<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
ALLEGHENY ENERGY, INC.
(Exact name of registrant as specified in its charter)
Maryland 1-267 13-5531602
(State or other (Commission File (IRS Employer
jurisdiction of Number)
Identification
incorporation) Number)
10435 Downsville Pike
Hagerstown, MD 21740
(Address of principal executive offices)
Registrant's telephone number,
including area code: (301) 790-3400
<PAGE>
Item 7 Financial Statements and Exhibits
(c) Exhibits
Ex. 99.1 Audited Consolidated Financial Statements of Allegheny
Energy, Inc. 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.
Allegheny Energy, Inc.
Dated: March 7, 2000 By: /s/ Michael P. Morrell
Name: Michael P. Morrell
Title: Senior Vice President
<PAGE>
EXHIBIT INDEX
Exhibits
Ex. 99.1 Consolidated Financial Statements of
Allegheny Energy, Inc. 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.
<TABLE>
<CAPTION>
EXHIBIT 99.1
CONSOLIDTED STATEMENT OF INCOME
Allegheny Energy, Inc.
Year ended December 31 1999 1998 1997
- --------------------------------------------------------------------------------------------
(Thousands of dollars except per share data)
Operating revenues:*
<S> <C> <C> <C>
Utility $2,273,727 $2,329,450 $2,283,697
Nonutility 534,714 246,986 85,794
- --------------------------------------------------------------------------------------------
Total operating revenues 2,808,441 2,576,436 2,369,491
- --------------------------------------------------------------------------------------------
Operating expenses:
Operation:
Fuel 535,674 566,453 559,939
Purchased power and exchanges, net 531,431 388,758 219,837
Deferred power costs, net 41,577 (6,639) (22,916)
Other 389,406 337,440 308,991
Maintenance 223,538 217,559 230,602
Depreciation and amortization 257,456 270,379 265,750
Taxes other than income taxes 190,271 194,583 186,978
Federal and state income taxes 164,441 168,396 168,073
- --------------------------------------------------------------------------------------------
Total operating expenses 2,333,794 2,136,929 1,917,254
- --------------------------------------------------------------------------------------------
Operating income 474,647 439,507 452,237
- --------------------------------------------------------------------------------------------
Other income and deductions:
Allowance for other than borrowed
funds used during construction 1,840 1,553 4,393
Other income, net 1,605 8,180 18,016
- --------------------------------------------------------------------------------------------
Total other income and deductions 3,445 9,733 22,409
- --------------------------------------------------------------------------------------------
Income before interest charges,
preferred dividends,
preferred redemption premiums,
and extraordinary charge, net 478,092 449,240 474,646
- --------------------------------------------------------------------------------------------
Interest charges, preferred dividends,
and preferred redemption premiums:
Interest on long-term debt 155,198 161,057 173,568
Other interest 31,612 19,395 14,409
Allowance for borrowed funds used
during construction and interest capitalized (5,070) (3,471) (3,907)
Dividends on preferred stock of subsidiaries 7,183 9,251 9,280
Redemption premiums on preferred stock of subsidiaries 3,780
- --------------------------------------------------------------------------------------------
Total interest charges, preferred dividends,
and preferred redemption premiums 192,703 186,232 193,350
- --------------------------------------------------------------------------------------------
Consolidated income before extraordinary charge 285,389 263,008 281,296
Extraordinary charge, net (26,968) (275,426)
- --------------------------------------------------------------------------------------------
Consolidated net income (loss) $ 258,421 $ (12,418) $ 281,296
- --------------------------------------------------------------------------------------------
Common stock shares outstanding (average) 116,237,443 122,436,317 122,208,465
Basic and diluted earnings per average share:
Consolidated income before extraordinary charge $ 2.45 $ 2.15 $ 2.30
Extraordinary charge, net (.23) (2.25)
- --------------------------------------------------------------------------------------------
Consolidated net income (loss) $ 2.22 $ (.10) $ 2.30
- --------------------------------------------------------------------------------------------
</TABLE>
*Excludes intercompany sales between utility and nonutility.
See accompanying notes to consolidated financial statements.
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
Allegheny Energy, Inc.
Year ended December 31 1999 1998* 1997*
- --------------------------------------------------------------------------------------------
(Thousands of dollars)
Cash flows from operations:
<S> <C> <C> <C>
Consolidated net income (loss) $ 258,421 $ (12,418) $ 281,296
Extraordinary charge, net of taxes 26,968 275,426
- --------------------------------------------------------------------------------------------
Consolidated income before extraordinary charge 285,389 263,008 281,296
Depreciation and amortization 257,456 270,379 265,750
Amortization of adverse purchase power contract (11,146)
Deferred revenues 34,849
Deferred investment credit and income taxes, net 40,035 20,998 66,362
Deferred power costs, net 41,577 (6,639) (22,916)
Allowance for other than
borrowed funds used during construction (1,840) (1,553) (4,393)
Internal restructuring liability (5,504) (50,597)
PURPA project buyout (48,000)
Write-off of merger-related and generation project costs 35,862
Changes in certain assets and liabilities:
Accounts receivable, net (77,679) 15,365 (6,052)
Materials and supplies 2,209 (12,852) (1,385)
Accounts payable 80,224 23,118 (17,172)
Taxes accrued 7,798 14,312 (3,653)
Benefit plans' investments (6,700) (7,994) (16,277)
Prepayments (19,158)
Restructuring settlement rate refund (25,100)
Other, net (25,516) 18,544 35,663
- ---------------------------------------------------------------------------------------------
618,260 591,182 478,626
- ---------------------------------------------------------------------------------------------
Cash flows from investing:
Utility construction expenditures
(less allowance for other than
borrowed funds used during construction) (264,365) (227,809) (280,255)
Nonutility construction expenditures and investments (147,160) (6,205) (829)
Acquisition of businesses (98,714)
- ---------------------------------------------------------------------------------------------
(510,239) (234,014) (281,084)
- ---------------------------------------------------------------------------------------------
Cash flows from financing:
Sale of common stock 16,706
Repurchase of common stock (398,407)
Retirement of preferred stock (96,086)
Issuance of long-term debt 824,143 211,952
Retirement of long-term debt (555,000) (419,780) (46,892)
Funds on deposit with trustees and restricted funds (13,279)
Short-term debt, net 382,258 52,436 49,971
Cash dividends paid on common stock (203,225) (210,591) (210,195)
- ---------------------------------------------------------------------------------------------
(59,596) (365,983) (190,410)
- ---------------------------------------------------------------------------------------------
Net change in cash and temporary cash investments 48,425 (8,815) 7,132
Cash and temporary cash investments at January 1 17,559 26,374 19,242
- --------------------------------------------------------------------------------------------
Cash and temporary cash investments at December 31 $ 65,984 $ 17,559 $ 26,374
- ---------------------------------------------------------------------------------------------
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $ 170,498 $ 171,719 $ 178,121
Income taxes 124,180 145,053 108,519
- ---------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes to consolidated financial statements.
*Certain amounts have been reclassified for comparative purposes.
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
Allegheny Energy, Inc.
As of December 31 1999 1998*
- --------------------------------------------------------------------------------------------
(Thousands of dollars)
ASSETS
Property, plant, and equipment:
<S> <C> <C>
Utility plant $ 6,547,533 $8,041,628
Nonutility plant 2,060,423 187,309
Construction work in progress 231,763 166,330
- --------------------------------------------------------------------------------------------
8,839,719 8,395,267
Accumulated depreciation (3,632,568) (3,395,603)
- --------------------------------------------------------------------------------------------
5,207,151 4,999,664
Investments and other assets:
Excess of cost over net assets acquired 42,584 15,077
Benefit plans' investments 94,168 87,468
Nonutility investments 15,252 9,361
Other 1,479 1,566
- --------------------------------------------------------------------------------------------
153,483 113,472
Current assets:
Cash and temporary cash investments 65,984 17,559
Accounts receivable:
Electric service 383,316 294,877
Other 12,273 17,712
Allowance for uncollectible accounts (26,975) (19,560)
Materials and supplies--at average cost:
Operating and construction 92,560 99,439
Fuel 62,280 57,610
Prepaid taxes 58,190 56,658
Deferred income taxes 30,477 21,868
Other, including current portion of regulatory assets 31,205 30,788
- --------------------------------------------------------------------------------------------
709,310 576,951
Deferred charges:
Regulatory assets 663,847 704,506
Unamortized loss on reacquired debt 41,825 48,671
Other 76,825 91,931
- --------------------------------------------------------------------------------------------
782,497 845,108
- --------------------------------------------------------------------------------------------
Total $ 6,852,441 $6,535,195
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CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital,
retained earnings, less treasury stock (at cost) $ 1,695,325 $ 2,033,889
Preferred stock 74,000 170,086
Long-term debt and QUIDS 2,254,463 2,179,288
- --------------------------------------------------------------------------------------------
4,023,788 4,383,263
Current liabilities:
Short-term debt 641,095 258,837
Long-term debt due within one year 189,734
Accounts payable 233,331 153,107
Taxes accrued:
Federal and state income 20,699 17,442
Other 67,292 62,751
Interest accrued 34,979 35,945
Adverse power purchase commitments 24,895 22,622
Other, including current portion of regulatory liabilities 96,510 101,239
- --------------------------------------------------------------------------------------------
1,308,535 651,943
Deferred credits and other liabilities:
Unamortized investment credit 116,971 125,396
Deferred income taxes 920,943 882,779
Regulatory liabilities 78,743 80,354
Adverse power purchase commitments 303,935 328,830
Other 99,526 82,630
- --------------------------------------------------------------------------------------------
1,520,118 1,499,989
Commitments and contingencies (Note P)
Total $ 6,852,441 $6,535,195
- --------------------------------------------------------------------------------------------
</TABLE>
*Certain amounts have been reclassified for comparative purposes.
See accompanying notes to consolidated financial statements.
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CAPITALIZATION
Allegheny Energy, Inc.
Thousands of dollars Capitalization
ratios
As of December 31 1999 1998 1999 1998
- --------------------------------------------------------------------------------------------
Common stock:
<S> <C> <C> <C> <C>
Common stock of Allegheny Energy, Inc.--
$1.25 par value per share,
260,000,000 shares authorized,
122,436,317 shares issued,
110,436,317 shares outstanding $ 153,045 $ 153,045
Other paid-in capital 1,044,085 1,044,085
Retained earnings 896,602 836,759
Treasury stock (at cost)--
12,000,000 shares (398,407)
- --------------------------------------------------------------------------------------------
Total 1,695,325 2,033,889 42.1% 46.4%
- --------------------------------------------------------------------------------------------
</TABLE>
Preferred stock of subsidiaries-cumulative, par value
$100 per share, authorized 38,878,611 shares:
<TABLE>
<CAPTION>
December 31, 1999
--------------------------------
Shares Regular Call Price
Series Outstanding Per Share
- ---------------------------------------------
<S> <C> <C> <C> <C> <C>
4.40-4.80% 190,000 $103.50 to $106.50 19,000 65,086
$5.88-$7.73 550,000 $100.00 to $102.86 55,000 65,000
Auction 40,000
- --------------------------------------------------------------------------------------------
Total (annual dividend requirements $5,037) 74,000 170,086 1.9% 3.9%
- --------------------------------------------------------------------------------------------
</TABLE>
Long-term debt and QUIDS of subsidiaries:
First mortgage bonds: December 31, 1999
Maturity Interest Rate--%
- ---------------------- ---------------------
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
2000 5 5/8 - 5 7/8 140,000 140,000
2002-2004 7 3/8 25,000 175,000
2006-2007 7 1/4 - 8 75,000 120,000
2021-2025 7 5/8 - 8 5/8 480,000 810,000
Transition bonds due 2000-2008 6.32 - 6.98 600,000
Debentures due 2003-2023 5 5/8 - 6 7/8 150,000 150,000
Quarterly Income Debt
Securities due 2025 8.00 155,457 155,457
Secured notes due 2003-2029 4.70 - 6.875 399,130 368,300
Unsecured notes due 2002-2012 4.35 - 5.10 23,695 23,695
Installment purchase
obligations due 2003 4.50 19,100 19,100
Medium-term debt due 2001-2010 5.56 - 7.36 401,025 237,025
Unamortized debt discount and premium, net (13,937) (19,289)
- --------------------------------------------------------------------------------------------
Total (annual interest requirements $165,938) 2,454,470 2,179,288
- --------------------------------------------------------------------------------------------
Less amounts on deposit with trustees (10,273)
Less current maturities (189,734)
- --------------------------------------------------------------------------------------------
Total 2,254,463 2,179,288 56.0% 49.7%
- --------------------------------------------------------------------------------------------
Total capitalization $4,023,788 $4,383,263 100.0% 100.0%
- --------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes to consolidated financial statements.
CONSOLIDATED STATEMENT OF COMMON EQUITY
Allegheny Energy, Inc.
<TABLE>
<CAPTION>
Thousands of Dollars
-------------------------------------------------
Other Retained Total
Shares Common Paid-In Earnings Treasury Common
Year ended December 31 Outstanding Stock Capital (Note H) Stock Equity
- -----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1997 121,840,327 $ 152,300 $1,028,124 $988,667 $2,169,091
- -----------------------------------------------------------------------------------------------------------
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
Purchase Plan, Employee Stock
Ownership and Savings Plan,
and Performance Share Plan 595,990 745 15,961 16,706
Consolidated net income 281,296 281,296
Dividends on common stock of
the Company (declared) (210,195) (210,195)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1997 122,436,317 $ 153,045 $1,044,085 $1,059,768 $2,256,898
- -----------------------------------------------------------------------------------------------------------
Consolidated net loss (12,418) (12,418)
Dividends on common stock of the
Company (declared) (210,591) (210,591)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 122,436,317 $ 153,045 $1,044,085 $836,759 $2,033,889
- -----------------------------------------------------------------------------------------------------------
Consolidated net income 258,421 258,421
Treasury stock (12,000,000) $(398,407) (398,407)
Dividends on common stock
of the Company (declared) (198,578) (198,578)
- -----------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 110,436,317 $ 153,045 $1,044,085 $896,602 $(398,407) $1,695,325
- -----------------------------------------------------------------------------------------------------------
</TABLE>
See accompanying notes to consolidated financial statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Allegheny Energy, Inc.
