SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1998
Registrant; I.R.S. Employer
Commission State of Incorporation; Identification
File Number Address; and Telephone Number Number
1-267 ALLEGHENY ENERGY, INC. 13-5531602
(A Maryland Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400
1-5164 MONONGAHELA POWER COMPANY 13-5229392
(An Ohio Corporation)
1310 Fairmont Avenue
Fairmont, West Virginia 26554
Telephone (304) 366-3000
1-3376-2 THE POTOMAC EDISON COMPANY 13-5323955
(A Maryland and Virginia
Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400
1-255-2 WEST PENN POWER COMPANY 13-5480882
(A Pennsylvania Corporation)
800 Cabin Hill Drive
Greensburg, Pennsylvania 15601
Telephone (724) 837-3000
0-14688 ALLEGHENY GENERATING COMPANY 13-3079675
(A Virginia Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400
Indicate by check mark whether the registrants (1) have filed all
reports required to be filed by Section 13 or 15(d) of the
Securities Exchange Act of 1934 during the preceding 12 months
and (2) have been subject to such filing requirements for the
past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers
pursuant to Item 405 of Regulation S-K is not contained herein,
and will not be contained, to the best of registrants' knowledge,
in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Registrant Title of each class on which registered
Allegheny Energy, Inc. Common Stock, New York Stock Exchange
$1.25 par value Chicago Stock Exchange
Pacific Stock Exchange
Amsterdam Stock Exchange
Monongahela Power
Company Cumulative Preferred
Stock,
$100 par value;
4.40% American Stock Exchange
4.50%, Series C American Stock Exchange
8% Quarterly Income
Debt Securities,
Junior Subordinated
Deferrable Interest
Debentures,
Series A New York Stock Exchange
The Potomac Edison
Company Cumulative Preferred
Stock,
$100 par value:
3.60% Philadelphia Stock Exchange
Inc.
$5.88, Series C Philadelphia Stock Exchange
Inc.
8% Quarterly Income
Debt Securities,
Junior Subordinated
Deferrable Interest
Debentures,
Series A New York Stock Exchange
West Penn Power Cumulative Preferred
Company Stock,
$100 par value:
4-1/2% New York Stock Exchange
8% Quarterly Income
Debt Securities,
Junior Subordinated
Deferrable Interest
Debentures,
Series A New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Allegheny Generating
Company Common Stock
$1.00 par value None
Aggregate market value Number of shares
of voting stock (common stock) of common stock
held by nonaffiliates of of the registrants
the registrants at outstanding at
March 4, 1999 March 4, 1998
Allegheny Energy, Inc. $3,833,787,176 122,436,317
($1.25 par value)
Monongahela Power None. (a) 5,891,000
Company ($50 par value)
The Potomac Edison None. (a) 22,385,000
Company (no par value)
West Penn Power None. (a) 24,361,586
Company (no par value)
Allegheny Generating
Company None. (b) 1,000
($1.00 par value)
(a) All such common stock is held by Allegheny
Energy, Inc., the parent company.
(b) All such common stock is held by its parents,
Monongahela Power Company, The Potomac Edison
Company, and West Penn Power Company.
CONTENTS
PART I: Page
ITEM 1. Business 1
Factors That May Affect Future Results 3
Proposed Merger with DQE, Inc. 4
Competition 4
Activities at the Federal Level 5
Activities at the State Level 5
Operating Subsidiaries' Sales 10
Regulatory Framework Affecting Power Sales 12
Other Subsidiaries' Sales 14
Electric Facilities 15
Allegheny Map 18
Research and Development 20
Capital Requirements and Financing 22
Financing Programs 24
Fuel Supply 26
Rate Matters 27
Environmental Matters 31
Air Standards 31
Water Standards 35
Hazardous and Solid Wastes 36
Toxic Release Inventory 36
Global Climate Change 37
Regulation 38
Year 2000 38
ITEM 2. Properties 39
ITEM 3. Legal Proceedings 39
ITEM 4. Submission of Matters to a Vote of Security
Holders 42
Executive Officers of the Registrants 43
PART II:
ITEM 5. Market for the Registrants' Common Equity
and Related Shareholder Matters 45
ITEM 6. Selected Financial Data 46
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 47
ITEM 8. Financial Statements and Supplementary Data 48
CONTENTS
Page
PART III:
ITEM 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 55
ITEM 10. Directors and Executive Officers of the Registrants 55
ITEM 11. Executive Compensation 56
ITEM 12. Security Ownership of Certain Beneficial Owners
and Management 62
ITEM 13. Certain Relationships and Related Transactions 63
PART IV:
ITEM 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 63
THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY ENERGY,
INC., MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY, WEST
PENN POWER COMPANY, AND ALLEGHENY GENERATING COMPANY.
INFORMATION CONTAINED HEREIN RELATING TO ANY INDIVIDUAL
REGISTRANT IS FILED BY SUCH REGISTRANT ON ITS OWN BEHALF. EACH
REGISTRANT MAKES NO REPRESENTATION AS TO INFORMATION RELATING TO
THE OTHER REGISTRANTS.
PART I
ITEM 1. BUSINESS
Allegheny Energy, Inc. (AE), incorporated in Maryland in
1925, is an electric utility holding company which owns directly
and indirectly various regulated and non-regulated subsidiaries
(collectively and generically, Allegheny). In 1998, AE derived
substantially all of its income from the electric utility
operations of its direct and indirect regulated subsidiaries
Monongahela Power Company (Monongahela), The Potomac Edison
Company (Potomac Edison), West Penn Power Company (West Penn),
and Allegheny Generating Company (AGC) (collectively, the
Regulated Subsidiaries). The properties of the Regulated
Subsidiaries are located in Maryland, Ohio, Pennsylvania,
Virginia, and West Virginia; are interconnected; and are operated
as a single integrated electric utility system (System), which is
interconnected with all neighboring utility systems. The three
electric utility operating subsidiaries are Monongahela, Potomac
Edison, and West Penn (collectively, the Operating Subsidiaries).
The Operating Subsidiaries are doing business under the trade
name Allegheny Power.
Monongahela, incorporated in Ohio in 1924, operates in
northern West Virginia and an adjacent portion of Ohio. It also
owns generating capacity in Pennsylvania. Monongahela serves
about 355,900 customers in a service area of about 11,900 square
miles with a population of about 710,000. The seven largest
communities served have populations ranging from 10,900 to
33,900. Monongahela's service area has navigable waterways and
substantial deposits of bituminous coal, glass sand, natural gas,
rock salt, and other natural resources. Its service area's
principal industries produce coal, chemicals, iron and steel,
fabricated products, wood products, and glass. There are two
municipal electric distribution systems and two rural electric
cooperative associations in its service area. Except for one of
the cooperatives, they purchase all of their power from
Monongahela.
Potomac Edison, incorporated in Maryland in 1923 and in
Virginia in 1974, operates in portions of Maryland, Virginia, and
West Virginia. It also owns generating capacity in Pennsylvania.
Potomac Edison serves about 390,200 customers in a service area
of about 7,300 square miles with a population of about 782,000.
The six largest communities served have populations ranging from
11,900 to 40,100. Potomac Edison's service area's principal
industries produce aluminum, cement, fabricated products, rubber
products, sand, stone, and gravel. There are four municipal
electric distribution systems in its service area, all of which
purchase power from Potomac Edison, and six rural electric
cooperatives, one of which purchases power from Potomac Edison.
2
West Penn, incorporated in Pennsylvania in 1916, operates in
southwestern and north and south-central Pennsylvania. It also
owns generating capacity in West Virginia. In December 1996,
Pennsylvania enacted the Electricity Generation Customer Choice
and Competition Act (Customer Choice Act) to restructure the
electric industry in Pennsylvania to create retail access to a
competitive electric energy generation market. As of January 2,
1999, two-thirds of West Penn's retail load was able to choose
their electric generation supplier. See ITEM 1. COMPETITION and
ITEM 1. RATE MATTERS for a discussion of the status of
competition in Pennsylvania. As a consequence of the Customer
Choice Act, West Penn reorganized into a Delivery Business Unit
(supplying transmission and distribution to customers in West
Penn's service territory), and a Supply Business Unit (supplying
retail generation throughout Pennsylvania, outside West Penn's
service area, and other states in the region implementing
customer choice, and wholesale generation anywhere). The next
step for the Supply Business Unit is for it to become a separate,
unregulated affiliate generation company, in 1999. Only one-
third of West Penn's retail load remains regulated, about 224,100
customers. West Penn's service area contains about 9,900 square
miles with a population of about 1,399,000. The 10 largest
communities served by West Penn have populations ranging from
11,200 to 38,900. West Penn's service area has navigable
waterways and substantial deposits of bituminous coal, limestone,
and other natural resources. Its service area's principal
industries produce steel, coal, fabricated products, and glass.
There are three municipal electric distribution systems in its
service area, all of which purchase their power requirements from
West Penn, and five rural electric cooperative associations,
located partly within the area, all of which purchase their power
from a pool that purchases a portion of its power from West Penn.
AGC, organized in 1981 under the laws of Virginia, is
jointly owned by the Operating Subsidiaries as follows:
Monongahela, 27%; Potomac Edison, 28%; and West Penn, 45%. AGC
has no employees, and its only asset is a 40% undivided interest
in the Bath County (Virginia) pumped-storage hydroelectric
station, which was placed in commercial operation in December
1985, and its connecting transmission facilities. AGC's 840-
megawatt (MW) share of capacity of the station is sold to its
three parents. The remaining 60% interest in the Bath County
Station is owned by Virginia Electric and Power Company (Virginia
Power).
AE, the Regulated Subsidiaries, and AYP Capital, Inc. and
its subsidiaries have no employees. Their officers are employed
by Allegheny Power Service Corporation (APSC), a wholly owned
subsidiary of AE, incorporated in Maryland in 1963. APSC's
employees provide all necessary services to AE, the Regulated
Subsidiaries, and AYP Capital, Inc. and its subsidiaries. Those
companies reimburse APSC for services provided by APSC's
employees. On December 31, 1998, APSC had approximately 4,817
employees.
AYP Capital, Inc. (AYP Capital), incorporated in Delaware in
1994, is a wholly owned nonutility subsidiary of AE. AYP Capital
has three wholly owned subsidiaries--AYP Energy, Inc. (AYP
Energy), Allegheny Communications Connect, Inc. (ACC), and
Allegheny Energy Solutions, Inc. (Allegheny Energy Solutions),
all Delaware corporations. AYP Capital is also part owner of APS
Cogenex, a limited liability company formed with EUA Cogenex.
APS Cogenex
3
ceased its marketing activities in 1996 and is
concluding existing projects. (See ITEM 1. COMPETITION and ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS - Significant Events in 1998, 1997 and
1996 for a further description of AYP Capital and its
subsidiaries' activities.) AYP Capital and its subsidiaries have
no employees. However, as of December 31, 1998, 25 APSC
employees were dedicated to AYP Capital and its subsidiaries'
activities on a full-time basis. Other APSC employees provide
services to AYP Capital as required. AE's total investment in
AYP Capital and its subsidiaries as of December 31, 1998, was
$19.7 million. AE is currently committed to invest up to an
additional $3.2 million in AYP Capital to fund AYP Capital's
investment in two limited partnerships.
The move to a more competitive environment presents
Allegheny with a new set of opportunities and challenges,
including determining the appropriate industry structure,
determining recovery of transition costs (those costs imposed or
incurred under a regulatory structure that would not be
recoverable in a competitive environment), retaining existing
customers and acquiring new customers, and, in general, changing
the way electric utilities do business.
FACTORS THAT MAY AFFECT FUTURE RESULTS
In addition to the historical information contained herein,
this report contains a number of "forward-looking statements" as
defined in the Private Securities Litigation Reform Act of 1995.
These include statements with respect to deregulation activities
and movements toward competition in states served by the
Operating Companies, the merger with DQE, Inc., capital
expenditures, earnings on assets, resolution and impact of
litigation, regulatory matters, liquidity and capital resources,
and accounting matters. 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, but are not limited to: the impact of general economic
changes in the U.S.; the impact of deregulation on the electric
utility business; increased competition and electric utility
restructuring in the U.S., including ongoing state and federal
activities; potential Year 2000 operation problems; developments
in the legislative, regulatory, and competitive environments in
which Allegheny operates, including regulatory proceedings
affecting rates charged by AE's subsidiaries; developments
relating to the proposed merger of AE with DQE, Inc., including
expenses that may be incurred in litigation; federal and state
regulatory developments and changes in law which may have a
substantial adverse impact on the value of the assets within the
Allegheny system; timing and adequacy of rate relief; adverse
changes in electric load and customer growth; climatic changes or
unexpected changes in weather patterns; changing fuel prices;
generating plant and distribution facility performance, including
unscheduled maintenance or repair requirements; and other
circumstances that could affect anticipated revenues and costs,
such as significant volatility in the market prices of wholesale
and retail power.
4
PROPOSED MERGER WITH DQE, INC.
On April 7, 1997, AE and DQE, Inc. (DQE) announced that they
had entered into an Agreement and Plan of Merger dated April 5,
1997 (Merger Agreement). The Merger Agreement provided for the
business combination of AE and DQE and was contingent upon the
approval of each company's shareholders and state and federal
regulators. At separate meetings held on August 7, 1997, the
shareholders of AE and DQE approved the merger. AE and DQE made
all necessary regulatory filings. Since then, AE and DQE
received approval from the Nuclear Regulatory Commission, the
Pennsylvania Public Utility Commission (Pennsylvania PUC) and the
Federal Energy Regulatory Commission (FERC). The Pennsylvania
PUC and FERC approvals are subject to certain conditions that are
acceptable to AE. The Maryland Public Service Commission
(Maryland PSC) and the Ohio Public Utilities Commission (Ohio
PUC) have also indicated their approval of the merger.
In a letter to AE dated October 5, 1998, DQE stated that it
had decided to unilaterally terminate the merger. In response,
on October 5, 1998, AE filed a lawsuit in the United States
District Court for the Western District of Pennsylvania against
DQE for specific performance of the Merger Agreement or, in the
alternative, for damages. AE also filed motions for a temporary
restraining order and preliminary injunction against DQE. On
October 28, 1998, the court denied AE's motions for a temporary
restraining order and preliminary injunction. On October 30,
1998, AE appealed the District Court's order to the United States
Court of Appeals for the Third Circuit. On March 11, 1999, the
U.S. Court of Appeals for the Third Circuit vacated the district
court's denial of Allegheny's motion for preliminary injunction,
enjoining DQE from taking actions prohibited by the merger
agreement. The Circuit Court stated that if DQE breached the
Merger Agreement, AE would be entitled to specific performance of
the Merger Agreement. The Circuit Court also stated that AE
would be irreparably harmed if DQE took actions that would
prevent AE from receiving the specific performance remedy. The
Circuit Court remanded the case to the District Court for further
proceedings consistent with its opinion.
In the District Court, discovery is ongoing, and AE cannot
predict the outcome of this litigation. However, AE believes
that DQE's basis for seeking to terminate the merger is without
merit. Accordingly, AE continues to seek the remaining
regulatory approvals from the Department of Justice and the
Securities and Exchange Commission. It is not likely either
agency will act on the requests unless AE obtains judicial relief
requiring DQE to move forward.
COMPETITION
The electric supply portion of the electric utility industry
in the United States is in the midst of becoming competitive.
The Energy Policy Act of 1992 (EPACT) began the process by
deregulating wholesale power sales within the electric industry
by permitting the FERC to compel electric utilities to allow
third parties to sell electricity to wholesale customers
5
over their transmission systems on a non-discriminatory basis.
Since 1992, wholesale electricity markets have become
increasingly competitive as companies began to engage in
nationwide power marketing. In addition, some states have
taken active steps toward allowing retail customers the
right to choose their electric supplier.
Activities at the Federal Level
Allegheny has been an advocate of federal legislation to
mandate competition in retail electricity markets nationwide to
avoid regional dislocations and ensure level playing fields. The
Operating Subsidiaries continue to participate in the Partnership
for Customer Choice 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 Allegheny unless certain outmoded and anti-
competitive laws, specifically the Public Utility Holding Company
Act of 1935 (PUHCA) and Section 210 of the Public Utility
Regulatory Policies Act of 1978 (PURPA), are repealed or
significantly revised. Allegheny continues to advocate the
repeal of PUHCA and PURPA, on the grounds that they are obsolete
and anti-competitive, and that PURPA results in utility customers
paying above-market prices for power. (See ITEM 3. LEGAL
PROCEEDINGS for information concerning PURPA-related litigation.)
Activities at the State Level
In the absence of federal legislation, state-by-state
implementation has begun. All of the states the Operating
Subsidiaries serve are at various stages of implementation or
investigation of programs that allow customers to choose their
electric supplier. Pennsylvania is furthest along with a program
in place, while Maryland and Virginia are moving to adopt plans
in 1999 to implement retail choice. Ohio and West Virginia
continue to study this issue.
Pennsylvania
The Customer Choice Act in Pennsylvania provides for
customer choice of electric supplier and deregulation of
generation in a competitive electric supply market. Pursuant to
the Customer Choice Act, all electric utilities in Pennsylvania
were required to establish and administer retail customer choice
of electric supply pilot programs to 5% of the load of each class
of their customer base. In order to assure participation in the
pilot program, a credit was established by the Pennsylvania PUC.
The credit for West Penn's customers participating in the pilot
was artificially high, and resulted in West Penn's suffering a
net loss of revenues of approximately $6.5 million for the total
pilot period that ended December 31, 1998. In order to mitigate
pilot losses, West Penn took action to become a licensed electric
supplier to the pilot customers of the other electric utilities
in Pennsylvania. However, sale prices were low and margins were
commensurately thin. As a result, West Penn was unable to
completely offset its pilot
6
losses with new revenues.<1> West Penn has authorization from the
Pennsylvania PUC to seek recovery of this lost pilot revenue, and
intends to do so in 1999.
Beginning in January 1999, two-thirds of West Penn's
customer load was permitted to choose an alternate electric
supplier. All of West Penn's customer load can choose an
electric supplier beginning in January 2000. (See ITEM 1. RATE
MATTERS for a discussion of the settlement agreement reached with
the Pennsylvania PUC, which included recovery of transition costs
and the ability to transfer generating assets to an affiliate at
net book value.) One result of the Customer Choice Act was the
bifurcation of West Penn's electricity supply and electricity
delivery functions into two separate businesses. The
transmission and distribution business remains under the
traditional regulated ratemaking. As it is deregulated, the
electric supply business pricing will be determined by the
marketplace. The delivery business in Pennsylvania has
responsibility as the electricity provider of last resort (for
those customers of West Penn who choose not to select an
alternate supplier or whose alternate supplier does not deliver)
and will generally obtain necessary electric supply for this
function from the market as the transition to competition is
implemented. The electric supply business will be free to sell
West Penn's deregulated generation in the wholesale and retail
markets, subject to codes of conduct, and subject to the
restriction that it may not, except under certain conditions,
sell at retail in West Penn's service territory through the year
2003.
Maryland
The Maryland PSC, in December 1997, issued an order to
implement retail competition in that state. The Maryland PSC's
order and its revised second order call for a deregulation
process, including a three-year phase-in beginning July 1, 2000,
with recovery of prudent transition costs after mitigation. The
orders recognized that many details were yet to be decided and
called for roundtable discussions and adjudicatory proceedings
for that purpose. On September 10, 1998, the Maryland PSC issued
a third order that clarified certain issues and questions
involved with the earlier orders. The main roundtable created by
the orders has been meeting since April 1998. This roundtable
formed six working groups to study various issues involved with
restructuring the electric industry. Each of the working groups
submitted their interim reports to the Maryland PSC on November
1, 1998. The roundtable's final report to the Maryland PSC is
due May 1, 1999, and the PSC's final order in connection with the
work of the roundtable is due August 1, 1999. Potomac Edison and
other Maryland utilities appealed the Commission's orders on the
grounds that the PSC did not have sufficient authority to implement
its plan absent authorizing legislation. In a settlement of the
appeal approved by the court, the Maryland PSC agreed that
_______________
<1> In 1997, Allegheny formed Allegheny Energy Solutions, which also
participated as a licensed electric supplier in the Pennsylvania
pilot program in all electric utility service areas within
Pennsylvania using electric energy purchased from the
competitive wholesale market. (See p. 9 in ITEM 1. COMPETITION
for a discussion of which part of the new corporate structure
will be participating in the deregulated retail energy markets
beginning in 1999.)
7
its orders in this case were not final and the utilities withdrew
their appeal. Authorizing legislation has been introduced in the
1999 session of the Maryland legislature that would permit the
Maryland PSC to implement its customer choice plan.
Two adjudicatory proceedings were established by the
Maryland PSC to aid in its implementation of retail competition,
one dealing with stranded cost quantification and recovery
mechanisms, price protection and unbundled rates and the other
with market power protective measures. Potomac Edison filed
testimony in the stranded cost proceeding on July 1, 1998. The
other parties filed testimony in mid-December and hearings are
scheduled to begin April 26, 1999. The parties are informally
exploring the possibility of settling this case subject to the
Maryland legislature passing necessary enabling legislation this
year.
Virginia
In February 1998, the Virginia General Assembly passed
Senate Joint Resolution 91 (SJR 91), which established a
subcommittee of the General Assembly to study electric utility
restructuring. The SJR 91 Subcommittee met throughout 1998 and
developed detailed restructuring legislation, which was
introduced in the 1999 session. The legislation would implement
a transition to choice for all Virginia electric customers
beginning in 2002. It allows for stranded and transition cost
recovery, and caps rates for retail customers during the
transition period. A separate Tax Task Force examined tax issues
arising from proposed restructuring and also introduced
legislation in the 1999 session. Both the restructuring and tax
bills passed the House and Senate in February and are awaiting
the Governor's signature.
The Virginia State Corporation Commission (Virginia SCC)
issued an order in 1998 that required Virginia Power and American
Electric Power Company, Inc., to develop and submit retail pilot
programs for customer choice. While Potomac Edison was not
required to develop a pilot for its customers in Virginia,
Potomac Edison is participating in the development of those
programs through pilot task forces established by the Virginia
SCC. The Virginia SCC also issued an order in 1998 requiring
Virginia utilities to submit monthly reports on the progress of
any Independent System Operator (ISO) discussions in which the
utilities are involved. Potomac Edison has reported on AE's
participation in certain activities related to the Midwest ISO.
AE's membership in the Midwest ISO is contingent upon its merger
with DQE. Virginia's ISO reporting obligation is ongoing.
By Order dated December 3, 1998, the Virginia SCC
established a proceeding to adopt interim rules to govern issues
common to both the natural gas and electricity restructuring
retail access pilot programs ordered in other cases, specifically
the issues of certification, code of conduct, and standards of
conduct governing relationships among entities participating in
pilot programs. The Task Force created in connection with this
proceeding began meeting in early 1999 to consider proposed rules
and issued its final report to the Commission in March 1999.
8
West Virginia
In December 1996, the Public Service Commission of West
Virginia (West Virginia PSC) issued an order initiating a general
investigation regarding the restructuring of the electric utility
industry. A Task Force was established to further investigate
restructuring issues. In December 1997, the Task Force approved
legislative language that would have given the West Virginia PSC
broad authority to implement retail choice. The proposed
legislation was substantially modified by the West Virginia
Legislature and passed in March 1998. The legislation directed
the West Virginia PSC to meet with all interested parties to
develop a restructuring plan, which plan would meet the dictates
and goals of the legislation. Interested parties formed a new
Task Force that met during 1998, but the Task Force was unable to
reach a consensus on a model for restructuring. The Task Force
anticipates reconvening in 1999 to further discuss restructuring.
The Commission has since issued an order setting a schedule for a
series of hearings in 1999 on major issues such as transition
costs, codes of conduct, and customer protections.
Ohio
In 1998, the Ohio PUC continued informal roundtable
discussions on issues concerning competition in the electric
utility industry. Several bills on restructuring and
deregulation were introduced in the Ohio Legislature and were the
subject of numerous hearings and negotiations at the committee
level but no consensus was achieved. In early 1999, a group of
legislators began closed door discussions to develop a
restructuring plan to be introduced in the 1999 session. The
legislators intend to reveal their plan in March 1999.
Allegheny over the past several years has taken steps to
better position itself to participate in the new competitive
markets. These include AYP Capital (AE's nonutility subsidiary)
forming two subsidiaries in 1996: AYP Energy and ACC. In
addition, in 1997 AYP Capital formed Allegheny Energy Solutions.
AYP Energy is a bulk power marketer. In October 1996, AYP Energy
purchased a 50% interest (276 MW) in Unit No. 1 of the Fort
Martin coal-fired power station in West Virginia. AYP Energy is
marketing the output of its 50% interest in Unit No. 1 of Fort
Martin, as well as engaging in other power marketing activities.
AYP Energy's losses in 1998 resulted primarily from low selling
prices in competitive markets and marketing losses. (For a
discussion of the losses, see ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -
Earnings Summary.) The operation of a merchant plant and power
marketing in the wholesale market is essentially participation in
a commodity market, which creates certain risk exposures. The
risks to which AYP Energy is exposed include underlying price
volatility, credit risk, and variation in cash flows, among
others. To manage these risks, Allegheny has risk management
policies and procedures, consistent with industry practice and
its goals. (See also discussion in Note N to the Consolidated
Financial Statements in ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA.)
9
During 1998, AYP Capital made several investments in funds
which were established in 1995. They include an investment in
EnviroTech Investment Fund I, L.P. (EnviroTech), a limited
partnership formed to invest in emerging electrotechnologies that
promote the efficient use of electricity and improve the
environment. AYP Capital committed to invest up to $5 million in
EnviroTech over 10 years, beginning in 1995. AYP Capital also
participates in the Latin American Energy and Electricity Fund I,
L.P. (FONDELEC), a limited partnership formed to invest in and
develop electric energy opportunities in Latin America. AYP
Capital committed to invest up to $5 million in FONDELEC over
eight years, beginning in 1995. Through FONDELEC, AYP Capital
has invested in electric distribution companies in Peru and
Argentina. Both EnviroTech and FONDELEC may offer AYP Capital
opportunities to identify investments in which AYP Capital may
coinvest in excess of its capital commitment in each limited
partnership.
AYP Capital is also developing other energy-related service
businesses. For example, AYP Capital offers engineering
consulting services and project management for transmission and
distribution facilities.
In 1997, ACC, an exempt telecommunications company, formed a
limited liability company with Hyperion Communications of
Pennsylvania, Inc., known as Allegheny Hyperion
Telecommunications, L.L.C. Allegheny Hyperion Telecommunications
began operations in the Altoona and State College markets in
October of 1998. Allegheny Hyperion Telecommunications offers a
full range of telecommunications services, including high-
capacity dedicated telecommunications services between business
and commercial locations; services connecting business locations
with long-distance carriers; and local telephone service.
In August 1998, ACC and AEP Communications, LLC, a
subsidiary of American Electric Power Company, Inc., announced
plans to connect and jointly market their fiber optic networks in
West Virginia, providing the state with increased access to high-
speed, broadband communications services. Through this venture,
the companies will provide high-speed communications services to
several West Virginia cities. In November 1998, ACC and AEP
Communications, LLC, widened their agreement to include the fiber
optic networks of First Energy Telcom Corp. and GPU Telcom
Services, Inc.
Allegheny Energy Solutions was formed in 1997 to market
electric energy to retail customers in deregulated retail markets
and to participate in the Pennsylvania pilot as an alternate
supplier to customers with choice within and outside the West
Penn service area, using electricity it purchased from the
competitive wholesale market. The limited liability company
formed between Allegheny Energy Solutions and DQE Energy
Partners, Inc. to participate in the Pennsylvania pilot will no
longer participate. (For a discussion of the activities
undertaken by Allegheny Energy Solutions in 1998 and related
nonutility losses, see ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -
Earnings Summary.) Because of organizational efficiencies gained
by using an alternate corporate structure, Allegheny Energy
Solutions will not compete in deregulated retail energy markets
beyond 1998. Rather, that role will be assumed by the
deregulated supply function of West Penn, acting under the name
of Allegheny Energy Supply. Allegheny Energy Supply has gained
several
10
hundred megawatts of load for 1999 through Pennsylvania customers'
choice of Allegheny Energy Supply as their new supplier of
generation services.
OPERATING SUBSIDIARIES' SALES
In 1998, consolidated regulated kilowatt-hour (kWh) sales to
regular customers (retail and wholesale power) increased 2.8%
from those of 1997 as a result of increases of .8%, 5.5% and 3.3%
in residential, commercial and industrial sales, respectively.
Consolidated regulated revenues from residential sales decreased
1.4%, while commercial and industrial sales increased 2.2% and
.8%, respectively. (See ITEM 1. RATE MATTERS and ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.)
Allegheny's all-time combined generation customer peak load
of 7,500 MW occurred on February 5, 1996. The control area peak
load in 1998 was 7,314 MW on July 22, 1998.
Consolidated regulated electric operating revenues for 1998
were derived as follows: Pennsylvania, 44.4%; West Virginia,
27.9%; Maryland, 19.2%; Virginia, 6.1%; Ohio, 2.4% (residential,
37.8%; commercial, 21.5%; industrial, 32.3%; bulk power
transactions, 4.9%; and other, 3.5%). The following percentages
of such revenues were derived from these industries: iron and
steel, 6.5%; aluminum and other nonferrous metals, 3.4%;
chemicals, 3.4%; coal mines, 3.3%; cement, 2.6%; fabricated
products, 1.8%; and all other industries, 11.4%.
During 1998, Monongahela's kWh sales to retail customers
increased 3.9%. Residential sales decreased .3% but commercial
and industrial sales increased 5.8% and 5.5%, respectively.
Revenues from residential, commercial, and industrial customers
increased .5%, 6.4%, and 6.0%, respectively, primarily due to an
increase in the fuel and energy cost component as well as an
increase in the number of customers and usage. Revenues from
bulk power transactions and sales to affiliates decreased 3.8%.
Monongahela's revenues represented 24.7% of Allegheny's total
regulated sales to regular customers. Monongahela's all-time
peak load of 1,844 MW occurred on July 21, 1998.
Monongahela's electric operating revenues were derived as
follows: West Virginia, 91.2%, and Ohio, 8.8% (residential,
31.1%; commercial, 19.6%; industrial, 32.3%; bulk power
transactions, 3.1%; and other, 13.9%).
During 1998, Potomac Edison's kWh sales to retail customers
increased 5.0%. Residential, commercial and industrial sales
increased 2.6%, 7.2% and 5.9%, respectively. Revenues from
residential, commercial and industrial customers increased 3.1%,
5.9% and 4.3%, respectively, primarily due to an increase in the
number of customers and usage. Revenues from bulk power
transactions and sales to affiliates increased 7.6%. Potomac
Edison's revenues represented 31.9% of Allegheny's total
regulated sales to regular customers. Potomac Edison's all-time
peak load of 2,614 MW occurred on January 17, 1997. The peak
load in 1998 was 2,413 MW on July 22, 1998.
11
Potomac Edison's electric operating revenues were derived as
follows: Maryland, 61.9%; West Virginia 19.0%, and Virginia,
19.1%; (residential, 41.9%; commercial, 21.3%; industrial, 28.0%;
bulk power transactions, 3.6%; and other, 5.2%). Revenues from
one industrial customer, the Eastalco aluminum reduction plant
near Frederick, Maryland, amounted to $64.8 million (8.8% of
total electric operating revenues). Minimum annual charges to
Eastalco under an electric service agreement which continues
through March 31, 2000, with automatic extensions thereafter
unless terminated on notice by either party, were $15.1 million
in 1998. This agreement may be canceled before the year 2000 upon
90 days' notice in the event of a governmental decision resulting
in a material modification of the agreement.
During 1998, West Penn's kWh sales to retail customers,
including sales to Pennsylvania retail pilot participants,
decreased 2.8% as a result of decreases of 4.6%, 1.6% and 2.2% in
residential, commercial, and industrial sales, respectively.
Revenues from residential, commercial and industrial customers
decreased 5.7%, 2.4%, and 4.1%, respectively, primarily due to a
$25.1 million rate refund resulting from the Pennsylvania
restructuring settlement agreement, a reduction in previously
bundled customers (full service customers) due to the
Pennsylvania retail pilot program, and a reduction in usage.
Revenues from bulk power transactions and sales to affiliates,
including bulk power sales under the Pennsylvania retail pilot
program, increased 43.3%. West Penn's regulated revenues
represented 43.4% of Allegheny's total regulated sales to regular
customers. West Penn's all-time peak load of 3,251 MW occurred on
July 15, 1997. The regulated peak load in 1998 was 3,067 MW on
June 25, 1998. The territorial West Penn share of the Allegheny
control area peak load in 1998 was 3,192 MW on June 25, 1998.
West Penn's electric operating revenues were derived as
follows: Pennsylvania, 100% (residential, 34.4%; commercial,
20.2%; industrial, 31.4%; bulk power transactions, 6.4%; and
other, 7.6%).
In 1998, the Operating Subsidiaries provided approximately
3.0 billion kWh of energy to nonaffiliated companies and
marketers from generation facilities operated by the Operating
Subsidiaries. Revenues from those sales of generation, including
Pennsylvania retail pilot sales, from the Operating Subsidiaries
were approximately $69.8 million.
