaking is also under
litigation.
The EPA is required by law to regularly review the NAAQS for
criteria pollutants. Recent court orders in litigation by the
American Lung Association have expedited these reviews. The EPA
in 1996 decided not to revise the SO2 and NOx standards.
Revisions to particulate matter and ozone standards were proposed
by the EPA in 1996 and finalized in July 1997. However, the
revised standards were legally challenged, and, in May 1999, the
District of Columbia Circuit Court of Appeals remanded the
revised standards back to EPA for further consideration. Also, in
May 1999, the EPA promulgated final regional
<PAGE>
Monongahela Power Company
haze regulations to improve visibility in Class I federal areas
(national parks and wilderness areas). If eventually upheld in
court, subsequent state regulations could require additional
reduction of SO2 and/or NOx emissions from Company facilities.
The effect on the Company of revision to any of these standards
or regulations is unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of
the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time. All are being challenged by rulemaking,
petition, and/or the litigation process. Implementation dates are
also uncertain at this time, but could be as early as 2003, which
would require substantial capital expenditures in the 2000
through 2003 period. The Company's construction forecast includes
the expenditure of $96 million of capital costs during the 2000
through 2003 period to comply with the SIP call. In addition, $3
million was spent in 1999.
Global climate change is alleged to be the result of the
atmospheric accumulation of certain gases collectively referred
to as greenhouse gases (GHG), the most significant of which is
carbon dioxide (CO2). Human activities, particularly combustion
of fossil fuels, are alleged to be responsible for this
accumulation of GHG. The Clinton Administration has signed an
international treaty called the Kyoto Protocol, which would
require the United States to reduce emissions of GHG by 7% from
1990 levels in the 2008 through 2012 time period. The United
States Senate must ratify the Kyoto Protocol before it enters
into force. The Senate passed a resolution in 1997 that placed
two conditions on entering into any international climate change
treaty. First, any treaty must include all nations, and, second,
any treaty must not cause serious harm to the United States'
economy. The Kyoto Protocol does not appear to satisfy either of
these conditions, and, therefore, the Clinton Administration has
withheld it from consideration by the Senate. Because coal
combustion in power plants produces about 33% of the United
States' CO2 emissions, implementation of the Kyoto Protocol would
raise considerable uncertainty about the future viability of coal
as a fuel source for new and existing power plants. The Company
has taken numerous voluntary, precautionary steps to address the
issue of global climate change.
Many uncertainties remain in the global climate change debate,
including the relative contributions of human activities and
natural processes, the extremely high potential costs of
extensive mitigation efforts, and the significant economic and
social disruptions which may result from a large-scale reduction
in the use of fossil fuels. The Company will continue to explore
cost-effective opportunities to improve efficiency and
performance.
The Company actively participates in climate-related research
programs and is responsive to the voluntary guidelines suggested
in the national Energy Policy Act of 1992, under Section 1605(b),
directed toward reducing, controlling, avoiding, and sequestering
greenhouse gases. The Company has taken many concrete steps to
reduce greenhouse gases and help stimulate a business climate
that encourages improved efficiency, performance, electrical loss
reductions, and cost effectiveness.
The Company previously reported that the EPA had identified the
Company and its regulated utility affiliates as potentially
responsible parties, along with approximately 175 others, 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 and its
regulated affiliates have also been named as defendants along
with multiple other defendants in pending asbestos cases
involving one or more plaintiffs.
<PAGE>
Monongahela Power Company
The Company believes that provisions for liability and insurance
recoveries are such that final resolution of these claims will
not have a material effect on its financial position (see Note L
to the financial statements for additional information).
On Earth Day 1997, President Clinton announced the expansion of
the federal Emergency Planning and Community Right-to-Know Act
(RTK) 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 RTK
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 the news media in the System's service area and
posted on the Parent Company's web site. The System filed its
first RTK-related report with the EPA in advance of the July 1,
1999, deadline, reporting 18 million pounds of total releases for
calendar year 1998.
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 of their intent to commence civil actions
against Allegheny Energy and/or its subsidiaries 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 and is now jointly
owned by the Company and its affiliates, Allegheny Energy Supply
and Potomac Edison. 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 effect, if any, these
actions threatened by the Attorneys General of New York and
Connecticut may have on them.
Regional Transmission Organization
In adopting its Rule 2000, the FERC defined requirements for
transmission facility owners to participate in some form of Regional
Transmission Organization. Additionally, the state jurisdictions
within which the Company operates have, to different degrees,
started to define their transition to a competitive marketplace. As
part of this, they have identified transmission as a key link to
making the electricity market efficient. The nature of this issue is
at least regional in scope. As a result, any solution will need to
be one that satisfies a diverse group of stakeholders. The Company
has actively participated in this debate and continues to evaluate
the available options to provide our customers with the most
reliable, cost-effective service while maintaining a clear focus on
the financial interests of our shareholders.
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Monongahela Power Company
Derivative Instruments and Hedging Activities
In June 1998, the FASB issued SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities." The Company will be
required to recognize derivatives as defined by SFAS No. 133 on the
balance sheet at fair value. The Company is evaluating the impact
of adopting SFAS No. 133 on its results of operations and financial
position which will be completed during the year 2000. Accounting
for changes in the fair value of a derivative depends on the
intended use of the derivative and whether the instrument meets the
requirements for designation as a hedge. The Company expects to
adopt SFAS No. 133 no later than January 1, 2001.