(These notes are an integral part of the consolidated financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Allegheny Energy, Inc. (the Company) is a utility holding company and its
principal business segments are utility and nonutility operations. The utility
subsidiaries, Monongahela Power Company (Monongahela Power), The Potomac Edison
Company (Potomac Edison), and West Penn Power Company (West Penn), collectively
now doing business as Allegheny Power, are engaged in the generation (except
West Penn), purchase, transmission, distribution, and sale of electric energy
and are subject to federal and state regulation including the Public Utility
Holding Company Act of 1935 (PUHCA). The markets for the subsidiaries' regulated
electric retail sales are in Pennsylvania, West Virginia, Maryland, Virginia,
and Ohio. In 1999, revenues from the 50 largest electric utility customers
provided approximately 15% of the consolidated retail revenues. Nonutility
operations consist of the Company's unregulated energy supply business, with the
primary objective of selling electricity into the competitive marketplace, and
Allegheny Ventures, Inc. (Allegheny Ventures), a wholly owned subsidiary which
develops new business opportunities, with an emphasis on telecommunications and
energy-related products and services. Unregulated energy supply includes the
Company's existing generation as deregulation is implemented in the five states
where the Company's traditional utility business has operated and new generating
capacity to be constructed or acquired by the Company. In November 1999, the
Company formed Allegheny Energy Supply Company, LLC (Allegheny Energy Supply), a
wholly owned nonutility generating subsidiary, to consolidate its unregulated
energy supply business.
Allegheny Energy Supply was formed when West Penn transferred its deregulated
generating capacity of 3,778 megawatts (MW) at book value to Allegheny Energy
Supply, as allowed by the final settlement in West Penn's Pennsylvania
restructuring case. Allegheny Energy Supply also purchased from AYP Energy, Inc.
(AYP Energy) its 276 MW of merchant capacity at Fort Martin Unit No. 1.
The Company's nonutility subsidiaries operate primarily in the Mid-Atlantic
region. In 1999, 82% of nonutility revenues were from bulk power sales.
Nonutility operations may be subject to federal regulation, but are not subject
to state regulation of rates.
See Note B for significant changes in the Pennsylvania and Maryland regulatory
environment. Certain amounts in the December 31, 1998, consolidated balance
sheet and in the December 31, 1998, and 1997 consolidated statement of cash
flows have been reclassified for comparative purposes. Significant accounting
policies of the Company and its subsidiaries are summarized below.
Consolidation The Company owns all of the outstanding common stock of its
subsidiaries. The consolidated financial statements include the accounts of the
Company and all subsidiary companies after elimination of intercompany
transactions.
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. Revenues from nonutility
activities are recorded in the period earned.
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
Maryland, Ohio, Virginia, and West Virginia. West Penn discontinued this
practice in Pennsylvania, effective May 1, 1997, and Potomac Edison will
discontinue this practice in Maryland, effective July 1, 2000.
Property, Plant, and Equipment Utility property, plant, and equipment 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 on utility 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 utility property units retired, plus removal costs less
salvage, are charged to accumulated depreciation by the utility subsidiaries
that apply the Financial Accounting Standards Board's (FASB) Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation."
Nonutility property, plant, and equipment are stated at original cost for self-
constructed assets. Property acquired from others is stated at fair market value
when acquired. West Penn transferred its deregulated generation plant to
Allegheny Energy Supply at book value. Nonutility property is depreciated by the
straight-line method over its estimated useful life.
For the nonutility subsidiaries, the cost and accumulated depreciation of
property, plant, and equipment retired or otherwise disposed of are removed from
related accounts and included in the determination of the gain or loss on
disposition.
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) and Capitalized Interest
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 by the utility
subsidiaries as a cost of utility property, plant, and equipment. Rates used by
the utility subsidiaries for computing AFUDC in 1999, 1998, and 1997 averaged
6.83%, 7.78%, and 8.59%, respectively.
For nonutility construction, which began after January 1, 1998, the Company
capitalizes interest costs in accordance with SFAS No. 34, "Capitalizing
Interest Costs." The interest capitalization rates in 1999 and 1998 were 7.14%
and 7.45%, respectively.
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 3.2% of average depreciable property in 1999 and
3.3% in each of the years 1998 and 1997. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.
Investments The Company records the acquisition cost in excess of net assets
acquired as an investment in goodwill. Goodwill recorded prior to 1966 is not
being amortized because, in management's opinion, there has been no reduction in
its value. Goodwill related to the acquisition of West Virginia Power Company in
December 1999 will be amortized over 40 years.
Benefit plans' investments primarily represent the estimated cash surrender
values of purchased life insurance on qualifying management employees under
executive life insurance and supplemental executive retirement plans.
Temporary Cash Investments For purposes of the consolidated statement of cash
flows, temporary cash investments with original maturities of three months or
less, generally in the form of commercial paper, certificates of deposit, and
repurchase agreements, are considered to be the equivalent of cash.
Regulatory Assets and Liabilities In accordance with SFAS No. 71, the Company's
consolidated financial statements include certain assets and liabilities
resulting from cost-based ratemaking regulation.
Income Taxes 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.
Postretirement Benefits The Company's subsidiaries have 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.
The Company's subsidiaries also provide 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: INDUSTRY RESTRUCTURING
Maryland Deregulation On September 23, 1999, Potomac Edison filed a settlement
agreement (covering its stranded cost quantification mechanism, price protection
mechanism, and unbundled rates) with the Maryland Public Service Commission
(Maryland PSC). The agreement was signed by all parties active in the case,
except Eastalco, which stated that it would not oppose it. The settlement
agreement, which was approved by the Maryland PSC on December 23, 1999, includes
the following provisions:
* The ability for nearly all of our 211,000 Maryland customers to have the
option of choosing an electric generation supplier starting July 1, 2000.
* The transfer of Potomac Edison's Maryland jurisdictional generating assets to
a nonutility affiliate at book value as of July 1, 2000.
* A reduction in base rates of 7% ($10.4 million each year totaling $72.8
million) for residential customers from 2002 through 2008. A reduction in base
rates of one-half of 1% ($1.5 million each year totaling $10.5 million) for the
majority of commercial and industrial customers from 2002 through 2008.
* Standard Offer Service (provider of last resort) will be provided to
residential customers during a transition period from July 1, 2000, to December
31, 2008, and to all other customers during a transition period of July 1, 2000,
to December 31, 2004.
* A cap on generation rates for residential customers from 2002 through 2008.
Generation rates for non-residential customers are capped from 2002 through
2004.
* A cap on transmission and distribution rates for all customers from 2002
through 2004.
* Unless Potomac Edison is subject to significant changes that would materially
affect Potomac Edison's financial condition, the parties agree not to seek a
reduction in rates which would be effective prior to January 1, 2005.
* The recovery of all purchased power costs incurred as a result of the contract
to buy generation from the AES Warrior Run cogeneration facility.
* The establishment of a fund (not to exceed $.001 per kilowatt-hour (kWh) for
residential customers) for the development and use of energy-efficient
technologies.
The Maryland PSC on December 23, 1999, also approved Potomac Edison's unbundled
rates covering the period 2000 through 2008.
Pennsylvania Deregulation In December 1996, Pennsylvania enacted the
Electricity Generation Customer Choice and Competition Act (Customer Choice Act)
to restructure the electric industry in Pennsylvania to create retail access to
a competitive electric energy supply market. Approximately 45% of the Company's
retail revenues were from its Pennsylvania subsidiary, West Penn. On August 1,
1997, West Penn filed with the Pennsylvania Public Utility Commission
(Pennsylvania PUC) a comprehensive restructuring plan to implement full customer
choice of electricity suppliers as required by the Customer Choice Act. The
filing included a plan for recovery of transition costs through a Competitive
Transition Charge (CTC).
On May 29, 1998 (as amended on November 19, 1998), the Pennsylvania PUC granted
final approval to West Penn's restructuring plan, which included the following
provisions:
* Established an average shopping credit for West Penn customers who shop for
the generation portion of electricity services.
* Provided two-thirds of West Penn's customers the option of selecting a
generation supplier on January 2, 1999, with all customers able to shop on
January 2, 2000.
* Required a rate refund from 1998 revenue (about $25 million) via a 2.5% rate
decrease throughout 1999, accomplished by an equal percentage decrease for each
rate class.
* Provided that customers have the option of buying electricity from West Penn
at capped generation rates through 2008, and that transmission and distribution
rates are capped through 2005, except that the capped rates are subject to
certain increases as provided for in the Public Utility Code.
* Prohibited complaints challenging West Penn's regulated transmission and
distribution rates through 2005.
* Provided about $15 million of West Penn funding for the development and use of
renewable energy and clean energy technologies, energy conservation, energy
efficiency, etc.
* Permitted recovery of $670 million in transition costs plus return over 10
years beginning in January 1999 for West Penn.
* Allowed for income recognition of transition cost recovery in the earlier
years of the transition period to reflect the Pennsylvania PUC's projections
that electricity market prices are lower in the earlier years.
* Granted West Penn's application to issue bonds to securitize up to $670
million in transition costs and to provide 75% of the associated savings to
customers, with 25% available to shareholders.
* Authorized the transfer of West Penn's generating assets to a nonutility
affiliate at book value. Subject to certain time-limited exceptions, the
nonutility business can compete in the unregulated energy market in
Pennsylvania.
As a result of the May 29, 1998, Pennsylvania PUC order and the November 19,
1998, settlement agreement, an extraordinary charge of $466.9 million ($275.4
million after taxes) was recorded in 1998 to reflect a write-off of costs
determined to be unrecoverable in connection with the deregulation proceedings
in Pennsylvania. 1998 also reflects additional charges of $40.3 million ($23.7
million after taxes) related to the West Penn revenue refund and energy program
payments. See Note C for additional details.
Starting in 1999, West Penn unbundled its rates to reflect separate prices for
the supply charge, the CTC, and transmission and distribution charges. While
supply is open to competition, West Penn continues to provide regulated
transmission and distribution services to customers in its service area at
rates approved by the Pennsylvania PUC and the Federal Energy Regulatory
Commission (FERC). West Penn is the electricity provider of last resort for
those customers who decide not to choose another electricity supplier.
The Pennsylvania PUC order authorized annual recovery of "transition costs" from
distribution customers as follows:
Amount
Year (Millions of dollars)
- -------------------------------
1999 $ 122
2000 121
2001 115
2002 113
2003 112
2004 104
2005 99
2006 98
2007 97
2008 97
- -------------------------------
These amounts represent the recovery of $670 million in transition costs plus a
return on the unrecovered investment.
Actual transition revenues billed to customers in 1999 totaled $101 million. The
Company has recorded a regulatory asset of $20 million for the difference in the
authorized CTC revenues, adjusted for $1 million securitization savings to be
shared with customers, and the actual transition revenues billed to customers.
The Pennsylvania PUC has approved the recovery of this regulatory asset through
a true-up mechanism currently in process.
The order also authorized recognition of an additional CTC regulatory asset
(Additional CTC Regulatory Asset) as follows:
Amount
Year (Millions of dollars)
- -------------------------------
1999 $ 25
2000 45
2001 60
2002 50
- -------------------------------
To the extent that West Penn records any or all of the Additional CTC Regulatory
Asset, it will be amortized in 2005 through 2008. This Additional CTC Regulatory
Asset was approved by the Pennsylvania PUC to reduce the adverse effects, if
any, that competition will have on West Penn during the years 1999 to 2002. No
Additional CTC Regulatory Asset was recorded by West Penn as of December 31,
1999.
Prior to 1999, the Pennsylvania Customer Choice Act, required all electric
utilities in Pennsylvania to establish and administer retail access pilot
programs under which customers representing 5% of the load of each rate class
would choose an electricity supplier other than their own local franchise
utility. The pilot programs began on November 1, 1997, and continued through
December 31, 1998. As ordered by the Pennsylvania PUC, pilot participants
received an energy credit to their bills from their local utility and paid an
alternate supplier for energy. To assure participation in the pilot program, the
credit established by the Pennsylvania PUC was artificially high (greater than
West Penn's generation costs), with the result that West Penn suffered a loss of
$8.6 million. West Penn mitigated the loss by competing for sales to pilot
participants of other utilities as an alternate supplier. The Pennsylvania PUC
approved West Penn's pilot compliance filing and thus has indicated its intent
to treat the net revenue loss as a regulatory asset subject to review and
potential rate recovery. Accordingly, West Penn deferred the net revenue loss as
a regulatory asset.
On August 12, 1999, West Penn filed its Competitive Transition Charge
Reconciliation Statement pursuant to the settlement agreement approved by the
Pennsylvania PUC. The reconciliation shows a seven-month under-collection and
its potential effects on the CTC rate effective January 1, 2000. The seven-month
transition cost under-collection for the period ended July 31, 1999, was $15.9
million.
On November 2, 1999, West Penn, the Office of Consumer Advocate, West Penn
Industrial Intervenors, and the Commission's Office of Trial Staff filed a Joint
Petition for Approval of Settlement Agreement. The agreement proposed that West
Penn use the savings from securitization during the remainder of 1999 and during
2000 to recover the existing 1999 CTC underrecovery and the expected increase in
year 2000 CTC underrecovery due to lower than projected energy sales. On
December 16, 1999, the Pennsylvania PUC approved the joint petition for
settlement allowing West Penn to collect the 1999 CTC underrecovery.
NOTE C: ACCOUNTING FOR THE EFFECTS OF PRICE DEREGULATION
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.
On December 23, 1999, the Maryland PSC approved a settlement agreement dated
September 23, 1999, setting forth the transition plan to deregulate electric
generation for Potomac Edison's Maryland jurisdiction. As required by EITF 97-4,
Potomac Edison discontinued the application of SFAS No. 71 for its Maryland
jurisdiction electric generation operations in the fourth quarter of 1999. As a
result, Potomac Edison recorded under the provisions of SFAS No. 101,
"Accounting for the Discontinuation of Application of FASB Statement No. 71," an
extraordinary charge of $26.9 million ($17.0 million after taxes), reflecting
the impairment of certain generating assets as determined under SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of," based on the expected future cash flows and net regulatory
assets associated with generating assets that will not be collected from
customers as shown below:
(Millions of dollars) Gross Net-of-Tax
- -------------------------------------------------------------------
Impaired generating assets $14.5 $ 9.9
Net regulatory assets 12.4 7.1
- -------------------------------------------------------------------
Total 1999 extraordinary charge $26.9 $ 17.0
- -------------------------------------------------------------------
On May 29, 1998, the Pennsylvania PUC issued an order approving a transition
plan for West Penn. This order was subsequently amended by a settlement
agreement approved by the Pennsylvania PUC on November 19, 1998. Based on the
Pennsylvania PUC order and subsequent settlement agreement, West Penn
discontinued the application of SFAS No. 71 to its generation operations in the
second quarter of 1998.
West Penn recorded under the provisions of SFAS No. 101 an extraordinary charge
of $466.9 million ($275.4 million after taxes) in 1998 to reflect the
disallowances of certain costs in the Pennsylvania PUC's May 29, 1998, order, as
revised by the Pennsylvania PUC-approved November 19, 1998, settlement
agreement. The charge reflects adverse power purchase commitments (commitments
to purchase power at prices above market prices for electricity), the impairment
of the investment in the Bath County pumped-storage plant, and net regulatory
assets that will not be collected from customers under the Pennsylvania PUC's
order and settlement agreement as follows:
(Millions of dollars) Gross Net-of-Tax
- -------------------------------------------------------------------
AES Beaver Valley nonutility
generation contract $ 197.5 $ 116.5
Impairment of Bath County
pumped-storage plant 165.6 97.7
Net regulatory assets 103.8 61.2
- -------------------------------------------------------------------
Total 1998 extraordinary charge $ 466.9 $ 275.4
- -------------------------------------------------------------------
On December 31, 1999, the Company's reserve for adverse power purchase
commitments was $328.8 million based on the Company's forecast of future energy
revenues and other factors. A change in the estimated energy revenues or other
factors could have a material effect on the amount of the reserve for adverse
power purchases.