The Operating Subsidiaries transmitted approximately 7.4
billion kWh to others located outside their service territories
under various forms of transmission service agreements. Revenues
from those sales were about $45.2 million.
Sales of generation and transmission services to others vary
with the needs of those customers for capacity and/or economic
replacement power; the availability of generating facilities and
excess power, fuel, and regional transmission facilities; and the
availability and price of competitive sources of power. Revenues
from sales of transmission services to others by the Operating
Subsidiaries increased in 1998 relative to 1997 despite decreased
transmission services activity. The increase in revenues was due
in part to transmission services' reservation charges paid to the
Operating Subsidiaries by others for the right to transmit
energy. Transmission activity was affected as a result of some
of the reservations to transmit
12
energy not being used. Sales of power generated
by the Operating Subsidiaries increased in 1998
relative to 1997 primarily from increased sales to brokers and
power marketers 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, and increased sales due to
participation in the Pennsylvania retail pilot program.
Substantially all of the benefits of power and transmission
service sales to nonaffiliates by the Operating Subsidiaries,
except West Penn, were passed on to retail customers and, as a
result, had little effect on Monongahela Power's and Potomac
Edison's net income. Effective May 1, 1997, West Penn no longer
passes these benefits on to retail customers.
Pursuant to a peak diversity exchange arrangement with
Virginia Power, the Operating Subsidiaries annually supply
Virginia Power with 200 MW during each June, July, and August
and, in return, Virginia Power supplies the Operating
Subsidiaries with 200 MW usually during each December, January,
and February, at least through February 2000. Beyond February
2000, no diversity exchange is planned.
The Operating Subsidiaries have an exchange arrangement with
Duquesne Light Company (Duquesne) which will continue through
February 2000. In this exchange arrangement, the Operating
Subsidiaries have, in the past, supplied Duquesne with up to 200
MW for a specified number of weeks, generally during each March,
April, May, September, October, and November. In return,
Duquesne had supplied the Operating Subsidiaries with up to 100
MW, generally during each December, January, and February.
Currently, there are no exchanges being made as Duquesne
endeavors to sell off its generating assets. The total number of
MWh to be delivered by each utility to the other over the active
term of the arrangement will have been the same.
Regulatory Framework Affecting Power Sales
EPACT initiated the restructuring of the electric utility
industry by permitting competition in the wholesale generation
market. In order to facilitate the efficient use of generation
facilities, on April 24, 1996, the FERC issued Orders 888 and
889. On March 4, 1997, the FERC issued Orders 888A and 889A
reaffirming and clarifying the legal and policy issues as
originally presented in the previous orders. In response to
requests for rehearing, the FERC issued Orders 888B and 889B on
November 25, 1997. The Commission again supported its original
intentions and presented explanations and minor revisions to
specific sections of the orders.
The FERC orders require all transmission providers to offer
service to entities selling generation services in a manner that
is comparable to their own use of the transmission system. The
orders required each transmission provider to file standardized
open access transmission service tariffs; therefore, the
Operating Subsidiaries have on file a pro forma open access
tariff under which they sell transmission services to all
eligible customers. The Operating Subsidiaries (and AYP Energy,
when appropriate) also arrange for transmission services for
their own sales pursuant to the rates, terms, and conditions of
the open access tariff. The tariff was accepted for filing by
the FERC on November 25, 1998. The Commission's order specified
a December 6, 1995, effective date and required refunds to be
paid on the time
13
value of money based upon the difference between the originally
filed rates and those authorized by the Commission.
To meet the objective of providing comparable or
nondiscriminatory transmission services, the FERC orders further
require that utilities functionally unbundle transmission
operations and reliability functions from wholesale merchant
functions within the Operating Subsidiaries. Accordingly,
discrete businesses have been formed, including a Delivery
Business Unit (inclusive of transmission) and a Supply Business
Unit. The Delivery Business Unit includes several sub-units,
including the System Planning and Operations group, which
provides transmission system operations and reliability
functions. Each unit has its own management, objectives, and
facilities. The Operating Subsidiaries conduct their business in
a manner that is consistent with FERC's Standards of Conduct.
The orders require that all transmission requests for
service be made over the Open Access Same Time Information System
(OASIS). The OASIS, an internet-based nationwide electronic
network, became operational on January 3, 1997. The Operating
Subsidiaries, in conjunction with a consortium of transmission
providers, continue to work to implement a revised version of the
OASIS Standards and Communications Protocols document issued by
FERC. OASIS Phase 1A will become operational on March 1, 1999.
The FERC established its jurisdiction over unbundled retail
as well as wholesale transmission services in Order 888.
Although states retain the authority to determine if retail
wheeling should be adopted, retail transmission service under the
jurisdiction of the FERC is available once these historically
franchised customers have access to alternate generation sources.
Pennsylvania enacted legislation authorizing retail choice for
selected customers as of November 1, 1997 (Customer Choice Act).
The Operating Subsidiaries added Schedule 10--Retail Transmission
Service to their open access tariff authorizing the sale of open
access transmission services to unbundled retail customers.
Initially, the Operating Subsidiaries will provide service to
Pennsylvania's unbundled retail customers and eventually to
retail customers with choice in Maryland, Virginia, West
Virginia, and Ohio.
In compliance with Pennsylvania's restructuring requirements
and in conjunction with the merger plans, AE and DQE filed
jointly with the FERC an Allegheny Energy open access tariff in
August 1997. No sales have been made under that tariff and none
will be made until the merger is consummated.
The Operating Subsidiaries also have on file with the FERC a
Standard Generation Service Rate Schedule for the sale of
wholesale power at cost-based rates. In October 1997, the
Operating Subsidiaries submitted a new wholesale tariff to the
FERC, asking for authority to sell power at market-based rates.
The Operating Subsidiaries began selling power at market-based
rates upon the filing's acceptance by the FERC in August 1998.
The Operating Subsidiaries continue their involvement as
General Agreement on Parallel Paths (GAPP) experiment
participants. The purpose of the experiment is to collect
operating data on the effect of parallel power flow on the
interconnected transmission system and to develop an equitable
14
compensation system reapportioning current contract path-based
revenues upon a reflection of the actual flow of power on the
interconnected electrical system. During the two-year term of
the experiment, many of the GAPP principles were successfully
incorporated into certain industry-wide system operating
practices established by the North American Electric Reliability
Council (NERC). When the experiment concludes on March 31, 1999,
the participants will publicly present information on the revenue
reallocation method they developed.
AE and DQE, Inc., conditionally executed a membership
agreement with the Midwest ISO; the commitment to join the
Midwest ISO was expressly contingent upon consummation of a
proposed merger between AE and DQE, Inc. The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998. AE's membership status remains
conditional until the merger is consummated or it is determined
that the Merger Agreement is terminated.
Under PURPA, certain municipalities, businesses and private
developers have installed, are installing, or are proposing to
install, generating facilities at various locations in or near
the Operating Subsidiaries' service areas with the intent of
selling some or all of the electric capacity and energy to the
Operating Subsidiaries at rates consistent with PURPA and ordered
by appropriate state commissions. As a result of PURPA, the
Operating Subsidiaries are committed to purchasing 299 MW of on-
line PURPA capacity. Payments for PURPA capacity and energy in
1998 totaled approximately $129.0 million, at an average cost to
the Operating Subsidiaries of 5.4 cents/kWh, as compared to the
Operating Subsidiaries' own generating cost of about 3 cents/kWh.
The Operating Subsidiaries project an additional 180 MW of PURPA
capacity (Warrior Run) to come on-line in 1999. The Warrior Run
project will result in rate increases for Potomac Edison's
Maryland customers pursuant to a 1998 rate case settlement in
that jurisdiction. (See ITEM 3. LEGAL PROCEEDINGS for a
description of litigation and regulatory proceedings in
Pennsylvania and West Virginia concerning other proposed PURPA
projects.)
OTHER SUBSIDIARIES' SALES
In 1998, AYP Energy provided 7.3 billion kWh of energy to
nonaffiliated customers, including generation from Fort Martin
Unit No. 1, amounting to 1.8 billion kWh. Revenues from those
sales were approximately $215.3 million. Total unregulated
operating revenues in 1998, including sales by Allegheny Energy
Solutions under the Pennsylvania retail pilot program, amounted
to $247.0 million. Allegheny Energy Solutions participated in
the pilot program as an alternate supplier to customers with
choice within and outside the West Penn service area. (For a
discussion of increases in nonutility losses in 1998, See ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS - Earnings Summary.)
15
ELECTRIC FACILITIES
The following table shows Allegheny's December 31, 1998,
operational generating capacity based on the maximum monthly
normal seasonal operating capacity of each unit. The Regulated
Subsidiaries' owned capacity totaled 8,121 MW, of which 7,091 MW
(87%) are coal-fired, 840 MW (10%) are pumped-storage, 132 MW
(2%) are oil-fired, and 58 MW (1%) are hydroelectric. AYP
Energy, an exempt wholesale generator in 1998, also owns 276 MW
of coal-fired generation. The term "pumped-storage" refers to
the Bath County station which stores energy for use principally
during peak load hours by pumping water from a lower to an upper
reservoir, using the most economic available electricity,
generally during off-peak hours. During the generating cycle,
power is produced by water falling from the upper to the lower
reservoir through turbine generators.
The weighted average age of the Regulated Subsidiaries'
owned steam stations shown on the following page is about 28.6
years. In 1998, their book value was $1.8 billion, average heat
rate was 9,939 Btu's/kWh, and their availability factor was
85.8%. The age of AYP Energy's owned generation is 32.0 years.
In 1998, the book value of AYP Energy's owned generation was
$163.5 million, average heat rate was 9,622 Btu's/kWh, and the
availability factor was 88.9%.
16
Allegheny Stations
Maximum Generating Capacity
(Megawatts) (a)
AYP Dates When
Station Monon- Potomac West Energy Service
Station Units Total gahela Edison Penn (b) Commenced(c)
Coal-fired (steam):
Albright 3 292 216 76 1952-4
Armstrong 2 352 352 1958-9
Fort Martin 2 1,107 249 304 278 276 1967-8
Harrison 3 1,920 480 629 811 1972-4
Hatfield's
Ferry 3 1,660 456 332 872 1969-71
Mitchell 1 284 284 1963
Pleasants 2 1,252 313 376 563 1979-80
Rivesville 2 142 142 1943-51
R. Paul Smith 2 115 115 1947-58
Willow Island 2 243 243 1949-60
Oil-fired (steam): (a)
Mitchell 2 132 132 1948
Pumped-storage and Hydro:
Bath County 6 840 227(d) 235(d) 378(d) 1985
Lake Lynn(e) 4 52 52 1926
Potomac Edison (e) 21 6 6 Various
Total Allegheny-owned
Capacity 54 8,397 2,326 2,073 3,722 276
Other Generation
Maximum Generating Capacity
(Megawatts) (f)
AYP Contract
Project Monon- Potomac West Energy Commencement
Project Total gahela Edison Penn (b) Date
Coal-fired: (steam)
AES Beaver Valley 125 125 1987
Grant Town 80 80 1993
West Virginia
University 50 50 1992
Hydro:
Allegheny Lock and Dam 5 6 6 1988
Allegheny Lock and Dam 6 7 7 1989
Hannibal Lock and Dam 31 31 1988
Total Other Capacity 299 161 0(g) 138 0
Total Allegheny-owned and
PURPA Committed 8,696 2,487 2,073 3,860 276
Generating Capacity (a)
17
(a) Winter rating. Excludes West Penn oil-fired capacity of
207 MW at Springdale Power Station which was placed on cold
reserve status as of June 1, 1983. On December 31, 1994, 82 MW,
and on July 1, 1998, 50 MW of the total MW at Mitchell Power
Station were reactivated.
(b) AYP Energy owns 50% of Unit No. 1 at Fort Martin.
(c) Where more than one year is listed as a commencement
date for a particular source, the dates refer to the years in
which operations commenced for the different units at that
source.
(d) Capacity entitlement through ownership of AGC, 27%,
28%, and 45% by Monongahela, Potomac Edison, and West Penn,
respectively.
(e) West Penn has a 30-year license for Lake Lynn,
effective December 1994. Potomac Edison's license for
hydroelectric facilities Dam No. 4 and Dam No. 5 will expire in
2003. Potomac Edison has received 30-year licenses, effective
January 1994, for the Shenandoah, Warren, Luray, and Newport
projects. The FERC accepted Potomac Edison's surrender of the
license for the Harper's Ferry Dam No. 3 and issued an order
effective October 1994.
(f) Other generating capacity available through state
utility commission-approved arrangements pursuant to PURPA.
(g) The 180-MW Warrior Run project is under construction
and is planned to begin providing capacity and energy to Potomac
Edison in 1999.
18
ALLEGHENY MAP
The Allegheny Power Map (Map), which has been omitted,
provides a broad illustration of the names and approximate
locations of Allegheny Power's major generation and transmission
facilities, both existing and under construction, in a five-state
region which includes portions of Maryland, Ohio, Pennsylvania,
Virginia, and West Virginia. Additionally, Extra High Voltage
substations are displayed. By use of shading, the map also
provides a general representation of the service areas of
Monongahela (portions of West Virginia and Ohio), Potomac Edison
(portions of Maryland, Virginia, and West Virginia), and West
Penn (portions of Pennsylvania).
Power Stations shown on the map which appear within the
Monongahela service area are Willow Island, Pleasants, Harrison,
Rivesville, Albright, and Fort Martin. The single power station
appearing within the Potomac Edison service area is R. Paul
Smith. The Bath County Power Station appears on the map just
south of the westernmost portion of Potomac Edison's service area
formed by the borders of Virginia and West Virginia. Power
stations appearing within the West Penn service area are
Armstrong, Mitchell, Hatfield's Ferry, Springdale, and Lake Lynn.
The map also depicts transmission facilities which are (i)
owned solely by the Operating Subsidiaries; (ii) owned by the
Operating Subsidiaries in conjunction with other utilities; or
(iii) owned solely by other utilities. The transmission
facilities portrayed range in capacity from 138 kV to 765 kV.
Additionally, interconnections with other utilities are
displayed.
19
The following table sets forth the existing miles of tower and pole
transmission and distribution lines and the number of
substations of the Regulated Subsidiaries as of December 31, 1998:
Miles of Above-Ground Transmission and
Distribution Lines (a) and Number of Substations
Number of
Portion of Total Transmission and
Total Miles Representing Distribution
Miles 500-Kilovolt (kV) Lines Substations(b)
Monongahela 21,035 283 331
Potomac Edison 18,135 202 276
West Penn 24,102 273 709
AGC(c) 85 85 1
Total 63,272 843 1,317
(a) The Operating Subsidiaries also have a total of 6,412 miles
of underground distribution lines.
(b) The substations have an aggregate transformer capacity of
56,317,204 kilovoltamperes.
(c) Total Bath County transmission lines, of which AGC owns an
undivided 40% interest and Virginia Power owns the remainder.
The Operating Subsidiaries have 12 extra-high-voltage (EHV),
345-kV and above, and 31 lower-voltage interconnections with
neighboring utility systems. The interregional EHV transmission
system, including System facilities, continued to operate near
reliability limits during periods of heavy power flows that are
predominantly in a west-to-east orientation. In early 1997, NERC
implemented the development of a national security process. The
Operating Subsidiaries serve as one of the 22 national Security
Coordinators. This process includes a Transmission Loading
Relief (TLR) procedure that identifies actual flow path
consequences of power transactions, reduces loading on the
transmission system when necessary and effectively addresses
parallel path flows. The TLR procedure has been effective. Its
use, and conditions in the Midwest that reversed the predominant
west-to-east power flow pattern across the AE system during the
summer of 1998, resulted in fewer constraints on System
transmission facilities that would require curtailments of
transmission service.
Wholesale generators and other wholesale customers may
now seek from owners of bulk power transmission facilities a
commitment to supply transmission services. (See discussion
under ITEM 1. SALES.) Such demand on the Operating
Subsidiaries' transmission facilities may add to heavy power
flows on the Operating Subsidiaries' facilities and may,
eventually, require construction of additional transmission
facilities.
20
The Operating Subsidiaries have, since the early 1980s,
provided managed contractual access to their transmission
facilities under various tariffs. As described earlier, for
new agreements starting in 1996, managed access is also
governed by the provisions of the Operating Subsidiaries' Open
Access Transmission Tariff mandated by and filed with the
FERC.
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $7.9 million, $7.4
million, and $7.7 million, in 1998, 1997, and 1996,
respectively, for research programs. Of these amounts, $5.5
million, $5.7 million, and $5.5 million were for Electric
Power Research Institute (EPRI) dues in 1998, 1997, and 1996,
respectively. EPRI is an industry-sponsored research and
development institution. The Operating Subsidiaries plan to
spend approximately $7.8 million for research in 1999, with
EPRI dues representing $5.6 million of that total.
In addition to EPRI support, in-house research conducted
by Allegheny concentrated on environmental protection,
generating unit performance, future generation technologies,
transmission system performance, delivery systems, customer-
related research, clean power technology focused on power
quality, and distributed resources technology for customers,
delivery equipment, and marketing. All Allegheny-funded
research is related to adapting both competitive and leading
edge technology to Allegheny's operations.
Research is also being directed to help address major
issues facing our industry, including electric and magnetic
field (EMF) assessment of employee exposure within the work
environment, waste disposal and discharges, greenhouse gases
(GHG), renewable resources, fuel cells, new combustion
turbines, cogeneration technologies, and transmission loading
mitigation using Flexible AC Transmission System (FACTS)
devices. An investigation of the value of biodiversity of
lands owned by Allegheny is being done. The financial effect
of these issues on Allegheny, if any, cannot be determined at
this time. During 1998, the Operating Subsidiaries supported
the federal government's National EMF Research and Public
Information Dissemination Program, a project on the
interaction of biomechanisms and electric and magnetic fields
(EMF); and an Edison Electric Institute (EEI) program to study
employee and public health effects, if any, of EMF. The World
Health Organization, the Director of the National Institute of
Environmental Health Services, and an interagency group
consisting of representation from nine federal agencies plan
to issue reports over the next two to three years on EMF,
which may affect future R&D funding. In addition, there is
continuing evaluation of technical proposals from outside
sources and monitoring of developments in industry-related
literature, law and litigation, general business and
environmental standards (ISO 9000 and ISO 14000), and
intellectual property rights.
Because of the nitrogen oxides (NOx) control requirements
of the Clean Air Act Amendments of 1990 (CAAA), Allegheny is
participating in a
21
collaborative effort coordinated by EPRI to
gain a greater understanding of the formation of ground level
ozone and how measures to control NOx and volatile organic
compounds affect ozone formation. The North American Research
Strategy for Tropospheric Ozone-Northeast is focused on this
effort. Other research is directed at NOx control
technologies for power station compliance, including
optimizing existing low NOx burners to improve performance.
The Operating Subsidiaries continue to monitor and
demonstrate technical solutions to greenhouse gas (GHG)
reduction, sequestration, capture, and control. As part of
their response to EPACT and President Clinton's subsequent
Climate Action Plan, the Operating Subsidiaries, as part of an
EEI program, have agreed to participate in research
initiatives which are designed to reduce, sequester, or
control GHG. This program is consistent with filings made
with the Department of Energy (DOE) in voluntary compliance
with Section 1605(b) of EPACT.
Electric vehicle (EV) research through 1998 included
participation in EV America and the Electric Transportation
Coalition, as well as the development of appropriate wiring
and building code standards to accommodate electric vehicles.
As a result, Allegheny is positioned to support commercial
manufacturers when they move forward with EV development.
Allegheny provided a grant to the University of Pittsburgh to
build an electric car from the frame up.
In 1998, research was also directed into communication
systems to develop and demonstrate a high-speed digital power
line communication system using existing utility wires to
serve information and automation needs of Allegheny's
customers and to support system requirements in retail
wheeling and marketing.
Allegheny continues to pursue beneficial uses of coal
combustion by-products. In cooperation with the West Virginia
Division of Environmental Protection, a project is under way
to investigate the feasibility and cost-effectiveness of
injecting fly ash from Allegheny-owned power stations into
abandoned underground mine sites in West Virginia to reduce
acid mine drainage and mine surface subsidence. The project
cost is being shared with EPRI as part of a Tailored
Collaboration Agreement. Also being investigated is the use
of fly ash as a construction material for a residential home
demonstration and the use of flue-gas desulfurization by-
products for road building.
As part of customer research, a model home program is
under way and adjustable speed drives for customer motor loads
are being used at a steel company and at an extrusion process
plant. West Penn participated in 1998 in the Pennsylvania
Electric Energy Research Council (PEERC). PEERC was formed in
1987 as a partnership of Pennsylvania-based electric utilities
and the State of Pennsylvania to promote technological
advancements related to the electric utility industry.
In 1998, the Operating Subsidiaries made research grants
to regional colleges and universities to encourage the
development of technical resources related to current and
future utility problems and to conduct
22
research. A grant was provided to West Virginia University to
evaluate the effect of Distributed Resources on feeders and for
customer uses.
CAPITAL REQUIREMENTS AND FINANCING
Construction expenditures by the Regulated Subsidiaries
in 1998 amounted to $229.4 million. Construction expenditures
for 1999 and 2000 are expected to aggregate $280.1 million and
$283.6 million, respectively. Construction expenditures by
AYP Capital, the wholly owned nonutility (unregulated)
subsidiary of AE, in 1998 amounted to $1.8 million and for
1999 and 2000 are expected to aggregate $34.9 million and
$10.6 million, respectively. The 1999 and 2000 estimated
regulated expenditures include $10.6 million and $55.7
million, respectively, to cover the costs of compliance with
the CAAA. Expenditures to cover the costs of compliance with
the CAAA and other environmental requirements have been and
are likely to continue to be significant. Additionally, new
environmental initiatives (See ITEM 1. ENVIRONMENTAL MATTERS)
may substantially increase Allegheny's construction
requirements as early as 2000.
On October 27, 1998, the EPA finalized rules for reducing
ground level ozone. The EPA is requiring 22 states and the
District of Columbia to submit state implementation plans
(SIPs) that address the regional transport of ozone. All of
the states served by Allegheny are required to submit the SIP
call. The intent of the SIP call is to reduce NOx emissions
from power plants, on average, to 0.15 pounds of NOx per
million BTU (MBTU). Although Allegheny has joined with other
parties to contest the EPA's actions in court, it is also
formulating plans to comply by making modifications to
existing generating units. The cost to comply will be about
$360 million of capital investments, to be spent during the
1999-2003 period. Of this amount, about $50 million was
already scheduled to be spent, so an additional $310 million
of capital will be required. Under the EPA's plan, Allegheny
would be required to reduce emissions to the 0.15 pounds per
MBTU requirement by May 2003.
23
Construction Expenditures
1998 1999 2000
Millions of Dollars
(Actual) (Estimated)
Monongahela
Generation $ 25.5 $ 26.1 $ 26.9
Transmission 7.6 11.2 4.6
Distribution 39.7 38.4 47.7
Total* $ 72.8 $ 75.7 $ 79.2
Potomac Edison
Generation $ 15.4 $ 31.2 $ 29.9
Transmission 0.9 2.1 13.8
Distribution 44.2 52.3 54.4
Total* $ 60.5 $ 85.6 $ 98.1
West Penn
Generation $ 34.2 $ 58.8 $ 54.8
Transmission 10.2 2.3 4.2
Distribution 49.2 54.2 46.3
Other 2.4 3.4 .7
Total* $ 96.0 $ 118.7 $ 106.0
AGC & APSC $ .1 $ 0.1 $ 0.3
Total Construction Expenditures, $ 229.4 $ 280.1 $ 283.6
Regulated
Nonutility $ 1.8 $ 34.9 $ 10.6
Total Construction Expenditures $ 231.2** $ 315.0** $ 294.2**
*Includes allowance for funds used during construction
(AFUDC), or capitalized interest in the case of the
generation business of West Penn, for 1998, 1999, and 2000
of: Monongahela $1.0, $1.7, and $1.3; Potomac Edison $1.6,
$1.8, and $1.5; and West Penn $2.4, $3.5, and $2.7.
**Includes amounts for projects connected with Allegheny's
corporate restructuring of $17.9, $5.9, and $0.0 for 1998,
1999, and 2000, respectively.
24
These capital expenditures include major projects at
existing generating stations, upgrading distribution lines and
substations, and the strengthening of the transmission and
subtransmission systems.
On a collective basis for the Regulated Subsidiaries,
expenditures for 1998, 1999, and 2000 include $12.8 million,
$62.8 million, and $84.9 million, respectively, for construction
of currently mandated environmental control technology. Outages
for construction, CAAA compliance, and other environmental work
is, and will continue to be, coordinated with other planned
outages, where possible.
Allegheny continues to study ways to reduce and meet
existing regulated customer generation service demand and future
increases in that demand, including demand-side management
programs; new and efficient electric technologies; construction
of various types and sizes of generating units; increasing the
efficiency and availability of Allegheny generating facilities;
reducing internal electrical use and transmission and
distribution losses; and acquisition of energy and capacity from
third-party suppliers. The advent of retail choice of generation
service supplier is expected to have a significant effect on
regulated generation service load growth and the Operating
Subsidiaries' obligation to meet such load growth.
Current forecasts, which reflect demand-side management
efforts and other considerations and assume normal weather
conditions, project average annual winter and summer peak load
growth rates for the regulated load of Monongahela and Potomac
Edison and the provider of last resort load of West Penn of 0.7%
and 0.6%, respectively, in the period 1999-2009. Competition for
existing loads can have a substantial effect on those
projections. It is anticipated that existing resources,
purchased power arrangements, reactivation of existing capacity,
and/or the acquisition of capacity will be sufficient for
Allegheny's future needs.
In connection with its construction and demand-side
management programs, Allegheny must make estimates of the
availability and cost of capital as well as the future demands of
its customers that are necessarily subject to regional, national,
and international developments, changing business conditions, and
other factors. The construction of facilities and their cost are
affected by laws and regulations; lead times in manufacturing;
availability of labor, materials and supplies; inflation;
interest rates; and licensing, rate, environmental, and other
proceedings before regulatory authorities. Decisions regarding
construction of facilities must now also take into account retail
competition. As a result, future plans of Allegheny are subject
to continuing review and substantial change.
Financing Programs
The Regulated Subsidiaries have financed their construction
programs through internally generated funds, first mortgage
bonds, debentures, medium-term notes, subordinated debt and
preferred stock issues, pollution control and solid waste
disposal notes, installment loans, long-term lease arrangements,
equity investments by AE (or, in the case of AGC, by the
Operating Subsidiaries), and, where necessary, interim short-term
debt. The future ability of the Regulated Subsidiaries to
finance their construction
25
programs by these means depends on
many factors, including effects of competition and
creditworthiness, and adequate revenues to produce satisfactory
internally generated funds and return on the common equity
portion of the Regulated Subsidiaries' capital structures and to
support their issuance of senior and other securities. AE
obtains funds for equity investments in its subsidiaries through
retained earnings and the issuance and sale of its common stock
publicly.
Beginning in the third quarter of 1997, AE began buying
shares in the open market for its Dividend Reinvestment and Stock
Purchase Plan, its Employee Stock Ownership and Savings Plan, and
in 1998 AE began buying shares in the open market for the
Performance Share Plan.
In February 1998, Monongahela, Potomac Edison and West Penn
issued $17.5 million, $30 million, and $45 million, respectively,
of 9-year and 14-year Pollution Control Revenue Notes to
Pleasants County, West Virginia. Pleasants County, in turn,
issued $92.5 million of 9-year and 14-year Pollution Control
Revenue Bonds with interest rates ranging from 4.70% to 5.05% to
refund $92.5 million of three series due in 2007 and 2012, with
rates ranging from 6.125% to 6.375%.
In March 1998, Monongahela, Potomac Edison and West Penn
issued $6.06 million, $3.2 million and $14.435 million,
respectively, in 4-year, 9-year, and 14-year Pollution Control
Revenue Notes to Greene County, Pennsylvania. Greene County, in
turn, issued $23.695 million of 4-year, 9-year, and 14-year
Pollution Control Revenue Bonds with interest rates ranging from
4.35% to 5.10% to refund $23.695 million of three series due in
2002, 2007, and 2012, with rates ranging from 6.1% to 6.4%.
Also in March 1998, Monongahela issued $19.1 million in 4.5%
5-year Pollution Control Revenue Notes to Marion, Pleasants, and
Preston Counties, West Virginia. These counties, in turn, issued
$19.1 million of 5-year Pollution Control Revenue Bonds to pay at
maturity $19.1 million of three series, with rates of 6.875%.
In September 1998, Monongahela and West Penn issued an
aggregate of $77.025 million of unsecured medium-term notes at
interest rates ranging from 5.56% to 5.71%. Monongahela issued
five-year unsecured medium-term notes totaling $43.475 million at
interest rates ranging from 5.56% to 5.71%. West Penn issued
four-year unsecured medium-term notes totaling $33.55 million at
interest rates of 5.56% and 5.66%.
In June and October 1998, Monongahela and Potomac Edison
redeemed an aggregate $115 million of First Mortgage Bonds.
Monongahela exercised its right of optional redemption in June
1998 to redeem its $65 million, 8.5% Series, prior to maturity.
Potomac Edison exercised its right of optional redemption in
October 1998 to redeem its $50 million 8-7/8% Series, prior to
maturity.
During 1998, the rate for West Penn's 400,000 shares of
market auction preferred stock, par value $100 per share, reset
approximately every 90 days at 3.95%, 4.084%, 4.019%, and 4.12%.
The rate set at auction on January 14, 1999, was 3.55%.
26
At December 31, 1998, short-term debt was outstanding in the
following amounts: AE $258.8 million, AGC $66.8 million,
Monongahela $49.0 million, and West Penn $65.1 million. At
December 31, 1998, Potomac Edison had $76.1 million invested.
The Regulated Subsidiaries' ratios of earnings to fixed
charges for the year ended December 31, 1998, were as follows:
Monongahela, 4.40; Potomac Edison, 4.09; West Penn, excluding the
effect of the extraordinary charge, 3.52; and AGC, 3.41.
Allegheny's consolidated capitalization ratios as of
December 31, 1998, were: common equity, 46.4%; preferred stock,
3.9%; and long-term debt, 49.7%, including Quarterly Income Debt
Securities (3.5%). AE's long-term objective is to maintain the
common equity portion above 46%.
During 1999, Monongahela, Potomac Edison, and West Penn
anticipate meeting their capital requirements through a
combination of internally generated funds, cash on hand, and
short-term borrowing as necessary.
However, due to the restructuring of electric generation by
Pennsylvania, a special-purpose subsidiary of West Penn is expected
to issue up to $670 million of bonds to securitize transition
costs related to West Penn's restructuring settlement, which West
Penn may use to reduce its capitalization.
FUEL SUPPLY
Allegheny stations burned approximately 17.5 million tons of
coal in 1998. Of that amount, 88% was either cleaned (5.8
million tons) or used in stations equipped with scrubbers (9.6
million tons). The use of desulfurization equipment and the
cleaning and blending of coal make burning local higher-sulfur
coal practical. In 1998, almost 100% of the coal received at
Allegheny-operated stations came from mines in West Virginia,
Pennsylvania, Maryland, and Ohio. Allegheny does not mine or
clean any coal. All raw, clean, or washed coal is purchased from
various suppliers as necessary to meet station requirements.
Long-term arrangements are in effect to provide for
approximately 14.3 million tons of coal in 1999. The Operating
Subsidiaries will depend on short-term arrangements and spot
purchases for their remaining requirements. Through the year
2001, the total coal requirements of present Allegheny-operated
stations are expected to be met with coal acquired under existing
contracts or from known suppliers.
For each of the years 1994 through 1997, the average cost
per ton of coal burned was $35.88, $32.68, $32.25, and $32.66,
respectively. For the year 1998, the cost per ton decreased to
$32.26.
Long-term arrangements, subject to price change, are in
effect and will provide for the lime requirements of scrubbers at
Allegheny's scrubbed stations.
27
In addition to using ash in various power plant applications
such as scrubber by-product stabilization at Harrison and
Mitchell Power Stations, the Operating Subsidiaries continue
their efforts to market coal combustion by-products for
beneficial uses and thereby reduce landfill requirements. (See a
discussion of research projects in ITEM 1. RESEARCH AND
DEVELOPMENT.) In 1998, the Operating Subsidiaries received
approximately $708,419 from the sale of 1,743,918 tons of fly ash
and 387,769 tons of bottom ash for various uses, including cement
replacement, mine grouting, oil well grouting, soil extenders,
anti-skid material, and grit blast material.
In 1998, the Operating Subsidiaries signed an agreement with
wallboard manufacturers to supply a minimum of 600,000 tons of
synthetic gypsum for use in making wallboard. The Operating
Subsidiaries will break ground in early 1999 to construct a
processing plant which will convert the Pleasants Power Station
flue gas desulfurization by-product into a commercial grade
synthetic gypsum for use in manufacturing wallboard. This will
reduce the amount of by-product going to landfill.
The Operating Subsidiaries own coal reserves estimated to
contain about 125 million tons of higher sulfur coal recoverable
by deep mining. There are no present plans to mine these
reserves and, in view of economic conditions now prevailing in
the coal market, the Operating Subsidiaries plan to hold the
reserves as a long-term resource.