See Note B for additional information regarding the transition plans approved in
Maryland and Pennsylvania.
In addition to the 1998 extraordinary charge, West Penn recorded an additional
charge against income in 1998 of $40.3 million ($23.7 million after taxes)
associated with a rate refund and development of renewable energy programs as
required by the Pennsylvania settlement agreement.
The Consolidated Balance Sheet includes the amounts listed below for assets,
primarily generation, not subject to SFAS No. 71.
December December
(Millions of dollars) 1999 1998
- --------------------------------------------------------------------------------
Property, plant, and equipment at original cost $ 2,690.1 $ 1,969.6
Amounts under construction included above 101.8 39.2
Accumulated depreciation (1,239.0) (870.8)
- --------------------------------------------------------------------------------
NOTE D: PROPOSED MERGER
On April 7, 1997, the Company and DQE, Inc. (DQE), parent company of Duquesne
Light Company in Pittsburgh, Pennsylvania, announced that they had agreed to
merge in a tax-free, stock-for-stock transaction (Merger Agreement).
At separate meetings held on August 7, 1997, the shareholders of the Company and
DQE approved the merger. The Company and DQE made all necessary regulatory
filings. Since then, the Company and DQE received approval of the merger from
the Nuclear Regulatory Commission, the Pennsylvania PUC, and the FERC. The
Pennsylvania PUC and the FERC approvals were subject to conditions acceptable to
the Company. In addition, while not required, the Maryland PSC and the Public
Utilities Commission of Ohio have indicated their approval.
On October 5, 1998, DQE notified the Company that it had unilaterally decided to
terminate the merger. In response, the Company filed with the United States
District Court for the Western District of Pennsylvania on October 5, 1998, a
lawsuit for specific performance of the Merger Agreement or, alternatively,
damages. The District Court held a trial on October 20 through 28, 1999, without
a jury, on the issues of whether DQE's termination of the Merger Agreement
breached the agreement and whether the Company is entitled to specific
performance.
On December 3, 1999, the Court handed down a decision which found that DQE did
not breach the April 1997 Merger Agreement. The Court accordingly found in favor
of DQE and granted judgment in favor of DQE on all claims and all requests for
injunctive relief. On December 14, 1999, the Company appealed the District
Court's judgment to the United States Court of Appeals for the Third Circuit,
and, on December 16, 1999, the Company filed a Motion for Expedited Treatment of
the Appeal requesting that briefings be completed by February 25, 2000, and that
arguments be scheduled promptly following the completion of briefings. On
December 29, 1999, the Third Circuit granted the Motion for Expedited Treatment.
As a result of the December 3, 1999, Court decision, the Company recorded a
charge against income of $19.7 million ($11.8 million after taxes) in the fourth
quarter of 1999 for merger-related costs previously deferred.
NOTE E: ACQUISITIONS
In December 1999, Monongahela Power acquired the assets of West Virginia Power
for approximately $95 million. In conjunction with this acquisition, the Company
purchased the assets of a heating, ventilation, and air conditioning business
for $2.1 million. The acquisition increased property, plant, and equipment and
accumulated depreciation by $105.0 million and $35.4 million, respectively.
Also, $27.5 million was recorded as the excess of cost over net assets acquired.
In December 1999, Monongahela Power 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.
NOTE F: EXTRAORDINARY CHARGE ON LOSS ON REACQUIRED DEBT
During 1999, West Penn reacquired $525 million of outstanding first mortgage
bonds and recorded a loss of $17.0 million ($10.0 million after taxes)
associated with this transaction. In accordance with Accounting Principles Board
(APB) Opinion
No. 26, "Early Extinguishment of Debt," and SFAS No. 4, "Reporting Gains and
Losses from Extinguishment of Debt," this amount is classified as an
extraordinary item in the consolidated statement of income.
NOTE G: INCOME TAXES
Details of federal and state income tax provisions are:
<TABLE>
<CAPTION>
(Thousands of dollars) 1999 1998 1997
- -------------------------------------------------------------------------------------------
Income taxes-current:
<S> <C> <C> <C>
Federal $100,724 $114,319 $ 87,394
State 26,156 33,385 23,960
- -------------------------------------------------------------------------------------------
Total 126,880 147,704 111,354
Income taxes-deferred, net of amortization 48,461 28,920 74,565
Income taxes-deferred, extraordinary charge (16,885) (191,480)
Amortization of deferred investment credit (8,426) (7,922) (8,203)
- -------------------------------------------------------------------------------------------
Total income taxes 150,030 (22,778) 177,716
Income taxes-charged to other income and deductions (2,474) (306) (9,643)
Income taxes-credited to extraordinary charge 16,885 191,480
- -------------------------------------------------------------------------------------------
Income taxes-charged to operating income $164,441 $168,396 $168,073
- -------------------------------------------------------------------------------------------
The total provision for income taxes is different from the amount produced by
applying the federal income statutory tax rate of 35% to financial accounting
income, as set forth below:
(Thousands of dollars) 1999 1998 1997
- --------------------------------------------------------------------------------------------
Income before preferred stock dividends
and redemption premiums,
income taxes, and extraordinary charge $460,793 $440,655 $458,649
- --------------------------------------------------------------------------------------------
Amount so produced $161,278 $154,229 $160,527
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation 6,500 6,700 14,200
Plant removal costs (9,100) (2,400) (1,700)
State income tax, net of federal income tax benefit 14,100 20,200 11,700
Amortization of deferred investment credit (8,426) (7,922) (8,203)
Other, net 89 (2,411) (8,451)
- --------------------------------------------------------------------------------------------
Total $164,441 $168,396 $168,073
- --------------------------------------------------------------------------------------------
</TABLE>
The provision for income taxes for the extraordinary charges is different from
the amount produced by applying the federal income statutory tax rate of 35% to
the gross amount, as set forth below:
(Thousands of dollars) 1999 1998
- -----------------------------------------------------------------------------
Extraordinary charge before income taxes $ 43,853 $ 466,905
- -----------------------------------------------------------------------------
Amount so produced $ 15,349 $ 163,417
Increased for state income tax,
net of federal income tax benefit 1,536 28,063
- -----------------------------------------------------------------------------
Total $ 16,885 $ 191,480
- -----------------------------------------------------------------------------
Federal income tax returns through 1995 have been examined and substantially
settled. 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>
Recovery of transition costs $ 141,844 $ 154,530
Unamortized investment tax credit 72,845 77,213
Tax interest capitalized 35,760 35,375
Postretirement benefits other than pensions 31,662 31,047
Contributions in aid of construction 23,387 23,643
Unbilled revenue 13,105 13,380
Revenue refund 10,301
Deferred power costs, net 16,741 8,736
Reserve for uncollectibles 10,044 7,904
Other 47,472 39,878
- -----------------------------------------------------------------------------------------
392,860 402,007
- ----------------------------------------------------------------------------------------
Deferred tax liabilities:
Book vs. tax plant basis differences, net 1,207,465 1,174,453
Other 75,861 88,465
- -----------------------------------------------------------------------------------------
1,283,326 1,262,918
- ----------------------------------------------------------------------------------------
Total net deferred tax liabilities 890,466 860,911
Portion above included in current assets 30,477 21,868
- ----------------------------------------------------------------------------------------
Total long-term net deferred tax liabilities $ 920,943 $ 882,779
- ----------------------------------------------------------------------------------------
</TABLE>
NOTE H: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of Monongahela
Power contain dividend restrictions under the most restrictive of which
$68,974,000 of the Company's consolidated retained earnings at December 31,
1999, is not available for cash dividends on Monongahela Power's common stock,
except that a portion thereof may be paid as cash dividends where concurrently
an equivalent amount of cash is received by Monongahela Power as a capital
contribution or as the proceeds of the issue and sale of shares of its common
stock.
NOTE I: PENSION BENEFITS AND POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
Net periodic (credit) cost for pension and postretirement benefits other than
pensions (principally health care and life insurance) for employees and covered
dependents, of which approximately 30% was (credited) charged to plant
construction, included the following components:
<TABLE>
<CAPTION>
Postretirement Benefits
Pension Benefits Other Than Pensions
- --------------------------------------------------------------------------------------------
(Thousands of dollars) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------------------
Components of net
periodic (credit) cost:
<S> <C> <C> <C> <C> <C> <C>
Service cost $15,350 $ 14,316 $12,435 $ 2,677 $2,566 $ 2,619
Interest cost 47,068 46,743 43,060 13,418 14,346 15,244
Expected return on plan assets (65,456) (61,280) (57,404) (6,217) (6,163) (4,705)
Amortization of unrecognized
transition (asset) obligation (3,146) (3,146) (3,146) 6,433 6,433 6,433
Amortization of prior service cost 2,386 2,360 1,441
Recognized net actuarial gain (119)
- --------------------------------------------------------------------------------------------
Periodic (credit) cost (3,798) (1,007) (3,614) 16,192 17,182 19,591
Reversal of previous deferrals 760 760
- --------------------------------------------------------------------------------------------
Net periodic (credit) cost $ (3,798) $ (247) $(2,854) $16,192 $17,182 $19,591
- --------------------------------------------------------------------------------------------
The discount rates and rates of compensation increases used in determining the
benefit obligations at September 30, 1999, 1998, and 1997, and the expected long-
term rate of return on assets in each of the years 1999, 1998, and 1997 were as
follows:
1999 1998 1997 1999 1998 1997
- ------------------------------------------------------------------------------------------
Discount rate 7.50% 7.00% 7.25% 7.50% 7.00% 7.25%
Expected return on plan assets 9.00% 9.00% 9.00% 8.25% 8.25% 8.25%
Rate of compensation increase 4.50% 4.00% 4.25% 4.50% 4.00% 4.25%
- -------------------------------------------------------------------------------------------
</TABLE>
For postretirement benefits other than pensions measurement purposes, a health
care cost trend rate of 6.5% for 2000 and beyond and plan provisions which limit
future medical and life insurance benefits were assumed. Because of the plan
provisions which limit future benefits, the assumed health care cost trend rate
has a limited effect on the amounts reported.
A one-percentage-point change in the assumed health care cost trend rate would
have the following effects:
<TABLE>
<CAPTION>
1-Percentage-Point 1-Percentage-Point
(Thousands of dollars) Increase Decrease
- --------------------------------------------------------------------------------------------
<S> <C> <C>
Effect on total of service and interest cost components $ 300 $ (289)
Effect on postretirement benefit obligation $2,609 $(2,635)
- --------------------------------------------------------------------------------------------
</TABLE>
The amounts (prepaid) accrued at December 31, using a measurement date of
September 30, included the following components:
<TABLE>
<CAPTION>
Postretirement Benefits
Pension Benefits Other Than Pensions
(Thousands of dollars) 1999 1998 1999 1998
- --------------------------------------------------------------------------------------------
Change in benefit obligation:
<S> <C> <C> <C> <C>
Benefit obligation at beginning of year $692,937 $ 664,695 $196,282 $202,274
Service cost 15,350 14,316 2,677 2,566
Interest cost 47,068 46,743 13,418 14,346
Plan amendments 360
Actuarial (gain) loss (21,369) 8,573 (20,159) (14,296)
Benefits paid (42,458) (41,750) (10,894) (8,608)
Benefit obligation at December 31 691,528 692,937 181,324 196,282
- --------------------------------------------------------------------------------------------
Change in plan assets:
Fair value of plan assets
at beginning of year 801,348 786,159 74,773 73,363
Actual return on plan assets 50,914 49,091 10,864 965
Employer contribution 7,848 7,848 4,406 2,451
Benefits paid (42,458) (41,750) (5,766) (2,006)
Fair value of plan assets at December 31 817,652 801,348 84,277 74,773
- -------------------------------------------------------------------------------------------
Plan assets (in excess of)
less than benefit obligation (126,124) (108,411) 97,047 121,509
Unrecognized transition asset (obligation) 3,152 6,298 (83,627) (90,060)
Unrecognized net actuarial gain 115,193 108,366 46,140 21,453
Unrecognized prior service
cost due to plan amendments (20,428) (22,814)
Fourth quarter contributions and benefit payments (6,203) (5,227)
- --------------------------------------------------------------------------------------------
(Prepaid) accrued at December 31 $ (28,207) $ (16,561) $ 53,357 $ 47,675
- --------------------------------------------------------------------------------------------
</TABLE>
The pension unrecognized transition asset is being amortized over 14 years
beginning January 1, 1987, and the postretirement benefits other than pensions
unrecognized transition obligation is being amortized over 20 years beginning
January 1, 1993.
NOTE J: STOCK-BASED COMPENSATION
Under the Company's Long-term Incentive Plan, options may be granted to officers
and key employees. A total of 10 million shares of the Company's common stock
have been authorized for issuance under the Long-term Incentive Plan. The Long-
term Incentive Plan, which was implemented during 1998, provides vesting periods
of one to seven years, with options remaining exercisable until 10 years from
the date of grant. There were no exercisable options at December 31, 1999. As
permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," the
Company follows APB Opinion No. 25, "Accounting for Stock Issued to Employees,"
and related interpretations in accounting for employee stock options. Under APB
No. 25, because the exercise price of stock options awarded under the Company's
Long-term Incentive Plan equals or exceeds the market price of the underlying
stock on the date of grant, no compensation expense is recognized. Disclosure of
pro-forma information regarding net income and earnings per share is required by
SFAS No. 123. The information presented has been determined as if the stock
options had been accounted for under the fair value method of that statement.
The weighted average fair value of the 1999 options was $5.07 per share. The
fair values were estimated at the date of grant using the Black-Scholes option
pricing model, with the following weighted average assumptions: risk-free
interest rate was 6.24%, expected lives of 10 years, expected stock volatility
of 22.83%, and dividend yield of 5.83%.
Under SFAS No. 123, pro-forma consolidated net income for common stock for the
Company would be $258,166,000, or $255,000 less than the amount reported for
1999. On a pro-forma basis, the Company's 1999 basic and diluted earnings per
share would remain at $2.22 per common share. There were no stock options issued
prior to 1999. During 1999, the Company granted 1,119,200 stock options at a
weighted average exercise price of $31.351. There were no stock options
exercised or forfeited during 1999. A summary of the stock options outstanding
at December 31, 1999, is as follows: range of exercise prices was $30.1875 to
$33.8125, weighted average exercise price was $31.351, shares outstanding were
1,119,200, and average remaining contractual life was 10 years.
Under the Company's Long-term Incentive Plan (formerly the Performance Share
Plan), certain officers of the Company and its subsidiaries may receive awards
based on meeting specific shareholder and customer performance rankings. The
Company recognized compensation expense in 1999, 1998, and 1997 of $1.1 million,
$2.0 million, and $1.1 million, respectively.
NOTE K: REGULATORY ASSETS AND LIABILITIES
Certain of the Company's utility 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 consolidated 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 $306,247 $317,745
Pennsylvania stranded cost recovery (CTC) 251,903 280,388
Pennsylvania CTC true-up 20,004
Pennsylvania pilot deferred revenue 9,040 6,726
Postretirement benefits 6,229 6,229
Pennsylvania tax increases 3,520
Storm damage 850 2,101
Demand-side management 184 8,157
Deferred revenues (14,900)
Other, net 2,027 2,806
- ------------------------------------------------------------------------------------------
Subtotal 585,104 624,152
Deferred power costs, net (
reported in other deferred charges/credits) (9,990) (2,455)
- -------------------------------------------------------------------------------------------
Subtotal 575,114 621,697
- ------------------------------------------------------------------------------------------
Current assets (liabilities), net
(reported in other current assets/liabilities):
CTC recovery 23,957 17,372
Income taxes, net 1,847 1,847
Deferred power costs, net (12,880) 7,211
Deferred revenues (19,949)
- ------------------------------------------------------------------------------------------
Subtotal (7,025) 26,430
- ------------------------------------------------------------------------------------------
Net regulatory assets $568,089 $648,127
- ------------------------------------------------------------------------------------------
</TABLE>
Future deregulation proceedings in Ohio, Virginia, and West Virginia may affect
the ratemaking treatment of the net regulatory assets related to generation in
these jurisdictions. See Notes B and C starting on pages 49 and 51,
respectively, for a discussion of deregulation plans approved in Pennsylvania
and Maryland. At this time, the Company cannot determine the effect of
deregulation plans in Ohio, Virginia, and West Virginia.
NOTE L: 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
- --------------------------------------------------------------------------------------------
Assets:
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Temporary cash investments $ 44,831 $ 44,831 $ 882 $ 882
Life insurance contracts 94,168 94,168 87,468 87,468
Liabilities:
Short-term debt 641,095 641,095 258,837 258,837
Long-term debt and QUIDS 2,468,407 2,370,723 2,198,577 2,307,081
Interest rate swap 1,528 3,831
Option contract for interest rate swap 5,717 5,717
- --------------------------------------------------------------------------------------------
</TABLE>
The carrying amount of temporary cash investments, as well as short-term debt,
approximates the fair value because of the short maturity of those instruments.
The fair value of the life insurance contracts was estimated based on cash
surrender value. The fair value of long-term debt and QUIDS was estimated based
on actual market prices or market prices of similar issues. The fair value of
the swap and option contract was estimated based on the present value of future
cash flows associated with these instruments. The swap and option were
terminated in June 1999.
The Company had no financial instruments held or issued for trading purposes.
NOTE M: CAPITALIZATION
Common Stock In March 1999, the Company announced a stock repurchase program
that authorized the repurchase of common stock worth up to $500 million from
time to time at price levels the Company deems attractive. The Company purchased
12 million shares of its common stock in 1999 at an aggregate cost of $398.4
million.
Preferred Stock West Penn called or redeemed all outstanding shares of its
cumulative preferred stock with a combined par value of $79.7 million plus
redemption premiums of $3.3 million on July 15, 1999, with proceeds from new
$84-million five-year unsecured medium-term notes issued in the second quarter
at a 6.375% coupon rate. Potomac Edison called all outstanding shares of its
cumulative preferred stock with a combined par value of $16.4 million plus
redemption premiums of $.5 million on September 30, 1999, with funds on hand.
Monongahela Power's outstanding 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, $189,734; 2001, $187,283; 2002, $134,105;
2003, $250,071; and 2004, $157,714. Substantially all of the properties of
Monongahela Power and Potomac Edison are held subject to the lien securing their
first mortgage bonds. Some properties are also subject to a second lien securing
certain pollution control and solid waste disposal notes. During 1999, West Penn
reacquired all of its outstanding $525 million of first mortgage bonds.
In November 1999, West Penn Funding, LLC, issued $600 million of transition
bonds as authorized by the Pennsylvania PUC (see Note B). The transition bonds
are secured by the collection of transition costs through a nonbypassable charge
to customers in the West Penn service area.
NOTE N: SHORT-TERM DEBT
To provide interim financing and support for outstanding commercial paper, lines
of credit have been established with several banks. The Company and its
regulated subsidiaries have fee arrangements on all of their lines of credit and
no compensating balance requirements. At December 31, 1999, unused lines of
credit with banks were $435 million. In addition to bank lines of credit, an
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><C> <C> <C><C>
Commercial paper $641,095 - 5.98% $208,837 - 5.40%
Notes payable to banks 50,000 - 5.40%
Average amount outstanding and interest rate during the year:
Commercial paper 418,166 - 5.41% 171,393 - 5.60%
Notes payable to banks 25,098 - 5.22% 44,789 - 5.62%
- ------------------------------------------------------------------------------------
</TABLE>
NOTE O: BUSINESS SEGMENTS
The Company's principal business segments are utility and nonutility operations.
The utility subsidiaries, Monongahela Power, Potomac Edison, and West Penn,
collectively now do business as Allegheny Power. Allegheny Power is involved in
the delivery (transmission and distribution) and procurement of electric energy
subject to federal and state traditional utility price regulation. Also,
Allegheny Power is involved in generation of electric energy in jurisdictions
which have not yet implemented deregulation of electric generation. Nonutility
operations consist primarily of the Company's energy supply business, now
Allegheny Energy Supply. Also included in nonutility operations is Allegheny
Ventures, a wholly owned subsidiary of the Company, which develops new business
opportunities, including telecommunications. Since January 1, 1999, the
Company's supply business has the primary objective of selling the output of the
West Penn generation that has been freed up by the Customer Choice Act in
Pennsylvania and is no longer regulated by the Pennsylvania PUC. In November
1999, the Company formed a new nonutility generating company, Allegheny Energy
Supply. West Penn transferred its deregulated generating capacity, which totaled
3,778 MW, at book value as allowed by the final settlement in West Penn's
Pennsylvania restructuring case. Allegheny Energy Supply also purchased from AYP
Energy its 276 MW of merchant capacity at Fort Martin Unit No. 1.
Business segment information for 1999, 1998, and 1997 is summarized below.
Transactions between affiliates are recognized at prices which approximate
market value. Significant transactions between reportable segments are
eliminated to reconcile the segment information to consolidated amounts. The
identifiable assets information does not reflect the elimination of intercompany
balances or transactions which are eliminated in the Company's consolidated
financial statements.
<TABLE>
<CAPTION>
(Thousands of dollars) 1999 1998 1997
- --------------------------------------------------------------------------------------------
Operating revenues:
<S> <C> <C> <C>
Utility $2,273,727 $2,330,261 $2,286,175
Nonutility 887,387 246,986 85,794
Eliminations (352,673) (811) (2,478)
Depreciation and amortization:
Utility 197,955 264,609 259,145
Nonutility 59,501 5,770 6,605
Federal and state income taxes:
Utility 131,225 178,929 177,581
Nonutility 33,216 (10,533) (9,508)
Operating income:
Utility 395,425 449,762 457,267
Nonutility 79,222 (10,255) (5,030)
Interest charges, preferred dividends,
and preferred redemption premiums:
Utility 160,934 176,073 182,564
Nonutility 31,871 10,159 10,786
Eliminations (102)
Consolidated income before extraordinary charge:
Utility 236,472 283,323 295,653
Nonutility 48,917 (20,315) (14,357)
Extraordinary charge, net:
Utility 26,968 275,426
Identifiable assets:
Utility 5,293,394 6,321,777 6,442,512
Nonutility 1,559,047 213,418 211,579
Capital expenditures:
Utility 266,205 229,362 284,648
Utility-acquisition of businesses 98,714
Nonutility 147,160 6,205 829
- --------------------------------------------------------------------------------------------
</TABLE>
See Notes C and F for a discussion of extraordinary charges, net.
NOTE P: COMMITMENTS AND CONTINGENCIES
Construction and Capital Program The subsidiaries have entered into commitments
for their construction and capital programs for which expenditures are estimated
to be $419 million for 2000 and $431 million for 2001. In addition, in 2000,
Monongahela Power plans to purchase Mountaineer Gas Company for approximately
$323 million (which includes the assumption of approximately $100 million in
existing debt). Construction expenditure levels 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.
Environmental Matters and Litigation The companies are subject to various laws,
regulations, and uncertainties as to environmental matters. Compliance may
require them 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 $370 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, Monongahela Power, Potomac Edison, and West Penn 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's share of the remediation costs based on the amount of
materials sent to the site. However, the Company estimates that its share of the
cleanup liability will not exceed $1 million, which has been accrued as a
liability at December 31, 1999.
Monongahela Power, Potomac Edison, and West Penn 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 $5.8 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 the Company of their intent to commence civil
actions against the Company 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 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 Allegheny Energy
Supply, Monongahela Power, 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, the Company 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 and its subsidiaries become
involved in various legal proceedings. The Company and its subsidiaries do not
believe that the ultimate outcome of these proceedings will have a material
effect on their financial position.
Leases The Company's lease obligations as of December 31, 1999, and 1998 were
not material.
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
Chairman, President, and Chief Executive Officer
Michael P. Morrell
Senior Vice President and Chief Financial Officer
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders of Allegheny Energy, Inc.
In our opinion, the accompanying consolidated balance sheets, consolidated
statements of capitalization and of common equity and the related consolidated
statements of income and of cash flows present fairly, in all material respects,
the financial position of Allegheny Energy, Inc. and its subsidiaries at
December 31, 1999 and 1998, and the results of their operations and their 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
<TABLE>
<CAPTION>
CONDENSED FINANCIAL STATEMENTS
Monongahela The Potomac West Penn Allegheny Energy Allegheny
Power Edison Power Company Supply Energy, Inc. and
Year ended December 31, 1999 Company Company and Subsidiaries Company, LLC Subsidiaries
- -----------------------------------------------------------------------------------------------------------
(Thousands of dollars)
BALANCE SHEETS
Assets
Property, plant, and equipment:
<S> <C> <C> <C> <C> <C> <C>
At original cost* $2,173,603 $2,322,104 $1,597,484 $2,060,040 $ 8,839,719
Accumulated depreciation (958,867) (998,710) (506,416) (940,672) (3,632,568)
- -----------------------------------------------------------------------------------------------------------
1,214,736 1,323,394 1,091,068 1,119,368 5,207,151
Excess of cost over
net assets acquired 26,325 42,584
Cash and temporary cash investments 3,826 34,509 19,288 1,668 65,984
Other current assets 228,393 173,171 272,600 245,802 643,326
Regulatory assets 145,176 46,121 467,982 663,847
Other 75,262 61,656 13,827 83,325 229,549
- ---------------------------------------------------------------------------------------------------------
Total $1,693,718 $1,638,851 $1,864,765 $1,450,163 $ 6,852,441
- ---------------------------------------------------------------------------------------------------------
$ 46,138 $ 53,354 $ 45,450 $ 86,147 $ 231,763
*Includes construction work in progress
Capitalization and liabilities
Common stock, other paid-in capital,
retained earnings, less
treasury stock (at cost) $ 578,951 $ 700,422 $ 79,658 $ 512,699 $ 1,695,325
Preferred stock 74,000 74,000
Long-term debt and QUIDS 503,741 510,344 966,026 356,239 2,254,463
Short-term debt 28,650 21,200 641,095
Other current liabilities 216,353 208,327 259,635 224,158 667,440
Unamortized investment credit 14,007 17,720 21,847 18,199 116,971
Deferred income taxes 248,987 159,351 211,369 128,639 920,943
Regulatory liabilities 13,961 25,319 15,126 78,743
Adverse power purchase commitments 303,935 185,626 303,935
Other 15,068 17,368 7,169 3,403 99,526
- ---------------------------------------------------------------------------------------------------------
Total $1,693,718 $1,638,851 $1,864,765 $1,450,163 $ 6,852,441
- ---------------------------------------------------------------------------------------------------------
Statements of income
Operating revenues $ 673,335 $ 753,257 $1,354,203 $ 140,874 $ 2,808,441
Operating expenses 554,298 617,535 1,160,434 130,408 2,333,794
- ---------------------------------------------------------------------------------------------------------
Operating income 119,037 135,722 193,769 10,466 474,647
Other income and deductions 7,178 8,518 9,654 1,159 3,445
- ---------------------------------------------------------------------------------------------------------
Income before interest charges,
preferred dividends,
preferred redemption premiums,
and extraordinary charge, net 126,215 144,240 203,423 11,625 478,092
Interest charges, preferred dividends,
and preferred redemption premiums 38,925 44,728 70,680 2,093 192,703
- ---------------------------------------------------------------------------------------------------------
Balance for common stock
before extraordinary charge, net 87,290 99,512 132,743 9,532 285,389
Extraordinary charge, net (16,949) (10,018) (26,968)
- ---------------------------------------------------------------------------------------------------------
Balance for common stock $ 87,290 $ 82,563 $ 122,725 $ 9,532 $ 258,421
- ---------------------------------------------------------------------------------------------------------
</TABLE>
Note: Allegheny Energy Supply Company, LLC, started operations on November 18,
1999.