RATE MATTERS
On November 19, 1998, the Pennsylvania PUC approved an
agreement between West Penn and intervenors in West Penn's
restructuring proceedings related to legislation in Pennsylvania
to provide customer choice of electric supplier and deregulate
electricity generation. (See Notes B and C to the Consolidated
Financial Statements for details of the settlement agreement and
other information about the deregulation process.)
Under the Customer Choice Act, all utilities were provided
an opportunity to recover their transition (or stranded) costs.
The determination of transition costs relied heavily on
projections of future market prices of electricity. West Penn's
transition cost recovery claim of $1.2 billion was the subject of
significant disagreement and debate by intervenors in the
restructuring proceedings, as were the transition cost claims of
the other Pennsylvania utilities.
Under the settlement agreement, West Penn has been
authorized to recover $670 million ($630 million if the DQE
merger is consummated) of transition costs, plus a return over a
ten-year period, and to record most of the income therefrom in
the earlier years of the transition period when electricity
market prices are assumed to be lowest. Additionally, West Penn
has written off as an extraordinary item in 1998 about $467
million ($275.4 after taxes) of costs which it deemed not
recoverable under the deregulation process. Of this amount, $451
million ($265.4 million after taxes) was recorded in the second
quarter and $16 million ($10 million after taxes) was recorded in
the fourth quarter. The settlement also provides for a rate
28
refund from 1998 revenue (about $25 million) via a 2.5% rate
decrease throughout 1999, capped rate provisions and
authorization to issue bonds to securitize up to $670 million in
transition costs.
Under the terms of the settlement agreement, two-thirds of
West Penn's customers were permitted to choose an alternate
electric supplier beginning in January 1999. All West Penn
customers can do so beginning in January 2000. (West Penn
customers represent about 45% of Allegheny's electricity supply
business.) They can choose to remain as a West Penn customer 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 (PLR) to all customers in their respective franchise
territories that do not choose an alternate supplier.
Beginning in 1999, in Pennsylvania, electric supply and
electric delivery will be two separate businesses. The
transmission and distribution business will be under traditional
regulated rate making, and the electric supply business will be
deregulated with pricing determined by the market place. The
transmission and distribution business will have the PLR
responsibility and will generally obtain its electric supply from
the market primarily by bidding, including bids from the
affiliated supply business.
The settlement agreement permits the transfer of West Penn's
generation assets to the unregulated supply business at West
Penn's book values. The new, unregulated supply business will be
free to sell, subject to a code of conduct, West Penn's
deregulated generation capacity and energy in the open wholesale
and retail markets, except that it is not permitted to sell at
retail, except under certain conditions, in West Penn's franchise
territory through the year 2003.
Current electric supply prices are below the level required
to produce results of operations equal to that obtained in the
regulated environment in part because, in Allegheny's opinion, of
abundant generation from other states, as well as in
Pennsylvania, to supply the deregulated market of Pennsylvania.
Allegheny believes that the utilities in states that are not yet
deregulated may now be selling and may continue to sell
electricity into Pennsylvania on average at a cost which is lower
than their total cost since their fixed costs are recovered from
franchise customers in their home state territories.
The Pennsylvania PUC's projections of electricity market
prices recognized this possibility, among others, and accordingly
assumed depressed prices in the earlier years of the transition
process from regulation to deregulation. The projections further
assumed that prices would increase in later years due to
increasing demand from deregulation in other states and normal
increases in customer demand, particularly because of
competition.
As stated above, West Penn made a filing concerning its
transition cost requirements in Pennsylvania based on its early
1997 projection of market prices. The Pennsylvania PUC issued an
order on May 29, 1998, to West Penn, as well as orders to all
other Pennsylvania electric utilities in 1998, based on
alternative projections. Current prices, which West Penn
believes are being influenced, among other things, by price
volatility in the summer of
29
1998, are equal to and in some cases
slightly higher than the projections adopted by the Pennsylvania
PUC in its deregulation orders issued to West Penn and other
utilities in Pennsylvania. If the Pennsylvania PUC's projections
are correct, West Penn believes that the transition costs
provided will be sufficient to permit it to recover its embedded
costs, with a return, during the transition from regulation to
deregulation of electricity generation.
The forward-looking statements above are provided to
describe Allegheny's plans and its reasoning for actions taken.
Of necessity, its plans are based on assessments of future
events. There can be no assurance that actual results will not
materially differ from those presented. (For a discussion of
West Penn's restructuring plan, see ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS - Significant Continuing Issues - Electric Energy
Competition and Notes B and C to the Consolidated Financial
Statements in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA.)
After substantial negotiations, Potomac Edison reached a
settlement agreement with various parties on the Office of
People's Counsel's (OPC) petition for a reduction in Potomac
Edison's Maryland rates. The agreement, which includes
recognition and dollar-for-dollar recovery of costs to be
incurred from the Warrior Run PURPA project, was filed with the
Maryland PSC on July 30, 1998, and approved by that Commission on
October 27, 1998. Rates to each customer class were approved by
the Maryland PSC on December 22, 1998. Under the terms of the
agreement, Potomac Edison will increase its rates about 4% ($13
million) in each of the years 1999, 2000, and 2001 (a $39 million
annual effect in 2001). The increases are designed to recover
additional costs of about $131 million, over the period 1999-
2001, for capacity purchases from the Warrior Run generation
project net of alleged overearnings of $52 million for the same
period absent these adjustments. The net effect of these changes
over the 1999-2001 time frame results in a pre-tax income
reduction of $12 million in 1999, $18 million in 2000, and $22
million in 2001. In the event the merger with DQE is
consummated, an additional rate reduction of $4.4 million
annually will occur, based upon expected synergy savings. In
addition, the settlement requires that Potomac Edison share, on a
50% customer, 50% shareholder basis, earnings above a threshold
return on equity (ROE) level of 11.4% for 1999-2001. This
sharing will occur through an after-the-fact true-up conducted
after each calendar year is completed. Warrior Run is a
cogeneration project being built by AES Enterprise, a non-
affiliated PURPA developer, in western Maryland. Potomac Edison
is required to purchase the project's energy at above-market
prices pursuant to the requirements of the federal PURPA law.
As required by the Maryland PSC, Potomac Edison, on July 1,
1998, filed testimony in Maryland's investigation into transition
costs, price protection, and unbundled rates. The filing also
requested a surcharge to recover the cost of the Warrior Run
cogeneration project, which is scheduled to commence production
on October 1, 1999. Hearings are scheduled to begin in April
1999. A second Maryland PSC proceeding is planned to begin
examining market power protective measures in December 1999.
Under the Maryland PSC's current timetable, and assuming the
necessary legislation is passed, one-third of the state's
electricity customers would be able to
30
choose their electricity supplier beginning in July 2000, and all
customers would have choice by mid-2002.
The West Virginia PSC, the Ohio PUC, and the Virginia
SCC began or continued investigations during 1998 regarding the
restructuring of and competition in the electric utility
industry. (See ITEM 1. BUSINESS - Competition for a description
of these activities.)
On September 23, 1998, the Maryland PSC accepted the
recommendations of Potomac Edison and its Collaborative Partners
to phase out three demand-side management (DSM) programs in
Maryland. Potomac Edison reexamined the cost-effectiveness of
the programs, and removed the savings associated with production
capacity and energy beginning in the year 2000, which is the
proposed start date for competition in Maryland. The analysis
indicated that the current programs are no longer cost-effective.
As a result, these programs will be terminated by December 1999.
Since 1993, Potomac Edison has spent $20 million to help
customers install energy-saving measures in their homes and
businesses through these programs. During 1998, Potomac Edison
expended $966,855 on program costs and rebates. These costs are
recoverable through a Commission-approved energy conservation
surcharge.
In 1997, the Maryland PSC instituted a proceeding to
investigate the effect of the proposed AE and DQE merger on
Potomac Edison's Maryland customers and operations. The Maryland
PSC approved a settlement agreement in this case on March 28,
1998. Upon merger consummation, Maryland retail rates will be
reduced by $4.4 million annually to reflect a portion of
expected synergy savings.
Potomac Edison and the Virginia Commission Staff entered
into discussions which resulted in a settlement agreement of
Potomac Edison's Annual Informational Filing (AIF) which the
Virginia SCC approved August 7, 1998. Effective September 1,
1998, Potomac Edison reduced base rates by $2.5 million and wrote
off $2.3 million of restructuring costs which had been deferred
for ratemaking purposes only, and $0.5 of loss on reacquired
debt. The return on equity (ROE) range was maintained at 11-12%
with the computed ROE, after adjustments, of 11.4%. Potomac
Edison agreed to file a full AIF for calendar year 1998 by March
31, 1999, with an earnings test. In the event Potomac Edison is
in an over-earning position at that time, its rates will
immediately become interim.
Currently, all state regulatory jurisdictions except
Pennsylvania and the FERC use fuel clause procedures to recognize
changes in fuel and other energy costs in rates. These
procedures use an expedited proceeding which permits energy costs
to be adjusted on a more timely basis than other costs.
Differences between revenues received for energy costs and actual
energy costs are deferred until the next proceeding when energy
rates are adjusted to return or recover previous overrecoveries
or underrecoveries, respectively. This procedure minimizes the
effect on net income associated with changes in energy costs.
On June 30, 1998, the West Virginia PSC issued an order in
the annual Expanded Net Energy Cost proceedings under which
Monongahela and Potomac Edison received annual increases of $8.9
million and $1.0 million,
31
respectively. The increases were primarily due to fuel cost
increases and to the removal of a credit, which had been
refunding to customers a prior overrecovery of fuel costs.
The new rates became effective July 1, 1998.
Fuel proceedings before the Ohio PUC require a mid-term
filing, financial audit, management performance audit, and an
annual filing. The Ohio PUC approved a stipulated agreement for
Monongahela on January 21, 1999, which granted a decrease of $1.4
million. The new rate was effective February 3, 1999.
On January 15, 1998, Potomac Edison filed with the Virginia
SCC for an annual increase in fuel rates of $2.1 million to
become effective March 9, 1998. The increase was primarily due
to the need to collect prior underrecovery of fuel costs and a
small increase in fuel costs. On February 25, 1998, the Virginia
SCC approved the increase. On January 15, 1999, Potomac Edison
filed for an annual decrease in fuel rates of $2.2 million to
become effective March 9, 1999. The decrease is primarily due to
the refunding of a prior overrecovery of fuel costs, coupled with
a small decrease in projected energy costs. On February 25,
1999, the Virginia SCC approved the decrease.
AGC's rates are set by a formula filed with and previously
accepted by the FERC. The only component that can change is the
ROE. Pursuant to a settlement agreement filed April 4, 1996,
with the FERC, AGC's ROE was set at 11% for 1996 and will
continue until the time any affected party requests a change. No
party has requested any change.
ENVIRONMENTAL MATTERS
The operations of the Allegheny-owned facilities, including
generating stations, are subject to regulation as to air and
water quality, hazardous and solid waste disposal, and other
environmental matters by various federal, state, and local
authorities. That portion of Fort Martin Unit 1 (50%) owned by
AYP Energy is subject to the same environmental regulations as
other units owned by the Operating Subsidiaries. Compliance
strategies, compliance assurance, permitting, compliance costs,
allowance allocation, etc., for this unit are closely coordinated
with AYP Capital.
Meeting known environmental standards is estimated to cost
the Operating Subsidiaries about $260 million in construction
expenditures over the next three years. Additional legislation
or regulatory control requirements have been proposed and, if
enacted, will require modifying, supplementing, or replacing
equipment at existing stations at substantial additional cost.
Air Standards
Allegheny currently meets applicable standards as to
particulate and opacity at its power stations through high-
efficiency electrostatic precipitators, cleaned coal, flue-gas
conditioning, and, at times, reduction of output. From time to
time, minor excursions of opacity, normal to fossil
32
fuel operations, are experienced and are accommodated by the
regulatory process.
Allegheny meets current emission standards as to sulphur
dioxide (SO2) by the use of scrubbers, the burning of low-sulfur
coal, the purchase of cleaned coal to lower the sulfur content,
and the blending of low-sulfur with higher sulfur coal.
The CAAA, among other things, requires an annual reduction
in total utility emissions within the United States of 10 million
tons of SO2 and two million tons of NOx from 1980 emission
levels, to be completed in two phases, Phase I and Phase II.
Five coal-fired Allegheny plants are affected in Phase I, and the
remaining plants will be affected in Phase II. Installation of
scrubbers at the Harrison Power Station was the strategy
undertaken by Allegheny to meet the required SO2 emission
reductions for Phase I (1995-1999). Allegheny estimates that its
banked emission allowances will allow it to comply with Phase II
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. It is expected that burner modifications
at most of the Allegheny-operated stations will satisfy the NOx
emission reduction requirements for the acid rain (Title IV)
provisions of the CAAA. Additional NOx reductions are being
mandated in Maryland, Pennsylvania, and West Virginia for ozone
nonattainment (Title I) reasons. Continuous emission monitoring
equipment has been installed on all Phase I and Phase II units.
In an effort to introduce market forces into pollution
control, the CAAA created SO2 emission allowances. An allowance
is defined as an authorization to emit one ton of SO2 into the
atmosphere. Subject to regulatory limitations, allowances
(including bonus and extension allowances) may be sold or banked
for future use or sale. Allegheny received, through an industry
allowance pooling agreement, a total of approximately 554,000
bonus and extension allowances during Phase I. These allowances
are in addition to the CAAA Table A allowances that the Operating
Subsidiaries receive of approximately 356,000 per year during the
Phase I years. Ownership of these allowances permits Allegheny
to operate in compliance with Phase I, and, as noted above, is
expected to facilitate compliance during the early years of Phase
II. As part of its compliance strategy, Allegheny continues to
study the allowance market to determine whether sales or
purchases of allowances or participation in certain derivative or
hedging allowance transactions are appropriate.
Pursuant to an option in the CAAA, Allegheny chose to treat
eight Phase II boilers as Phase-I-affected units (Substitution
Units) for calendar year 1998. The status of all substitution
units is evaluated on an annual basis to ascertain the financial
benefits of retaining these units as Phase I-affected units. As
a result of being Phase I-affected, these Substitution Units are
required to comply with the Phase I SO2 limits for each year that
they are accorded substitution status by Allegheny.
Title I of the CAAA established an Ozone Transport Region
(OTR) consisting of the District of Columbia, the northern part
of Virginia, and 11 northeastern states including Maryland and
Pennsylvania. Sources within the
33
OTR will be required to reduce
NOx emissions, a precursor of ozone, to a level conducive to
attainment of the ozone National Ambient Air Quality Standard
(NAAQS). The installation of Reasonably Available Control
Technology (RACT) (overfire air equipment and/or low NOx burners)
at all Pennsylvania and Maryland stations has been completed.
The installation of RACT satisfies both Title I and Title IV NOx
reduction requirements.
Title I of the CAAA also established an Ozone Transport
Commission (OTC), which has determined that utilities within the
OTR will be required to make additional NOx reductions beyond
RACT in order for the OTR to meet the ozone NAAQS. Under terms
of a Memorandum of Understanding (MOU) among the OTR states,
Allegheny-operated stations located in Maryland and Pennsylvania
are required to reduce NOx emissions by approximately 55% from
the 1990 baseline emissions, with a compliance date of May 1999.
RACT controls installed in Allegheny's Maryland and Pennsylvania
generating plants are expected to meet the 55% reduction
requirement through the year 2002. Further reductions of 75%
from the 1990 baseline may be required by May 2003 under Phase
III of the MOU. However, the MOU Phase III NOx reductions will
most likely be suspended by the EPA's NOx SIP call as discussed
below. Pennsylvania promulgated regulations to implement Phase
II of the MOU in November 1997. Maryland promulgated regulations
to implement Phase II of the MOU in May 1998.
During 1995, the Environmental Council of States and the
U.S. Environmental Protection Agency (EPA) established the Ozone
Transport Assessment Group (OTAG) to develop recommendations for
the regional control of NOx and Volatile Organic Compounds in 37
states east of and bordering the west bank of the Mississippi
River plus Texas. OTAG issued its final report in June 1997 that
recommended EPA consider a range of utility NOx controls between
existing Clean Air Act (Title IV) controls and the less stringent
of 85% reduction from the 1990 emission rate or 0.15 lb/mmBtu.
According to OTAG recommendations, the states would have the
opportunity to conduct additional local and subregional modeling
in order to develop and propose appropriate levels and timing of
controls. The EPA initiated the regulatory process to adopt the
OTAG recommendations with a proposed SIP call issued October
1998. The EPA NOx SIP call requires the equivalent of a uniform
0.15 lb/mmBtu emission rate throughout a 22-state region,
including Maryland, Pennsylvania, and West Virginia, without the
benefit of the OTAG recommended additional subregional modeling
evaluation. Implementation of controls will be required by
summer 2003. States are required to develop and submit
implementing regulations to the EPA by September 1999.
Allegheny's compliance with such stringent regulations will
require the installation of expensive post-combustion control
technologies on most of its power stations, with a total capital
cost of approximately $360 million.
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 of the ozone standard. In December 1997, the
petitioning states and EPA signed a Memorandum of Agreement to
address these petitions in conjunction with the OTAG-related SIP
call mentioned above. In October 1998, the EPA proposed approval
of the petitions. However, the EPA has stated its
34
belief that implementation of the NOx SIP call will alleviate
the need to grant the petitions. EPA intends to issue a final
rule by April 1999.
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
promulgated by the EPA in July 1997. State attainment plans to
meet the revised standards will not be developed for several
years. Also, in July 1997, EPA proposed regional haze
regulations to improve visibility in Class I federal areas
(natural parks and wilderness areas). If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Allegheny facilities. The effect on
Allegheny of revision to any of these standards or regulations is
unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase
III of the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time. All are being challenged via
rulemaking, petition, and/or litigation.
In 1989, the West Virginia Air Pollution Control Commission
approved the construction of a third-party cogeneration facility
in the vicinity of Rivesville, West Virginia. Emissions impact
modeling for that facility raised concerns about the compliance
of Monongahela's Rivesville Station with ambient standards for
SO2. Pursuant to a consent order, Monongahela agreed to collect
on-site meteorological data and conduct additional dispersion
modeling in order to demonstrate compliance. The modeling study
and a compliance strategy recommending construction of a new
"good engineering practices" (GEP) stack were submitted to the
West Virginia Department of Environmental Protection (WVDEP) in
June 1993. Costs associated with the GEP stack are approximately
$20 million. Monongahela is awaiting action by the WVDEP.
Under an EPA-approved consent order with Pennsylvania, West
Penn completed construction of a GEP stack at the Armstrong Power
Station in 1982 at a cost of more than $13 million with the
expectation that EPA's reclassification of Armstrong County to
"attainment status" under NAAQS for SO2 would follow. As a
result of the 1985 revision of its stack height rules, EPA
refused to reclassify the area to attainment status.
Subsequently, West Penn filed an appeal with the U.S. Court of
Appeals for the Third Circuit for review of that decision as well
as a petition for reconsideration with EPA. In 1988, the Court
dismissed West Penn's appeal, stating it could not decide the
case while West Penn's request for reconsideration before EPA was
pending. West Penn cannot predict the outcome of this
proceeding.
In March 1998, the EPA released its Utility Air Toxics
Report to Congress. The report itself does not recommend
regulatory controls. However, the EPA is expected to make a
recommendation on regulatory controls by December 2000. The EPA
has identified mercury emissions as requiring further research
and monitoring because of the potential concern for public
health. While it appears that EPA wants to control utility
mercury
35
emissions, it currently lacks the technical
justification. In late November 1998, the EPA issued a mercury
data collection request that requires utilities to sample and
analyze coal shipments for mercury and chlorine throughout 1999.
In addition, some plants may be required to conduct stack testing
to determine the effectiveness of existing particulate and SO2
control equipment in the reduction of mercury emissions.
Water Standards
Under the National Pollutant Discharge Elimination System
(NPDES), permits for all of Allegheny's stations and disposal
sites are in place. However, NPDES permit renewals for several
West Virginia and Pennsylvania disposal sites contain what
Allegheny believes are overly stringent discharge limitations.
Allegheny, in cooperation with the states and EPA, has developed
alternate water quality criteria which, if approved by the
agencies, will result in less stringent permit limits. If their
criteria are not approved, installation of wastewater treatment
facilities may become necessary. The cost of such facilities, if
required, cannot be predicted at this time.
As the result of a lawsuit by environmental groups, the EPA
and WVDEP, on October 27, 1997, proposed total maximum daily
loads (TMDLs) for the Blackwater River and South Fork of the
Potomac River and five of its tributaries. This is the first of
44 court-ordered waste load allocations for West Virginia to be
issued over six years which will, when implemented, reduce the
amount of pollutants that can be discharged into rivers that do
not meet water quality standards. The final Blackwater TMDL
allows the existing waste loads to continue but eliminates unused
waste load allocations, including those owned by Allegheny,
thereby precluding further development in the area. Because of
the precedent setting nature of the Blackwater TMDL, Allegheny
and others have challenged the TMDL before the West Virginia
Environmental Quality Board. Environmental groups have also
filed lawsuits in a number of other states, including
Pennsylvania and Maryland, which will, when settled, force these
states and the EPA to develop and implement wastewater discharge
restrictions. The direct result of these actions will be further
reductions in the amount of pollutants that can be discharged by
certain company-owned power stations which are located on rivers
whose water quality does not meet standards. Indirectly, the
TMDL process can adversely affect the region's economy and
therefore the financial performance of Allegheny by limiting
economic development and curtailing the wastewater discharges of
existing industrial customers in certain areas. The total
implications of the pending waste load allocations will not be
known until the agencies develop and implement TMDLs in specific
watersheds.
The Pennsylvania Land Recycling Act, adopted in 1996, and
the West Virginia Voluntary Cleanup Act, adopted in 1997, allow
for the development and application of site-specific, risk-based
groundwater cleanup standards to both abandoned and active
industrial sites. The intent is to encourage the reuse of
abandoned but contaminated industrial sites and to allow for
continual operation of industrial sites whose operation began
before groundwater protection statutes were in place -- as long
as it can be demonstrated by the owner/operator that there is
little or no risk to human
36
health or the environment. The
implementing regulations provide for reasonable and cost-
effective groundwater cleanup of Allegheny facilities should it
become necessary and will encourage economic development in
Allegheny's service territories in Pennsylvania and West
Virginia.
Hazardous and Solid Wastes
Pursuant to the Resource Conservation and Recovery Act of
1976 (RCRA) and the Hazardous and Solid Waste Management
Amendments of 1984, the EPA regulates the disposal of hazardous
and solid waste materials. Maryland, Ohio, Pennsylvania,
Virginia, and West Virginia have also enacted hazardous and solid
waste management regulations that are as stringent as or more
stringent than the corresponding EPA regulations.
Allegheny is in a continual process of either permitting new
or re-permitting existing disposal capacity to meet future
disposal needs. All disposal areas are currently operated to be
in compliance with their permits.
Allegheny continues to actively pursue, with PADEP and WVDEP
encouragement, ash utilization projects such as deep mine
injection for subsidence and water quality improvement,
structural fills for highway and building construction, and soil
enhancement for surface mine reclamation. The Operating
Subsidiaries will break ground in early 1999 to construct a
processing plant which will convert the Pleasants Power Station
flue gas desulfurization by-product into a commercial grade
synthetic gypsum for use in manufacturing wallboard.
Potomac Edison received a notice from the Maryland
Department of the Environment (MDE) in 1990 regarding a
remediation ordered under Maryland law at a facility previously
owned by Potomac Edison. The MDE has identified Potomac Edison
as a potentially responsible party under Maryland law.
Remediation is being implemented by the current owner of the
facility which is located in Frederick. It is not anticipated
that Potomac Edison's share of remediation costs, if any, will be
substantial.
The Operating Subsidiaries are also among a group of
potentially responsible parties under the Comprehensive
Environmental Response, Compensation and Liability Act of 1980,
as amended (CERCLA), for the Jack's Creek/Sitkin Smelting
Superfund Site and the Butler Tunnel Superfund Site in
Pennsylvania. (See ITEM 3. LEGAL PROCEEDINGS for a description
of these Superfund cases.)
Toxic Release Inventory (TRI)
On Earth Day 1997, President Clinton announced the expansion
of TRI to include electric utilities, limited to facilities that
combust coal and/or oil for the purpose of generating power for
distribution in commerce. The purpose of TRI is to provide site-
specific information on chemical releases to the air, land, and
water. The first TRI report is due on July 1, 1999, for calendar
year 1998. The reports will be filed with EPA and made available
through publication of the reported information and posting on
the
37
Internet. Allegheny is actively working on a communications
plan to proactively educate employees and the community on the
TRI program and the amounts of reportable chemicals released by
Allegheny.
Global Climate Change
Climate change is alleged to be the result of the
atmospheric accumulation of certain gases collectively referred
to as GHG, the most significant of which is carbon dioxide (CO2).
Human activities, including 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 will require the U.S. to reduce
emissions of GHG by 7% from 1990 levels in the 2008-2012 time
period. The U.S. Senate must ratify the Kyoto Protocol before it
enters into force, as must other nations subject to the treaty's
provisions. The Senate passed a resolution in 1997 (S.R. 98) by
a vote of 95-0 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 U.S. 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 U.S. 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.
If and when the need for reducing greenhouse gas emissions
has been identified and scientifically supported, Allegheny
believes that a global solution involving all nations and must
give credit for preventive actions taken. Allegheny believes
precipitous and urgent action under strict limits and timetables
will result in severe economic dislocation and is not warranted.
Allegheny does believe that appropriate results can be achieved
domestically by continuing to build upon the notable progress of
existing voluntary programs.
For these reasons, Allegheny actively participates in a
number of groups to address this environmental matter. Allegheny
supports research on the climate change issue through EPRI and
participates in a number of organizations to help influence
policy matters at the domestic and international levels.
Allegheny has also undertaken a program to identify cost-
effective and voluntary measures that reduce emissions of GHG in
all areas of its business and in other areas, such as forestry,
international projects, and emissions trading.
The Operating Subsidiaries maintain an active climate-
related research program and are responsive to the greenhouse gas
guidelines suggested in the 1992 National Energy Policy Act. As a
result, the Operating Subsidiaries have voluntarily reduced their
total annual emissions of GHG by 1,090,501, as described in the
latest filing with the Department of Energy.
The Operating Subsidiaries support EPRI which funds climate
research targets at around $7 to $10 million per year and Edison
Electric Institute's Climate Challenge Initiative funded at
$100,000 per-year; and have committed
38
to invest $3.11 million in an electrotechnology and renewable
energy venture capital fund.
The Operating Subsidiaries' in-house research program has
contributed to applications of new technology, operating
efficiencies, reduced electrical losses and pollution emission
reductions.
West Penn recently settled a restructuring plan with the
Pennsylvania PUC that included five important climate related
issues: 1) Renewable Energy Development, 2) Sustainable Energy
Fund ($11,425,721 paid on December 31, 1998), 3) Renewable Energy
Pilot Program ($300,000 each year), 4) Energy Cooperative
Association of Pennsylvania (contribution of $4 million) and 5)
Universal Service and Energy Conservation Program ($8.082 million
per year).
In response to environmental issues over the past 18 years,
the Operating Subsidiaries spent over $1.6 billion in capital
expenditures and approximately $200 million annually in
operations and maintenance and are committed to environmental
stewardship and the research needed to provide answers to
difficult compliance problems. These actions will mitigate the
impact of the Operating Subsidiaries' operations on the
environment and ameliorate the global warming problem.
REGULATION
Allegheny is subject to the broad jurisdiction of the SEC
under PUHCA. The Regulated Subsidiaries are regulated as to
substantially all of their operations by regulatory commissions
in the states in which they operate. The Regulated Subsidiaries,
West Penn's unregulated generation, and AYP Energy are also
regulated as to various aspects of their business by the FERC.
In addition, they are subject to numerous other local, state, and
federal laws, regulations, and rules.
In June 1995, the SEC published its report which recommended
changes to PUHCA, including a recommendation to Congress to
repeal the entire act. Bills have been introduced in the
Congress to repeal PUHCA, but have not passed. Allegheny cannot
predict what changes, if any, will be made to PUHCA as a result
of these activities.
In 1998, the Operating Subsidiaries continued to take part
in and fund various programs to assist low-income customers,
customers with special needs, and/or customers experiencing
temporary financial hardship.
YEAR 2000
Year 2000 (Y2K) readiness is a top priority. Allegheny has
an Executive Task Force, led by a Vice President, that is
coordinating the efforts of 24 individual Y2K teams, representing
all business and support units in Allegheny. The teams are
actively working to investigate, evaluate, and mitigate all
critical Y2K concerns.
39
The teams have completed their inventory of all critical
elements (computer hardware and software, embedded chips and
vendors) that may be affected by Y2K and are well into their
remediation, testing, and contingency planning efforts.
Allegheny's goal is to have most mission critical components and
systems Y2K-ready by the first quarter of 1999, and all of them
ready by mid-year.
Allegheny's Y2K teams are involved in contingency planning
and are working with other utilities, customers, government
agencies, financial institutions, suppliers, and vendors to
achieve a cooperative and thorough effort. Allegheny believes
its critical equipment will be ready for the Year 2000, but
Allegheny must prepare for any contingency. In 1999, Allegheny
will participate in two nationwide testing drills.
ITEM 2. PROPERTIES
Substantially all of the properties of the Operating
Subsidiaries are held subject to the lien of the indenture
securing each Operating Subsidiary's first mortgage bonds and, in
many cases, subject to certain reservations, minor encumbrances,
and title defects which do not materially interfere with their
use. Some of the Operating Subsidiaries' properties are also
subject to a second lien securing certain solid waste disposal
and pollution control notes. The indenture under which AGC's
unsecured debentures and medium-term notes are issued prohibits
AGC, with certain limited exceptions, from incurring or
permitting liens to exist on any of its properties or assets
unless the debentures and medium-term notes are contemporaneously
secured equally and ratably with all other indebtedness secured
by such lien. Transmission and distribution lines, in
substantial part, some substations and switching stations, and
some ancillary facilities at power stations are on lands of
others, in some cases by sufferance, but in most instances
pursuant to leases, easements, rights-of-way, permits or other
arrangements, many of which have not been recorded and some of
which are not evidenced by formal grants. In some cases, no
examination of titles has been made as to lands on which
transmission and distribution lines and substations are located.
Each of the Operating Subsidiaries possesses the power of eminent
domain with respect to its public utility operations. (See also
ITEM 1. BUSINESS and ALLEGHENY MAP.)
ITEM 3. LEGAL PROCEEDINGS
In a letter to AE dated October 5, 1998, DQE stated that it
had decided to unilaterally terminate the merger. In response,
on October 5, 1998, AE filed a lawsuit in the United States
District Court for the Western District of Pennsylvania against
DQE for specific performance of the Merger Agreement or, in the
alternative, for damages. AE also filed motions for a temporary
restraining order and preliminary injunction against DQE. On
October 28, 1998, the court denied AE's motions for a temporary
restraining order and preliminary injunction. On October 30,
1998, AE appealed the District Court's order to the United States
Court of Appeals for the Third Circuit. On March 11, 1999, the
U.S. Court of Appeals for the Third Circuit vacated the district
court's denial of Allegheny's motion for preliminary injunction,
enjoining DQE from taking actions prohibited by the merger
agreement. The Circuit Court stated that if DQE breached the
Merger Agreement, AE would be entitled to
40
specific performance of the Merger Agreement. The Circuit
Court also stated that AE would be irreparably harmed if
DQE took actions that would prevent AE from receiving the
specific performance remedy. The Circuit Court remanded
the case to the District Court for further proceedings
consistent with its opinion.
In the District Court, discovery is ongoing, and AE cannot
predict the outcome of this litigation. However, AE believes
that DQE's basis for seeking to terminate the merger is without
merit. Accordingly, AE continues to seek the remaining
regulatory approvals from the Department of Justice and the
Securities and Exchange Commission. It is not likely either
agency will act on the requests unless AE obtains judicial relief
requiring DQE to move forward.
On September 29, 1997, the City of Pittsburgh filed an
antitrust and conspiracy lawsuit in the Federal District Court
for the Western District of Pennsylvania against AE, West Penn,
DQE, and Duquesne. The complaint alleged eight counts, two of
which were claimed violations of the antitrust statutes and six
were state law claims. The relief sought included a request that
the proposed merger between AE and DQE be stopped, and requested
unspecified monetary damages relating to alleged collusion
between the two companies in their actions dealing with proposals
to provide electric service to redevelopment zones in the city.
On October 27, 1997, all defendants filed motions to dismiss the
complaint. On January 6, 1998, the District Court issued an
order which granted the motions to dismiss. On January 14, 1998,
the City appealed the order to the United States Court of Appeals
for the Third Circuit. On June 12, 1998, the Third Circuit
upheld the District Court's order. This matter was subsequently
settled.
On September 7, 1995, MidAtlantic Energy (MidAtlantic) sued
Monongahela, Potomac Edison, and AE in state court in Marshall
County, W.Va., alleging failure to comply with PURPA regulations
in refusing to purchase capacity and energy from a proposed PURPA
project and interference with MidAtlantic's contract with the
Babcock and Wilcox Company (B and W), among other things. This
suit followed an unsuccessful complaint proceeding by MidAtlantic
requesting the West Virginia PSC to order Monongahela and Potomac
Edison to purchase capacity and energy from the project. The
MidAtlantic suit also named B and W as a defendant. MidAtlantic
seeks compensatory and punitive damages. Monongahela, Potomac
Edison, and AE filed an answer and B and W filed an answer and
counterclaim. Monongahela, Potomac Edison, and AE cannot predict
the outcome of this litigation.