<TABLE>
<CAPTION>
CONSOLIDATED STATISTICS
Year ended December 31 1999 1998 1997 1996 1995 1994 1989
- -------------------------------------------------------------------------------------------------------------
Summary of operations (Millions of dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $2,808.4 $2,576.4 $2,369.5 $2,327.6 $2,315.2 $2,184.6 $1,790.6
- -------------------------------------------------------------------------------------------------------------
Operation expense 1,498.1 1,286.0 1,065.9 1,013.0 1,024.9 1,017.8 867.0
Maintenance 223.5 217.5 230.6 243.3 249.5 241.9 185.5
Restructuring charges and asset write-offs 103.9 23.4 9.2
Depreciation 257.5 270.4 265.7 263.2 256.3 223.9 172.3
Taxes other than income 190.3 194.6 187.0 185.4 184.7 183.1 139.5
Taxes on income 164.4 168.4 168.1 128.0 154.2 125.9 89.0
Allowance for funds
used during construction (6.9) (5.0) (8.3) (5.9) (8.2) (19.6) (7.7)
Interest charges, preferred dividends,
and preferred redemption premiums 197.7 189.7 197.2 191.1 196.9 184.1 156.0
Other income and deductions (1.6) (8.2) (18.0) (4.4) (6.2) (1.5) (5.9)
- -------------------------------------------------------------------------------------------------------------
Consolidated income before
extraordinary charge
and cumulative effect
of accounting change 285.4 263.0 281.3 210.0 239.7 219.8 194.9
Extraordinary charge, net a (27.0) (275.4)
Cumulative effect of accounting change, net b 43.4
- -------------------------------------------------------------------------------------------------------------
Consolidated net income (loss) $ 258.4 $ (12.4) $ 281.3 $ 210.0 $ 239.7 $ 263.2 $ 194.9
- -------------------------------------------------------------------------------------------------------------
Common stock data c
Shares issued (thousands) 122,436 122,436 122,436 121,840 120,701 119,293 105,579
Treasury shares (thousands) (12,000)
- -------------------------------------------------------------------------------------------------------------
Shares outstanding (thousands) 110,436 122,436 122,436 121,840 120,701 119,293 105,579
- -------------------------------------------------------------------------------------------------------------
Average shares outstanding (thousands) 116,237 122,436 122,208 121,141 119,864 118,272 104,787
Earnings per average share: d
Consolidated income before
extraordinary charge
and cumulative effect
of accounting change $ 2.45 $ 2.15 $ 2.30 $ 1.73 $ 2.00 $ 1.86 $ 1.86
Extraordinary charge, net a (.23) (2.25) .37
Cumulative effect of accounting
change, net b
Consolidated net income (loss) $ 2.22 $ (.10) $ 2.30 $ 1.73 $ 2.00 $ 2.23 $ 1.86
Dividends paid per share $ 1.72 $ 1.72 $ 1.72 $ 1.69 $ 1.65 $ 1.64 $ 1.55
Dividend payout ratioe 64.6% 73.5% 74.7% 97.5% 82.5% 88.3% 83.3%
Shareholders 44,873 48,869 53,389 58,677 63,280 66,818 68,156
Market price per share:
High $ 35 3/16 $ 34 15/16 $ 32 19/32 $31 1/8 $ 29 1/4 $ 26 1/2 $21 1/4
Low $ 26 3/16 $ 26 5/8 $ 25 1/2 $ 28 $21 1/2 $ 19 3/4 $17 13/16
Close $ 26 15/16$ 34 1/2 $ 32 1/2 $ 30 3/8 $28 5/8 $ 21 3/4 $20 15/16
Book value per share $ 15.35 $ 16.61 $ 18.43 $ 17.80 $ 17.65 $ 17.26 $ 14.99
Return on average common equity e 16.16% 13.26% 12.63% 9.69% 11.35% 10.96% 12.41%
- --------------------------------------------------------------------------------------------------------------
Capitalization data (Millions of dollars)
Common stock $1,695.3 $2,033.9 $2,256.9 $2,169.1 $2,129.9 $2,059.3 $1,582.4
Preferred stock:
Not subject to mandatory redemption 74.0 170.1 170.1 170.1 170.1 300.1 235.1
Subject to mandatory redemption 25.2 30.6
Long-term debt and QUIDS 2,254.5 2,179.3 2,193.1 2,397.1 2,273.2 2,178.5 1,578.4
- -------------------------------------------------------------------------------------------------------------
Total capitalization $4,023.8 $4,383.3 $4,620.1 $4,736.3 $4,573.2 $4,563.1 $3,426.5
- -------------------------------------------------------------------------------------------------------------
Capitalization ratios:
Common stock 42.1% 46.4% 48.8% 45.8% 46.6% 45.1% 46.2%
Preferred stock:
Not subject to mandatory redemption 1.9 3.9 3.7 3.6 3.7 6.6 6.8
Subject to mandatory redemption .6 .9
Long-term debt and QUIDS 56.0 49.7 47.5 50.6 49.7 47.7 46.1
- --------------------------------------------------------------------------------------------------------------
Total assets (Millions of dollars) $6,852.4 $6,535.2 $6,654.1 $6,618.5 $6,447.3 $6,362.2 $4,433.3
- --------------------------------------------------------------------------------------------------------------
Property data (Millions of dollars)
Gross property $8,839.7 $8,395.3 $8,451.4 $8,206.2 $7,812.7 $7,586.8 $5,721.5
Accumulated depreciation (3,632.6) (3,395.6) (3,155.2) (2,910.0) (2,700.1) (2,529.4) (1,807.1)
- --------------------------------------------------------------------------------------------------------------
Net property $5,207.1 $4,999.7 $5,296.2 $5,296.2 $5,112.6 $5,057.4 $3,914.4
Gross additions during year-utility $ 266.2 $ 229.4 $ 284.7 $ 289.5 $ 319.1 $ 508.3 $ 302.5
-nonutility $ 141.3 $ 1.8 $ 1.4 $ 178.5
Ratio of provisions for
depreciation to depreciable property 3.23% 3.28% 3.34% 3.47% 3.50% 3.32% 3.26%
- -------------------------------------------------------------------------------------------------------------
Revenues (Millions of dollars) f
Residential $ 930.3 $ 880.6 $ 892.9 $ 932.2 $ 927.0 $ 863.7 $ 626.2
Commercial 500.3 501.4 490.5 492.7 493.7 459.3 327.5
Industrial 720.5 753.5 748.1 752.9 770.2 728.0 553.5
Wholesale and street lighting 42.4 69.0 65.1 66.6 59.6 58.7 46.2
- -------------------------------------------------------------------------------------------------------------
Revenues from
regular utility customers 2,193.5 2,204.5 2,196.6 2,244.4 2,250.5 2,109.7 1,553.4
Other non-gWh 9.2 9.9 6.4 7.7 6.5 7.1 5.0
Bulk power 22.5 69.8 39.6 22.4 13.0 29.0 189.7
Transmission and other energy services 48.5 45.2 41.1 52.4 45.2 38.8 42.5
- -------------------------------------------------------------------------------------------------------------
Total utility revenues $2,273.7 $2,329.4 $2,283.7 $2,326.9 $2,315.2 $2,184.6 $1,790.6
- -------------------------------------------------------------------------------------------------------------
Total nonutility revenues $ 887.4 $ 247.0 $ 85.8 $ .7
- -------------------------------------------------------------------------------------------------------------
Sales volumes-gWh
Residential 13,562 12,939 12,832 13,328 13,003 12,630 11,042
Commercial 8,955 8,626 8,176 8,132 7,963 7,607 6,479
Industrial 19,846 19,675 19,040 18,568 18,457 17,708 16,239
Wholesale and street lighting 1,478 1,409 1,422 1,456 1,304 1,275 1,110
- -------------------------------------------------------------------------------------------------------------
Regular utility transactions 43,841 42,649 41,470 41,484 40,727 39,220 34,870
- -------------------------------------------------------------------------------------------------------------
Bulk power 571 3,037 1,667 966 507 1,086 7,011
Transmission and other energy services 8,450 7,345g 12,367 17,402 14,586 9,405 17,777
- -------------------------------------------------------------------------------------------------------------
Total utility transactions 52,862 53,031 55,504 59,852 55,820 49,711 59,658
- -------------------------------------------------------------------------------------------------------------
Total nonutility transactions 15,854 8,278 3,734 109
- -------------------------------------------------------------------------------------------------------------
Output and delivery-gWh
Steam generation 44,776 44,323 43,463 40,067 39,174 38,959 43,497
Hydro and pumped-storage generation 1,648 1,326 1,171 1,348 1,234 1,390 1,774
Pumped-storage input (1,963) (1,498) (1,298) (1,405) (1,390) (1,564) (1,973)
Purchased power 17,365 11,505 6,485 5,518 5,021 4,136 1,797
Transmission and other energy services 8,450 7,777 12,367 17,402 14,586 9,405 17,777
Combustion turbines 7
Losses and system uses (3,066) (2,124) (2,950) (2,969) (2,805) (2,615) (3,214)
- -------------------------------------------------------------------------------------------------------------
Total transactions as above 67,217h 61,309 59,238 59,961 55,820 49,711 59,658
- -------------------------------------------------------------------------------------------------------------
Energy supply
Generating capability-MW
Utility-owned 4,451 8,121 8,071 8,070 8,070 8,070 7,906
Nonutility-owned 4,142 276 276
Nonutility contracts i 299 299 299 299 299 299 160
Maximum hour peak-MW 7,788j 7,314j 7,423 7,500 7,280 7,153 6,489
Load factor 70.5%k 69.1%k 68.3% 67.5% 68.3% 66.8% 67.0%
Heat rate-Btus per kWh 9,963 9,939 9,936 9,910 9,970 9,927 9,967
Fuel costs-cents per million Btus 119.61 128.92 130.05 129.22 130.20 141.50 136.70
- -------------------------------------------------------------------------------------------------------------
</TABLE>
a Write-off in connection with deregulation proceedings in Maryland and
Pennsylvania and costs associated with the reacquisition of first
mortgage bonds.
b To record unbilled revenues, net of income taxes.
c Reflects a two-for-one common stock split effective November 4, 1993.
d Basic and diluted earnings per average share.
e Excludes the cumulative effect of the accounting change in 1994, the
extraordinary charge, net, and Pennsylvania restructuring activities
in 1998, and the extraordinary charge and other charges for merger-
related costs and a long dormant pumped-storage generation project
in 1999. Includes the effect of internal restructuring in 1995 and
1996.
f Eliminations between utility and nonutility are shown on page 32.
g Excludes 432 gWh delivered to customers participating in the Pennsylvania
pilot program that are included in regular utility transactions sales
volumes.
h Net of 1,499 gWh eliminated between utility and nonutility.
i Capability available through contractual arrangements with nonutility
generators.
j Peak coincident load of all customers provided delivery service within the
Company's service territory irrespective of the generation service chosen
by the customers therein.
k Based on peak coincident load.
<TABLE>
<CAPTION>
UTILITY STATISTICS
Year ended December 31 1999 1998 1997 1996 1995 1994 1989
- ------------------------------------------------------------------------------------------------------------
Customers (thousands) a
<S> <C> <C> <C> <C> <C> <C> <C>
Residential 1,250.6 1,236.9 1,224.9 1,213.7 1,204.4 1,189.7 1,118.1
Commercial 158.1 154.7 151.5 148.5 146.0 143.0 128.9
Industrial 25.9 25.5 25.2 25.0 24.6 24.2 22.4
Other 1.3 1.3 1.3 1.3 1.3 1.3 1.2
- ------------------------------------------------------------------------------------------------------------
Total customers 1,435.9 1,418.4 1,402.9 1,388.5 1,376.3 1,358.2 1,270.6
- ------------------------------------------------------------------------------------------------------------
Average annual use-kWh per
customer b
Residential 10,913 10,486 10,521 11,042 10,865 10,682 9,950
All retail service 28,285 28,174 28,647 29,085 28,908 28,205 26,866
- ------------------------------------------------------------------------------------------------------------
Average rate-cents per kWh b
Residential 7.03 6.90 6.96 6.99 7.13 6.84 5.67
All retail service 5.45 5.32 5.36 5.46 5.58 5.43 4.48
- ------------------------------------------------------------------------------------------------------------
</TABLE>
a Customers in the Company's service territory receiving delivery service.
b Use and rate statistics are calculated based on full service customers
(customers receiving both generation and delivery from the Company).
INVESTOR INFORMATION
Dividend Declarations Dividends are normally declared on the first Thursday of
March, June, September, and December. Record dates are normally the second
Monday after the dividend is declared, with payment dates the last business day
of March, June, September, and December.
Dividend Reinvestment and Stock Purchase Plan Our Dividend Reinvestment and
Stock Purchase Plan provides shareholders with a convenient way to purchase
additional shares of the Company's stock. Participants may at the time of each
cash dividend payment on the stock have all or part of their dividends
automatically invested in additional shares or invest any additional amount they
wish between $50 and $10,000 in such shares or do both. The offering of shares
under the Plan is made only by Prospectus. To get the Prospectus and an
Authorization Form to enroll in the Plan, write to Eileen M. Beck, Secretary,
Allegheny Energy, Inc., 10435 Downsville Pike, Hagerstown, MD 21740-1766, or
[email protected].
Annual Meeting The Annual Meeting of Shareholders will be held on the eleventh
floor of the World Headquarters of Chase Manhattan Bank, 270 Park Ave., New
York, NY, on Thursday, May 11, 2000, at 9:30 a.m.
Form 10-K The Company will provide without charge to each beneficial holder of
its common stock, on the written request of such person, a copy of Allegheny
Energy's combined Annual Report to the Securities and Exchange Commission on
Form 10-K for 1999. Any such request should be directed to Cynthia A. Shoop,
Director, Corporate Communications, Allegheny Energy, Inc., 10435 Downsville
Pike, Hagerstown, MD 21740-1766, or [email protected].
Duplicate Mailings/Direct Deposit of Dividends If you receive duplicate
mailings of the Annual Report or wish to have your dividends deposited directly
to your banking institution, please notify ChaseMellon Shareholder Services,
L.L.C., P.O. Box 3316, South Hackensack, NJ 07606. To speak to a representative
responsible for Allegheny Energy, Inc. shareholder accounts, call 1-800-648-
8389.
Stock Transfer Agent and Registrar ChaseMellon Shareholder Services, L.L.C.,
Overpeck Centre, 85 Challenger Road, Ridgefield Park, NJ 07660. The internet
address is www.chasemellon.com.
DIVIDENDS PAID-RANGE OF COMMON STOCK PRICES PER SHARE
<TABLE>
<CAPTION>
1999 1998
------------------------------------------- ---------------------------------------------
NYSE Composite
Transactions Dividend High Low Close Dividend High Low Close
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
1st Quarter .43 $ 34 1/2 $28 11/16 $ 29 1/2 .43 $ 33 9/16 $ 30 1/8 $ 33 9/16
2nd Quarter .43 35 3/16 29 1/2 32 1/16 .43 34 27 5/16 30 1/8
3rd Quarter .43 34 7/8 31 31 7/8 .43 31 15/16 26 5/8 31 9/16
4th Quarter .43 33 1/8 26 3/16 26 15/16 .43 34 15/16 29 1/2 34 1/2
</TABLE>
The high and low prices in 2000 were $ 29 and $ 25 9/16 through February 3,
2000. The last reported sale on that date was $ 28 5/8.
- ------------------------------------------------------------------------------
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
<TABLE>
<CAPTION>
(Millions of dollars)
Basic and Diluted Earnings Per Average Share
-------------------------------------------
Consolidated Consolidated
Income Before Consolidated Income Before Consolidated
Operating Operating Extraordinary Extraordinary Net Income Extraordinary Extraordinary Net Income
Quarter Ended Revenues Income Charge, Net Charge, Net (Loss) Charge, Net Charge, Net (Loss)
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C>
March 1998 $645.5 $124.7 $78.2 $ 78.2 $.64 $ .64
June 1998* 627.6 100.1 53.8 $(265.4) (211.6) .44 $(2.17) (1.73)
September 1998 726.6 128.6 82.7 82.7 .68 .68
December 1998* 576.7 86.1 48.3 (10.0) 38.3 .39 (.08) .31
March 1999 690.0 140.2 97.8 97.8 .80 .80
June 1999 643.4 111.7 64.5 64.5 .55 .55
September 1999 741.4 117.2 71.3 71.3 .63 .63
December 1999** 733.7 105.5 51.8 (27.0) 24.8 .46 (.24) .22
- ----------------------------------------------------------------------------------------------------------------------
</TABLE>
*Results for the second and fourth quarters of 1998 reflect Pennsylvania
restructuring activities.