On August 13, 1996, American Bituminous Partners, L.P.,
(AmBit), filed a request for arbitration alleging that the energy
rate payable under its purchase power contract with Monongahela
had been improperly calculated. The arbitration proceeding was
bifurcated into a liability phase and, if necessary, a damages
phase. A hearing in the liability phase of the arbitration
proceeding has been completed and briefed. On February 18, 1998,
the arbitration panel made a determination in the liability
phase. They determined that certain lime handling costs should
have been a component of the energy rate and therefore were
improperly accounted for in 1995 and 1996. The damages phase of
the arbitration on this issue will be limited to determination of
the extent of these costs and any related lime handling
41
costs that AmBit can show should have been included in the calculation
of the energy rate. Monongahela cannot predict the outcome of
this proceeding.
As of January 19, 1999, Monongahela has been named as a
defendant along with multiple other defendants in a total of
7,680 pending asbestos cases involving one or more plaintiffs.
Potomac Edison and West Penn have been named as defendants along
with multiple other defendants in approximately one-half of those
cases. Because these cases are filed in a "shot-gun" format
whereby multiple plaintiffs file claims against multiple
defendants in the same case, it is presently impossible to
determine the actual number of cases in which plaintiffs make
claims against the Operating Subsidiaries. However, based upon
past experience and available data, it is estimated that about
one-third of the total number of cases filed actually involve
claims against any or all of the Operating Subsidiaries. All
complaints allege that the plaintiffs sustained unspecified
injuries resulting from claimed exposure to asbestos in various
generating plants and other industrial facilities operated by the
various defendants, although all plaintiffs do not claim exposure
at facilities operated by all defendants. With very few
exceptions, plaintiffs claiming exposure at stations operated by
the Operating Subsidiaries were employed by third-party
contractors, not the Operating Subsidiaries. Three plaintiffs
are known to be either present or former employees of
Monongahela. Each plaintiff generally seeks compensatory and
punitive damages against all defendants in amounts of up to $1
million and $3 million, respectively; in those cases which
include a spousal claim for loss of consortium, damages are
generally sought against all defendants in an amount of up to an
additional $1 million. A total of 94 cases have been previously
settled and/or dismissed against Monongahela for an amount
substantially less than the anticipated cost of defense. While
the Operating Subsidiaries believe that all of the cases are
without merit, they cannot predict the outcome nor are they able
to determine whether additional cases will be filed.
On January 27, 1995, Allegheny filed a declaratory judgment
action in the Court of Common Pleas of Westmoreland County, Pa.,
against its historic comprehensive general liability (CGL)
insurers. This suit seeks a declaration that the CGL insurers
have a duty to defend and indemnify the Operating Subsidiaries in
the asbestos cases, as well as in certain environmental actions.
To date, two insurers have settled. However, the final outcome
of this proceeding cannot be predicted.
On March 4, 1994, the Operating Subsidiaries 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 the Jack's Creek/Sitkin Smelting Superfund Site (Site). There
are approximately 175 other PRPs involved. A Remedial
Investigation/Feasibility Study (RI/FS) prepared by the EPA
originally indicated remedial alternatives which ranged as high
as $113 million, to be shared by all responsible parties. A PRP
Group consisting of approximately 40 members, and to which the
Operating Subsidiaries belong, has been formed and has submitted
an addendum to the RI/FS which proposes a substantially less
expensive cleanup remedy. In January 1998, this PRP Group has
made a good-faith offer to the EPA to settle this matter. A
final determination has not been made for the Operating
Subsidiaries' share of the remediation costs
42
based on the amount of materials sent to the site. However, at
this time it is estimated that the effect on the Operating
Subsidiaries will not be material.
Potomac Edison received a questionnaire on October 1, 1996,
from the EPA concerning a release or threat of release of
hazardous substances, pollutants, or contaminants into the
environment at the Butler Tunnel Site located in Luzerne County,
Pa. Potomac Edison notified the EPA that it has no records or
recollection of any business relations with the site or any of
the companies identified in the questionnaire. It is not
possible to determine at this time what effect, if any, this
matter may have on Potomac Edison.
After protracted litigation concerning the Operating
Subsidiaries' application for a license to build a 1,000-MW
energy-storage facility near Davis, W.Va., in 1988, the U.S.
District Court reversed the U.S. Army Corps of Engineers' (Corps)
denial of a dredge and fill permit on the grounds that, among
other things, the Operating Subsidiaries were denied an
opportunity to review and comment upon written materials and
other communications used by the Corps in reaching its decision.
As a result, the Court remanded the matter to the Corps for
further proceedings. This remand order has been appealed. The
Operating Subsidiaries cannot predict the outcome of this
proceeding.
In 1979, National Steel Corporation (National Steel) filed
suit against AE and certain subsidiaries in the Circuit Court of
Hancock County, W.Va., alleging damages of approximately $7.9
million as a result of an order issued by the West Virginia PSC
requiring curtailment of National Steel's use of electric power
during the United Mine Workers' strike of 1977-8. A jury verdict
in favor of AE and the subsidiaries was rendered in June 1991.
National Steel has filed a motion for a new trial, which is still
pending before the Circuit Court of Hancock County. AE and the
subsidiaries believe the motion is without merit; however, they
cannot predict the outcome of this case.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
AE, Monongahela, Potomac Edison, West Penn, and AGC did not
submit any matters to a vote of shareholders during the fourth
quarter of 1998.
43
Executive Officers of the Registrants
The names of the executive officers of each company, their ages
as of December 31, 1998, the positions they hold, or held during
1998, and their business experience during the past five years
appears below:
Position (a) and Period of Service
Name Age AE MP PE WP AGC
Charles S. Ault 60 V.P.
(1990- )
Eileen M. Beck 57 Secretary Secretary Secretary Secretary Secretary
(1988- ) (1995- ) (1996-) (1996- ) (1982- )
Previously Previously, Previously Previously
Asst. Treas. Asst. Treas. Asst.Sec. Asst. Sec.
(1979-95) (1981-95) (1988-95) (1988-95)
Asst. Sec.
(1988-94)
Regis F. Binder(b) 46 V.P. & Treas. Treas. Treas. Treas. Treas.
(12/98- ) (12/98- ) (12/98- (12/98- ) (2/99- )
Nancy L.Campbell(c) 59 V.P. Treasurer Treasurer Treasurer Treasurer
(1994-12/98) (1995-12/98) (1996-12/98) (1996-12/98) (1988-12/98)
& Treas. Previously, Previously,
(1988-12/98) Asst.Sec. Asst. Sec.
(1988-96) (1988-96)
Asst. Treas.
(1988-95)
C. Vernon Estel, Jr.(d) 43 V.P.
(1996-10/98)
Richard J. Gagliardi 48 V.P. Asst. Sec. Asst.
(1991- ) (1990-96) Treas.
(1982-96)
James R. Haney(e) 42 V.P. V.P. V.P.
(1998- ) (1998- ) (1998- )
Thomas K. Henderson 58 V.P. V.P. V.P. V.P. Dir.& V.P.
(1997- ) (1995- ) (1995-) (1985- ) (1996- )
Kenneth M. Jones 61 V.P. Dir.& V.P.
(1991- ) (1991-2/99)
Previously,
Controllor.
(1991-1998)
Thomas J. Kloc 46 V.P. & Controller Controller Controller Dir.& V.P.
Controlle r (1996- ) (1988- ) (1995- ) (2/99- )
(1998- ) Controller
(1988- )
44
Executive Officers of the Registrants, cont'd.
The names of the executive officers of each company, their ages
as of December 31, 1998, the positions they hold, or held during
1998, and their business experience during the past five years
appears below:
Position (a) and Period of Service
Name Age AE MP PE WP AGC
James D. Latimer 60 V.P. V.P. V.P.
(1995- ) (1995- ) (1995- )
Previously,
Executive V.P.
(1994-95)
V.P.
(1988-94)
Michael P. Morrell(f) 50 Sr. V.P. Dir & V.P. Dir.& V.P. Dir. & V.P. Dir.& V.P.
(1996- ) (1996- ) (1996- ) (1996- ) (1996- )
Alan J. Noia 51 Chairman Chairman Chairman Chairman Chairman,
& CEO & CEO & CEO & CEO Pres.& CEO
(1996- ) (1996- ) (1996- ) (1996- ) (1996- )
Pres.& Dir. Dir. Dir. Dir. Dir.& V.P.
(1994- ) (1994- ) (1990-) (1994- ) (1994-96)
Previously, Previously,
COO Pres.
(1994-96) (1990-94)
Karl V. Pfirrmann 50 V.P. V.P. V.P.
(1996-8/98) (1996-8/98) (1996-8/98)
Jay S. Pifer 61 Sr. V.P. Pres.&Dir. Pres.&Dir. Pres.
(1996- ) 1995- ) (1995- ) (1990- )
& Dir.
(1992- )
Victoria V. Schaff(g) 54 V.P.
(1997- )
Peter J. Skrgic 57 Sr. V.P. V.P. V.P.& Dir. V.P. V.P.& Dir.
(1994- ) (1996- ) (1990- ) (1996- ) (1989- )
Previously, & Dir. & Dir.
V.P. (1990- ) (1990- )
(1989-94)
Robert R. Winter 55 V.P. V.P. V.P.
(1987- ) (1995- ) (1995- )
(a) All officers and directors are elected annually.
(b) Prior to his appointment as Vice President and Treasurer of
AE and Treasurer of MP, PE, WPP, and AGC, Mr. Binder was
Executive Director, Regulation and Rates for APSC (1997-1998);
General Manager, Industrial Marketing for APSC (1996-1997);
Director, Rates for APSC (1995-1996); and Assisant Director
Rates for APSC (1993-1995).
(c) Ms. Campbell retired effective December 1, 1998.
(d) Prior to his appointment as Vice President, Mr. Estel was
Director, Communications (12/95-4/96), Asst. Director
Communications (10/95-12/95), Director, Human Resources
(1/95-10/95) and Director, Personnel 12/90-1/95). Mr. Estel
resigned as a Vice President in October 1998.
45
(e) Prior to his appointment as Vice President Customer
Operations, Mr. Haney was Executive Director, Operating
Business Unit (8/98-10/98); Director, Operations Services
(5/96-8/98); Director, Transmission Projects (12/95-5/96);
Manager, Construction (APSC) (2/95-12/95); and Division Manager,
Monongahela (12/90-2/95).
(f) Prior to joining Allegheny, Mr. Morrell was V.P. - Regulatory
and Public Affairs, Jersey Central Power & Light Company (JCP&L)
(8/94-4/96); V.P. - Materials Services and Regulatory Affairs,
JCP&L (1/93-8/94); and V.P. and Treasurer, GPU, Inc. and
Subsidiaries (2/86-1/93).
(g) Prior to joining Allegheny, Ms. Schaff was a Federal
Affairs Representative with the Union Electric Company
(4/88-12/95).
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
AE
AYE is the trading symbol of the common stock of AE on the
New York, Chicago, and Pacific Stock Exchanges. The stock is also
traded on the Amsterdam (Netherlands) and other stock exchanges.
As of December 31, 1998, there were 48,869 holders of record of
AE's common stock.
The tables below show the dividends paid and the high and
low sale prices of the common stock for the periods indicated:
1998 1997
Dividend High Low Dividend High Low
1st Quarter 43 cents $33-9/16 $30-1/8 43 cents $31-5/8 $29-1/8
2nd Quarter 43 cents 34 $27-5/16 43 cents $30-1/8 $25-1/2
3rd Quarter 43 cents 31-15/16 $26-5/8 43 cents $30-3/8 $26-5/8
4th Quarter 43 cents 34-15/16 $29-1/2 43 cents $32-19/32 $27-1/4
The high and low prices through March 4, 1999 were $34-l/2
and $28-11/16. The last reported sale on that date was at $31-5/16.
Monongahela, Potomac Edison, and West Penn. The information
required by this Item is not applicable as all the common stock
of the Operating Subsidiaries is held by AE.
AGC. The information required by this Item is not
applicable as all the common stock of AGC is held by Monongahela,
Potomac Edison, and West Penn.
46
ITEM 6. SELECTED FINANCIAL DATA
Page No.
AE D- 1
Monongahela D- 4
Potomac Edison D- 6
West Penn D- 8
AGC D-10
Allegheny Energy, Inc.
Condensed Financial Statements
Monongahela The Potomac West Penn Allegheny
Power Edison Power Company Energy, Inc.
Year ended December 31, 1998 Company Company and Subsidiaries and Subsidiaries
(Thousands of Dollars)
Balance Sheets
Assets
Property, plant, and equipment:
At original cost* $2,007,876 $2,249,716 $3,365,784 $8,629,733
Accumulated depreciation (883,915) (926,840) (1,362,413) (3,395,603)
1,123,961 1,322,876 2,003,371 5,234,130
Investments in subsidiaries-excess of cost
over book equity at acquisition 15,077
Cash and temporary cash investments 1,835 1,805 4,523 17,559
Other current assets 155,776 221,150 245,704 537,524
Regulatory assets 154,882 66,792 475,776 704,506
Other 82,574 89,504 113,695 238,997
Total $1,519,028 $1,702,127 $2,843,069 $6,747,793
*Includes construction work in progress $ 43,657 $ 46,353 $ 75,725 $ 166,330
Capitalization and Liabilities
Common stock, other paid-in capital,
and retained earnings $ 570,188 $ 762,912 $ 732,161 $2,033,889
Preferred stock 74,000 16,378 79,708 170,086
Long-term debt and QUIDS 453,917 578,817 837,725 2,179,288
Short-term debt 49,000 65,066 258,837
Other current liabilities 77,561 119,209 235,785 436,375
Unamortized investment credit 16,155 19,592 42,630 125,396
Deferred income taxes 242,805 170,349 260,477 842,193
Regulatory liabilities 15,476 11,233 28,325 80,354
Adverse power purchase commitments 538,745 538,745
Other 19,926 23,637 22,447 82,630
Total $1,519,028 $1,702,127 $2,843,069 $6,747,793
Statements of Income
Operating revenues $ 645,122 $ 737,494 $1,078,727 $2,576,436
Operating expenses 533,636 598,698 912,195 2,136,929
Operating income 111,486 138,796 166,532 439,507
Other income and deductions 6,425 9,894 11,906 9,733
Income before interest charges, preferred
dividends, and extraordinary charge, net 117,911 148,690 178,438 449,240
Interest charges and preferred dividends 40,523 48,026 69,214 186,232
Balance for common stock before extraordinary
charge, net 77,388 100,664 109,224 263,008
Extraordinary charge, net (275,426) (275,426)
Balance for common stock $ 77,388 $ 100,664 $ (166,202) $ (12,418)
D-1
Allegheny Energy, Inc.
Consolidated Statistics
Year ended December 31 1998 1997 1996 1995 1994 1993 1988
Summary of Operations (Millions of Dollars)
Operating revenues $2,576.4 $2,369.5 $2,327.6 $2,315.2 $2,184.6 $2,050.6 $1,852.6
Operation expense 1,286.0 1,065.9 1,013.0 1,024.9 1,017.8 927.5 938.5
Maintenance 217.5 230.6 243. 249.5 241.9 231.2 166.6
Restructuring charges and asset
write-offs 103.9 23.4 9.2
Depreciation 270.4 265.7 263.2 256.3 223.9 210.4 165.7
Taxes other than income 194.6 187.0 185.4 184.7 183.1 178.8 127.5
Taxes on income 168.4 168.1 128.0 154.2 125.9 128.1 103.7
Allowance for funds used
during construction (5.0) (8.3) (5.9) (8.2) (19.6) (21.5) (4.3)
Interest charges and
preferred dividends 189.7 197.2 191.1 196.9 184.1 180.3 155.1
Other income and deductions (8.2) (18.0) (4.4) (6.2) (1.5) (5.3)
Consolidated income before extraordinary
charge and cumulative effect of
accounting change 263.0 281.3 210.0 239.7 219.8 215.8 205.1
Extraordinary charge, net<a> (275.4)
Cumulative effect of accounting change,
Net<b> 43.4
Consolidated net (loss) income $ (12.4) $ 281.3 $ 210.0 $ 239.7 $ 263.2 $215.8 $ 205.1
Common Stock Data
Shares outstanding (Thousands) 122,436 122,436 121,840 120,701 119,293 117,664 104,268
Average shares outstanding
(Thousands) 122,436 122,208 121,141 119,864 118,272 114,937 103,460
Earnings per average share:<d>
Consolidated income before extraordinary
charge and cumulative effect of
accounting change $ 2.15 $ 2.30 $ 1.73 $ 2.00 $ 1.86 $ 1.88 $ 1.98
Extraordinary charge, net<a> (2.25)
Cumulative effect of accounting
change<b> .37
Consolidated net (loss) income $ (.10) $ 2.30 $ 1.73 $ 2.00 $ 2.23 $ 1.88 $ 1.98
Dividends paid per share $ 1.72 $ 1.72 $ 1.69 $ 1.65 $ 1.64 $ 1.63 $ 1.51
Dividend payout ratio<e> 73.5% 74.7% 97.5% 82.5% 88.3% 86.9% 76.2%
Shareholders 48,869 53,389 58,677 63,280 66,818 63,396 71,748
Market price per share:
High $ 34-15/16 $ 32-19/32 $ 31-1/8 $ 29-1/4 $ 26-1/2 $ 28-7/16 $ 20-3/4
Low $ 26-5/8 $ 25-1/2 $ 28 21-1/2 $ 19-3/4 $ 23-7/16 $ 17-15/16
Close $ 34-1/2 $ 32-1/2 $ 30-3/8 $ 28-5/8 $ 21-3/4 $ 26-1/2 $ 18-11/16
Book value per share $ 16.61 $ 18.43 $ 17.80 $ 17.65 $ 17.26 $ 16.62 $ 14.62
Return on average common equity<e> 12.42% 12.63% 9.69% 11.35% 10.96% 11.40% 13.64%
Capitalization Data (Millions of Dollars)
Common stock $2,033.9 $2,256.9 $2,169.1 $2,129.9 $2,059.3 $1,955.8 $1,524.9
Preferred stock:
Not subject to mandatory
redemption 170.1 170.1 170.1 170.1 300.1 250.1 235.1
Subject to mandatory redemption 25.2 26.4 30.7
Long-term debt and QUIDS 2,179.3 2,193.1 2,397.1 2,273.2 2,178.5 2,008.1 1,586.0
Total capitalization $4,383.3 $4,620.1 $4,736.3 $4,573.2 $4,563.1 $4,240.4 $3,376.7
Capitalization ratios:
Common stock 46.4% 48.8% 45.8% 46.6% 45.1% 46.1% 45.1%
Preferred stock:
Not subject to mandatory
redemption 3.9 3.7 3.6 3.7 6.6 5.9 7.0
Subject to mandatory redemption .6 .6 .9
Long-term debt and QUIDS 49.7 47.5 50.6 49.7 47.7 47.4 47.0
Total Assets (Millions of Dollars) $6,747.8 $6,654.1 $6,618.5 $6,447.3 $6,362.2 $5,949.2 $4,334.4
Property Data (Millions of Dollars)
Gross property $8,629.7 $8,451.4 $8,206.2 $7,812.7 $7,586.8 $7,176.9 $5,493.1
Accumulated depreciation (3,395.6) (3,155.2) (2,910.0) (2,700.1) (2,529.4) (2,388.8) (1,680.2)
Net property $5,234.1 $5,296.2 $5,296.2 $5,112.6 $5,057.4 $4,788.1 $3,812.9
Gross additions during year
-utility $ 229.4 $ 284.7 $ 289.5 $ 319.1 $ 508.3 $ 574.0 $ 199.5
-nonutility $ 1.8 $ 1.4 $ 178.5
Ratio of provisions for depreciation
To depreciable property 3.28% 3.34% 3.47% 3.50% 3.32% 3.37% 3.23%
D-2
Allegheny Energy, Inc.
Consolidated Statistics (continued)
Year ended December 31 1998 1997 1996 1995 1994 1993 1988
Revenues (Millions of Dollars)
Residential $ 880.6 $ 892.9 $ 932.2 $ 927.0 $ 863.7 $ 818.4 $ 635.1
Commercial 501.4 490.5 492.7 493.7 459.3 430.2 328.8
Industrial 753.5 748.1 752.9 770.2 728.0 673.4 564.8
Wholesale and street lighting 69.0 65.1 66.6 59.6 58.7 55.0 45.3
Revenues from regular
utility customers 2,204.5 2,196.6 2,244.4 2,250.5 2,109.7 1,977.0 1,574.0
Other non-gWh 9.9 6.4 7.7 6.5 7.1 5.3 10.4
Bulk power 69.8 39.6 22.4 13.0 29.0 28.5 238.4
Transmission services 45.2 41.1 52.4 45.2 38.8 39.8 29.8
Total utility revenues $2,329.4 $2,283.7 $2,326.9 $2,315.2 $2,184.6 $2,050.6 $1,852.6
Total nonutility revenues $ 247.0 $ 85.8 $ .7
Sales Volumes-gWh
Residential 12,939 12,832 13,328 13,003 12,630 12,514 10,772
Commercial 8,626 8,176 8,132 7,963 7,607 7,440 6,260
Industrial 19,675 19,040 18,568 18,457 17,708 16,967 16,005
Wholesale and street lighting 1,409 1,422 1,456 1,304 1,275 1,240 1,088
Regular utility transactions 42,649 41,470 41,484 40,727 39,220 38,161 34,125
Bulk power 3,037 1,667 966 507 1,086 1,145 9,604
Transmission services 7,345f 12,367 17,402 14,586 9,405 11,864 13,084
Total utility transactions 53,031 55,504 59,852 55,820 49,711 51,170 56,813
Total nonutility transactions 8,278 3,734 109
Output and Delivery-gWh
Steam generation 44,323 43,463 40,067 39,174 38,959 38,247 42,955
Hydro and pumped-storage generation 1,326 1,171 1,348 1,234 1,390 1,233 1,644
Pumped-storage input (1,498) (1,298) (1,405) (1,390) (1,564) (1,385) (1,904)
Purchased power 11,505 6,485 5,518 5,021 4,136 4,002 4,059
Transmission services 7,777 12,367 17,402 14,586 9,405 11,864 13,084
Losses and system uses (2,124) (2,950) (2,969) (2,805) (2,615) (2,791) (3,025)
Total transactions as above 61,309 59,238 59,961 55,820 49,711 51,170 56,813
Utility Statistics
Year ended December 31 1998 1997 1996 1995 1994 1993 1988
Energy Supply
Generating capability-MW
Utility-owned 8,121 8,071 8,070 8,070 8,070 7,991 7,906
Nonutility contracts<g> 299 299 299 299 299 292 160
Maximum hour peak-MW 7,314 7,423 7,500 7,280 7,153 6,678 6,045
Load factor 69.1% 68.3% 67.5% 68.3% 66.8% 70.0% 70.0%
Heat rate-Btu's per kWh 9,939 9,936 9,910 9,970 9,927 10,020 9,938
Fuel costs-cents per million Btu's 128.92 130.05 129.22 130.20 141.50 142.12 135.66
Customers (Thousands)
Residential 1,236.9 1,224.9 1,213.7 1,204.4 1,189.7 1,176.6 1,102.3
Commercial 154.7 151.5 148.5 146.0 143.0 140.1 125.6
Industrial 25.5 25.2 25.0 24.6 24.2 23.8 21.8
Other 1.3 1.3 1.3 1.3 1.3 1.2 1.2
Total customers 1,418.4 1,402.9 1,388.5 1,376.3 1,358.2 1,341.7 1,250.9
Average Annual Use-kWh per customer
Residential-Allegheny Energy 10,486 10,521 11,042 10,865 10,682 10,715 9,850
Residential-National 9,952h 9,552 9,713 9,583 9,378 9,394 9,082
All retail service-Allegheny
Energy 28,174 28,647 29,085 28,908 28,205 27,800 26,715
Average Rate-cents per kWh
Residential-Allegheny Energy 6.90 6.96 6.99 7.13 6.84 6.54 5.90
Residential-National 8.77h 8.94 8.86 8.87 8.83 8.73 7.78
All retail service-Allegheny Energy 5.32 5.36 5.46 5.58 5.43 5.23 4.65
a Write-off in connection with deregulation proceedings in Pennsylvania.
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, and the
extraordinary charge, net and Pennsylvania restructuring activities
in 1998. Includes the effect of internal restructuring in 1995 and 1996.
f Excludes 432 gWh delivered to customers participating in the Pennsylvania
pilot program that are included in regular utility transactions sales
volumes.
g Capability available through contractual arrangements with nonutility
generators.
h Preliminary
D-3
Monongahela Power Company
QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)
Quarter Ended
1998 1997
Dec. Sept. June March Dec. Sept. June March
Electric operating
revenues ............. $155,712 $177,364 $153,774 $158,272 $163,190 $158,240 $144,078 $162,803
Operating income........ 28,154 31,887 24,087 27,358 26,701 28,493 23,701 30,480
Net income.............. 21,143 25,244 16,611 19,427 18,342 23,457 16,174 22,556
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
1998 1997 1996 1995 1994 1993
Electric operating revenues:
Residential.......................... $200,896 $199,931 $206,033 $209,065 $190,861 $185,141
Commercial........................... 126,464 118,825 121,631 124,457 116,201 110,762
Industrial........................... 208,613 196,716 200,970 212,427 202,181 187,669
Wholesale and street lighting........ 7,656 7,600 7,513 7,255 7,142 6,663
Revenues from regular customers.... 543,629 523,072 536,147 553,204 516,385 490,235
Affiliated........................... 77,314 83,600 74,825 73,216 79,674 61,677
Other non-kWh........................ 4,426 4,379 4,136 3,722 3,535 3,233
Bulk power........................... 8,509 7,299 4,772 2,749 7,681 8,382
Transmission services................ 11,244 9,961 12,591 10,589 9,172 9,754
Total revenues..................... 645,122 628,311 632,471 643,480 616,447 573,281
Operation expense...................... 313,795 305,487 310,480 330,740 330,909 295,464
Maintenance............................ 67,033 70,561 74,735 73,041 69,389 67,770
Internal restructuring charges
and asset write-off.................. 24,299 5,493
Depreciation........................... 58,610 56,593 55,490 57,864 57,952 56,056
Taxes other than income................ 44,742 38,776 40,418 38,551 40,404 34,076
Taxes on income........................ 49,456 47,519 34,496 41,834 30,650 33,612
Allowance for funds used
during construction.................. (1,043) (1,386) (672) (1,393) (2,946) (5,780)
Interest charges....................... 36,153 38,730 38,604 39,872 38,156 37,588
Other income, net...................... (6,049) (8,498) (6,831) (9,235) (8,003) (7,203)
Income before cumulative effect
of accounting change................. 82,425 80,529 61,452 66,713 59,936 61,698
Cumulative effect of accounting
change, net (a)...................... 7,945
Net income............................. $ 82,425 $ 80,529 $ 61,452 $ 66,713 $ 67,881 $ 61,698
Return on average common equity (b).... 13.62% 13.99% 11.00% 11.92% 10.66% 11.83%
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994 and
includes the effect of internal restructuring in 1995 and 1996.
D-4
Monongahela Power Company
FINANCIAL AND OPERATING STATISTICS
1998 1997 1996 1995 1994 1993
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.......................... $2,007,876 $1,950,478 $1,879,622 $1,821,613 $1,763,533 $1,684,322
Accumulated depreciation....... (883,915) (840,525) (790,649) (747,013) (701,271) (664,947)
Net.......................... $1,123,961 $1,109,953 $1,088,973 $1,074,600 $1,062,262 $1,019,375
GROSS ADDITIONS TO PROPERTY
(Thousands):..................... $ 72,795 $ 78,139 $ 72,577 $ 75,458 $ 103,975 $ 140,748
TOTAL ASSETS at Dec. 31
(Thousands)...................... $1,519,028 $1,493,254 $1,486,755 $1,480,591 $1,476,483 $1,407,453
CAPITALIZATION at Dec. 31
(Thousands):
Common stock................... $ 570,188 $ 540,930 $ 512,212 $ 505,752 $ 495,693 $ 483,030
Preferred stock................ 74,000 74,000 74,000 74,000 114,000 64,000
Long-term debt and QUIDS....... 453,917 455,088 474,841 489,995 470,131 460,129
$1,098,105 $1,070,018 $1,061,053 $1,069,747 $1,079,824 $1,007,159
Ratios:
Common stock................... 51.9% 50.6% 48.3% 47.3% 45.9% 48.0%
Preferred stock................ 6.8 6.9 7.0 6.9 10.6 6.3
Long-term debt and QUIDS....... 41.3 42.5 44.7 45.8 43.5 45.7
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31:
Company-owned.................. 2,326,300 2,326,300 2,326,300 2,326,300 2,326,300 2,325,300
Nonutility contracts (a)....... 161,000 161,000 161,000 161,000 161,000 159,000
KILOWATT-HOURS (Thousands):
Sales Volumes:
Residential.................... 2,757,067 2,764,630 2,815,414 2,807,135 2,674,664 2,689,830
Commercial..................... 2,102,604 1,987,147 2,007,116 1,967,473 1,846,791 1,825,127
Industrial..................... 5,510,925 5,224,364 5,024,257 5,114,126 4,942,388 4,656,921
Wholesale and street lighting.. 142,797 142,827 142,198 138,456 134,351 134,042
Sales to regular customers... 10,513,393 10,118,968 9,988,985 10,027,190 9,598,194 9,305,920
Affiliated..................... 1,950,803 2,080,542 1,694,722 1,596,081 1,791,099 1,431,519
Bulk power..................... 301,656 249,505 196,843 105,126 285,048 338,476
Transmission services.......... 1,932,160 3,007,439 4,218,150 3,497,216 2,278,111 2,938,187
Total sales volumes.......... 14,698,012 15,456,454 16,098,700 15,225,613 13,952,452 14,014,102
Output and Delivery:
Steam generation............... 11,251,721 10,936,469 10,678,491 10,620,003 10,743,934 10,194,794
Pumped-storage generation...... 288,266 241,958 263,640 257,284 290,586 263,329
Pumped-storage input........... (370,822) (310,565) (337,451) (330,915) (373,116) (337,737)
Purchased power................ 2,283,055 2,294,059 2,040,136 1,903,644 1,685,938 1,637,677
Transmission services.......... 1,932,160 3,007,439 4,218,150 3,497,216 2,278,111 2,938,187
Losses and system uses......... (686,368) (712,906) (764,266) (721,619) (673,001) (682,148)
Total transactions as above.. 14,698,012 15,456,454 16,098,700 15,225,613 13,952,452 14,014,102
CUSTOMERS at Dec. 31:
Residential...................... 309,760 307,920 305,579 303,568 300,465 297,865
Commercial....................... 37,929 37,168 36,323 35,793 35,268 34,626
Industrial....................... 7,992 7,996 8,019 8,085 8,029 8,014
Other............................ 218 199 182 170 171 170
Total customers................ 355,899 353,283 350,103 347,616 343,933 340,675
RESIDENTIAL SERVICE:
Average use-
kWh per customer............... 8,938 9,023 9,256 9,306 8,957 9,093
Average revenue-
dollars per customer........... 651.29 652.53 677.37 693.11 639.16 625.87
Average rate-
cents per kWh.................. 7.29 7.23 7.32 7.45 7.14 6.88
(a) Capability available through contractual arrangements with nonutility
generators.
D-5
The Potomac Edison Company
QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)
Quarter Ended
1998 1997
Dec. Sept. June March Dec. Sept. June March
Electric operating
revenues.............. $177,744 $190,533 $177,519 $191,698 $176,222 $175,464 $164,867 $192,228
Operating income........ 34,458 36,680 30,036 37,622 34,428 30,388 26,894 37,062
Net income.............. 25,757 27,299 20,504 27,922 24,360 25,296 18,376 27,723
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
1998 1997 1996 1995 1994 1993
Electric operating revenues:
Residential.......................... $309,058 $299,876 $324,120 $316,714 $296,090 $274,358
Commercial........................... 156,973 148,287 146,432 145,096 135,937 124,667
Industrial........................... 206,638 198,174 196,813 200,890 195,089 175,902
Wholesale and street lighting........ 27,667 30,443 32,907 27,028 26,109 24,351
Revenues from regular customers.... 700,336 676,780 700,272 689,728 653,225 599,278
Affiliated........................... 9,401 9,687 2,399 2,525 2,716 3,041
Other non-kWh........................ 1,358 (1,273) (405) (961) (4,647) 1,352
Bulk power........................... 11,690 10,035 7,577 4,566 8,932 8,585
Transmission services................ 14,709 13,552 16,917 14,811 12,675 12,423
Total.............................. 737,494 708,781 726,760 710,669 672,901 624,679
Operation expense...................... 369,998 359,350 373,133 374,731 362,167 325,239
Maintenance............................ 52,186 56,815 62,248 60,052 58,624 64,376
Internal restructuring charges
and asset write-off.................. 26,094 6,847
Depreciation........................... 74,344 71,763 71,254 68,826 59,989 56,449
Taxes other than income................ 49,567 47,585 45,809 47,629 46,740 46,813
Taxes on income........................ 52,603 44,496 34,132 36,936 33,126 30,086
Allowance for funds used
during construction.................. (1,576) (2,830) (2,491) (1,752) (5,874) (7,134)
Interest charges....................... 48,187 49,823 50,197 51,179 46,456 43,802
Other income, net...................... (9,297) (13,976) (11,791) (12,044) (10,310) (8,419)
Income before cumulative effect
of accounting change................. 101,482 95,755 78,175 78,265 81,983 73,467
Cumulative effect of accounting
change, net (a)...................... 16,471
Net income............................. $101,482 $ 95,755 $ 78,175 $ 78,265 $ 98,454 $ 73,467
Return on average common equity (b).... 13.90% 13.44% 11.42% 11.34% 11.86% 11.63%
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994 and
includes the effect of internal restructuring in 1995 and 1996.
D-6
The Potomac Edison Company
FINANCIAL AND OPERATING STATISTICS
1998 1997 1996 1995 1994 1993
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.................................. $2,249,716 $2,196,262 $2,124,956 $2,050,835 $1,978,396 $1,857,961
Accumulated depreciation............... (926,840) (859,076) (791,257) (729,653) (673,853) (632,269)
Net.................................. $1,322,876 $1,337,186 $1,333,699 $1,321,182 $1,304,543 $1,225,692
GROSS ADDITIONS TO PROPERTY
(Thousands).............................. $ 60,525 $ 78,298 $ 86,256 $ 92,240 $ 142,826 $ 179,433
TOTAL ASSETS at Dec. 31
(Thousands).............................. $1,702,127 $1,660,647 $1,677,886 $1,654,444 $1,629,535 $1,519,763
CAPITALIZATION at Dec. 31:
(Thousands):
Common stock........................... $ 762,912 $ 689,781 $ 678,116 $ 667,242 $ 658,146 $ 626,467
Preferred stock:
Not subject to mandatory redemption.. 16,378 16,378 16,378 16,378 36,378 36,378
Subject to mandatory redemption...... 25,200 26,400
Long-term debt and QUIDS............... 578,817 627,012 628,431 628,854 604,749 517,910
$1,358,107 $1,333,171 $1,322,925 $1,312,474 $1,324,473 $1,207,155
Ratios:
Common stock........................... 56.2% 51.8% 51.3% 50.8% 49.7% 51.9%
Preferred stock:
Not subject to mandatory redemption.. 1.2 1.2 1.2 1.3 2.7 3.0
Subject to mandatory redemption...... 1.9 2.2
Long-term debt and QUIDS............... 42.6 47.0 47.5 47.9 45.7 42.9
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31 2,073,292 2,073,292 2,072,292 2,072,292 2,072,292 2,076,592
KILOWATT-HOURS (Thousands):
Sales Volumes:
Residential............................ 4,401,238 4,290,117 4,599,758 4,377,416 4,214,997 4,144,958
Commercial............................. 2,498,546 2,331,789 2,288,229 2,213,052 2,136,081 2,091,930
Industrial............................. 5,922,274 5,593,722 5,567,088 5,485,220 5,339,737 5,194,909
Wholesale and street lighting.......... 657,357 666,383 724,011 603,572 591,799 582,259
Sales to regular customers........... 13,479,415 12,882,011 13,179,086 12,679,260 12,282,614 12,014,056
Affiliated............................. 498,069 591,876 47,781 52,967 61,815 67,377
Bulk power............................. 402,635 369,732 315,808 173,110 331,832 343,837
Transmission services.................. 2,470,365 4,044,837 5,617,912 4,740,010 3,031,339 3,693,330
Total sales volumes.................. 16,850,484 17,888,456 19,160,587 17,645,347 15,707,600 16,118,600
Output and Delivery:
Steam generation....................... 11,254,505 11,002,533 10,762,678 10,410,118 10,464,607 10,103,411
Hydro and pumped-storage generation.... 416,983 370,026 401,998 395,315 426,550 368,834
Pumped-storage input................... (486,823) (426,087) (455,142) (452,151) (506,213) (433,885)
Purchased power........................ 4,190,098 3,934,815 3,639,519 3,318,302 3,033,744 3,174,838
Transmission services.................. 2,470,365 4,044,837 5,617,912 4,740,010 3,031,339 3,693,330
Losses and system uses................. (994,644) (1,037,668) (806,378) (766,247) (742,427) (787,928)
Total transactions as above.......... 16,850,484 17,888,456 19,160,587 17,645,347 15,707,600 16,118,600
CUSTOMERS at Dec. 31:
Residential.............................. 339,584 333,224 327,344 321,813 315,309 309,096
Commercial............................... 44,828 43,794 42,670 41,759 40,927 40,173
Industrial............................... 5,122 5,010 4,887 4,733 4,595 4,509
Other.................................... 641 598 571 543 524 510
Total customers........................ 390,175 382,626 375,472 368,848 361,355 354,288
RESIDENTIAL SERVICE:
Average use-
kWh per customer....................... 13,093 13,003 14,179 13,729 13,506 13,562
Average revenue-
dollars per customer................... 919.42 908.87 999.10 993.35 948.76 897.70
Average rate-
cents per kWh.......................... 7.02 6.99 7.05 7.24 7.02 6.62
D-7
West Penn Power Company
and Subsidiaries
QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)
Quarter Ended
1998 1997
Dec. Sept. June March Dec. Sept. June March
Electric operating
revenues................ $246,729 $288,272 $263,023 $280,703 $280,155 $266,746 $252,731 $282,530
Operating income.......... 17,038 56,248 40,627 52,619 55,850 43,865 35,661 47,271
Consolidated net (loss)
income.................. (5,504) 42,835 (239,138) 39,001 41,468 34,333 21,963 36,901
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
1998 1997 1996 1995 1994 1993
Electric operating revenues:
Residential.......................... $ 370,636 $ 393,036 $ 402,083 $ 401,186 $ 376,776 $ 358,900
Commercial........................... 217,954 223,347 224,663 224,144 207,165 194,773
Industrial........................... 338,254 352,730 355,120 356,937 330,739 309,847
Wholesale and street lighting........ 33,650 27,051 26,194 25,330 25,425 23,945
Revenues from regular customers.... 960,494 996,164 1,008,060 1,007,597 940,105 887,465
Affiliated........................... 45,180 39,031 44,231 44,293 37,915 40,169
Other non-kWh........................ 4,152 6,377 3,903 3,765 3,980 3,692
Bulk power........................... 49,605 22,188 10,012 5,687 12,339 11,547
Transmission services................ 19,296 18,402 22,918 19,751 16,998 17,625
Total.............................. 1,078,727 1,082,162 1,089,124 1,081,093 1,011,337 960,498
Operation expense...................... 552,514 524,051 531,522 523,279 531,059 500,790
Maintenance............................ 91,724 98,252 104,211 114,489 111,841 96,706
Internal restructuring charges
and asset write-offs................. 53,343 11,099 8,919
Depreciation........................... 114,709 113,793 119,066 112,334 88,935 80,872
Taxes other than income................ 88,722 90,140 90,132 89,694 87,224 89,249
Taxes on income........................ 64,526 73,279 47,455 61,745 46,645 51,529
Allowance for funds used
during construction.................. (2,403) (4,085) (2,723) (5,041) (10,777) (8,566)
Interest charges....................... 67,640 69,629 71,072 67,902 60,274 60,585
Other income, net...................... (11,325) (17,562) (13,439) (12,287) (13,798) (12,728)
Consolidated income before
extraordinary charge and cumulative
effect of accounting change.......... 112,620 134,665 88,485 117,879 101,015 102,061
Extraordinary charge, net (a).......... (275,426)
Cumulative effect of accounting
change, net (b)...................... 19,031
Consolidated net (loss) income......... $ (162,806) $ 134,665 $ 88,485 $ 117,879 $ 120,046 $ 102,061
Return on average common equity (c).... 13.12% 13.70% 8.72% 11.46% 9.94% 11.49%
(a) Write-off in connection with Pennsylvania deregulation proceedings.
(b) To record unbilled revenues, net of income taxes.
(c) Excludes the cumulative effect of the accounting change in 1994, and the
extraordinary charge, net and Pennsylvania restructuring activities in
1998. Includes the effect of internal restructuring in 1995 and 1996.
D-8
West Penn Power Company
and Subsidiaries
FINANCIAL AND OPERATING STATISTICS
1998 1997 1996 1995 1994 1993
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross................................. $3,365,784 $3,293,039 $3,182,208 $3,097,522 $3,013,777 $2,803,811
Accumulated depreciation.............. (1,362,413) (1,254,900) (1,152,383) (1,063,399) (1,009,565) (962,623)
Net................................. $2,003,371 $2,038,139 $2,029,825 $2,034,123 $2,004,212 $1,841,188
GROSS ADDITIONS TO PROPERTY
(Thousands)............................. $ 95,975 $ 128,054 $ 130,606 $ 149,122 $ 260,366 $ 251,017
TOTAL ASSETS at Dec. 31
(Thousands)............................. $2,843,069 $2,747,159 $2,699,737 $2,771,164 $2,731,858 $2,544,763
CAPITALIZATION at Dec. 31:
(Thousands):
Common stock.......................... $ 732,161 $ 997,027 $ 962,752 $ 973,188 $ 955,482 $ 893,969
Preferred stock....................... 79,708 79,708 79,708 79,708 149,708 149,708
Long-term debt and QUIDS.............. 837,725 802,319 905,243 904,669 836,426 782,369
$1,649,594 $1,879,054 $1,947,703 $1,957,565 $1,941,616 $1,826,046
Ratios:
Common stock.......................... 44.4% 53.1% 49.4% 49.7% 49.2% 49.0%
Preferred stock....................... 4.8 4.2 4.1 4.1 7.7 8.2
Long-term debt and QUIDS............. 50.8 42.7 46.5 46.2 43.1 42.8
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31:
Company-owned......................... 3,721,408 3,671,408 3,671,408 3,671,408 3,671,408 3,589,408
Nonutility contracts (a).............. 138,000 138,000 138,000 138,000 138,000 133,000
KILOWATT-HOURS (Thousands):
Sales Volumes:
Residential........................... 5,778,155 5,756,594 5,913,412 5,818,838 5,740,028 5,679,746
Commercial............................ 4,023,523 3,833,178 3,835,831 3,782,250 3,624,117 3,522,566
Industrial............................ 8,237,627 8,046,166 7,974,265 7,857,689 7,426,267 7,114,765
Wholesale and street lighting......... 617,841 611,105 591,122 561,893 548,296 523,233
Regular customer transactions....... 18,657,146 18,247,043 18,314,630 18,020,670 17,338,708 16,840,310
Affiliated............................ 1,974,497 1,789,476 1,068,712 1,059,852 982,557 1,297,956
Bulk power............................ 2,332,825 1,046,905 453,028 227,893 471,050 462,286
Transmission services................. 2,942,868(b) 5,392,916 7,567,153 6,348,926 4,093,693 5,233,229
Total transactions.................. 25,907,336 26,476,340 27,403,523 25,657,341 22,886,008 23,833,781
Output and Delivery:
Steam generation...................... 20,053,422 19,523,537 18,578,677 18,143,822 17,750,267 17,949,335
Hydro and pumped-storage generation... 620,496 559,241 682,747 581,353 673,195 600,497
Pumped-storage input.................. (640,242) (561,135) (612,877) (606,953) (684,715) (613,290)
Purchased power....................... 2,890,986 2,968,258 2,583,166 2,507,196 2,253,701 1,985,240
Transmission services................. 3,850,394 5,392,916 7,567,153 6,348,926 4,093,693 5,233,229
Losses and system uses................ (867,720) (1,406,477) (1,395,343) (1,317,003) (1,200,133) (1,321,230)
Total transactions as above......... 25,907,336 26,476,340 27,403,523 25,657,341 22,886,008 23,833,781
CUSTOMERS at Dec. 31:
Residential............................. 587,503 583,745 580,816 578,983 573,963 569,601
Commercial.............................. 71,920 70,559 69,457 68,500 66,842 65,337
Industrial.............................. 12,389 12,142 12,051 11,801 11,563 11,218
Other................................... 608 629 607 598 586 576
Total customers....................... 672,420 667,075 662,931 659,882 652,954 646,732
RESIDENTIAL SERVICE:
Average use-
kWh per customer...................... 9,775 9,903 10,223 10,096 10,041 10,025
Average revenue-
dollars per customer.................. 644.98 674.73 695.08 696.06 659.07 633.48
Average rate-
cents per kWh......................... 6.60 6.81 6.80 6.89 6.56 6.32
(a) Capability available through contractual arrangements with nonutility
generators.
(b) Excludes 907,526 kWh (in thousands) delivered to customers
participating in the Pennsylvania pilot program that are
included in regular customer transactions sales volumes.
D-9
Allegheny Generating Company
QUARTERLY FINANCIAL INFORMATION
(Thousands of Dollars)
Quarter Ended
1998 1997
Dec. Sept. June March Dec. Sept. June March
Electric operating
revenues.................. $17,783 $18,303 $19,126 $18,604 $16,170 $19,664 $20,408 $20,216
Operating income............ 8,699 9,297 9,258 9,400 7,664 10,230 10,311 10,328
Net income.................. 5,230 5,625 5,961 5,937 4,109 15,396 6,395 6,368
D-10
Allegheny Generating Company
STATISTICS
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
1998 1997 1996 1995 1994 1993
Electric operating revenues............ $ 73,816 $ 76,458 $ 83,402 $ 86,970 $ 91,022 $ 90,606
Operation and maintenance expense...... 4,592 4,877 5,165 5,740 6,695 6,609
Depreciation........................... 16,949 17,000 17,160 17,018 16,852 16,899
Taxes other than income taxes.......... 4,662 4,835 4,801 5,091 5,223 5,347
Federal income taxes................... 10,959 11,213 13,297 13,552 14,737 13,262
Interest charges....................... 13,987 15,391 16,193 18,361 17,809 21,635
Other income, net...................... (86) (9,126) (3) (16) (11) (328)
Net Income........................... $ 22,753 $ 32,268 $ 26,789 $ 27,224 $ 29,717 $ 27,182
Return on average common equity........ 12.57% 15.98% 12.58% 12.46% 13.14% 11.72%
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.............................. $828,806 $828,658* $837,050 $836,894* $824,714 $824,904
Accumulated depreciation........... (210,198) (193,173) (176,178) (159,037) (143,965) (128,375)
Net.............................. $618,608 $635,485 $660,872 $677,857 $680,749 $696,529
GROSS ADDITIONS TO PROPERTY
(Thousands).......................... $ 69 $ 444 $ 178 $ 14,165* $ 1,065 $ 2,729
TOTAL ASSETS
at Dec. 31 (Thousands)............... $639,458 $663,920 $692,408 $710,287 $714,236 $735,929
CAPITALIZATION AND SHORT-TERM DEBT
at Dec. 31:
Amount (in thousands):
Common stock..................... $165,276 $199,523 $202,955 $214,153 $222,729 $228,512
Long-term and short-term debt.... 215,579 208,735 239,234 256,084 268,165 287,196
$380,855 $408,258 $442,189 $470,237 $490,894 $515,708
Ratios:
Common stock....................... 43.4% 48.9% 45.9% 45.5% 45.4% 44.3%
Long-term and short-term debt...... 56.6 51.1 54.1 54.5 54.6 55.7
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
KILOWATT-HOURS (Thousands):
Pumping energy supplied by Parents... 1,497,887 1,297,787 1,405,470 1,390,019 1,564,044 1,384,912
Pumped-storage generation............ 1,164,325 1,011,366 1,098,278 1,081,112 1,218,446 1,079,985
*Reflects a balance sheet reclassification in 1995 of $12 million from
deferred charges to plant for a prior tax payment, and a related
settlement of $8.8 million in 1997 that was recorded as a reduction to plant.
D-11
47
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Page No.
AE M- 1
Monongahela M-21
Potomac Edison M-36
West Penn M-51
AGC M-67
Allegheny Energy, Inc.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Factors That May Affect Future Results
This management's discussion and analysis of financial condition and
results of operations contains forecast information items that are "forward-
looking statements" as defined in the Private Securities Litigation Reform
Act of 1995. These include statements with respect to deregulation
activities and movements toward competition in states served by the
Company, the merger with DQE, Inc. (DQE), parent company of Duquesne Light
Company in Pittsburgh, Pa., and results of operations. All such forward-
looking information is necessarily only estimated. There can be no
assurance that actual results will not materially differ from expectations.
Actual results have varied materially and unpredictably from past
expectations.
Factors that could cause actual results to differ materially include,
among other matters, electric utility restructuring, including the ongoing
state and federal activities; potential Year 2000 operation problems;
developments in the legislative, regulatory, and competitive environments
in which the Company operates, including regulatory proceedings affecting
rates charged by the Company's subsidiaries; environmental, legislative,
and regulatory changes; future economic conditions; earnings retention and
dividend payout policies; developments relating to the proposed merger with
DQE, including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs such as
significant volatility in the market price of wholesale power, unscheduled
maintenance or repair requirements, weather, and compliance with laws and
regulations.
Significant Events in 1998, 1997, and 1996
Pennsylvania Deregulation
On November 19, 1998, the Pennsylvania Public Utility Commission
(Pennsylvania PUC) approved a settlement agreement between West Penn Power
Company (West Penn), the Company's Pennsylvania electric utility
subsidiary, and intervenors in 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 that
under the provisions of Statement of Financial Accounting Standards No.
101, "Accounting for the Discontinuation of Application of FASB Statement
No. 71," an extraordinary charge of $466.9 million ($275.4 million after
taxes) was required to reflect a write-off of certain disallowances. In
addition, charges of $40.3 million ($23.7 million after taxes) related to
the West Penn revenue refund and energy program payments were also
recorded.
Under the terms of the 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 can do so beginning in
January 2000. They can also choose 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.
M-1
Allegheny Energy, Inc.
Merger with DQE
See page 38 and also Note D to the consolidated financial statements
for more information about the merger.
Maryland Settlement and Deregulation
The Company's Maryland subsidiary, The Potomac Edison Company (Potomac
Edison), reached a settlement agreement with various parties on the Office
of People's Counsel's
petition for a reduction in Potomac Edison's Maryland rates. Further
information on the settlement agreement is provided under Sales and
Revenues starting on page 31.
On July 1, 1998, Potomac Edison filed testimony in Maryland's
investigation into transition costs, price protection, and unbundled rates.
See Electric Energy Competition on page 38 for more information regarding
the restructuring in Maryland.
Nonutility Operations
In 1996, the Company's nonutility subsidiary, AYP Capital, Inc. (AYP
Capital) expanded its nonutility operations by forming AYP Energy, Inc.
(AYP Energy) and Allegheny Communications Connect, Inc. (ACC). ACC was
formed to develop opportunities in the deregulated telecommunications
market. AYP Energy is a bulk power marketer. In October 1996, AYP Energy
purchased for about $170 million a 50%, 276-megawatt (MW), interest in Unit
No. 1 of the Fort Martin coal-fired power station in West Virginia. Two of
the Company's utility subsidiaries own the other 50%.
In 1997, AYP Capital formed Allegheny Energy Solutions, Inc.
(Allegheny Energy Solutions). Allegheny Energy Solutions was formed to
market electric energy to retail customers in deregulated markets. Because
of organizational efficiencies available in an alternate corporate
structure, Allegheny Energy Solutions no longer competes in deregulated
energy markets as of January 1999. Rather, that role has been assumed by
the Energy Supply Division of the Supply Business of West Penn. With
customer choice now under way in Pennsylvania, the Energy Supply Division
attracted about 1,300 MW of load for 1999. West Penn lost only about 400 MW
of load in this competitive environment, giving it a net gain of about 900
MW.
AYP Capital, in its own name, also markets various services related to
the electric industry and has investments in two limited energy
partnerships.
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
M-2
Allegheny Energy, Inc.
prices well above current market price estimates. In 1996, West
Penn and the developers of a proposed Shannopin PURPA project reached an
agreement to terminate that project at a buyout price of $31 million. The
Shannopin buyout will reduce West Penn's costs approximately $665 million
over 30 years by eliminating the need to buy the uneconomic power.
Internal Restructuring
In 1994, the Company and its subsidiaries initiated an internal
restructuring process to consolidate and re-engineer their utility
operations to meet the competitive challenges of the changing electric
utility industry. As a result of this process, the subsidiaries reduced
employment by about 1,000 employees through a voluntary separation plan,
attrition and layoffs, and changed processes to obtain efficiencies to
reduce operating and maintenance costs. This process resulted in internal
restructuring charges and an asset write-off in 1996 as described in Note E
to the consolidated financial statements.
Review of Operations
Earnings Summary
Basic and Diluted Earnings
Earnings Per Average Share
(Millions of Dollars Except Per Share Data) 1998 1997 1996 1998 1997 1996
Operations Before Restructuring Activities:
Utility $ 307.0 $295.7 $275.5 $ 2.51 $2.42 $2.27
Nonutility (20.3) (14.4) (2.9) (.17) (.12) (.02)
Consolidated Income Before Restructuring
Activities 286.7 281.3 272.6 2.34 2.30 2.25
Costs Related to Restructuring Activities* (23.7) (62.6) (.19) (.52)
Extraordinary Charge, Net (Notes B and C
to Consolidated Financial Statements) (275.4) (2.25)
Consolidated Net (Loss) Income $ (12.4) $281.3 $210.0 $ (.10) $2.30 $1.73
*Pennsylvania deregulation settlement costs in 1998 and internal
restructuring costs in 1996.
The increase in 1998 earnings from utility operations, before costs
related to Pennsylvania restructuring and settlement activities, resulted
from increased kilowatt-hour (kWh) sales to commercial and industrial
customers and from reduced power station operation and maintenance (O&M)
spending. The 1998 costs from restructuring activities and the
extraordinary charge are related to Pennsylvania deregulation and the
Pennsylvania restructuring Order. These costs are described in Notes B and
C to the consolidated financial statements. The 1996 restructuring costs
resulted from internal restructuring initiated in 1994 which is described
in Note E to the consolidated financial statements and Internal
Restructuring on page 30. The increase in 1997 earnings from utility
operations resulted primarily from reductions in O&M expenses from the
internal restructuring process and additional actions taken during the year
to achieve further O&M reductions in response to significant decreases in
residential kWh sales caused primarily by mild weather.
M-3
Allegheny Energy, Inc.
The increase in losses from nonutility operations in 1998 resulted
primarily from AYP Energy sales commitments for energy in excess of owned
generating capacity which required settlement by open market purchases
during a period of high wholesale prices. Other marketing activities served
to mitigate these losses as described on page 33. After purchasing a 50%
ownership interest in Unit No. 1 of Fort Martin power station in October
1996, AYP Energy completed its first full year of operation in 1997.
Because of considerable excess generating capacity pursuing limited demand
in 1997 and 1998, AYP Energy's operating margins were insufficient to cover
all of its fixed costs. This condition may continue until further deregulation
activities expand market opportunities and competing excess capacity is
absorbed by demand growth. Another item contributing to the nonutility
losses was Allegheny Energy Solutions' net losses of $1.7 million and $1.4
million in 1998 and 1997, respectively, for its participation in the
Pennsylvania pilot program (see Note B to the consolidated financial
statements for more information about the pilot program)
Sales and Revenues
Total operating revenues for 1998, 1997, and 1996
were as follows:
(Millions of Dollars) 1998 1997 1996
Operating revenues:
Utility revenues:
Bundled retail sales $2,135.5 $2,139.5 $2,184.6
Unbundled retail sales 14.0 2.5
Wholesale and other 64.9 61.0 67.5
Bulk power and transmission
services sales 115.0 80.7 74.8
Total utility revenues 2,329.4 2,283.7 2,326.9
Nonutility revenues:
Retail and other 31.7 4.9
Bulk power sales 215.3 80.9 .7
Total nonutility revenues 247.0 85.8 .7
Total operating revenues $2,576.4 $2,369.5 $2,327.6
M-4
Allegheny Energy, Inc.
Bundled retail sales revenues (full service sales to retail
customers) include a $25.1 million rate refund from 1998
revenues, pursuant to the terms of the Pennsylvania restructuring
settlement agreement. This refund to customers will be made in
1999. Excluding this rate decrease, bundled retail sales
increased $21.1 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.
Retail sales include sales to residential, commercial,
industrial, and street lighting customers. Bundled retail sales
revenues were also affected by the Electricity Generation
Customer Choice and Competition Act (Customer Choice Act) in
Pennsylvania. As part of the Customer Choice Act, all utilities
in Pennsylvania were required to administer retail access pilot
programs under which customers, representing 5% of the load of
each rate class, would choose a generation supplier other than
their own local franchise utility. As a result, 5% of previously
fully bundled customers participated in the Pennsylvania pilot
program and were required to buy energy from another supplier of
their choice. The pilot program began on November 1, 1997, and
continued through December 31, 1998. Unbundled retail sales
revenues represent transmission and distribution revenues from
Pennsylvania pilot customers who chose another supplier to
provide their energy needs.
To assure participation in the pilot program, pilot
participants 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, with the result
that West Penn incurred a revenue loss of $6.5 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. Wholesale and other revenues
include an accrual of such revenue losses, as well as sales to
wholesale customers (cooperatives and municipalities that own
their own distribution systems and buy all or part of their bulk
power needs from the subsidiaries under Federal Energy Regulatory
Commission (FERC) regulation) and non-kWh revenues.
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.
In 1999, utility revenues will reflect a reduction for a
settlement agreement with various parties on the Maryland Office
of People's Counsel's petition for a reduction in Potomac
Edison's Maryland rates. The agreement, which includes
recognition of costs to be incurred from the Applied Energy
Services (AES) Warrior Run PURPA cogeneration project, was
approved by the Maryland Public Service Commission (Maryland PSC)
on October 27, 1998. Under the terms of that agreement, Potomac
Edison will increase its rates about 4% ($13 million) in each of
the years 1999, 2000, and 2001 (a $39 million annual effect in
2001). The increases are designed to recover additional costs of
about $131 million over the period 1999-2001 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 1999-2001 timeframe results in a
pre-tax income reduction of $12 million in 1999,
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Allegheny Energy, Inc.
$18 million in 2000, and $22 million in 2001. In addition, the
settlement requires that Potomac Edison share, on a 50% customer, 50%
shareholder basis, earnings above a return on equity of 11.4% for
1999-2001. This sharing will occur through an annual true-up.
Bundled retail 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. Changes in fuel revenues in those jurisdictions
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. The decrease in
1997 bundled retail revenues resulted primarily from a decrease
in the fuel component of revenues and a decrease in residential
kWh sales due to mild weather in 1997.
The increase in wholesale and other revenues in 1998 was due
primarily to deferred net revenue losses. West Penn recorded a
regulatory asset of $6.4 million in 1998 and $.1 million in 1997
to offset revenue losses suffered as a result of the pilot
program.
Nonutility retail and other revenues increased in 1998 due
to Allegheny Energy Solutions' electric energy sales to retail
customers in deregulated markets.
Utility and nonutility revenues include sales of bulk power
to power marketers and other utilities. Utility revenues also
include sales of transmission services to such marketers and
utilities. Significant bulk power sales in 1998 acted to offset
certain second and third quarter marketing losses in nonutility
operations. The Company has discontinued the types of marketing
activities which caused the losses. Bulk power and transmission
services sales for 1998, 1997, and 1996 were as follows:
1998 1997 1996
KWh Transactions (in billions):
Utility:
Bulk power $ 3.0 1.7 1.0
Transmission services 7.4 12.3 17.4
Total utility 10.4 14.0 18.4
Nonutility bulk power 7.3 3.7 .1
Revenues (in millions):
Utility:
Bulk power $ 69.8 $39.6 $22.4
Transmission services 45.2 41.1 52.4
Total utility $115.0 $80.7 $74.8
Nonutility bulk power $215.3 $80.9 $ .7
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Allegheny Energy, Inc.
The 1998 increase in revenues from utility bulk power was
due to increased sales that occurred primarily in the second
quarter as a result of warm weather which increased the demand
and price for energy. In 1998, revenues from utility transmission
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 recently approved by the FERC.
A provision for these rate reductions was recorded in 1998, with
the revenues to be refunded to customers in the first quarter of
1999.
Revenues from utility operations' transmission 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. Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used.
Revenues from utility operations' transmission services in
1997 decreased due to reduced demand, primarily because of mild
weather.
In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level. These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The potential exists for such volatility to significantly
affect the Company's operating results. The 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 includable in fuel or energy cost recovery
clauses in their respective jurisdictions. The effect of such
price volatility in June and the third quarter of 1998 differed
between the Company's utility and nonutility subsidiaries, but
was insignificant in total.
The increase in nonutility bulk power revenues resulted
primarily from increased bulk power sales by the Company's
nonutility bulk power marketer, AYP Energy, which began
operations in late 1996, and from Allegheny Energy Solutions,
which was formed in the third quarter of 1997 to market energy to
retail customers in deregulated markets and other energy-related
services. Increased prices for energy in the wholesale market
also contributed to the increase. Allegheny Energy Solutions
recorded $24.9 million and $1.2 million of revenues in 1998 and
1997, respectively. Allegheny Energy Solutions ceased operations
as an electric generation supplier in January 1999. The Company
will continue to market nonutility energy supply to retail
customers under the brand name of Allegheny Energy Supply under
the direction of a newly created Energy Supply Division of the
Supply Business. The Energy Supply Division will also market
nonutility energy supply to wholesale customers.
Operating Expenses
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Allegheny Energy, Inc.
Fuel expenses for 1998, 1997, and 1996 were as follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $545.4 $535.7 $512.5
Nonutility operations 21.1 24.2 .7
Total fuel expenses $566.5 $559.9 $513.2
Fuel expenses for utility operations in 1998 and 1997
increased 2% and 5%, respectively, due primarily to an increase
in kWhs generated. The increase in kWhs generated for utility
operations was primarily the result of increased bulk power sales
to power marketers and other utilities.
Fuel expenses for nonutility operations reflect the kWhs
generated by the 50% of Unit No. 1 of the Fort Martin power
station purchased by AYP Energy in late 1996.
The 1998 decrease in fuel expense for nonutility operations
was due to a decrease in kWhs generated as a result of
a scheduled outage at the unit.
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:
(Millions of Dollars) 1998 1997 1996
Purchased power:
Utility operations:
From PURPA generation* $129.0 $134.8 $132.7
Other 50.0 41.2 47.3
Total purchased power for
utility operations 179.0 176.0 180.0
Power exchanges, net (.7) .3 3.3
Nonutility operations 210.5 43.5 1.1
Purchased power and
exchanges, net $388.8 $219.8 $184.4
*PURPA cost (cents per kWh) 5.4 5.6 5.5
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 will be reduced $197 million during the period 1999-2016
related to the AES Beaver Valley nonutility generation contract
as a result of the 1998 extraordinary charge. See Notes B and C
to the consolidated financial statements for further information.
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Allegheny Energy, Inc.
The increase in other purchased power in 1998 for utility
operations resulted primarily from increased purchases for sales.
An increase in price caused by volatility in the spot prices for
electricity at the wholesale level in the second and third
quarters of 1998 also contributed to the increase. The decrease
in 1997 was a result of decreased demand due to decreased sales
to retail customers related to mild 1997 weather, as well as
increased availability of the subsidiaries' power stations.
Nonutility operations purchased power is the result of power
replacement requirements and transaction opportunities by AYP
Energy which began operations in late 1996. The increases in
nonutility purchases in 1998 and 1997 are due primarily to an
increase in volume attributable to AYP Energy's increased
participation in the market and increased prices.
The AES Warrior Run PURPA cogeneration project in Potomac
Edison's Maryland service territory, scheduled to commence
generation in October 1999, will increase the cost of power
purchases $60 million or more annually. The settlement, described
under Sales and Revenues starting on page 31, is designed to
recover all such costs through 2001.
Other operation expenses for 1998, 1997, and 1996 were as
follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $319.2 $292.3 $298.5
Nonutility operations 18.2 16.7 1.3
Total other operation expenses $337.4 $309.0 $299.8
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.
Utility other operation expenses in 1997 include $3.3
million for increased allowances for uncollectible accounts and
$4.4 million of legal expenses incurred by West Penn to defend
itself against an antitrust lawsuit filed by the developers of
the proposed Washington Power PURPA project. The dispute was
settled in December 1997. Nevertheless, utility other operation
expense decreased in 1997 because of a reduction in embedded
expenses achieved through the 1996 internal restructuring
process. The increase in nonutility other operation expenses was
due to startup expenses incurred by the Company's nonutility
subsidiary, AYP Capital.
Maintenance expenses for 1998, 1997, and 1996 were
as follows:
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Allegheny Energy, Inc.
(Millions of Dollars) 1998 1997 1996
Utility operations $212.3 $227.1 $242.5
Nonutility operations 5.3 3.5 .8
Total maintenance expenses $217.6 $230.6 $243.3
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 is postponing these
expenses primarily by extending the time between maintenance
outages. The 1997 decrease in utility maintenance expenses
resulted from reduced expenses achieved through internal
restructuring efforts and other cost controls. Maintenance
expenses represent costs incurred to maintain the power stations,
the transmission and distribution (T&D) system, and general
plant, and reflect routine maintenance of equipment and rights-of-
way, as well as planned major repairs and unplanned expenditures,
primarily from forced outages at the power stations and periodic
storm damage on the T&D system. Variations in maintenance expense
result primarily from unplanned events and planned major
projects, which vary in timing and magnitude depending upon the
length of time equipment has been in service without a major
overhaul and the amount of work found necessary when the
equipment is dismantled. The increases in nonutility maintenance
expense in 1998 and 1997, respectively, were primarily related to
a 1998 planned outage for maintenance of Unit No. 1 of the Fort
Martin power station, 50% owned by AYP Energy, and in 1997 due to
the first full year of AYP Energy operations.