**Results for the fourth quarter of 1999 reflect charges for Maryland
restructuring, retiring debt related to the securitization of Pennsylvania
stranded costs, merger-related costs, and a long dormant pumped-storage
generation project.
<PAGE>
EXHIBIT 99.2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
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 Allegheny Energy, Inc. (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, regulatory, and competitive
environments in which the Company operates, including regulatory proceedings
affecting rates charged by the Company's subsidiaries; environmental,
legislative, and regulatory changes; future economic conditions; earnings
retention and dividend payout policies; the Company's ability to compete in
unregulated energy markets; 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 Generation of electricity will continue to be a core
component of the Company's business. The Company's goal is to grow generation
through building and buying generating facilities. The energy delivery (wires
and pipes) business will also continue to be an important part of the Company's
business which the Company plans to expand. Existing nonutility businesses,
primarily telecommunications, that are closely tied to our core business will
continue to be developed.
The Company's settlement agreement in Pennsylvania permitted West Penn Power
Company (West Penn) to transfer 3,778 megawatts (MW) of generating capacity at
net book value to a new, unregulated, wholly owned subsidiary of the Company.
The recent settlement in Maryland will allow about 1,300 MW of additional
generating capacity to be transferred at net book value in 2000. The Company 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 us to capitalize on the
Company's strengths in the generation business.
SIGNIFICANT EVENTS IN 1999, 1998, AND 1997
Maryland Deregulation On September 23, 1999, a settlement agreement between The
Potomac Edison Company (Potomac Edison), the Staff of the Maryland Public
Service Commission (Maryland PSC), and other parties working to implement
customer choice and deregulation of electric generation for Potomac Edison in
Maryland was filed with the Maryland PSC. On December 23, 1999, the Maryland PSC
approved the settlement agreement, which provides nearly all of Potomac Edison's
211,000 Maryland customers with the ability to choose an electric generation
supplier starting July 1, 2000.
As a result of the Maryland settlement agreement, Potomac Edison discontinued
the application of the Financial Accounting Standards Board's (FASB) Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," for the electric generation portion of its
Maryland operations and has adopted SFAS No. 101, "Accounting for the
Discontinuation of Application of FASB Statement No. 71." Accordingly, Potomac
Edison recorded an extraordinary charge of $26.9 million ($17.0 million after
taxes) during the fourth quarter of 1999. This write-off reflects the impairment
of certain electric generation assets as determined by applying SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of," and the write-off of generation-related net regulatory assets.
See Notes B and C to the consolidated financial statements for details of the
settlement agreement and other information about the deregulation process.
See Electric Energy Competition on page 38 for more information regarding
restructuring in Maryland.
Pennsylvania Deregulation On November 19, 1998, the Pennsylvania Public Utility
Commission (Pennsylvania PUC) approved a settlement agreement between West
Penn-the Company's Pennsylvania electric utility subsidiary-and parties to West
Penn's restructuring proceedings related to legislation in Pennsylvania to
provide customer choice of electric suppliers and deregulate electricity
generation.
As a result of the May 29, 1998, Pennsylvania PUC order and as revised by the
November 19, 1998, settlement agreement, West Penn determined in 1998 that,
under the provisions of SFAS No. 101, an extraordinary charge of $466.9 million
($275.4 million after taxes) was required to reflect a write-off of certain
disallowances. Charges of $40.3 million ($23.7 million after taxes) related to
the West Penn revenue refund and energy program payments were also recorded in
1998.
Under the terms of the Pennsylvania settlement agreement, two-thirds of West
Penn's customers were permitted to choose an alternate generation supplier
beginning in January 1999.
All West Penn customers were permitted to do so beginning in January 2000. They
were able to remain as West Penn customers at West Penn's capped generation
rates or to alternate back and forth. Under the law, all electric utilities,
including West Penn, retain the responsibility of electricity provider of last
resort to all customers in their respective franchise territories who do not
choose an alternate supplier. See Notes B and C to the consolidated financial
statements for details of the settlement agreement and other information about
the deregulation process.
See Electric Energy Competition on page 38 for more information regarding the
restructuring in Pennsylvania.
Nonutility Sales of Electricity Since 1997, the Company has been marketing
electric energy to customers in deregulated markets. During 1999, the Company's
energy supply business sold 2,912,273 megawatt-hours (MWh) of electricity to
customers in deregulated retail markets and 21,374,732 MWh to customers in
deregulated wholesale markets. During 1999, West Penn's former generation
customers purchased 2,522,611 MWh of electricity from alternative energy
suppliers as a result of customer choice in Pennsylvania.
Unregulated Generating Subsidiary During 1999, the Company obtained the
necessary regulatory approvals to form an unregulated generating subsidiary,
Allegheny Energy Supply Company, LLC (Allegheny Energy Supply). During the
fourth quarter of 1999, West Penn transferred its deregulated generating
capacity, which totaled 3,778 MW, to Allegheny Energy Supply at book value as
allowed by the final settlement in West Penn's Pennsylvania restructuring case.
In addition, Allegheny Energy Supply purchased from AYP Energy, Inc. (AYP
Energy) its 276 MW of merchant capacity at Fort Martin Unit No. 1.
Recapitalization In 1999, the Company completed the following steps in its
recapitalization process for West Penn concurrent with the implementation of
deregulation of electric generation in Pennsylvania:
* $600 million of transition bonds were issued in November 1999;
* $525 million of first mortgage bonds were called or redeemed during the year;
* $79.7 million of preferred stock was called or redeemed
in July 1999; and
* West Penn revised its Articles of Incorporation to provide greater financial
flexibility.
During 1999, West Penn reacquired all of its outstanding first mortgage bonds.
As a result, the Company incurred an extraordinary charge of $17.0 million
($10.0 million after taxes) during the fourth quarter of 1999. The extraordinary
charge was the result of premiums paid to reacquire the first mortgage bonds as
compared to the carrying value of the bonds.
In addition, the Company repurchased 12 million shares of its outstanding common
stock for $398.4 million, and Potomac Edison also called $16.4 million of
preferred stock. Potomac Edison also plans to revise its Articles of
Incorporation to provide greater financial flexibility.
Additional Generation In 1999, the Company installed two 44-MW simple-cycle gas
combustion turbines in Springdale Borough in Allegheny County, Pennsylvania, at
a cost of approximately $46 million. These units are unregulated merchant plants
and became operational at the end of 1999. Both run on either No. 2 diesel oil
or natural gas. As part of the installation, existing gas lines were upgraded
and 500,000 gallons of oil storage capacity will be built. Transmission
facilities at the site and the nearby interconnections were also upgraded. The
generation output is being sold into the competitive power markets in the
eastern United States. These combustion turbines will be transferred to
Allegheny Energy Supply in the first quarter of 2000 or as soon thereafter that
the necessary regulatory approval can be obtained from the Securities and
Exchange Commission (SEC).
Allegheny Energy Supply is purchasing additional combustion turbines that will
add 220 MW to our fleet in 2000 at a cost of approximately $120 million. Also,
Allegheny Energy Supply is building a 540-MW combined-cycle generating plant at
Springdale, Pennsylvania, at a cost of $235 million. The new facility will
include two gas-fired combustion turbines and a steam turbine. All are expected
to be operational and providing power for sale into competitive markets in 2003.
Another new project is the anticipated development of a 100-MW generation
project in Warren County in northwestern Pennsylvania. A memorandum of
understanding was signed with Foster Wheeler Power Systems, Inc. (Foster
Wheeler) and United Refining Company (United Refining). The project will include
an upgrade by Foster Wheeler to United Refining's facility in the city of
Warren, Pennsylvania, with the installation of a petroleum coker and associated
equipment.
The generation project, if it is developed as planned, will be co-owned by
Allegheny Energy Supply, Foster Wheeler, and United Refining. It will
incorporate circulating fluidized-bed technology and use waste by-products from
the petroleum coking process in the production of electricity for the refinery
and for sale in the open market. Excess capacity from the generation will be
marketed by Allegheny Energy Supply, and steam produced by the project will be
used by the refinery. Construction expenditures for the entire project are
estimated at up to $300 million, of which Allegheny Energy Supply's share is
estimated at up to $100 million based on the participation of all three
potential co-owners or up to $150 million if one of the other potential co-
owners elects not to participate. Construction is anticipated to begin in early
2001. The memorandum of understanding to develop the facility has been signed by
all the parties, but a satisfactory feasibility study, acceptable financing
terms and conditions, permitting, and execution of definitive project agreements
are necessary before construction can begin.
Acquisitions In December 1999, Monongahela Power Company (Monongahela Power),
one of the Company's West Virginia subsidiaries, 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 Monongahela
Power's service territory in southern West Virginia, for approximately $95
million. As part of the transaction, Monongahela Power signed a 20-year option
agreement with UtiliCorp United's subsidiary, Aquila Energy, for gas supply to
Monongahela Power. 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 the Company 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 Monongahela Power. 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 has approximately 120 employees.
In conjunction with the acquisition of West Virginia Power's assets, the Company
purchased for $2.1 million the assets of a heating, ventilation, and air
conditioning business with approximately 10,000 customers and 52 employees.
In December 1999, Allegheny Communications Connect, Inc., the telecommunications
subsidiary of Allegheny Ventures, Inc., purchased for $3.1 million approximately
10% of Genosys Technology Management Inc., a recently formed network operation
center services company. The new enterprise will enable the Company to provide
value-added services, such as around-the-clock network monitoring and
maintenance services, to customers of its growing fiber optic network.
Monongahela Power 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 SEC. The companies
anticipate that regulatory approval could be received by mid-2000.
PURPA Power Project Terminations On August 26, 1997, and December 3, 1997, West
Penn announced that it had negotiated agreements to buy out and settle disputes
with developers of proposed power plants (the Milesburg and Washington Power
projects) for $15 million and $48 million, respectively, reducing costs over the
proposed 30- and 33-year lives of the projects by an estimated $1.4 billion. The
disputed projects were being developed under the Public Utility Regulatory
Policies Act of 1978 (PURPA) and would have required West Penn to buy 43 MW and
80 MW of capacity and energy, respectively, over the lives of the projects at
prices well above current market price estimates. In 1999, the Company settled
for $5 million litigation by another developer alleging failure by the Company
to comply with PURPA regulations.
Articles of Incorporation As a result of the passage of Maryland legislation
affecting corporate governance of companies incorporated in the state, the Board
of Directors by resolution in July 1999 amended the Company's Articles of
Incorporation. The Board resolution adopted a provision creating three classes
of directors of nearly even size, with the term of each director continuing for
the full initial term of the class to which he or she is designated; a provision
that directors cannot be removed from the Board except by a two-thirds vote of
all votes entitled to be cast by shareholders in an election of directors; that
vacancies may be filled only by the Board and for the full remainder of the
term; and that the number of directors may be fixed only by the Board.
Proposed Merger with DQE, Inc. See Note D to the consolidated financial
statements for information about the proposed merger with DQE, Inc.
Electric Industry Restructuring See Electric Energy Competition on page 38 for
ongoing information regarding electric industry restructuring.
REVIEW OF OPERATIONS
Earnings Summary
<TABLE>
<CAPTION>
Basic and Diluted
Earnings Per
Earnings Average Share
- --------------------------------------------------------------------------------
(Millions of dollars
except per share data) 1999 1998 1997 1999 1998 1997
- --------------------------------------------------------------------------------
Operations:
<S> <C> <C> <C> <C> <C> <C>
Utility $236.5 $ 283.3 $295.7 $2.03 $ 2.32 $2.42
Nonutility 48.9 (20.3) (14.4) .42 (.17) (.12)
- --------------------------------------------------------------------------------
Consolidated income 285.4 263.0 281.3 2.45 2.15 2.30
before extraordinary
charges
Extraordinary charges, (27.0) (275.4) (.23) (2.25)
net (Notes B, C, and F to
consolidated financial statements)
- -------------------------------------------------------------------------------
Consolidated net income
(loss) $258.4 $ (12.4) $281.3 $2.22 $ (.10) $2.30
- --------------------------------------------------------------------------------
</TABLE>
The decrease in 1999 earnings from utility operations, before extraordinary
charges, reflects the deregulation of two-thirds of West Penn's electric
generation effective January 1, 1999, as approved by the Pennsylvania PUC's
restructuring order for West Penn. Accordingly, the operating results for these
assets are classified as nonutility in 1999. The 1999 utility operations also
reflect higher operation and maintenance expenses, including the write-off of
$19.7 million of merger-related costs and $16.2 million of costs from a long
dormant pumped-storage generation project. The decrease in 1998 earnings from
utility operations, before extraordinary charges, reflects $23.7 million of
costs, after taxes, related to the Pennsylvania restructuring settlement.
In 1999, earnings from nonutility operations, before extraordinary charges,
increased consolidated net income by $48.9 million, an increase of $69.2 million
over 1998's loss. This increase in nonutility earnings reflects the sale of
generation from two-thirds of West Penn's generation assets into deregulated
markets as discussed under Sales and Revenues and improved results over 1998
performance in such markets. The 1998 increase in the losses from nonutility
operations, before extraordinary charges, resulted from AYP Energy sales
commitments for energy in excess of owned generating capacity which required
settlement by open market purchases during periods of high wholesale prices.
Also contributing to the nonutility losses in 1998 and 1997 were losses of $1.7
million and $1.4 million, respectively, by Allegheny Energy Solutions for its
participation in the Pennsylvania pilot program (see Note B to the consolidated
financial statements for more information about the pilot program).
Extraordinary charges in 1999 and 1998 resulted from the Maryland and
Pennsylvania electric utility restructuring orders as discussed in Notes B and C
to the consolidated financial statements and the redemption of debt by West Penn
in 1999 related to the securitization of stranded costs as discussed in Note F
to the consolidated financial statements.
Earnings per share in 1999 increased $.11 per share due to the Company's common
stock repurchase program.
Sales and Revenues Total operating revenues for 1999, 1998, and 1997 were as
follows:
<TABLE>
<CAPTION>
OPERATING REVENUES
(Millions of dollars) 1999 1998 1997
- ---------------------------------------------------------------------------------------
Operating revenues:
Utility revenues:
<S> <C> <C> <C>
Regulated $2,168.4 $2,201.2 $2,203.0
Choice 34.3 14.0 2.5
Bulk power 22.5 69.8 39.6
Transmission and other energy services 48.5 45.2 41.1
- ---------------------------------------------------------------------------------------
Total utility revenues 2,273.7 2,330.2 2,286.2
- ---------------------------------------------------------------------------------------
Nonutility revenues:
Retail and other 156.0 31.7 4.9
Bulk power 731.4 215.3 80.9
- ---------------------------------------------------------------------------------------
Total nonutility revenues 887.4* 247.0 85.8
- ---------------------------------------------------------------------------------------
Elimination between utility and nonutility (352.7) (.8) (2.5)
- ---------------------------------------------------------------------------------------
Total operating revenues $2,808.4 $2,576.4 $2,369.5
- ---------------------------------------------------------------------------------------
</TABLE>
*Nonutility operating revenues include $57.1 million in 1999 of allocated
Competitive Transition Charge revenues to compensate for certain transition
costs transferred to nonutility operations.