Internal restructuring charges and an asset write-off in
1996 resulted from internal restructuring activities, which have
been completed, and the write-off of previously accumulated costs
related to a proposed transmission line.
Depreciation expenses for 1998, 1997, and 1996 were as
follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $264.6 $259.1 $263.2
Nonutility operations 5.8 6.6
Total depreciation expense $270.4 $265.7 $263.2
Higher utility depreciation in 1998 resulted from increased
investment. The decrease in utility depreciation expense in 1997
was the result of a change in the retirement dates for West Penn
for the Mitchell power station and the Pleasants power station
scrubbers. The increase in nonutility depreciation expense in
1997 was the result of depreciation incurred by AYP Energy
because of its purchase in October 1996 of a 50% ownership in
Unit No. 1 of the Fort Martin power station.
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Allegheny Energy, Inc.
Taxes other than income taxes for 1998, 1997, and 1996 were
as follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $187.7 $181.4 $185.4
Nonutility operations 6.9 5.6
Total taxes other than
income taxes $194.6 $187.0 $185.4
The increase in utility taxes other than income taxes in
1998 was due primarily to increased West Virginia Business and
Occupation Taxes (B&O) resulting from an adjustment for a prior
period and increased property taxes. The nonutility increase in
1998 was due to gross receipts taxes resulting from higher
revenues from retail customers. The 1997 increase in taxes other
than income taxes was due to an increase in nonutility taxes of
$5.6 million in B&O and property taxes resulting from AYP
Energy's purchase of an ownership interest in the Fort Martin
power station offset by a $4 million decrease in utility taxes
because of a decrease in gross receipts taxes due to lower retail
revenues and lower FICA taxes due to the Company's prior year
internal restructuring.
The 1997 increase in federal and state income taxes was
primarily due to increased income in 1997 compared with 1996.
Note F to the consolidated financial statements provides a
further analysis of income tax expenses.
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 allowance for borrowed funds used
during construction component of the formula receives greater
weighting when short-term debt increases. The decrease also
reflects adjustments of prior periods.
The decrease in other income, net, of $9.8 million in 1998
and the increase in 1997 of $13.6 million was primarily due to
1997 increases for an interest refund on a tax-related contract
settlement ($8.3 million, net of taxes) and income on the sale of
land ($2.8 million, net of taxes).
Interest on long-term debt for 1998, 1997, and 1996 was as
follows:
(Millions of Dollars) 1998 1997 1996
Utility operations $151.0 $162.8 $164.3
Nonutility operations 10.1 10.8 2.1
Total interest on long-term
debt $161.1 $173.6 $166.4
The decrease in interest on long-term debt in 1998 of $12.5
million resulted from reduced long-term debt and lower interest
rates. Interest on nonutility long-term debt in 1997 increased
due to October 1996 bank borrowings of $160 million by AYP Energy
related to its purchase of an ownership interest in the Fort
Martin power station. 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.
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Allegheny Energy, Inc.
The extraordinary charge 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 as described in Notes B and C to the consolidated
financial statements.
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.
Construction expenditures of all the subsidiaries in 1998
were $231 million and, for 1999 and 2000, are estimated at $315
million and $294 million, respectively. The 1999 and 2000
estimated expenditures include $63 million and $85 million,
respectively, for construction of environmental control
technology. It is the Company's goal to constrain future utility
construction spending to the approximate level of depreciation
currently in rates. The subsidiaries also have additional capital
requirements for debt maturities (see Note K to the consolidated
financial statements).
Internal Cash Flow
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $381 million in 1998,
compared with $268 million in 1997. Reduced 1997 cash flow was
the result of the $48 million buyout of the Washington Power
PURPA project and payment of internal restructuring liabilities.
Current rate levels and reduced levels of construction
expenditures permitted the subsidiaries to finance all of their
construction expenditures in 1998 and nearly all in 1997 with
internal cash flow. As described under Environmental Issues
starting on page 39, the subsidiaries could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues. Whether the
regulated subsidiaries can continue to meet the majority of their
construction needs with internally generated cash is largely
dependent upon the outcome of these issues.
Dividends paid on common stock in each of the years 1998 and
1997 were $1.72 per share. The dividend payout ratio, excluding
the extraordinary charge and Pennsylvania settlement costs in
1998, decreased slightly from 1997.
Financing
The Company did not issue any common stock in 1998. The
shares for its Dividend Reinvestment and Stock Purchase Plan,
Employee Stock Ownership and
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Allegheny Energy, Inc.
Savings Plan, and Performance Share Plan were purchased on the
open stock market. Short-term debt is used to meet temporary
cash needs. Short-term debt increased $52.4 million to $258.8
million in 1998. At December 31, 1998, unused lines of credit
with banks were $300 million. The utility subsidiaries anticipate
meeting their 1999 cash needs through internal cash generation,
cash on hand, and short-term borrowings as necessary. However,
West Penn is expected to issue up to $670 million of bonds to
"securitize" transition costs related to its restructuring
settlement described in Note B to the consolidated financial statements.
Significant Continuing Issues
Proposed Merger with DQE
The Company believes that DQE's basis for seeking to
terminate the merger (described in Note D to the consolidated
financial statements) is without merit. Accordingly, the Company
continues to seek the remaining regulatory approvals from the
Department of Justice and the Securities and Exchange Commission
(SEC). It is not likely either agency will act on the requests
unless the Company obtains judicial relief requiring DQE to move
forward.
Electric Energy Competition
The electricity supply segment of the electric utility
industry in the United States is in the midst of becoming a
competitive marketplace. The Energy Policy Act of 1992 began the
process of deregulating the wholesale exchange of power within
the electric industry by permitting the FERC to compel electric
utilities to allow third parties to sell electricity to wholesale
customers over their transmission systems. Since 1992, the
wholesale electricity market has become increasingly competitive
as companies began to engage in nationwide power trading. In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries have
investigated or implemented retail access to alternate
electricity suppliers. 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. In the absence of federal legislation,
state-by-state implementation has begun.
The Customer Choice Act in Pennsylvania has created retail
access to a competitive electric energy market. Pursuant to the
Customer Choice Act, all electric utilities in Pennsylvania were
required in 1998 to establish and administer retail access pilot
programs to 5% of the load of each class of their customers.
Beginning in January 1999, two-thirds of West Penn's customers
were permitted to choose an alternate electricity supplier.
Remaining West Penn customers can do so in January 2000. See Note
B to the consolidated financial statements for additional
information on the settlement agreement reached with the
Pennsylvania PUC, which included transition costs and the ability
to transfer generating assets to an affiliate at net book value.
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Allegheny Energy, Inc.
One result of the Customer Choice Act is the bifurcation of
electricity supply and electricity delivery into two separate
businesses. The transmission and distribution (wires) business
remains under the traditional regulated ratemaking, while the
electricity supply business in Pennsylvania is deregulated, and
its pricing will be determined by the marketplace. The wires
business will have responsibility as the electricity provider of
last resort and will generally obtain its electricity supply from
the market, primarily by competitive bidding. Provider of last
resort service will continue to be regulated and provided at
capped rates. The electricity supply business will be free to
sell West Penn's generation capacity and energy in the open
wholesale and retail market, subject to codes of conduct and the
restriction that it may not sell at retail, except under certain
conditions, in West Penn's service territory through 2003.
Because of these new regulations, West Penn reorganized for 1999
into a Delivery Business (wires) and a Supply Business (marketing
capacity and energy). West Penn's Delivery Business will continue
to provide transmission and distribution service and will bill a
Competitive Transition Charge to native load customers exercising
choice.
The Maryland PSC in December 1997 issued an Order to
implement retail competition in that state. The Maryland PSC's
Order and its revised second Order call for a deregulation
process, including a three-year phase-in beginning July 1, 2000,
with recovery of prudent transition costs after mitigation. On
September 10, 1998, the Maryland PSC issued a third Order which
clarified certain issues and questions involved with the earlier
orders. A court-approved settlement of appeals of these orders
provides that the Maryland PSC orders are not final. Roundtable
discussions created by the orders have been held since April
1998. The roundtable's final report to the Maryland PSC is due
May 1, 1999, and the Maryland PSC's final Order in connection
with the work of the roundtable is due August 1, 1999. As
required by the Maryland PSC, Potomac Edison, on July 1, 1998,
filed testimony in Maryland's investigation into transition
costs, price protection, and unbundled rates. The filing
requested recovery of transition costs and a surcharge to recover
the cost of the AES Warrior Run cogeneration project which is
scheduled to commence production on October 1, 1999. Hearings are
scheduled to begin in April 1999. Several electricity competition
bills have been introduced in the 1999 legislative session, and
we continue to support bringing customer choice to Maryland
customers.
Throughout 1998, a Subcommittee of the Virginia General
Assembly studied electric utility restructuring and made
recommendations to the General Assembly. The process led to the
introduction of detailed restructuring legislation in both the
House and Senate in the 1999 session. The legislation would
implement a transition to choice beginning in 2002. The Senate
passed the bill and referred it to the House. We expect the bill
to be signed into law this year.
In December 1996, the Public Service Commission of West
Virginia (W.Va. PSC) issued an Order initiating a general
investigation regarding the restructuring of the regulated
electric utility industry. A task force was established to
further investigate restructuring issues. Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the
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Allegheny Energy, Inc.
legislation, and to then submit that plan to the
Legislature for review and possible approval. The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections.
The Public Utilities Commission of Ohio (Ohio PUC) has
continued informal roundtable discussions on issues concerning
competition in the electric utility industry. The Governor
established a legislative committee from members of both the
Senate and House to further review issues regarding deregulation.
Several bills on restructuring and deregulation have been
introduced in the Ohio Legislature and are subject to continuing
hearings and negotiations at the committee level.
Fully meeting challenges in the emerging competitive
environment will be challenging for the Company unless certain
outmoded and anti-competitive laws, specifically the Public
Utility Holding Company Act of 1935 (PUHCA) and Section 210 of
PURPA, are repealed or significantly revised. The Company
continues to advocate the repeal or reform of PUHCA and PURPA on
the grounds that they are obsolete and anti-competitive, and that
PURPA, in particular, results in utility customers paying above-
market prices for power.
Business Strategy
Generation will continue to be a core part of the Company's
business. The Company's goal is to grow generation through
building and buying generating facilities. The energy delivery or
wires business will also continue to be a core part of the
Company's business. The Company plans to expand the energy
delivery business primarily through acquisitions of other
electric distribution properties. 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
the transfer of West Penn's 3,722 MW of generating capacity to a
new, unregulated, wholly owned subsidiary. The Company plans to
transfer these generating assets at book value. The unregulated
generation will be sold in both the wholesale and retail
competitive marketplace, allowing greater earnings growth
potential, subject to market risk, while allowing us to
capitalize on the Company's strengths in the generation business.
The Company continues to study ways to meet existing and
future increases in regulated customer demand, including new and
efficient electric technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the subsidiaries are
subject to various contingencies and uncertainties relating to
their operations and
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Allegheny Energy, Inc.
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 being recovered currently from
customers in rates. 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 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
Company's 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 suspended by the
proposed NOx State Implementation Plan (SIP) call rule discussed
below. 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. 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.
The Ozone Transport Assessment Group issued its final report
in June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 85% reduction from
the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the
regulatory process to adopt the recommendations and issued its
final NOx SIP call rule on September 24, 1998. The EPA's SIP call
rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone nonattainment in downwind
states. The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis. The final SIP call rule
requires that all state-adopted NOx reduction measures must be
incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.
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
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Allegheny Energy, Inc.
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 mentioned above. In October 1998, the EPA proposed approval
of the petitions. However, the EPA believes implementation of the
NOx SIP call will alleviate the need to grant the petitions. The
EPA intends to issue a final rule by April 1999.
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. State attainment
plans to meet the revised standards will not be developed for
several years. Also, in July 1997, the EPA proposed regional haze
regulations to improve visibility in Class I federal areas
(national parks and wilderness areas). If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities. The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase
III of the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time. All are being challenged by rulemaking,
petition, and/or the litigation process. Implementation dates are
also uncertain at this time, but could be as early as 2003, which
would require substantial capital expenditures in the 1999-2000
period. The Company's construction forecast includes the
expenditure of $360 million of capital costs during the 1999-2003
period to comply with the SIP call.
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 will
require the United States to reduce emissions of GHG by 7% from
1990 levels in the 2008-2012 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 utility subsidiaries previously reported that the EPA
had identified them 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 utility
subsidiaries' share of the remediation costs based on the amount
of materials sent to the site. The utility subsidiaries
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Allegheny Energy, Inc.
have also been named as defendants along with multiple other
defendants in pending asbestos cases involving one or more
plaintiffs. The utility subsidiaries believe that provisions
for liability and insurance recoveries are such that final
resolution of these claims will not have a material effect
on their financial position.
Independent Transmission System Operator
The Company conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of a proposed merger with DQE. The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998. The Company's membership status remains
conditional upon the outcome of the merger. Many industry
participants, including customers and regulatory authorities,
believe that an entity independent of the utilities which own the
transmission systems is needed to operate the systems to ensure
nondiscriminatory access to the transmission systems by all
users. Should these beliefs result in a mandate, the Company may
either voluntarily or involuntarily sustain membership or achieve
new membership in some form of Independent System Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations,
including the Company, could experience serious problems related
to software and various equipment with embedded chips which may
not properly recognize calendar dates. To minimize such problems,
the Company is proceeding with a comprehensive effort to continue
operations without significant problems in 2000 and beyond. An
Executive Task Force is coordinating the efforts of 24 separate
Y2K Teams, representing all business and support units in the
Company.
In May 1998, the North American Electric Reliability Council
(NERC), of which the Company is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts. The electric utility industry and the
Company have segmented the Y2K problem into the following
components:
- - Computer hardware and software;
- - Embedded chips in various equipment; and
- - Vendors and other organizations on which the Company relies
for critical materials and services.
The industry's and the Company's efforts for each of these
three components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.
The NERC has established a goal of having the industry
achieve a state of Y2K readiness for critical systems by June 30,
1999, and, to monitor progress, requires each utility to prepare
and submit a monthly report showing progress and dated plans. By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to
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Allegheny Energy, Inc.
file contingency plans by that date. The Company's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each
other to avoid, in a worst case situation, cascading failure of
the entire electrical system. The Company is working with the
Edison Electric Institute, the Electric Power Research Institute,
the NERC, and the East Central Area Reliability Agreement group
to capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning. The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is clearly much more
work to be done, we have found that North America's electric
power supply and delivery systems are well on their way to being
Y2K ready."
The SEC requires that each company disclose its estimate of
the "most reasonably likely worst case scenario" of a negative
Y2K event. Since the Company and the industry are working
diligently to avoid any disruption of electric service, the
Company does not believe it or its customers will experience any
significant long-term disruptions of electric service. It is the
Company's opinion that the "most reasonably likely worst case
scenario" is that there could be isolated problems at various
Company facilities or at the facilities of neighboring utilities
that may have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service. All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.
The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems. Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions. To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning. While outside contractors and equipment vendors will be
employed for some of the work, the Company believes it must rely
on its own employees for most of the effort because of their
experience with the Company's systems and equipment. The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $15 to $20 million. Of that amount, about $9
million has been incurred through 1998.
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Allegheny Energy, Inc.
The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act. Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995. Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning activities. There
can be no assurance that actual results will not materially
differ from expectations.
M-20
Monongahela Power Company
1998 Financial Statements
Monongahela Power Company
Part of Allegheny Energy
M-21
Monongahela Power Company
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995. These include
statements with respect to deregulation activities and movements
toward competition in states served by Monongahela Power Company
(the Company), the proposed merger of Allegheny Energy, Inc.
(Allegheny Energy) with DQE, Inc. (DQE), parent company of
Duquesne Light Company in Pittsburgh, Pa., and results of
operations. All such forward-looking information is necessarily
only estimated. There can be no assurance that actual results
will not materially differ from expectations. Actual results
have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which the Company
operates, including regulatory proceedings affecting rates
charged by the Company; environmental, legislative, and
regulatory changes; future economic conditions; developments
relating to the proposed merger of Allegheny Energy with DQE,
including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
Merger with DQE
See Page 7 and also Note B to the financial statements for
information about the proposed merger of Allegheny Energy with
DQE.
Internal Restructuring
In 1994, the Allegheny Energy integrated electric utility system
(the System), including the Company, initiated an internal
restructuring process to consolidate and re-engineer their
utility operations to meet the competitive challenges of the
changing electric utility industry. As a result of this process,
the System reduced employment by about 1,000 employees through a
voluntary separation plan, attrition and layoffs, and changed
processes to obtain efficiencies to reduce operating and
maintenance (O&M) costs. This process resulted in internal
restructuring charges in 1996 as described in Note C to the
financial statements.
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Monongahela Power Company
REVIEW OF OPERATIONS
Earnings Summary
(Millions of Dollars) Earnings
1998 1997 1996
Operations.................................... $82.4 $80.5 $76.1
Expenses related to internal restructuring
activities.................................. (14.6)
Net Income.................................... $82.4 $80.5 $61.5
The increase in 1998 earnings from operations resulted from
increased kilowatt-hour (kWh) sales to commercial and industrial
customers and from reduced power station O&M spending. The 1996
restructuring costs resulted from internal restructuring
initiated in 1994 which is described in Note C to the financial
statements and Internal Restructuring on page 1. The increase in
1997 earnings from operations resulted primarily from reductions
in O&M expenses from the internal restructuring process and
additional actions taken during the year to achieve further O&M
reductions in response to significant decreases in residential
kWh sales caused primarily by mild weather. Also contributing to
the increase was additional revenues due to a change in
allocation of affiliated transmission services, increased
generating capacity sales to an affiliate, and an interest refund
on a tax-related contract settlement by the Company's 27% owned
subsidiary, Allegheny Generating Company (AGC), recorded in other
income as increased equity in earnings of AGC.
Sales and Revenues
Percentage changes in revenues and kWh sales in 1998 and 1997 by
major retail customer classes were:
1998 vs. 1997 1997 vs. 1996
Revenues kWh Revenues kWh
Residential................. 0.5% (0.3)% (3.0)% (1.8)%
Commercial.................. 6.4 5.8 (2.3) (1.0)
Industrial.................. 6.0 5.5 (2.1) 4.0
Total..................... 4.0% 4.0 % (2.5)% 1.3 %
The changes in residential kWh sales, which are more weather
sensitive than the other classes, were due primarily to changes
in customer usage because of weather conditions. The growth in
the number of residential customers was .6% and .8% in 1998 and
1997, respectively. The weather in 1997 was mild in both the
early and late winter and in the summer, causing the 1.8%
decrease in residential kWh sales.
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Monongahela Power Company
Commercial kWh sales are also affected by weather, but to a
lesser extent than residential. The 5.8% increase in 1998
reflects growth in the number of customers and increased usage.
The increases in industrial kWh sales in 1998 and 1997 were
primarily due to increased sales to one of the Company's
customers who switched an additional portion of their load
requirements to the Company in September 1997.
Changes in revenues from retail customers resulted from the
following:
Changes from Prior Year
(Millions of Dollars) 1998 vs. 1997 1997 vs. 1996
Fuel clauses............................... $11.8 $(10.2)
All other.................................. 8.7 (3.0)
Net change in retail revenues............ $20.5 $(13.2)
Revenues reflect not only changes in kWh sales and base rate
changes, but also any changes in revenues from fuel and energy
cost adjustment clauses (fuel clauses) which have little effect
on net income because increases and decreases in fuel and
purchased power costs and sales of transmission services and bulk
power are passed on to customers by adjustment of customers'
bills through fuel clauses.
All other is the net effect of kWh sales changes due to changes
in customer usage (primarily weather for residential customers),
growth in the number of customers, and changes in pricing other
than changes in general tariff and fuel clause rates. The
increase in 1998 all other retail revenues was primarily the
result of increased customer usage and growth in the number of
customers. The decrease in 1997 all other retail revenues is
primarily the result of mild weather in 1997.
Wholesale and other revenues were as follows:
(Millions of Dollars) 1998 1997 1996
Wholesale customers...................... $ 5.2 $ 4.9 $ 5.0
Affiliated companies..................... 77.3 83.6 74.9
Street lighting and other................ 6.9 7.1 6.6
Total wholesale and other revenues..... $89.4 $95.6 $86.5
Wholesale customers are cooperatives and municipalities that own
their own distribution systems and buy all or part of their bulk
power needs from the Company under Federal Energy Regulatory
Commission (FERC) regulation. Competition in the wholesale market
for electricity was initiated by the National Energy Policy Act
of 1992, which permits wholesale generators, utility-owned and
otherwise, and wholesale customers to request from owners of bulk
power transmission facilities a commitment to supply transmission
services. All of the Company's wholesale customers have signed
contracts to remain as customers until December 1, 2000.
Revenues from affiliated companies represent sales of energy and
intercompany allocations of generating capacity, generation
spinning reserves, and
M-24
Monongahela Power Company
transmission services pursuant to a power supply agreement among
the Company and the other regulated utility subsidiaries of
Allegheny Energy. The decrease in such revenues in 1998 resulted
primarily from decreased generating capacity sales ($4.7 million).
The increase in 1997 resulted primarily from an increase in the
allocation of transmission services revenues and increased generating
capacity sales ($6.5 million).
Bulk power transactions include sales of bulk power and
transmission services to power marketers and other utilities.
Bulk power and transmission services sales for 1998, 1997, and
1996 were as follows:
1998 1997 1996
KWh Transactions (in billions):
Bulk power............................... .3 .3 .2
Transmission services to
nonaffiliated companies................ 1.9 3.0 4.2
Total................................ 2.2 3.3 4.4
Revenues (in millions):
Bulk power............................... $ 8.5 $ 7.3 $ 4.8
Transmission services to
nonaffiliated companies................ 11.3 10.0 12.6
Total................................ $19.8 $17.3 $17.4
The 1998 increase in revenues from bulk power was due to
increased sales that occurred primarily in the second quarter as
a result of warm weather which increased the demand and price for
energy. In 1998, revenues from transmission 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 recently approved by the FERC. A provision
of $1.7 million for these rate reductions was recorded in 1998,
with the revenues to be refunded to customers in the first
quarter of 1999.
Revenues from transmission services to nonaffiliated companies 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. Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used. Revenues from transmission services to
nonaffiliated companies in 1997 decreased due to reduced demand,
primarily because of mild weather.
In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level. These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The costs of purchased power and revenues from sales to
power marketers and other utilities, including transmission
services, are currently recovered from or credited to customers
under fuel and energy cost recovery procedures. The impact to the
fuel and energy cost recovery clauses, either positively or
negatively, depends on whether the Company is a net
M-25
Monongahela Power Company
buyer or seller of electricity during such periods. The impact
of such price volatility in June and the third quarter of 1998 was
insignificant to the Company because changes are passed through
to customers through operation of fuel clauses.
Operating Expenses
Fuel expenses increased 1.9% in 1998 due primarily to an increase
in kWhs generated. The 4.1% increase in 1997 was caused by a
2.4% increase in kWh's generated, a 1.4% increase in average fuel
prices, and a .3% increase in the average heat rate of the
generating stations. The increases in kWh's generated in 1998
and 1997 were primarily the result of increased retail sales and
bulk power sales to power marketers and other utilities.
Purchased power and exchanges, net, represents power purchases
from and exchanges with other companies and purchases from
qualified facilities under the Public Utility Regulatory Policies
Act of 1978 (PURPA), capacity charges paid to AGC, and other
transactions with affiliates made pursuant to a power supply
agreement whereby each company uses the most economical
generation available in the System at any given time, and
consists of the following items:
(Millions of Dollars) 1998 1997 1996
Nonaffiliated transactions:
Purchased power:
From PURPA generation*................ $65.5 $69.8 $ 69.1
Other................................. 11.6 9.6 11.3
Power exchanges, net.................... (.2) .1 .9
Affiliated transactions:
AGC capacity charges.................... 18.4 18.5 20.2
Energy and spinning reserve charges..... .3 .3 .1
Purchased power and exchanges, net.... $95.6 $98.3 $101.6
*PURPA cost (cents per kWh) 5.1 5.3 5.3
The decrease in purchased power from PURPA generation in 1998 was
due primarily to reduced generation at hydroelectric plants due
to river flow. The increase in other purchased power in 1998
resulted primarily from increased purchases for sales. An
increase in price caused by volatility in the spot prices for
electricity at the wholesale level in the second and third
quarters of 1998 also contributed to the increase. The decrease
in other purchased power in 1997 was a result of decreased demand
due to decreased sales related to mild 1997 weather.
None of the Company's purchased power contracts are capitalized
since there are no minimum payment requirements absent associated
kWh generation and under a regulated environment recovery of the
costs are reasonably assured.
The increase in other operation expenses in 1998 resulted
primarily from increases in salaries and wages and employee
benefits, increased property insurance expense due in part to a
prior period adjustment, and an increase in expense related to
Year 2000 readiness. Other operation expenses in 1997
M-26
Monongahela Power Company
include $1.7 million for increased allowances for uncollectible
accounts. Nevertheless, other operation expense decreased in
1997 because of a reduction in embedded expenses achieved through
the 1996 internal restructuring process.
The decrease in maintenance expenses 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 is postponing these expenses
primarily by extending the time between maintenance outages. The
1997 decrease in maintenance expenses resulted from reduced
expenses achieved through internal restructuring efforts and
other cost controls. Maintenance expenses represent costs
incurred to maintain the power stations, the transmission and
distribution (T&D) system, and general plant, and reflect routine
maintenance of equipment and rights-of-way, as well as planned
major repairs and unplanned expenditures, primarily from forced
outages at the power stations and periodic storm damage on the
T&D system.
Variations in maintenance expense result primarily from unplanned
events and planned major projects, which vary in timing and
magnitude depending upon the length of time equipment has been in
service without a major overhaul and the amount of work found
necessary when the equipment is dismantled.
Internal restructuring charges in 1996 resulted from internal
restructuring activities, which have been completed.
Depreciation expense in 1998 and 1997 increased $2.0 million and
$1.1 million, respectively, due to increased investment.
Taxes other than income taxes increased $6.0 million in 1998 due
primarily to West Virginia Business and Occupation Taxes
resulting from an adjustment for a prior period and increased
property taxes. The decrease in 1997 taxes other than income
taxes was because of a decrease in gross receipts taxes due to
lower retail revenues and lower FICA taxes due to the Company's
prior year internal restructuring.
The increases in federal and state income taxes were primarily
due to increased income before income taxes. Note D to the
financial statements provides a further analysis of income tax
expenses.
The decrease in other income, net, of $2.4 million in 1998 and
the increase in 1997 of $1.7 million was primarily due to a 1997
interest refund on a tax-related contract settlement ($2.2
million, net of taxes) received by the Company's subsidiary, AGC.
The decrease in interest on long-term debt in 1998 of $3.7
million resulted from reduced long-term debt and lower interest
rates. Other interest expense reflects changes in the levels of
short-term debt maintained by the Company throughout the year, as
well as the associated interest rates.
M-27
Monongahela Power Company
FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the
sale of common and preferred stock, debt instruments, installment
loans, and lease arrangements. The timing and amount of external
financings depend primarily upon economic and financial market
conditions, the Company's cash needs, and capitalization ratio
objectives. The availability and cost of external financings
depend upon the financial health of the companies seeking those
funds and market conditions.
Construction expenditures in 1998 were $73 million and, for 1999
and 2000, are estimated at $76 million and $79 million,
respectively. The 1999 and 2000 estimated expenditures include
$13 million and $20 million, respectively, for construction of
environmental control technology. It is the Company's goal to
constrain future construction spending to the approximate level
of depreciation currently in rates. The Company also has
additional capital requirements for debt maturities (see Note J
to the financial statements).
Internal Cash Flow
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $108 million in 1998,
compared with $65 million in 1997. Reduced 1997 cash flow was
primarily the result of the payment of internal restructuring and
other liabilities. Current rate levels and reduced levels of
construction expenditures permitted the Company to finance all of
its construction expenditures in 1998 and nearly all in 1997 with
internal cash flow. As described under Environmental Issues
starting on page 9, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues. Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues.
Financing
Short-term debt is used to meet temporary cash needs. Short-term
debt, including notes payable to affiliates under the money pool,
decreased $9.3 million to $49.0 million in 1998. At December 31,
1998, the Company had Securities and Exchange Commission (SEC)
authorization to issue up to $106 million of short-term debt.
The Company and its regulated affiliates use an Allegheny Energy
internal money pool as a facility to accommodate intercompany
short-term borrowing needs, to the extent that certain of the
companies have funds available. The Company anticipates meeting
its 1999 cash needs through internal cash generation, cash on
hand, and short-term borrowings as necessary.
M-28
Monongahela Power Company
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy believes that DQE's basis for seeking to
terminate the merger (described in Note B to the financial
statements) is without merit. Accordingly, Allegheny Energy
continues to seek the remaining regulatory approvals from the
Department of Justice and the SEC. It is not likely either
agency will act on the request unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.
Electric Energy Competition
The electricity supply segment of the electric utility industry
in the United States is in the midst of becoming a competitive
marketplace. The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems. Since 1992, the wholesale
electricity market has become increasingly competitive as
companies began to engage in nationwide power trading. In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries of Allegheny
Energy have investigated or implemented retail access to
alternate electricity suppliers. 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. In the absence of federal legislation,
state-by-state implementation has begun.
The Company has franchised regulated customers in West Virginia
and Ohio.
In West Virginia, the Public Service Commission of West Virginia
(W.Va. PSC) issued an Order in December 1996 initiating a general
investigation regarding the restructuring of the regulated
electric utility industry. A task force was established to
further investigate restructuring issues. Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the legislation, and to then submit that plan to the
Legislature for review and possible approval. The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections.
In Ohio, the Public Utilities Commission of Ohio has continued
informal roundtable discussions on issues concerning competition
in the electric utility industry. The Governor established a
legislative committee from members of both the Senate and House
to further review issues regarding deregulation. Several bills
on restructuring and deregulation have been introduced in the
Ohio Legislature and are subject to continuing hearings and
negotiations at the committee level.
The status of electric energy competition in Maryland, Virginia,
and Pennsylvania in which affiliates of the Company serve are as
follows.
M-29
Monongahela Power Company
In Maryland, the Maryland Public Service Commission (Maryland
PSC) in December 1997 issued an Order to implement retail
competition in that state. The Maryland PSC's Order and its
revised second Order, call for a deregulation process, including
a three-year phase-in beginning July 1, 2000, with recovery of
prudent transition costs after mitigation. The Maryland PSC
subsequently issued a third Order which clarified certain issues
and questions involved with the earlier Orders. A court-approved
settlement of appeals of these Orders provides that the Maryland
PSC Orders are not final. The Company's Maryland affiliate, The
Potomac Edison Company (Potomac Edison), is subject to these
orders and appeals.
In Virginia, a Subcommittee of the Virginia General Assembly
studied electric utility restructuring and made recommendations
to the General Assembly throughout 1998. The process led to the
introduction of detailed restructuring legislation in both the
House and Senate in the 1999 session. The legislation would
implement a transition to choice beginning in 2002. The Senate
passed the bill and referred it to the House. It is expected
that the bill will be signed into law this year. The Company's
affiliate, Potomac Edison, is subject to this action.
In Pennsylvania, the Electricity Generation Customer Choice and
Competition Act has created retail access to a competitive
electric energy market. The Company's Pennsylvania affiliate,
West Penn Power Company (West Penn), is subject to this Act.
Beginning in January 1999, two-thirds of West Penn's customers
were permitted to choose an alternate electricity supplier.
Remaining West Penn customers can do so in January 2000. As a
result of a Pennsylvania Public Utility Commission (Pennsylvania
PUC) Order and settlement agreement, West Penn determined that
under the provisions of Statement of Financial Accounting
Standards No. 101, "Accounting for the Discontinuation of
Application of FASB Statement No. 71," in 1998 an extraordinary
charge of $466.9 million ($275.4 million after taxes) was
required to reflect a write-off of certain disallowances. In
addition, charges of $40.3 million ($23.7 million after taxes)
related to West Penn's revenue refund and energy program payments
were also recorded.
Fully meeting challenges in the emerging competitive environment
will be challenging for the Company unless certain outmoded and
anti-competitive laws, specifically the Public Utility Holding
Company Act of 1935 (PUHCA) and Section 210 of PURPA, are
repealed or significantly revised. Allegheny Energy continues to
advocate the repeal or reform of PUHCA and PURPA on the grounds
that they are obsolete and anti-competitive, and that PURPA, in
particular, results in utility customers paying above-market
prices for power.
Business Strategy
Generation will continue to be a core part of Allegheny Energy's
business. Allegheny Energy's goal is to grow generation through
building and buying generating facilities. The energy delivery
or wires business will also continue to be a core part of
Allegheny Energy's business. Allegheny Energy plans to expand
the energy delivery business primarily through acquisitions of
other electric distribution properties.