The decrease in regulated revenues (regulated revenues include revenues from
West Penn customers eligible to choose an alternate energy supplier but electing
not to do so) in 1999 was due primarily to Pennsylvania deregulation, which gave
two-thirds of West Penn's regulated customers the ability to choose another
energy supplier and to a reduction in Potomac Edison's Maryland rates as part of
a settlement agreement. In 1999, 2,522,611 MWh of electric energy was supplied
to West Penn customers by alternative energy suppliers, which represented only
11% of West Penn's total MWh sales. The decrease to regulated revenues was
offset in part by colder winter weather in 1999, which led to increased
residential kilowatt-hour (kWh) sales and revenues. Utility regulated revenues
in 1998 included a $25.1 million rate refund, pursuant to the terms of the
Pennsylvania restructuring settlement agreement. Excluding this rate decrease,
utility regulated revenues increased $23.3 million in 1998, primarily due to
increased kWh sales to commercial and industrial customers. The increase in 1998
was also due to an increase in the number of customers.
Utility choice revenues for 1999 represent transmission and distribution
revenues from West Penn franchised customers (customers in West Penn's
territory) who chose another supplier to provide their energy needs. In 1999,
less than 2% of West Penn's customers chose alternate energy suppliers. The
Company's nonutility supply business had the primary objective of selling the
output from the two-thirds of West Penn's generation that had been freed up by
the Electricity Generation Customer Choice and Competition Act (Customer Choice
Act) in Pennsylvania.
In 1998 and 1997, the choice revenues represent the 5% of previously fully
bundled customers (full service customers) who participated in the Pennsylvania
pilot program that began November 1, 1997, and continued through December 31,
1998, and were required to buy energy from an alternate supplier. To assure
participation in the pilot program, pilot participants received an energy credit
from their local utility and a price for energy pursuant to an agreement with an
alternate supplier. The credit established by the Pennsylvania PUC was
artificially high to encourage customer shopping, and, as a result, West Penn
incurred a revenue loss of $8.6 million for the pilot. The Pennsylvania PUC has
approved West Penn's pilot compliance filing and thus has indicated its intent
to treat the revenue loss as a regulatory asset.
On August 7, 1998, the Virginia State Corporation Commission (Virginia SCC)
approved an agreement reached between Potomac Edison and the Staff of the
Virginia SCC which reduced base rates for Virginia customers beginning September
1, 1998, by about $2.5 million annually. The review of rates was required by an
annual information filing in Virginia.
On February 25, 1999, the Virginia SCC approved Potomac Edison's rate reduction
request, which decreased the fuel portion of Virginia customers' bills by
approximately 7.6% (a decrease in annual fuel revenue of about $2.2 million).
The decrease is primarily due to refunding a prior overrecovery of fuel costs,
coupled with a small decrease in projected energy costs. The new rates were
effective with bills rendered on or after March 9, 1999.
On May 21, 1999, the Virginia SCC approved an agreement reached between Potomac
Edison and the staff of the Virginia SCC which reduced base rates for Virginia
customers effective June 1, 1999, by about $3 million annually. The review of
rates is required by an annual information filing in Virginia.
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 Potomac Edison and
Monongahela Power 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 Monongahela Power's
fuel rates by $10.9 million and decrease Potomac Edison's fuel rates by $8.0
million will become effective March 15, 2000.
On November 8, 1999, Potomac Edison filed with the Maryland PSC a request to
decrease the fuel portion of Maryland customers' bills by about $6.4 million
annually. The requested decrease is primarily due to greater efficiencies, lower
fuel costs, and increased nonaffiliated generation and transmission sales. The
new fuel rates were effective with bills rendered on or after December 7, 1999,
subject to refund, based on the outcome of proceedings before the Maryland PSC.
On October 27, 1998, the Maryland PSC approved a settlement agreement for
Potomac Edison. Under the terms of that agreement, Potomac Edison increased its
rates $13 million in 1999, will increase its rates an additional $13 million in
2000, and an additional increase of $13 million will go into effect in 2001 (a
$79 million total revenue increase during 1999 through 2001). The increases are
designed to recover additional costs of about $131 million over the 1999 through
2001 period for capacity purchases from the AES Warrior Run cogeneration
project, net of alleged over-earnings of $52 million for the same period. The
net effect of these changes over the 1999 through 2001 time frame results in a
pre-tax income reduction of $12 million in 1999, $21 million in 2000, and $19
million in 2001. Also, Potomac Edison will share, on a 50% customer, 50%
shareholder basis, earnings above a return on equity of 11.4% in Maryland for
1999 and 2000. This sharing will occur through an annual true-up. Potomac
Edison's 1999 revenues reflect an estimated obligation for shared earnings above
an 11.4% return on equity.
Utility-related 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 are still applicable in all Company jurisdictions
served, except for Pennsylvania. Effective July 1, 2000, Potomac Edison's
Maryland jurisdiction will also cease to have a fuel clause under the terms of
the September 23, 1999, settlement agreement. Changes in fuel revenues in
jurisdictions for which a fuel clause continues to exist have no effect on
consolidated 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.
Effective May 1, 1997, as a result of the Customer Choice Act, West Penn
obtained Pennsylvania PUC authorization to set its fuel clause to zero and to
roll its then-applicable fuel clause rates into base rates. Thereafter, West
Penn assumed the risks and benefits of changes in fuel and purchased power costs
and sales of transmission services and bulk power. Effective July 1, 2000,
Potomac Edison will assume similar risks and benefits for its Maryland
jurisdiction.
The 1999 decrease in revenues from utility bulk power was due to the movement of
generation available for sale from regulated utility to nonutility. The 1998
increase in revenues from utility bulk power and transmission and other energy
services sales 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. In 1998, revenues from utility 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 Federal Energy Regulatory Commission (FERC). A provision for these rate
reductions was recorded in 1998, with the revenues refunded to customers in the
first quarter of 1999.
Revenues from utility operations transmission and other energy services in 1998
increased, despite decreased transmission services activity. The increase in
revenues was due in part to transmission services reservation charges paid to
the Company by others for the right to transmit energy.
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
potential exists for such volatility to significantly affect the Company's
operating results. The effect may be either positive or negative, depending on
whether the Company's subsidiaries are net buyers or sellers of electricity
during such periods, the open commitments which exist at such times, and whether
the effects of such transactions by the Company's utility subsidiaries are
included in fuel or energy cost recovery clauses in their respective
jurisdictions. The effect of such price volatility in June and July of 1998
differed between the Company's utility and nonutility subsidiaries, but was
insignificant in total. The effect in 1999 was to measurably increase earnings
in total for the Company even though individual subsidiary experiences were
again diverse.
Nonutility revenues have increased primarily because of bulk power sales to
nonaffiliated companies and new sales in Pennsylvania's competitive marketplace.
The Company's supply business officially began supplying unregulated electricity
to retail customers in Pennsylvania and wholesale customers throughout eastern
North America on January 1, 1999. Allegheny Energy Supply also engages in other
transactions in the unregulated marketplace to sell electricity to both
wholesale and retail customers.
The elimination (see page 32) between utility and nonutility revenues is
necessary to remove the effect of affiliated revenues, primarily sales of power.
See Note B to the consolidated financial statements for information regarding
the Competitive Transition Charge.
OPERATING EXPENSES
Fuel expenses for 1999, 1998, and 1997 were as follows:
Fuel expenses
(Millions of dollars) 1999 1998 1997
- -------------------------------------------------------------
Utility operations $ 355.5 $545.4 $535.7
Nonutility operations 180.2 21.1 24.2
- -------------------------------------------------------------
Total fuel expenses $ 535.7 $566.5 $559.9
- -------------------------------------------------------------
Total fuel expenses decreased 5% in 1999 due to a 7% decrease in average fuel
prices offset by a 2% increase related to kWhs generated. The decrease in fuel
expenses for utility operations and the increase in fuel expenses for nonutility
operations in 1999 were due to the fuel expenses associated with the two-thirds
of West Penn's freed up generation being marketed as part of nonutility
operations.
Purchased power and exchanges, net, represents power purchases from and
exchanges with other companies and purchases from qualified facilities under
PURPA and consists of the following items:
<TABLE>
<CAPTION>
PURCHASED POWER AND EXCHANGES, NET
(Millions of dollars) 1999 1998 1997
- ------------------------------------------------------------------------------------
Utility operations:
Purchased power:
<S> <C> <C> <C>
From PURPA generation* $ 104.1 $129.0 $134.8
Other 395.8 50.0 41.2
- ------------------------------------------------------------------------------------
Total purchased power for utility operations 499.9 179.0 176.0
Power exchanges, net (2.6) (.7) .3
Nonutility operations purchased power 390.1 210.5 43.5
Elimination (356.0)
- ------------------------------------------------------------------------------------
Purchased power and exchanges, net $ 531.4 $388.8 $219.8
- ------------------------------------------------------------------------------------
*PURPA cost (cents per kWh) .048 .054 .056
</TABLE>
Utility purchased power from PURPA generation decreased $24.9 million in 1999.
This decrease reflects a $11.1 million reduction related to West Penn's purchase
commitment at costs in excess of the market value of the AES Beaver Valley PURPA
contract. This reduction reflects the amortization of the adverse purchased
power commitment reserve recorded in 1998, which is net of the Competitive
Transition Charge revenue recovery in conjunction with deregulation proceedings
in Pennsylvania. The decrease in purchased power also includes a $12.5 million
reduction in the purchase price for that contract due to a scheduled capacity
rate decrease defined annually in the contract. The decrease in utility
purchased power from PURPA generation in 1998 was due primarily to reduced
generation at hydroelectric plants due to river flow. PURPA purchased power
costs may be reduced by $197 million during the period 1999 through 2016 related
to the AES Beaver Valley contract as a result of the 1998 extraordinary charge.
See Notes B and C to the consolidated financial statements for further
information.
The increase in other utility operations purchased power in 1999 was due
primarily to West Penn's purchase of power from its nonutility affiliate,
Allegheny Energy Supply, in order to provide energy to the two-thirds of its
customers eligible to choose an alternate supplier, but who elected not to do
so. The increase in other utility operations purchased power in 1998 resulted
primarily from increased purchases for sales.
An increase in market prices caused by volatility in the spot prices for
electricity at the wholesale level in the second and third quarters of 1998 also
contributed to the increase.
The increase in nonutility purchases in 1999 was due to increased purchases for
sale to its utility affiliate and to take advantage of transaction opportunities
in the market. The increase in nonutility purchases in 1998 was due primarily to
an increase in volume attributable to AYP Energy's increased participation in
the market.
The elimination as shown on page 34 between utility and nonutility purchased
power is necessary to remove the effect of affiliated purchased power expenses.
The AES Warrior Run PURPA cogeneration contract in Potomac Edison's Maryland
service territory will increase the cost of power purchases by about $60 million
annually. Commencement of operation was scheduled for October 1999. Pre-
commencement testing is not completed. Although AES Warrior Run has until
October 1, 2000, to complete pre-commencement testing, it is anticipated that it
will be in commercial operation in the first quarter of 2000. The Maryland PSC
has approved Potomac Edison's full recovery of the AES Warrior Run purchased
power costs as part of the September 23, 1999, settlement agreement. See Sales
and Revenues starting on page 32 for more information on the settlement
agreement.
Other operation expenses for 1999, 1998, and 1997 were as follows:
OTHER OPERATION EXPENSES
(Millions of dollars) 1999 1998 1997
- -----------------------------------------------------------------
Utility operations $346.7 $319.2 $292.3
Nonutility operations 72.4 18.2 16.7
Elimination (29.7)
- -----------------------------------------------------------------
Total other operation expenses $389.4 $337.4 $309.0
- -----------------------------------------------------------------
The increase in total other operation expenses in 1999 of $52.0 million was due
primarily to recording $19.7 million in merger-related costs previously deferred
and $16.2 million related to a pumped-storage generation project no longer
considered useful, increases in salaries and wages of $8.0 million, $5.0 million
for costs associated with settling litigation concerning a PURPA project, and
increased allowances for uncollectible accounts of $2.1 million. The increase in
utility other operation expenses in 1998 was due primarily to increased expenses
related to competition and the Pennsylvania restructuring order ($24.3 million).
See Note B to the consolidated financial statements for additional information
related to Pennsylvania restructuring. Nonutility other operation expenses
reflect increased business activity.
The elimination between utility and nonutility operation expenses is primarily
to remove the effect of affiliated transmission purchases.
Maintenance expenses for 1999, 1998, and 1997 were as follows:
MAINTENANCE EXPENSES
(Millions of dollars) 1999 1998 1997
- -----------------------------------------------------------
Utility operations $182.6 $212.3 $227.1
Nonutility operations 40.9 5.3 3.5
- -----------------------------------------------------------
Total maintenance expenses $223.5 $217.6 $230.6
- -----------------------------------------------------------
Total maintenance expenses increased $5.9 million in 1999 due primarily to
increased maintenance and renovations of general plant structures of $5.1
million. The decrease in utility maintenance and the increase in nonutility
maintenance was due to the maintenance associated with the two-thirds of West
Penn generation which is now deregulated and being classified as nonutility
maintenance. The decrease in utility maintenance in 1998 was due primarily to 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. The increase
in nonutility maintenance expense in 1998 was primarily related to a 1998
planned outage for maintenance of Unit No. 1 of the Fort Martin Power Station.
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
expenses 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 and amortization expenses for 1999, 1998, and 1997 were as follows:
DEPRECIATION AND AMORTIZATION EXPENSES
(Millions of dollars) 1999 1998 1997
- -----------------------------------------------------------------------------
Utility operations $198.0 $264.6 $259.1
Nonutility operations 59.5 5.8 6.6
- -----------------------------------------------------------------------------
Total depreciation and amortization expenses $257.5 $270.4 $265.7
- -----------------------------------------------------------------------------
Total depreciation and amortization expenses in 1999 decreased $12.9 million due
primarily to a $24.6 million reduction related to a 1998 write-down of West
Penn's share of costs in excess of the fair value of the Allegheny Generating
Company (AGC) pumped-storage project. Depreciation expense will be reduced $234
million during the period 1999 through 2016 from the historical depreciation
amounts as a result of the AGC plant impairment charge recorded as an
extraordinary charge in 1998 by West Penn. Absent this decrease, depreciation
expense would have risen due to increased investment.
Higher utility depreciation in 1998 resulted from increased investment. In 1999,
utility and nonutility depreciation expense reflects the movement of
depreciation expense associated with the two-thirds of West Penn's generation
transferred from utility operations to nonutility operations.