M-30
Monongahela Power Company
The settlement agreement for the Company's affiliate, West Penn,
in Pennsylvania permitted the transfer of its 3,722 MW of
generating capacity to a new, unregulated company that is
expected to be a wholly owned subsidiary of West Penn. West Penn
plans to transfer these generating assets at book value. The
unregulated generation will be sold in both the wholesale and
retail competitive marketplace, allowing greater earnings growth
potential, subject to market risk, while allowing Allegheny
Energy to capitalize on its strengths in the generation business.
Allegheny Energy continues to study ways to meet existing and
future increases in regulated customer demand, including new and
efficient electric technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the Company is subject to
various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.
The significant costs of complying with Title IV (acid rain)
provisions of Phase I of the Clean Air Act Amendments of 1990
(CAAA) have been incurred and are being recovered currently from
customers in rates. 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 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
Company's generating station located in Pennsylvania was required
to reduce NOx emissions by approximately 55% from the 1990
baseline emissions, with a compliance date of May 1999. Further
reductions of 75% from the 1990 baseline may be required by May
2003 under Phase III of the MOU. However, this reduction will
most likely be suspended by the proposed NOx State Implementation
Plan (SIP) call rule discussed below. 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. If reductions of 75% are required,
installation of post-combustion control technologies would be
very expensive. Pennsylvania promulgated regulations to
implement Phase II of the MOU in November 1997.
The Ozone Transport Assessment Group issued its final report in
June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 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
M-31
Monongahela Power Company
nonattainment in downwind
states. The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis. The final SIP call
rule requires that all state-adopted Nox reduction measures must
be incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.
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 mentioned above. In October 1998, the EPA proposed approval
of the petitions. However, the EPA believes implementation of
the NOx SIP call will alleviate the need to grant the petitions.
The EPA intends to issue a final rule by April 1999.
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. State attainment
plans to meet the revised standards will not be developed for
several years. Also, in July 1997, the EPA proposed regional
haze regulations to improve visibility in Class I federal areas
(national parks and wilderness areas). If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities. The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of
the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time. All are being challenged by rulemaking,
petition, and/or the litigation process. Implementation dates
are also uncertain at this time, but could be as early as 2003,
which would require substantial capital expenditures in the 1999-
2000 period. The Company's construction forecast includes the
expenditure of $96 million of capital costs during the 1999-2003
period to comply with the SIP call.
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 will require the United
States to reduce emissions of GHG by 7% from 1990 levels in the
2008-2012 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
M-32
Monongahela Power Company
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 Unites 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 Unites 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 previously reported that the EPA had identified the
Company and its regulated affiliates as potentially responsible
parties, along with approximately 175 others, in a Superfund site
subject to cleanup. A final determination has not been made for
the Company's share of the remediation costs based on the amount
of materials sent to the site. The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs. 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.
Independent Transmission System Operator
Allegheny Energy conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of a proposed merger with DQE. The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998. Allegheny Energy's membership status
remains conditional upon the outcome of the merger. Many
industry participants, including customers and regulatory
authorities, believe that an entity independent of the utilities
which own the transmission systems is needed to operate the
systems to ensure nondiscriminatory access to the transmission
systems by all users. Should these beliefs result in a mandate,
Allegheny Energy may either voluntarily or involuntarily sustain
membership or achieve new membership in some form of Independent
System Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations, including
the Company, could experience serious problems related to
software and various equipment with embedded chips which may not
properly recognize calendar dates. To minimize such problems,
the Company and its affiliates in the System are
proceeding with a comprehensive effort to continue operations
without significant problems in 2000 and beyond. An Executive
Task Force is coordinating the efforts of 24 separate Y2K Teams,
representing all business and support units in the System.
M-33
Monongahela Power Company
In May 1998, the North American Electric Reliability Council
(NERC), of which the System is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts. The electric utility industry and the
System have segmented the Y2K problem into the following
components:
- - Computer hardware and software;
- - Embedded chips in various equipment; and
- - Vendors and other organizations on which the System relies
for critical materials and services.
The industry's and the System's efforts for each of these three
components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.
The NERC has established a goal of having the industry achieve a
state of Y2K readiness for critical systems by June 30, 1999,
and, to monitor progress, requires each utility to prepare and
submit a monthly report showing progress and dated plans. By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to
file contingency plans by that date. The System's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, cascading failure of the
entire electrical system. The System is working with the Edison
Electric Institute, the Electric Power Research Institute, the
NERC, and the East Central Area Reliability Agreement group to
capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning. The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is clearly much more
work to be done, we have found that North America's electric
power supply and delivery systems are well on their way to being
Y2K ready."
The SEC requires that each company disclose its estimate of the
"most reasonably likely worst case scenario" of a negative Y2K
event. Since the Company and the industry are working diligently
to avoid any disruption of electric service, the Company does not
believe it or its customers will experience any significant long-
term disruptions of electric service. It is the Company's
opinion that the "most reasonably likely worst case scenario" is
that there could be isolated problems at various Company
facilities or at the facilities of neighboring utilities that may
have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service. All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.
M-34
Monongahela Power Company
The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems. Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions. To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning. While outside contractors and equipment vendors will
be employed for some of the work, the Company believes it must
rely on System employees for most of the effort because of their
experience with the Company's systems and equipment. The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $4 to $5 million. Of that amount, about $2
million has been incurred through 1998.
The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act. Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995. Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning activities. There
can be no assurance that actual results will not materially
differ from expectations.
M-35
The Potomac Edison Company
1998 Financial Statements
The Potomac Edison Company
Part of Allegheny Energy
M-36
The Potomac Edison Company
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995. These include
statements with respect to deregulation activities and movements
toward competition in states served by The Potomac Edison Company
(the Company), the proposed merger of Allegheny Energy, Inc.
(Allegheny Energy) with DQE, Inc. (DQE), parent company of
Duquesne Light Company in Pittsburgh, Pa., and results of
operations. All such forward-looking information is necessarily
only estimated. There can be no assurance that actual results
will not materially differ from expectations. Actual results
have varied materially and unpredictably from past expectations.
Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which the Company
operates, including regulatory proceedings affecting rates
charged by the Company; environmental, legislative, and
regulatory changes; future economic conditions; developments
relating to the proposed merger of Allegheny Energy with DQE,
including expenses that may be incurred in litigation; and other
circumstances that could affect anticipated revenues and costs
such as significant volatility in the market price of wholesale
power, unscheduled maintenance or repair requirements, weather,
and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
Merger with DQE
See Page 8 and also Note B to the financial statements for
information about the proposed merger of Allegheny Energy with
DQE.
Maryland Settlement and Deregulation
The Company reached a settlement agreement with various parties
on the Office of People's Counsel's petition for a reduction in
the Company's Maryland rates. Further information on the
settlement agreement is provided under Sales and Revenues
starting on page 2.
On July 1, 1998, the Company filed testimony in Maryland's
investigation into transition costs, price protection, and
unbundled rates. See Electric Energy Competition on page 8 for
more information regarding the restructuring in Maryland.
M-37
The Potomac Edison Company
Internal Restructuring
In 1994, the Allegheny Energy integrated electric utility system
(the System), including the Company, initiated an internal
restructuring process to consolidate and re-engineer their
utility operations to meet the competitive challenges of the
changing electric utility industry. As a result of this process,
the System reduced employment by about 1,000 employees through a
voluntary separation plan, attrition and layoffs, and changed
processes to obtain efficiencies to reduce operating and
maintenance (O&M) costs. This process resulted in internal
restructuring charges in 1996 as described in Note C to the
financial statements.
REVIEW OF OPERATIONS
Earnings Summary
Earnings
(Millions of Dollars) 1998 1997 1996
Operations................................... $101.5 $95.8 $94.7
Expenses related to internal
restructuring activities................... 16.5
Net Income................................... $101.5 $95.8 $78.2
The increase in 1998 earnings from operations resulted from
increased kilowatt-hour (kWh) sales to retail customers and from
reduced power station O&M spending. The 1996 restructuring costs
resulted from internal restructuring initiated in 1994 which is
described in Note C to the financial statements and Internal
Restructuring on page 1. The increase in 1997 earnings from
operations resulted primarily from reductions in O&M expenses
from the internal restructuring process and additional actions
taken during the year to achieve further O&M reductions in
response to significant decreases in kWh sales to residential
customers caused primarily by mild weather. Also contributing to
the increase was additional revenues due to a change in
allocation of affiliated transmission services and an interest
refund on a tax-related contract settlement by the Company's 28%
owned subsidiary, Allegheny Generating Company (AGC), recorded in
other income as increased equity in earnings of AGC.
Sales and Revenues
Percentage changes in revenues and kWh sales in 1998 and 1997 by
major retail customer classes were:
1998 vs. 1997 1997 vs. 1996
Revenues kWh Revenues kWh
Residential................... 3.1% 2.6% (7.5)% (6.7)%
Commercial.................... 5.9 7.2 1.3 1.9
Industrial.................... 4.3 5.9 .7 .5
Total....................... 4.1% 5.0% (3.2)% (1.9)%
The changes in residential kWh sales, which are more weather
sensitive than the other classes, were due primarily to changes
in customer usage because of
M-38
The Potomac Edison Company
weather conditions. The growth in
the number of residential customers was 1.9% and 1.8% in 1998 and
1997, respectively. The weather in 1997 was mild in both the
early and late winter and in the summer, causing the 6.7%
decrease in residential kWh sales.
Commercial kWh sales are also affected by weather, but to a
lesser extent than residential. The 7.2% increase in 1998
reflects increased usage due to weather and commercial activity
as well as growth in the number of customers. The 1.9% increase
in 1997 reflects growth in the number of customers.
The increases in industrial kWh sales in 1998 and 1997 reflect a
trend of continued economic growth in the service territory. The
increase in 1998 also reflects increased sales to paper and
printing customers and to the Eastalco aluminum reduction plant.
On August 7, 1998, the Virginia State Corporation Commission
(Virginia SCC) approved an agreement reached between the Company
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.
In 1999, revenues will reflect a reduction for a settlement
agreement with various parties on the Maryland Office of People's
Counsel's petition for a reduction in the Company's Maryland
rates. The agreement, which includes recognition of costs to be
incurred from the Applied Energy Services (AES) Warrior Run
cogeneration project being developed under the Public Utility
Regulatory Policies Act of 1978 (PURPA), was approved by the
Maryland Public Service Commission (Maryland PSC) on October 27,
1998. Under the terms of that agreement, the Company will
increase its rates about 4% ($13 million) in each of the years
1999, 2000, and 2001 (a $39 million annual effect in 2001). The
increases are designed to recover additional costs of about $131
million over the period 1999-2001 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 1999-2001 time frame results in a pre-tax
income reduction of $12 million in 1999, $18 million in 2000, and
$22 million in 2001. In addition, the settlement requires that
the Company share, on a 50% customer, 50% shareholder basis,
earnings above a return on equity of 11.4% for 1999-2001. This
sharing will occur through an annual true-up.
Changes in revenues from retail customers resulted from the
following:
Changes from Prior Year
(Millions of Dollars) 1998 vs. 1997 1997 vs. 1996
Fuel clauses............................. $10.9 $ (9.6)
All other................................ 15.4 (11.4)
Net change in retail revenues.......... $26.3 $(21.0)
Revenues reflect not only changes in kWh sales and base rate
changes, but also any changes in revenues from fuel and energy
cost adjustment clauses (fuel clauses) which have little effect
on net income because increases and decreases in fuel and
purchased power costs and sales of transmission services and bulk
power are passed on to customers by adjustment of customers'
bills through fuel clauses.
M-39
The Potomac Edison Company
All other is the net effect of kWh sales changes due to changes
in customer usage (primarily weather for residential customers),
growth in the number of customers, and changes in pricing other
than changes in general tariff and fuel clause rates. The
increase in 1998 all other retail revenues was primarily the
result of increased customer usage and growth in the number of
customers. The decrease in 1997 all other retail revenues is
primarily the result of mild weather in 1997.
Wholesale and other revenues were as follows:
(Millions of Dollars) 1998 1997 1996
Wholesale customers....................... $23.5 $26.6 $29.1
Affiliated companies...................... 9.4 9.7 2.5
Street lighting and other................. 5.5 2.6 3.3
Total wholesale and other revenues...... $38.4 $38.9 $34.9
Wholesale customers are cooperatives and municipalities that own
their own distribution systems and buy all or part of their bulk
power needs from the Company under Federal Energy Regulatory
Commission (FERC) regulation. Competition in the wholesale
market for electricity was initiated by the National Energy
Policy Act of 1992, which permits wholesale generators, utility-
owned and otherwise, and wholesale customers to request from
owners of bulk power transmission facilities a commitment to
supply transmission services. Five-year contracts have been
signed (one in 1997 with an expiration date in 2002 with
estimated annual revenues of $3 million, and four in 1998 with
expiration dates in 2003 with estimated annual revenues of $19
million) with the Company's wholesale customers allowing the
Company to continue as their wholesale supplier. The decrease in
wholesale revenues in 1998 was primarily due to the mild 1998
winter weather. The decrease in wholesale revenues in 1997 was
primarily due to the reduced electricity requirements of one
wholesale customer caused by the shut-down in early 1997 of a
large fiber plant on the wholesale customer's system.
Revenues from affiliated companies represent sales of energy and
intercompany allocations of generating capacity, generation
spinning reserves, and transmission services pursuant to a power
supply agreement among the Company and the other regulated
utility subsidiaries of Allegheny Energy. The increase in such
revenues in 1997 resulted primarily from an increase in the
allocation of transmission services revenues ($5.3 million) to
the Company.
The increases in street lighting and other revenues in 1998 were
primarily due to the recording in 1998 of pole attachment
revenues for 1998 and 1997.
M-40
The Potomac Edison Company
Bulk power transactions include sales of bulk power and
transmission services to power marketers and other utilities.
Bulk power and transmission services sales for 1998, 1997, and
1996 were as follows:
1998 1997 1996
KWh Transactions (in billions):
Bulk power................................ .4 .4 .3
Transmission services to
nonaffiliated companies................. 2.5 4.0 5.6
Total................................. 2.9 4.4 5.9
Revenues (in millions):
Bulk power................................ $11.7 $10.0 $ 7.6
Transmission services to
nonaffiliated companies................. 14.7 13.6 16.9
Total................................. $26.4 $23.6 $24.5
The 1998 increase in revenues from bulk power was due to
increased sales that occurred primarily in the second quarter as
a result of warm weather which increased the demand and price for
energy. In 1998, revenues from transmission 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 recently approved by the FERC. A provision
of $2.2 million for these rate reductions was recorded in 1998,
with the revenues to be refunded to customers in the first
quarter of 1999.
Revenues from transmission services to nonaffiliated companies 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. Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used. Revenues from transmission services to
nonaffiliated companies in 1997 decreased due to reduced demand,
primarily because of mild weather.
In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level. These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The costs of purchased power and revenues from sales to
power marketers and other utilities, including transmission
services, are currently recovered from or credited to customers
under fuel and energy cost recovery procedures. The impact to the
fuel and energy cost recovery clauses, either positively or
negatively, depends on whether the Company is a net buyer or
seller of electricity during such periods. The impact of such
price volatility in June and the third quarter of 1998 was
insignificant to the Company because changes are passed through
to customers through operation of fuel clauses.
Operating Expenses
Fuel expenses increased 2.1% in each of the years 1998 and 1997
due to increases in kWhs generated. The increases in kWhs
generated were primarily the result of increased bulk power sales
to power marketers and other utilities and in 1998 also due to
increased sales to retail customers.
M-41
The Potomac Edison Company
Purchased power and exchanges, net, represents power purchases
from and exchanges with other companies, capacity charges paid to
AGC, and other transactions with affiliates made pursuant to a
power supply agreement whereby each company uses the most
economical generation available in the System at any given time,
and consists of the following items:
(Millions of Dollars) 1998 1997 1996
Nonaffiliated transactions:
Purchased power.......................... $ 15.2 $ 13.2 $ 14.8
Power exchanges, net..................... (.1) 1.7
Affiliated transactions:
AGC capacity charges..................... 23.8 25.5 26.9
Other affiliated capacity charges........ 42.9 50.8 47.7
Energy and spinning reserve charges...... 56.5 50.7 49.9
Purchased power and exchanges, net..... $138.3 $140.2 $141.0
The increase in purchased power in 1998 resulted primarily from
increased purchases for sales. An increase in price caused by
volatility in the spot prices for electricity at the wholesale
level in the second and third quarters of 1998 also contributed
to the increase. Purchased power in 1997 decreased because of
decreased demand due to decreased sales to retail customers
related to mild 1997 weather. The increase in affiliated energy
and spinning reserve charges was due to an increase in retail kWh
sales.
The AES Warrior Run PURPA cogeneration project in the Company's
Maryland service territory, scheduled to commence generation in
October 1999, will increase the cost of power purchases $60
million or more annually. The settlement, described under Sales
and Revenues starting on page 2, is designed to recover all such
costs through 2001.
The increase in other operation expenses in 1998 resulted
primarily from increased expenses related to competition in
Maryland ($1.6 million), an increase in expense related to Year
2000 Readiness, and increases in salaries and wages and employee
benefits. These expenses were partially offset by a reduction in
expenses related to provisions for uninsured claims. Other
operation expenses in 1997 include $1.2 million for increased
allowances for uncollectible accounts. Nevertheless, other
operation expense decreased in 1997 because of a reduction in
embedded expenses achieved through the 1996 internal
restructuring process.
The decrease in maintenance expenses 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 is postponing these expenses
primarily by extending the time between maintenance outages. The
1997 decrease in maintenance expenses resulted from reduced
expenses achieved through internal restructuring efforts and
other cost controls. Maintenance expenses represent costs
incurred to maintain the power stations, the transmission and
distribution (T&D) system, and general plant, and reflect routine
maintenance of equipment and rights-of-way, as well as planned
major repairs and unplanned expenditures, primarily from forced
outages at the power stations and periodic storm damage on the
T&D system. Variations in maintenance expense result primarily
from unplanned events and planned major projects, which vary in
timing and magnitude depending upon the length of time equipment
has been
M-42
The Potomac Edison Company
in service without a major overhaul and the amount of
work found necessary when the equipment is dismantled.
Internal restructuring charges in 1996 resulted from internal
restructuring activities, which have been completed.
Depreciation expense increases resulted from increased
investment.
The increase in taxes other than income taxes of $2 million in
1998 was primarily due to an increase in gross receipts taxes
resulting from greater revenues from retail customers and
increased property taxes. The increase in taxes other than
income taxes of $1.8 million in 1997 was due to increased
property taxes and capital stock and franchise taxes related to
an increase in the assessment of property in Maryland.
The 1998 and 1997 increases in federal and state income taxes
were primarily due to increased income before taxes. Note D to
the financial statements provides a further analysis of income
tax expenses.
The decrease in allowance for other than borrowed funds used
during construction of $1.1 million in 1998 resulted primarily
from adjustments of prior periods.
The decrease in other income, net, of $4.7 million in 1998 and
the increase in 1997 of $2.2 million was primarily due to a 1997
interest refund on a tax-related contract settlement ($2.5
million, net of taxes) received by the Company's subsidiary, AGC.
The decrease in interest on long-term debt in 1998 of $1.6
million resulted from reduced long-term debt and lower interest
rates. Other interest expense reflects changes in the levels of
short-term debt maintained by the Company throughout the year, as
well as the associated interest rates.
FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the
sale of common and preferred stock, debt instruments, installment
loans, and lease arrangements. The timing and amount of external
financings depend primarily upon economic and financial market
conditions, the Company's cash needs, and capitalization ratio
objectives. The availability and cost of external financings
depend upon the financial health of the companies seeking those
funds and market conditions.
Construction expenditures in 1998 were $61 million and, for 1999
and 2000, are estimated at $86 million and $98 million,
respectively. The 1999 and 2000 estimated expenditures include
$17 million and $22 million, respectively, for construction of
environmental control technology. It is the Company's goal to
constrain future construction spending to the approximate level
of depreciation currently in rates. The Company also has
additional capital requirements for debt maturities (see Note I
to the financial statements).
M-43
The Potomac Edison Company
Internal Cash Flow
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $187 million in 1998,
compared with $87 million in 1997. The increase in 1998 cash
flows resulted primarily from a reduction in the level of common
stock dividends payable to its Parent, Allegheny Energy, Inc.
Reduced 1997 cash flow was primarily the result of payment of
internal restructuring liabilities. Current rate levels and
reduced levels of construction expenditures permitted the Company
to finance all of its construction expenditures in 1998 and 1997
with internal cash flow. As described under Environmental Issues
starting on page 10, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues. Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues.
Financing
Short-term debt is used to meet temporary cash needs. The
Company had no short-term debt outstanding at December 31, 1998
or December 31, 1997. At December 31, 1998, the Company had
Securities and Exchange Commission (SEC) authorization to issue
up to $130 million of short-term debt. The Company and its
regulated affiliates use an Allegheny Energy internal money pool
as a facility to accommodate intercompany short-term borrowing
needs, to the extent that certain of the companies have funds
available. The Company anticipates meeting its 1999 cash needs
through internal cash generation, cash on hand, and short-term
borrowings as necessary.
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy believes that DQE's basis for seeking to
terminate the merger (described in Note B to the financial
statements) is without merit. Accordingly, Allegheny Energy
continues to seek the remaining regulatory approvals from the
Department of Justice and the SEC. It is not likely either
agency will act on the request unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.
Electric Energy Competition
The electricity supply segment of the electric utility industry
in the United States is in the midst of becoming a competitive
marketplace. The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems. Since 1992, the wholesale
electricity market has become increasingly competitive as
companies began to engage in nationwide power trading. In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries of Allegheny
Energy have investigated or implemented retail access to
alternate electricity suppliers. 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. In the absence of federal legislation,
state-by-state implementation has begun.
M-44
The Potomac Edison Company
The Company has franchised regulated customers in Maryland,
Virginia, and West Virginia.
In Maryland, the Maryland PSC in December 1997 issued an Order to
implement retail competition in that state. The Maryland PSC's
Order and its revised second Order call for a deregulation
process, including a three-year phase-in beginning July 1, 2000,
with recovery of prudent transition costs after mitigation. On
September 10, 1998, the Maryland PSC issued a third Order which
clarified certain issues and questions involved with the earlier
Orders. A court-approved settlement of appeals of these orders
provides that the Maryland PSC orders are not final. Roundtable
discussions created by the Orders have been held since April
1998. The roundtable's final report to the Maryland PSC is due
May 1, 1999, and the Maryland PSC's final Order in connection
with the work of the roundtable is due August 1, 1999. As
required by the Maryland PSC, the Company, on July 1, 1998, filed
testimony in Maryland's investigation into transition costs,
price protection, and unbundled rates. The filing requested
recovery of transition costs and a surcharge to recover the cost
of the AES Warrior Run cogeneration project
which is scheduled to commence production on October 1, 1999.
Hearings are scheduled to begin in April 1999. Several
electricity competition bills have been introduced in the 1999
legislative session, and we continue to support bringing customer
choice to Maryland customers.
In Virginia, a Subcommittee of the Virginia General Assembly
studied electric utility restructuring and made recommendations
to the General Assembly throughout 1998. The process led to the
introduction of detailed restructuring legislation in both the
House and Senate in the 1999 session. The legislation would
implement a transition to choice beginning in 2002. The Senate
passed the bill and referred it to the House. We expect the bill
to be signed into law this year.
In West Virginia, the Public Service Commission of West Virginia
(W.Va. PSC) issued an Order in December 1996 initiating a general
investigation regarding the restructuring of the regulated
electric utility industry. A task force was established to
further investigate restructuring issues. Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the legislation, and to then submit that plan to the
Legislature for review and possible approval. The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections.
The status of electric energy competition in Ohio and
Pennsylvania in which affiliates of the Company serve are as
follows:
In Ohio, the Public Utilities Commission of Ohio has continued
informal roundtable discussions on issues concerning competition
in the electric utility industry. The Governor established a
legislative committee from members of both the Senate and House
to further review issues regarding deregulation. Several bills
on restructuring and deregulation have been introduced in the
Ohio Legislature and are subject to continuing hearings and
negotiations at the committee level. The Company's affiliate,
Monongahela Power Company, is subject to these discussions and
hearings.
M-45
The Potomac Edison Company
In Pennsylvania, the Electricity Generation Customer Choice and
Competition Act has created retail access to a competitive
electric energy market. The Company's Pennsylvania affiliate,
West Penn Power Company (West Penn), is subject to this Act.
Beginning in January 1999, two-thirds of West Penn's customers
were permitted to choose an alternate electricity supplier.
Remaining West Penn customers can do so in January 2000. As a
result of a Pennsylvania Public Utility Commission (Pennsylvania
PUC) Order and settlement agreement, West Penn determined that
under the provisions of Statement of Financial Accounting
Standards No. 101, "Accounting for the Discontinuation of
Application of FASB Statement No. 71," in 1998 an extraordinary
charge of $466.9 million ($275.4 million after taxes) was
required to reflect a write-off of certain disallowances. In
addition, charges of $40.3 million ($23.7 million after taxes)
related to West Penn's revenue refund and energy program payments
were also recorded.
Fully meeting challenges in the emerging competitive environment
will be challenging for the Company unless certain outmoded and
anti-competitive laws, specifically the Public Utility Holding
Company Act of 1935 (PUHCA) and Section 210 of PURPA, are
repealed or significantly revised. Allegheny Energy continues to
advocate the repeal or reform of PUHCA and PURPA on the grounds
that they are obsolete and anti-competitive, and that PURPA, in
particular, results in utility customers paying above-market
prices for power.
Business Strategy
Generation will continue to be a core part of Allegheny Energy's
business. Allegheny Energy's goal is to grow generation through
building and buying generating facilities. The energy delivery
or wires business will also continue to be a core part of
Allegheny Energy's business. Allegheny Energy plans to expand
the energy delivery business primarily through acquisitions of
other electric distribution properties.
The settlement agreement for the Company's affiliate, West Penn,
in Pennsylvania permitted the transfer of its 3,722 MW of
generating capacity to a new, unregulated company that is
expected to be a wholly owned subsidiary of West Penn. West Penn
plans to transfer these generating assets at book value. The
unregulated generation will be sold in both the wholesale and
retail competitive marketplace, allowing greater earnings growth
potential, subject to market risk, while allowing Allegheny
Energy to capitalize on its strengths in the generation business.
Allegheny Energy continues to study ways to meet existing and
future increases in regulated customer demand, including new and
efficient electric technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the Company is subject to
various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.
M-46
The Potomac Edison Company
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 being recovered currently from
customers in rates. 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 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
Company's 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 suspended by
the proposed NOx State Implementation Plan (SIP) call rule
discussed below. 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.
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.
The Ozone Transport Assessment Group issued its final report in
June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 85% reduction from
the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the
regulatory process to adopt the recommendations and issued its
final NOx SIP call rule on September 24, 1998. The EPA's SIP
call rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone nonattainment in downwind
states. The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis. The final SIP call
rule requires that all state-adopted NOx reduction measures must
be incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.
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 mentioned above. In October 1998, the EPA proposed approval
of the petitions. However, the EPA believes implementation of
the NOx SIP call will alleviate the need to grant the petitions.
The EPA intends to issue a final rule by April 1999.
M-47
The Potomac Edison Company
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. State attainment
plans to meet the revised standards will not be developed for
several years. Also, in July 1997, the EPA proposed regional
haze regulations to improve visibility in Class I federal areas
(national parks and wilderness areas). If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities. The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of
the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time. All are being challenged by rulemaking,
petition, and/or the litigation process. Implementation dates
are also uncertain at this time, but could be as early as 2003,
which would require substantial capital expenditures in the 1999-
2000 period. The Company's construction forecast includes the
expenditure of $103 million of capital costs during the 1999-2003
period to comply with the SIP call.
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 will require the United
States to reduce emissions of GHG by 7% from 1990 levels in the
2008-2012 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 Unites 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 Unites 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 previously reported that the EPA had identified the
Company and its regulated affiliates as potentially responsible
parties, along with approximately 175 others, in a Superfund site
subject to cleanup. A final determination has not been made for
the Company's share of the remediation costs based on the amount
of materials sent to the site. The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs. 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.
Independent Transmission System Operator
Allegheny Energy conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of
M-48
The Potomac Edison Company
a proposed merger with DQE. The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998. Allegheny Energy's membership status
remains conditional upon the outcome of the merger. Many
industry participants, including customers and regulatory
authorities, believe that an entity independent of the utilities
which own the transmission systems is needed to operate the
systems to ensure nondiscriminatory access to the transmission
systems by all users. Should these beliefs result in a mandate,
Allegheny Energy may either voluntarily or involuntarily sustain
or achieve new membership in some form of Independent System
Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations, including
the Company, could experience serious problems related to
software and various equipment with embedded chips which may not
properly recognize calendar dates. To minimize such problems,
the Company and its affiliates in the System are proceeding with
a comprehensive effort to continue operations without significant
problems in 2000 and beyond. An Executive Task Force is
coordinating the efforts of 24 separate Y2K Teams, representing
all business and support units in the System.
In May 1998, the North American Electric Reliability Council
(NERC), of which the System is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts. The electric utility industry and the
System have segmented the Y2K problem into the following
components:
Computer hardware and software;
Embedded chips in various equipment; and
Vendors and other organizations on which the System relies for
critical materials and services.
The industry's and the System's efforts for each of these three
components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.
The NERC has established a goal of having the industry achieve a
state of Y2K readiness for critical systems by June 30, 1999,
and, to monitor progress, requires each utility to prepare and
submit a monthly report showing progress and dated plans. By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to
file contingency plans by that date. The System's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, cascading failure of the
entire electrical system. The System is working with the Edison
Electric Institute, the Electric Power Research Institute, the
NERC, and the East Central Area Reliability Agreement group to
capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning. The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is
M-49
The Potomac Edison Company
clearly much more work to be done, we have found that North
America's electric power supply and delivery systems are well
on their way to being Y2K ready."
The SEC requires that each company disclose its estimate of the
"most reasonably likely worst case scenario" of a negative Y2K
event. Since the Company and the industry are working diligently
to avoid any disruption of electric service, the Company does not
believe it or its customers will experience any significant long-
term disruptions of electric service. It is the Company's
opinion that the "most reasonably likely worst case scenario" is
that there could be isolated problems at various Company
facilities or at the facilities of neighboring utilities that may
have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service. All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.
The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems. Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions. To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning. While outside contractors and equipment vendors will
be employed for some of the work, the Company believes it must
rely on System employees for most of the effort because of their
experience with the Company's systems and equipment. The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $4 to $5 million. Of that amount, about $2
million has been incurred through 1998.
The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act. Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995. Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning activities. There
can be no assurance that actual results will not materially
differ from expectations.
M-50
West Penn Power Company
and Subsidiaries
1998 Financial Statements
West Penn Power Company
Part of Allegheny Energy
M-51
West Penn Power Company
and Subsidiaries
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995. These include
statements with respect to deregulation activities and movements
toward competition in Pennsylvania, the proposed merger of
Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa., and
results of operations. All such forward-looking information is
necessarily only estimated. There can be no assurance that
actual results will not materially differ from expectations.
Actual results have varied materially and unpredictably from past
expectations.
Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which West Penn Power
Company (the Company) operates, including regulatory proceedings
affecting rates charged by the Company; environmental,
legislative, and regulatory changes; future economic conditions;
developments relating to the proposed merger of Allegheny Energy
with DQE, including expenses that may be incurred in litigation;
and other circumstances that could affect anticipated revenues
and costs such as significant volatility in the market price of
wholesale power, unscheduled maintenance or repair requirements,
weather, and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
Pennsylvania Deregulation
On November 19, 1998, the Pennsylvania Public Utility Commission
(Pennsylvania PUC) approved a settlement agreement between the
Company and intervenors in the Company'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, the
Company determined that under the provisions of Statement of
Financial Accounting Standards No. 101, "Accounting for the
Discontinuation of Application of FASB Statement No. 71," an
extraordinary charge of $466.9 million ($275.4 million after
taxes) was required to reflect a write-off of certain
disallowances. In addition, charges of $40.3 million ($23.7
million after taxes) related to the Company's revenue refund and
energy program payments were also recorded.
Under the terms of the settlement agreement, two-thirds of the
Company's customers were permitted to choose an alternate
generation supplier beginning in January 1999. All of the
Company's customers can do so beginning in January 2000. They
can also choose to remain as a customer at the Company's capped
generation rates or to alternate back and forth. Under the law,
all electric utilities, including the Company, retain the
responsibility of electricity provider of last resort to all
customers in their respective
M-52
West Penn Power Company
and Subsidiaries
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.
Merger with DQE
See page 9 and also Note D to the consolidated financial
statements for information about the proposed merger of Allegheny
Energy with DQE.
PURPA Power Project Terminations
On August 26, 1997, and December 3, 1997, the Company 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 the Company
to buy 43 megawatts (MW) and 80 MW of capacity and energy,
respectively, over the lives of the projects at prices well above
current market price estimates. In 1996, the Company and the
developers of a proposed Shannopin PURPA project reached an
agreement to terminate that project at a buyout price of $31
million. The Shannopin buyout will reduce the Company's costs
approximately $665 million over 30 years by eliminating the need
to buy the uneconomic power.