Taxes other than income taxes for 1999, 1998, and 1997 were as follows:
TAXES OTHER THAN INCOME TAXES
(Millions of dollars) 1999 1998 1997
- --------------------------------------------------------------------
Utility operations $157.9 $187.7 $181.4
Nonutility operations 32.4 6.9 5.6
- --------------------------------------------------------------------
Total taxes other than income taxes $190.3 $194.6 $187.0
- --------------------------------------------------------------------
Total taxes other than income taxes decreased $4.3 million in 1999 primarily due
to an adjustment which increased 1998's West Virginia Business and Occupation
Taxes by $1.4 million related to a previous period, lower capital stock taxes
relating to the 1998 asset write-down as a result of Pennsylvania restructuring,
and decreased gross receipts taxes, partially offset by higher FICA taxes. The
increase in total taxes other than income taxes in 1998 was due primarily to
increased West Virginia Business and Occupation Taxes resulting from an
adjustment for a prior period and increased property taxes. Utility and
nonutility taxes other than income taxes reflect the movement of taxes other
than income taxes associated with the two-thirds of West Penn's generation
transferred from utility operations to nonutility operations.
The 1999 decrease in federal and state income taxes of $4.0 million was
primarily due to tax benefits related to plant removal costs, offset in part by
increased taxable income.
Note G to the consolidated financial statements provides a further analysis of
income tax expenses.
The increase in allowance for borrowed funds used during construction of $1.6
million in 1999 reflects an increase in construction activity financed by short-
term debt. The allowance for borrowed funds used during construction component
of the formula receives greater weighting when short-term debt increases. The
decrease in allowance for other than borrowed funds used during construction of
$2.8 million in 1998 reflects lower-cost short-term debt financing. The decrease
also reflects adjustments of prior periods.
The decrease in other income, net, of $6.6 million in 1999, was primarily due to
a $4.3 million insurance settlement received in 1998. The decrease in other
income, net, of $9.8 million in 1998, was primarily due to 1997 increases for an
interest refund on a tax-related contract settlement ($8.3 million after taxes)
and income on the sale of land ($2.8 million after taxes) offset in part by a
$4.3 million insurance settlement received in 1998.
Interest on long-term debt and other interest for 1999, 1998, and 1997 were as
follows:
INTEREST EXPENSE
(Millions of dollars) 1999 1998 1997
- --------------------------------------------------------------------
Interest on long-term debt:
Utility operations $126.0 $151.0 $162.8
Nonutility operations 29.2 10.1 10.8
- --------------------------------------------------------------------
Total interest on long-term debt 155.2 161.1 173.6
- --------------------------------------------------------------------
Other interest:
Utility operations 27.9 19.4 14.4
Nonutility operations 3.7
- --------------------------------------------------------------------
Total other interest 31.6 19.4 14.4
- --------------------------------------------------------------------
Total interest expense $186.8 $180.5 $188.0
- --------------------------------------------------------------------
The decrease in total interest on long-term debt in 1999 of $5.9 million and in
1998 of $12.5 million resulted from reduced average long-term debt outstanding
and, in 1998, also from lower interest rates.
Other interest expense reflects changes in the levels of short-term debt
maintained by the companies throughout the year, as well as the associated
interest rates. The increase in other interest expense of $12.2 million in 1999
resulted primarily from the increase in short-term debt outstanding in
conjunction with the repurchase of the Company's common stock that began in the
first quarter of 1999.
Dividends on the preferred stock of the subsidiaries decreased due to the
redemption by Potomac Edison and West Penn of their cumulative preferred stock
on September 30, 1999, and July 15, 1999, respectively.
The redemption premiums on preferred stock of the subsidiaries represents the
premiums paid by Potomac Edison and West Penn to retire their cumulative
preferred stock.
The extraordinary charge in 1999 of $43.9 million ($27.0 million after taxes)
was required to reflect a write-off of $26.9 million ($17.0 million after taxes)
of certain disallowances in the Maryland PSC's December 1999 order and $17.0
million ($10.0 million after taxes) for the difference between the reacquisition
price and the net carrying amount of first mortgage bonds repurchased with
proceeds from the sale of transition bonds as a result of the deregulation
process in Pennsylvania. The extraordinary charge in 1998 of $466.9 million
($275.4 million after taxes) was required to reflect a write-off of certain
disallowances in the Pennsylvania PUC's May and November 1998 orders. See Notes
B, C, and F to the consolidated financial statements for additional information.
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 their construction programs, the companies have 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 companies' 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.
Capital expenditures, primarily construction, of all of the subsidiaries in 1999
were $413 million and, for 2000 and 2001, are estimated at $419 million and $431
million, respectively. In addition, in 1999 Monongahela Power acquired the
assets of West Virginia Power for approximately $95 million, and, in 2000,
Monongahela Power also plans to purchase Mountaineer Gas Company for
approximately $323 million (which includes the assumption of approximately $100
million in existing debt). The 2000 and 2001 estimated expenditures include $115
million and $136 million, respectively, for construction of environmental
control technology. Future nonutility construction expenditures will reflect
additions of generating capacity to sell into deregulated markets. It is the
Company's goal to constrain future utility construction spending to the
approximate level of depreciation currently in rates. As described under
Environmental Issues starting on page 40, the subsidiaries could potentially
face significant mandated increases in construction expenditures and operating
costs related to environmental issues. Whether the regulated utility
subsidiaries can continue to meet the majority of their construction needs with
internally generated cash is largely dependent upon the outcome of these issues.
The subsidiaries also have additional capital requirements for debt maturities
(see Note M to the consolidated financial statements).
Internal Cash Flow Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $415 million in 1999, compared with $381
million in 1998. Current rate levels and reduced levels of construction expen-
ditures permitted the utility subsidiaries to finance all of their construction
expenditures in 1999 and 1998 with internal cash flow.
Dividends paid on common stock in each of the years 1999 and 1998 were $1.72 per
share. The dividend payout ratio in 1999 of 64.6%, excluding the extraordinary
and other charges, decreased from the 73.5% ratio in 1998, excluding the
extraordinary charge and the Pennsylvania settlement costs.
Financing The Company did not issue any common stock in 1999 or 1998. The
Company began a stock repurchase program in 1999 to repurchase common stock
worth up to $500 million from time to time at price levels the Company deems
attractive. The Company repurchased 12 million shares of its common stock in
1999 at an aggregate cost of $398.4 million (an average cost of $33.20 per
share). The shares for its Dividend Reinvestment and Stock Purchase Plan,
Employee Stock Ownership and Savings Plan, Restricted Stock Plan for Outside
Directors, and Performance Share Plan were purchased on the open market.
Short-term debt is used to meet temporary cash needs and increased $382.3
million to $641.1 million in 1999. At December 31, 1999, unused lines of credit
with banks were $435 million.
The Company and its subsidiaries anticipate meeting their 2000 cash needs
through internal cash generation, cash on hand, short-term borrowings as
necessary, external financings, and by issuing debt to refinance maturing first
mortgage bonds. In 1999, West Penn issued $600 million of transition bonds with
varying average lives ranging from one to eight years with a weighted average
cost of 6.887% to "securitize" transition costs related to its restructuring
settlement described in Note B to the consolidated financial statements. During
1999, West Penn reacquired all of its outstanding $525 million of first mortgage
bonds.
West Penn called or redeemed all outstanding shares of its cumulative preferred
stock with a combined par value of $79.7 million plus redemption premiums of
$3.3 million on July 15, 1999, with proceeds from new $84-million five-year
unsecured medium-term notes issued in the second quarter at a 6.375% coupon
rate. Potomac Edison called all outstanding shares of its cumulative preferred
stock with a combined par value of $16.4 million plus redemption premiums of $.5
million on September 30, 1999, with funds on hand. The redemption of the
preferred stock allowed West Penn to revise its Articles of Incorporation,
providing greater financial flexibility in restructuring debt. Potomac Edison
also plans to revise its Articles of Incorporation.
In April 1999, Monongahela Power, Potomac Edison, and West Penn issued $7.7
million, $9.3 million, and $13.83 million, respectively, of 5.50% 30-year
pollution control revenue notes to Pleasants County, West Virginia. In December
1999, Monongahela Power issued $110 million of 7.36% unsecured medium-term
notes, due in January 2010, in part to finance the purchase of West Virginia
Power.
In October 1999, AYP Energy prepaid $30 million of its bank loan, reducing the
obligation from $160 million to $130 million. In December 1999, the $130 million
debt obligation was assigned to Allegheny Energy Supply.
The Company's and West Penn's aggregate limit of short-term debt financing was
increased in accordance with SEC authorization on May 19, 1999, and October 8,
1999, respectively. The Company's limit increased from $400 million to $750
million through December 31, 2007, to enhance its ability to participate in
evolving energy markets resulting from deregulation and, upon application and
approval, to support acquisition and diversification plans. West Penn's limit
increased from $182 million to $500 million through December 31, 2001, related
to meeting the requirements of restructuring in Pennsylvania.
The long-term debt due within one year at December 31, 1999, of $189.7 million
represents $65 million of Monongahela Power 5-5/8% first mortgage bonds due
April 1, 2000, $75 million of Potomac Edison 5-7/8% first mortgage bonds due
March 1, 2000, and $49.7 million of West Penn Funding, LLC, transition bonds
due on various dates. The transition bonds are supported by an Intangible
Transition Charge (ITC) that replaces a portion of the Competitive Transition
Charge customers pay. The proceeds from the ITC will be used to pay the
principal and interest on these transition bonds, as well as other associated
expenses.
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 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 has
been an advocate of federal legislation to create competition in the retail
electricity markets to avoid regional dislocations and ensure level playing
fields. Legislation before the U.S. Congress to restructure the nation's
electric utility industry cleared an important hurdle on October 28, 1999, when
a House Commerce Committee subcommittee gave its approval to 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 five states in which the
Company's utility operating companies 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
Potomac Edison to implement generation competition in Maryland.
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 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.
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 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 generating 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.
See Note B to the consolidated financial statements for additional information
related to Maryland restructuring.
Ohio Activities On June 22, 1999, the Ohio General Assembly passed legislation
to restructure its electric utility industry. Governor Taft added his signature
soon thereafter, and all of the state's customers will be able to choose their
electricity supplier starting January 1, 2001, beginning a five-year transition
to market rates. Total electric rates will be frozen over that period, and
residential customers are guaranteed a 5% cut in the generation portion of their
rate. The determination of stranded cost recovery will be handled by the Public
Utilities Commission of Ohio (Ohio PUC). On January 3, 2000, Monongahela Power
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
Monongahela Power'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.
Pennsylvania Activities In December 1996, Pennsylvania enacted the Customer
Choice Act to restructure its electric industry to create retail access to a
competitive electric energy supply market. Approximately 45% of the Company's
retail revenues were from its Pennsylvania subsidiary, West Penn. On May 29,
1998 (as amended on November 19, 1998), the Pennsylvania PUC 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 the
Company, only about 12,700 of its 656,000 Pennsylvania customers eligible to
shop in 1999 have chosen an alternate energy supplier. The Company 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. See Notes B and C to the consolidated financial statements for
additional information related to Pennsylvania restructuring.
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 working with the Virginia SCC Staff to develop the rules governing the
proposed retail pilot programs of other utilities in the state.
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 Monongahela Power and 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 Monongahela Power and Potomac Edison, to the
Legislature for approval.
Accounting for the Effects of Price Deregulation In July 1997, the Emerging
Issues Task Force (EITF) of the FASB released Issue No. 97-4, "Deregulation of
the Pricing of Electricity-Issues Related to the Application of FASB Statement
Nos. 71 and 101," which concluded that utilities should discontinue application
of SFAS No. 71 for the generation portion of their business when a deregulation
plan is in place and its terms are known. In accordance with guidance of EITF
Issue No. 97-4, the Company has discontinued the application of SFAS No. 71 to
its electric generation business in Pennsylvania and Maryland. The legislation
passed in Ohio and Virginia established definitive processes for transition to
deregulation and market-based pricing for electric generation. However, the
deregulation plans and their terms in Ohio and Virginia will not be known until
relevant regulatory proceedings are complete and final orders are received. The
Company is unable to predict the effect of discontinuing SFAS No. 71 in Ohio and
Virginia, but it may be required to write off unrecoverable regulatory assets,
impaired assets, and uneconomic commitments. Also, the Company is unable to
predict the outcome of the deregulation process in West Virginia until further
actions are taken by the Legislature and the W.Va. PSC.
Environmental Issues In the normal course of business, the subsidiaries are
subject to various contingencies and uncertainties relating to their 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.
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
subsidiaries' generating stations located in Maryland and Pennsylvania were
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 the subsidiaries' 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 the EPA for further
consideration. Also, in May 1999, the EPA promulgated final regional 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 the
subsidiaries' 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
call rule, 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
$358 million of capital costs during the 2000 through 2003 period to comply with
the SIP call. In addition, $12 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 EPA had identified Monongahela Power, Potomac Edison, and West Penn 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. Monongahela Power, Potomac Edison, and West Penn have also
been named as defendants along with multiple other defendants in pending
asbestos cases involving one or more plaintiffs. 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 P to the consolidated 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 Company joined with other members of the Edison
Electric Institute in reporting power station releases to the public. Packets of
information about the Company's releases were provided to the news media in the
Company's service area and posted on the Company's web site. The Company 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 the Company of their intent to commence civil
actions against the Company and/or 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 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 Allegheny Energy
Supply, Monongahela Power, 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, the Company 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 its customers with the most reliable, cost-effective service
while maintaining a clear focus on the financial interests of its shareholders.
Energy Risk Management The Company is exposed through one of its nonutility
subsidiaries, Allegheny Energy Supply, to a variety of commodity-driven risks
associated with energy trading activities. Market risk arises from the potential
for changes in the value of energy related to price and volatility of the
market. These risks are reduced by using the Company's generation assets to back
positions on physical transactions. Credit risk represents the potential loss
that the Company would incur as a result of non-performance by counterparties in
honoring their contractual commitments. These risks can influence earnings, cash
flows, and the ability to provide value to shareholders.
The Company has a Corporate Energy Risk Control Policy adopted by the Board of
Directors and monitored by an Exposure Management Committee of senior
management. An independent risk management function is responsible for insuring
compliance with the Policy. A value at risk model is used to measure the market
exposure resulting from trading activities. Value at risk is a statistical model
that attempts to predict risk of loss based on historical market price and
volatility data over a given period of time. The credit standing of
counterparties is established through the evaluation of the prospective
counterparty's financial condition, specified collateral requirements where
deemed necessary, and the use of standardized agreements which facilitate the
netting of cash flows associated with a single counterparty. Financial
conditions of existing counterparties are monitored on an ongoing basis. Market
exposure and credit risk have established aggregate and counterparty limits that
are monitored within the guidelines of the Company's Energy Risk Control Policy.
Fort Martin Power Station Unit No. 1, a stand-alone unit owned by an unregulated
subsidiary, AYP Energy, was transferred to Allegheny Energy Supply. Transfer of
this generation asset mitigates the trading risk that exists with a single
generating unit.
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 effect 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.