Internal Restructuring
In 1994, the Allegheny Energy integrated electric utility system
(the System), including the Company, initiated an internal
restructuring process to consolidate and re-engineer their
utility operations to meet the competitive challenges of the
changing electric utility industry. As a result of this process,
the System reduced employment by about 1,000 employees through a
voluntary separation plan, attrition and layoffs, and changed
processes to obtain efficiencies to reduce operating and
maintenance (O&M) costs. This process resulted in internal
restructuring charges and an asset write-off in 1996 as described
in Note E to the consolidated financial statements.
REVIEW OF OPERATIONS
Earnings Summary
Earnings
(Millions of Dollars) 1998 1997 1996
Consolidated income before
restructuring activities................... $ 136.3 $134.7 $119.9
Costs related to restructuring
activities, net of taxes*.................. (23.7) (31.4)
Extraordinary charge, net of taxes (Notes B
and C to consolidated financial
statements)................................ (275.4)
Consolidated Net (Loss) Income............... $(162.8) $134.7 $ 88.5
*Pennsylvania deregulation settlement costs in 1998 and internal
restructuring costs in 1996.
M-53
West Penn Power Company
and Subsidiaries
The increase in 1998 consolidated income before costs related to
Pennsylvania restructuring and settlement activities, resulted
primarily from increased bulk power transactions and from reduced
power station O&M spending. The 1998 costs from restructuring
activities and the extraordinary charge are related to
Pennsylvania deregulation and the Pennsylvania restructuring
Order. These costs are described in Notes B and C to the
consolidated financial statements. The 1996 restructuring costs
resulted from internal restructuring initiated in 1994 which is
described in Note E to the consolidated financial statements and
Internal Restructuring on page 2. The increase in 1997
consolidated income before restructuring activities resulted
primarily from reductions in O&M expenses from the internal
restructuring process and additional actions taken during the
year to achieve further O&M reductions in response to significant
decreases in residential kilowatt-hour (kWh) sales caused
primarily by mild weather. The reductions from the internal
restructuring process were offset in part by a change in
allocation of affiliated transmission services which resulted in
higher charges to the Company. Also contributing to the 1997
increase was a $3.6 million (after tax) interest refund on a tax-
related contract settlement by the Company's 45% owned
subsidiary, Allegheny Generating Company (AGC), recorded in other
income as increased equity in earnings of AGC, a gain on a sale
of land by a subsidiary of $2.8 million (after tax), and
decreased depreciation expense.
Sales and Revenues
Total operating revenues for 1998, 1997, and 1996 were as
follows:
(Millions of Dollars) 1998 1997 1996
Operating revenues:
Bundled retail sales.................... $ 920.1 $ 973.6 $ 988.9
Unbundled retail sales.................. 14.0 2.5
Wholesale and other*.................... 75.7 65.5 67.3
Bulk power and transmission
services sales........................ 68.9 40.6 32.9
Total operating revenues............ $1,078.7 $1,082.2 $1,089.1
*Excludes street lighting sales which are
included in bundled retail sales. $7.3 $7.0 $7.0
Bundled retail sales revenues (full service sales to retail
customers) include a $25.1 million rate refund from 1998
revenues, pursuant to the terms of the Pennsylvania restructuring
settlement agreement. This refund to customers will be made in
1999. Excluding this rate decrease, bundled retail sales
revenues decreased $28.4 million in 1998 primarily due to
previously fully bundled customers participating in the
Pennsylvania pilot by buying energy from another supplier of
their choice. As a result of the Company's nonutility affiliate,
Allegheny Energy Solutions, being permitted to sell to all
Pennsylvania customers participating in the pilot, Allegheny
Energy was able to recover some of the Company's generation sales
lost as a result of customers participating in the Pennsylvania
pilot program. Retail sales include sales to residential,
commercial, industrial, and street lighting customers. Bundled
retail sales revenues were affected by the Electricity Generation
Customer Choice and Competition Act (Customer Choice Act) in
Pennsylvania. As part of the Customer Choice Act, all utilities
in Pennsylvania were required to administer retail access pilot
programs under
M-54
West Penn Power Company
and Subsidiaries
which customers, representing 5% of the load of
each rate class, would choose a generation supplier other than
their own local franchise utility. As a result, 5% of previously
fully bundled customers participated in the Pennsylvania pilot
program and were required to buy energy from another supplier of
their choice. The pilot program began on November 1, 1997, and
continued through December 31, 1998. Unbundled retail sales
revenues represent transmission and distribution revenues from
Pennsylvania pilot customers who chose another supplier to
provide their energy needs.
To assure participation in the pilot program, pilot participants
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, with the result that the
Company incurred a revenue loss of $6.5 million for the pilot.
The Pennsylvania PUC has approved the Company's pilot compliance
filing and thus has indicated its intent to treat the revenue
loss as a regulatory asset. Wholesale and other revenues include
an accrual of such revenue losses, as well as sales to wholesale
customers (cooperatives and municipalities that own their own
distribution systems and buy all or part of their bulk power
needs from the Company under Federal Energy Regulatory Commission
(FERC) regulation) and non-kWh revenues. All of the Company's
wholesale customers have signed contracts to remain as customers
through at least November 2001.
Effective May 1, 1997, as a result of the Customer Choice Act,
the Company obtained Pennsylvania PUC authorization to set its
fuel clause to zero and to roll its then-applicable fuel clause
rates into base rates. Thereafter, the Company assumed the risks
and benefits of changes in fuel and purchased power costs and
sales of transmission services and bulk power. The decrease in
1997 bundled retail revenues resulted primarily from a decrease
in the fuel component of revenues and a decrease in residential
kWh sales due to mild weather in 1997.
The increase in wholesale and other revenues in 1998 was due
primarily to deferred net revenue losses. The Company recorded
a regulatory asset of $6.4 million in 1998 and $.1 million in
1997 to offset revenue losses suffered as a result of the pilot
program.
Bulk power transactions includes sales of bulk power and
transmission services to power marketers and other utilities.
Bulk power and transmission services sales for 1998, 1997, and
1996 were as follows:
1998 1997 1996
KWh Transactions (in billions):
Bulk power............................... 2.3 1.0 0.4
Transmission services to
nonaffiliated companies................ 3.0 5.4 7.6
Total................................ 5.3 6.4 8.0
Revenues (in millions):
Bulk power............................... 49.6 22.2 10.0
Transmission services to
nonaffiliated companies................ 19.3 18.4 22.9
Total................................ 68.9 40.6 32.9
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The 1998 increase in revenues from bulk power was due to
increased sales that occurred primarily in the second quarter as
a result of warm weather which increased the demand and price for
energy. In 1998, revenues from transmission 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 recently approved by the FERC. A provision
of $2.9 million for these rate reductions was recorded in 1998,
with the revenues to be refunded to customers in the first
quarter of 1999.
Revenues from transmission services to nonaffiliated companies 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. Transmission services activity was
affected as a result of some of the reservations to transmit
energy not being used. Revenues from transmission services to
nonaffiliated companies in 1997 decreased due to reduced demand,
primarily because of mild weather.
In June and July 1998, certain events combined to produce
significant volatility in the spot prices for electricity at the
wholesale level. These events included extremely hot weather,
Midwest generation unit outages, and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The potential exists for such volatility to significantly
affect the Company's operating results. The effect may be either
positive or negative, depending on whether the Company is a net
buyer or seller of electricity during such periods, and the open
commitments which exist at such times.
Operating Expenses
Fuel expenses in 1998 and 1997 increased 1.6% and 6.2%,
respectively, due primarily to increases in kWhs generated. The
increases in kWhs generated were primarily the result of
increased bulk power sales to power marketers and other
utilities.
Purchased power and exchanges, net, represents power purchases
from and exchanges with other companies and purchases from
qualified facilities under PURPA, capacity charges paid to AGC,
and other transactions with affiliates made pursuant to a power
supply agreement whereby each company uses the most economical
generation available in the System at any given time, and
consists of the following items:
(Millions of Dollars) 1998 1997 1996
Nonaffiliated transactions:
Purchased power:
From PURPA generation*................ $ 63.5 $ 65.1 $ 63.6
Other................................. 23.2 18.4 22.3
Power exchanges, net.................... (.3) .2 .7
Affiliated transactions:
AGC capacity charges.................... 31.5 32.4 36.3
Energy and spinning reserve charges..... 3.4 3.9 4.0
Purchased power and exchanges, net.... $121.3 $120.0 $126.9
*PURPA cost (cents per kWh) 5.8 6.0 5.8
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The increase in other purchased power in 1998 resulted primarily
from increased purchases for sales. An increase in price caused
by volatility in the spot prices for electricity at the wholesale
level in the second and third quarters of 1998 also contributed
to the increase. The decrease in other purchased power in 1997
was a result of decreased demand due to decreased sales to retail
customers related to mild 1997 weather.
None of the Company's purchased power contracts are capitalized
since there are no minimum payment requirements absent associated
kWh generation.
PURPA purchased power costs will be reduced $197 million during
the period 1999-2016 related to the Applied Energy Services
Corporation's Beaver Valley nonutility generation 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 operation expenses in 1998 was due
primarily to increased expenses related to competition and the
Pennsylvania restructuring Order. See Note B to the consolidated
financial statements for additional information related to
Pennsylvania restructuring. The increase in other operation
expenses in 1997 was primarily due to increased transmission
services cost allocations from affiliated companies under the
power supply agreement ($10.1 million) and Pennsylvania pilot-
related expenses. Other operation expense for 1997 also includes
$4.4 million of legal expenses incurred by the Company to defend
itself against an antitrust lawsuit filed by the developers of
the proposed Washington Power PURPA project. The dispute was
settled in December 1997. These expenses more than offset the
reduction in embedded expenses achieved through the 1996 internal
restructuring process.
The decrease in maintenance expenses 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 is postponing these expenses
primarily by extending the time between maintenance outages. The
1997 decrease in maintenance expenses resulted from reduced
expenses achieved through internal restructuring efforts and
other cost controls. Maintenance expenses represent costs
incurred to maintain the power stations, the transmission and
distribution (T&D) system, and general plant, and reflect routine
maintenance of equipment and rights-of-way, as well as planned
major repairs and unplanned expenditures, primarily from forced
outages at the power stations and periodic storm damage on the
T&D system. Variations in maintenance expense result primarily
from unplanned events and planned major projects, which vary in
timing and magnitude depending upon the length of time equipment
has been in service without a major overhaul and the amount of
work found necessary when the equipment is dismantled.
Internal restructuring charges and an asset write-off in 1996
resulted from internal restructuring activities, which have been
completed, and the write-off of previously accumulated costs
related to a proposed transmission line.
Higher depreciation expense in 1998 resulted from increased
investment. The decrease in depreciation expense in 1997 was the
result of a change in the retirement dates for the Mitchell power
station and the Pleasants power station scrubbers.
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The decrease in federal and state income taxes in 1998 resulted
primarily from a decrease in income before taxes, primarily
because of costs related to restructuring activities recorded in
1998. The 1997 increase in federal and state income taxes was
primarily due to increased income in 1997 compared with 1996.
Note F to the consolidated financial statements provides a
further analysis of income tax expenses.
The decrease in allowance for other than borrowed funds used
during construction of $1.5 million in 1998 reflects lower-cost
short-term debt financing. The allowance for borrowed funds used
during construction component of the formula receives greater
weighting when short-term debt increases. The decrease also
reflects adjustments of prior periods. Starting in July 1998, as
a result of the Pennsylvania restructuring, the Company stopped
accruing allowance for funds used during construction and began
accruing capitalized interest for generation construction
projects. Capitalized interest is reported within allowance for
borrowed funds used during construction.
The decrease in other income, net, of $6.2 million in 1998 and
the increase in 1997 of $4.1 million was primarily due to 1997
increases for an interest refund on a tax-related contract
settlement ($3.6 million, net of taxes) received by the Company's
subsidiary, AGC, and income on the sale of land ($2.8 million,
net of taxes) by the Company's subsidiary, West Virginia Power
and Transmission Company.
The decrease in interest on long-term debt in 1998 of $3.3
million resulted from reduced long-term debt and lower interest
rates.
Other interest expense reflects changes in the levels of short-
term debt maintained by the Company throughout the year, as well
as the associated interest rates. The decrease in other interest
expense in 1997 resulted primarily from decreased interest due to
reduced overcollections of the fuel cost portion of customer
billings.
The extraordinary charge 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 as described in Notes B and C to the consolidated
financial statements.
FINANCIAL CONDITION, REQUIREMENTS, AND RESOURCES
Liquidity and Capital Requirements
To meet cash needs for operating expenses, the payment of
interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the
sale of common and preferred stock, debt instruments, installment
loans, and lease arrangements. The timing and amount of external
financings depend primarily upon economic and financial market
conditions, the Company's cash needs, and capitalization ratio
objectives. The availability and cost of external financings
depend upon the financial health of the companies seeking those
funds and market conditions.
Construction expenditures in 1998 were $96 million and, for 1999
and 2000, are estimated at $119 million and $106 million,
respectively. The 1999 and 2000 estimated expenditures include
$33 million and $43 million, respectively, for construction of
environmental control technology. It is
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the Company's goal to constrain future utility construction
spending to the approximate level of depreciation currently
in rates. The Company also has additional capital requirements
for debt maturities (see Note L to the consolidated financial statements).
Internal Cash Flow
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $151 million in 1998,
compared with $103 million in 1997. Reduced 1997 cash flow was
the result of the $48 million buyout of the Washington Power
PURPA project and payment of internal restructuring liabilities.
Current rate levels and reduced levels of construction
expenditures permitted the Company to finance all of its
construction expenditures in 1998 and nearly all in 1997 with
internal cash flow. As described under Environmental Issues
starting on page 11, the Company could potentially face
significant mandated increases in construction expenditures and
operating costs related to environmental issues. Whether the
Company can continue to meet the majority of its construction
needs with internally generated cash is largely dependent upon
the outcome of these issues.
Financing
Short-term debt is used to meet temporary cash needs. Short-term
debt, including notes payable to affiliates under the money pool,
increased $13 million to $65 million in 1998. At December 31,
1998, the Company had Securities and Exchange Commission (SEC)
authorization to issue up to $182 million of short-term debt.
The Company and its regulated affiliates use an Allegheny Energy
internal money pool as a facility to accommodate intercompany
short-term borrowing needs, to the extent that certain of the
companies have funds available. The Company anticipates meeting
its 1999 cash needs through internal cash generation, cash on
hand, and short-term borrowings as necessary. However, the
Company is expected to issue up to $670 million of bonds to
"securitize" transition costs related to its restructuring
settlement described in Note B to the consolidated financial
statements.
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy believes that DQE's basis for seeking to
terminate the merger (described in Note D to the consolidated
financial statements) is without merit. Accordingly, Allegheny
Energy continues to seek the remaining regulatory approvals from
the Department of Justice and the SEC. It is not likely either
agency will act on the requests unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.
Electric Energy Competition
The electricity supply segment of the electric utility industry
in the United States is in the midst of becoming a competitive
marketplace. The Energy Policy Act of 1992 began the process of
deregulating the wholesale exchange of power within the electric
industry by permitting the FERC to compel electric utilities to
allow third parties to sell electricity to wholesale customers
over their transmission systems. Since 1992, the wholesale
electricity market has become increasingly competitive as
companies began to
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engage in nationwide power trading. In
addition, some states have taken active steps toward allowing
retail customers the right to choose their electricity supplier.
All of the states served by the utility subsidiaries of Allegheny
Energy have investigated or implemented retail access to
alternate electricity suppliers. Allegheny Energy has been an
advocate of federal legislation to create competition in the
retail electricity markets to avoid regional dislocations and
ensure level playing fields. In the absence of federal
legislation, state-by-state implementation has begun.
The Customer Choice Act in Pennsylvania has created retail access
to a competitive electric energy market. Pursuant to the
Customer Choice Act, all electric utilities in Pennsylvania were
required in 1998 to establish and administer retail access pilot
programs to 5% of the load of each class of their customers.
Beginning in January 1999, two-thirds of the Company's customers
were permitted to choose an alternate electricity supplier.
Remaining Company customers can do so in January 2000. See Note
B to the consolidated financial statements for additional
information on the settlement agreement reached with the
Pennsylvania PUC, which included transition costs and the ability
to transfer generating assets to an affiliate at net book value.
One result of the Customer Choice Act is the bifurcation of
electricity supply and electricity delivery into two separate
businesses. The transmission and distribution (wires) business
remains under the traditional regulated ratemaking, while the
electricity supply business in Pennsylvania is deregulated, and
its pricing will be determined by the marketplace. The wires
business will have responsibility as the electricity provider of
last resort and will generally obtain its electricity supply from
the market, primarily by competitive bidding. Provider of last
resort service will continue to be regulated and provided at
capped rates. The electricity supply business will be free to
sell the Company's generation capacity and energy in the open
wholesale and retail market, subject to codes of conduct and the
restriction that it may not sell at retail, except under certain
conditions, in the Company's service territory through 2003.
Because of these new regulations, the Company reorganized for
1999 into a Delivery Business (wires) and a Supply Business
(marketing capacity and energy). The Company's Delivery Business
will continue to provide transmission and distribution service
and will bill a Competitive Transition Charge to native load
customers exercising choice.
The status of electric energy competition in Maryland, Virginia,
West Virginia, and Ohio in which affiliates of the Company serve
are as follows.
In Maryland, the Maryland Public Service Commission (Maryland
PSC) in December 1997 issued an Order to implement retail
competition in that state. The Maryland PSC's Order and its
revised second Order, call for a deregulation process, including
a three-year phase-in beginning July 1, 2000, with recovery of
prudent transition costs after mitigation. The Maryland PSC
subsequently issued a third Order which clarified certain issues
and questions involved with the earlier Orders. A court-approved
settlement of appeals of these Orders provides that the Maryland
PSC Orders are not final. The Company's Maryland affiliate, The
Potomac Edison Company, is subject to these orders and appeals.
In Virginia, a Subcommittee of the Virginia General Assembly
studied electric utility restructuring and made recommendations
to the General Assembly throughout 1998. The process led to the
introduction of detailed
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restructuring legislation in both the
House and Senate in the 1999 session. The legislation would
implement a transition to choice beginning in 2002. The Senate
passed the bill and referred it to the House. It is expected
that the bill will be signed into law this year. The Company's
affiliate, The Potomac Edison Company, is subject to this action.
In West Virginia, the Public Service Commission of West Virginia
(W.Va. PSC) issued an Order in December 1996 initiating a general
investigation regarding the restructuring of the regulated
electric utility industry. A task force was established to
further investigate restructuring issues. Legislation passed in
March 1998 directed the W.Va. PSC to meet with all interested
parties to develop a restructuring plan, which meets the dictates
and goals of the legislation, and to then submit that plan to the
Legislature for review and possible approval. The W.Va. PSC has
since issued an Order setting a schedule for a series of hearings
this summer on major issues such as transition costs, codes of
conduct, and customer protections. The Company's affiliates,
Monongahela Power Company and The Potomac Edison Company, are
subject to this restructuring plan.
In Ohio, the Public Utilities Commission of Ohio has continued
informal roundtable discussions on issues concerning competition
in the electric utility industry. The Governor established a
legislative committee from members of both the Senate and House
to further review issues regarding deregulation. Several bills
on restructuring and deregulation have been introduced in the
Ohio Legislature and are subject to continuing hearings and
negotiations at the committee level. The Company's affiliate,
Monongahela Power Company, is subject to these discussions and
hearings.
Fully meeting challenges in the emerging competitive environment
will be challenging for Allegheny Energy unless certain outmoded
and anti-competitive laws, specifically the Public Utility
Holding Company Act of 1935 (PUHCA) and Section 210 of PURPA, are
repealed or significantly revised. Allegheny Energy continues to
advocate the repeal or reform of PUHCA and PURPA on the grounds
that they are obsolete and anti-competitive, and that PURPA, in
particular, results in utility customers paying above-market
prices for power.
Business Strategy
Generation will continue to be a core part of Allegheny Energy's
business. Allegheny Energy's goal is to grow generation through
building and buying generating facilities. The energy delivery
or wires business will also continue to be a core part of
Allegheny Energy's business. Allegheny Energy plans to expand
the energy delivery business primarily through acquisitions of
other electric distribution properties.
The Company's settlement agreement in Pennsylvania permitted the
transfer of the Company's 3,722 MW of generating capacity to a
new, unregulated, company that is expected to be a wholly owned
subsidiary. The Company plans to transfer these generating
assets at book value. The unregulated generation will be sold in
both the wholesale and retail competitive marketplace, allowing
greater earnings growth potential, subject to market risk, while
allowing Allegheny Energy to capitalize on its strengths in the
generation business.
Allegheny Energy continues to study ways to meet existing and
future increases in regulated customer demand, including new and
efficient electric
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technologies, construction of various types
and sizes of generating units, increasing the efficiency and
availability of Company generating facilities, reducing internal
electrical use and transmission and distribution losses, and
acquisition of energy and capacity from third-party suppliers.
Environmental Issues
In the normal course of business, the Company is subject to
various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.
The significant costs of complying with Title IV (acid rain)
provisions of Phase I of the Clean Air Act Amendments of 1990
(CAAA) have been incurred and are being recovered currently from
customers in rates. 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 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
Company's generating station located in Pennsylvania was required
to reduce NOx emissions by approximately 55% from the 1990
baseline emissions, with a compliance date of May 1999. Further
reductions of 75% from the 1990 baseline may be required by May
2003 under Phase III of the MOU. However, this reduction will
most likely be suspended by the proposed NOx State Implementation
Plan (SIP) call rule discussed below. 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. If reductions of 75% are required,
installation of post-combustion control technologies would be
very expensive. Pennsylvania promulgated regulations to
implement Phase II of the MOU in November 1997.
The Ozone Transport Assessment Group issued its final report in
June 1997 that recommended the Environmental Protection Agency
(EPA) consider a range of NOx controls between existing CAAA
Title IV controls and the less stringent of 85% reduction from
the 1990 emission rate or 0.15 lb/mmBtu. The EPA initiated the
regulatory process to adopt the recommendations and issued its
final NOx SIP call rule on September 24, 1998. The EPA's SIP
call rule finds that 22 eastern states (including Maryland,
Pennsylvania, and West Virginia) and the District of Columbia are
all contributing significantly to ozone nonattainment in downwind
states. The final rule declares that this downwind nonattainment
will be eliminated (or sufficiently mitigated) if the upwind
states reduce their NOx emissions by an amount that is precisely
set by the EPA on a state-by-state basis. The final SIP call
rule requires that all state-adopted Nox reduction measures must
be incorporated into SIPs by September 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations.
The Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states to
challenge this EPA action.
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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 mentioned above. In October 1998, the EPA proposed approval
of the petitions. However, the EPA believes implementation of
the NOx SIP call will alleviate the need to grant the petitions.
The EPA intends to issue a final rule by April 1999.
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. State attainment
plans to meet the revised standards will not be developed for
several years. Also, in July 1997, the EPA proposed regional
haze regulations to improve visibility in Class I federal areas
(national parks and wilderness areas). If finalized, subsequent
state regulations could require additional reduction of SO2
and/or NOx emissions from Company facilities. The effect on the
Company of revision to any of these standards or regulations is
unknown at this time, but could be substantial.
The final outcome of the revised ambient standards, Phase III of
the MOU, SIP calls, and Section 126 petitions cannot be
determined at this time. All are being challenged by rulemaking,
petition, and/or the litigation process. Implementation dates
are also uncertain at this time, but could be as early as 2003,
which would require substantial capital expenditures in the 1999-
2000 period. The Company's construction forecast includes the
expenditure of $147 million of capital costs during the 1999-2003
period to comply with the SIP call.
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 will require the United
States to reduce emissions of GHG by 7% from 1990 levels in the
2008-2012 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 Unites 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 Unites 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 previously reported that the EPA had identified the
Company and its regulated affiliates as potentially responsible
parties, along with approximately 175 others, in a Superfund site
subject to cleanup. A final determination has not been made for
the Company's share of the remediation costs based on the amount
of materials sent to the site. The Company and its
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regulated affiliates 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.
Independent Transmission System Operator
Allegheny Energy conditionally executed a membership agreement
with the Midwest Independent System Operator expressly contingent
upon consummation of a proposed merger with DQE. The membership
agreement was entered into on April 9, 1998, and filed with the
FERC on April 13, 1998. Allegheny Energy's membership status
remains conditional upon the outcome of the merger. Many
industry participants, including customers and regulatory
authorities, believe that an entity independent of the utilities
which own the transmission systems is needed to operate the
systems to ensure nondiscriminatory access to the transmission
systems by all users. Should these beliefs result in a mandate,
Allegheny Energy may either voluntarily or involuntarily sustain
membership or achieve new membership in some form of Independent
System Operator.
Year 2000 Readiness Disclosure
As the Year 2000 (Y2K) approaches, most organizations, including
the Company, could experience serious problems related to
software and various equipment with embedded chips which may not
properly recognize calendar dates. To minimize such problems,
the Company and its affiliates in the System are proceeding with
a comprehensive effort to continue operations without significant
problems in 2000 and beyond. An Executive Task Force is
coordinating the efforts of 24 separate Y2K Teams, representing
all business and support units in the System.
In May 1998, the North American Electric Reliability Council
(NERC), of which the System is a member, accepted a request from
the United States Department of Energy to coordinate the
industry's Y2K efforts. The electric utility industry and the
System have segmented the Y2K problem into the following
components:
Computer hardware and software;
Embedded chips in various equipment; and
Vendors and other organizations on which the System relies for
critical materials and services.
The industry's and the System's efforts for each of these three
components include assessment of the problem areas and
remediation, testing, and contingency plans for critical
functions for which remediation and testing are not possible or
which do not provide reasonable assurance.
The NERC has established a goal of having the industry achieve a
state of Y2K readiness for critical systems by June 30, 1999,
and, to monitor progress, requires each utility to prepare and
submit a monthly report showing progress and dated plans. By
Order dated July 9, 1998, the Pennsylvania PUC initiated a
proceeding requiring each utility that cannot meet a Y2K
readiness date of March 31, 1999, for mission critical systems to
file contingency plans by
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that date. The System's Y2K plans are
designed to achieve the NERC and Pennsylvania PUC goals.
Integrated electric utilities are uniquely reliant on each other
to avoid, in a worst case situation, cascading failure of the
entire electrical system. The System is working with the Edison
Electric Institute, the Electric Power Research Institute, the
NERC, and the East Central Area Reliability Agreement group to
capitalize on industry-wide experiences and to participate in
industry-wide testing and contingency planning. The NERC, on
January 11, 1999, issued a press release stating, based on the
individual NERC reports it had received from 98% of the
electrical industry, that "although there is clearly much more
work to be done, we have found that North America's electric
power supply and delivery systems are well on their way to being
Y2K ready."
The SEC requires that each company disclose its estimate of the
"most reasonably likely worst case scenario" of a negative Y2K
event. Since the Company and the industry are working diligently
to avoid any disruption of electric service, the Company does not
believe it or its customers will experience any significant long-
term disruptions of electric service. It is the Company's
opinion that the "most reasonably likely worst case scenario" is
that there could be isolated problems at various Company
facilities or at the facilities of neighboring utilities that may
have somehow escaped discovery in the identification,
remediation, and testing process, and that these problems may
cause isolated disruptions of service. All utilities, including
the Company, have experience in the implementation of existing
emergency plans and are currently expanding their emergency plans
to include contingency plans to respond quickly to any such
events.
The Company is aware of the importance of electricity to its
customers and is using its best efforts to avoid any serious Y2K
problems. Despite the Company's best efforts, including working
with internal resources, external vendors, and industry
associations, the Company cannot guarantee that it will be able
to conduct all of its operations without Y2K interruptions. To
the extent that any Y2K problem may be encountered, the Company
is committed to resolution as expeditiously as possible to
minimize the effect of any such event.
Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents a labor-intensive effort of remediation, component
testing, multiple systems testing, documentation, and contingency
planning. While outside contractors and equipment vendors will
be employed for some of the work, the Company believes it must
rely on System employees for most of the effort because of their
experience with the Company's systems and equipment. The Company
currently estimates that its total incremental expenditures for
the Y2K effort since it began identification of Y2K costs will be
within a range of $7 to $10 million. Of that amount, about $4
million has been incurred through 1998.
The descriptions herein of the Company's Y2K effort are made
pursuant to the Year 2000 Information and Readiness Disclosure
Act. Forward-looking statements herein are made pursuant to the
Private Securities Litigation Reform Act of 1995. Of necessity,
the Company's Y2K effort is based on estimates of assessment,
remediation, testing, and contingency planning
M-65
West Penn Power Company
and Subsidiaries
activities. There can be no assurance that actual results will
not materially differ from expectations.
M-66
Allegheny Generating Company
1998 Financial Statements
Allegheny Generating Company
Part of Allegheny Energy
M-67
Allegheny Generating Company
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
FACTORS THAT MAY AFFECT FUTURE RESULTS
This management's discussion and analysis of financial condition
and results of operations contains forecast information items
that are "forward-looking statements" as defined in the Private
Securities Litigation Reform Act of 1995. All such forward-
looking information is necessarily only estimated. There can be
no assurance that actual results will not materially differ from
expectations. Actual results have varied materially and
unpredictably from past expectations.
Factors that could cause actual results to differ materially
include, among other matters, electric utility restructuring,
including the ongoing state and federal activities; potential
Year 2000 operation problems; developments in the legislative,
regulatory, and competitive environments in which Allegheny
Generating Company (the Company) operates, including regulatory
proceedings affecting rates charged by the Company;
environmental, legislative, and regulatory changes; future
economic conditions; developments relating to the proposed merger
of Allegheny Energy, Inc. (Allegheny Energy) with DQE, Inc.
(DQE), parent company of Duquesne Light Company in Pittsburgh,
Pa.; and other circumstances that could affect anticipated
revenues and costs such as unscheduled maintenance or repair
requirements and compliance with laws and regulations.
SIGNIFICANT EVENTS IN 1998, 1997, AND 1996
See page 3 and also Note B to the financial statements for
information about the proposed merger of Allegheny Energy with
DQE.
REVIEW OF OPERATIONS
As described under Liquidity and Capital Requirements, revenues
are determined under a cost-of-service formula rate schedule.
Revenues are expected to decrease each year due to a normal
continuing reduction in the Company's net investment in the Bath
County station and its connecting transmission facilities upon
which the return on investment is determined. The net investment
(primarily net plant less deferred income taxes) decreases to the
extent that provisions for depreciation and deferred income taxes
exceed net plant additions. Revenues for 1998 and 1997 decreased
due to a reduction in net investment and reduced operating
expenses.
The decrease in operating expenses in 1998 and 1997 resulted from
a decrease in federal income taxes due to a decrease in operating
income before taxes, exclusive of other income which is reported
net of taxes combined with a decrease in operation and
maintenance expense.
Effective June 1, 1995, the Federal Energy Regulatory Commission
(FERC) gave approval for the Company to add a prior tax payment
of approximately $12 million to rate base. In September 1997,
the Company received a tax-related contract settlement of $8.8
million of taxes related to the $12 million added to rate base
M-68
Allegheny Generating Company
in 1995. The 1997 settlement amount was recorded as a reduction
to plant and was removed from rate base.
The increase in other income, net in 1997 was due to interest on
the refund on the tax-related contract settlement (see above).
The decrease in interest on long-term debt in 1998 and 1997 was
primarily the result of a decrease in the average amount of long-
term debt outstanding.
The increase in other interest expense in 1998 was due to an
increased level of short-term debt maintained by the Company upon
retirement of medium-term debt.
LIQUIDITY AND CAPITAL REQUIREMENTS
The Company's only operating assets are an undivided 40% interest
in the Bath County (Virginia) pumped-storage hydroelectric
station and its connecting transmission facilities. The Company
has no plans for construction of any other major facilities.
Pursuant to an agreement, Monongahela Power Company, The Potomac
Edison Company, and West Penn Power Company (the Parents), buy
all of the Company's capacity in the station priced under a "cost-
of-service formula" wholesale rate schedule approved by the FERC.
Under this arrangement, the Company recovers in revenues all of
its operation and maintenance expenses, depreciation, taxes, and
a return on its investment. On December 29, 1998, the FERC
issued an Order accepting a proposed amendment to the Parent's
Power Supply Agreement for the Company effective January 1, 1999.
This amendment sets the generation demand for each Parent
proportional to its ownership in the Company. Previously, demand
for each Parent fluctuated due to customer usage.
The Company's rates are set by a formula filed with and
previously accepted by the FERC. The only component which
changes is the return on equity (ROE). Pursuant to a settlement
agreement filed with and approved by the FERC, the Company's ROE
is set at 11% and will continue at that rate unless any affected
party seeks a change.
As previously reported, the Company has received authority from
the Securities and Exchange Commission (SEC) to pay common
dividends from time to time through December 31, 2001, out of
capital to the extent permitted under applicable corporation law
and any applicable financing agreements which restrict
distributions to shareholders. Due to the nature of being a
single asset company with declining capital needs, the Company
systematically reduces capitalization each year as its asset
depreciates. This has resulted in the payment of dividends in
excess of current earnings out of other paid-in capital and the
reduction of retained earnings to zero. The Company's goal is to
retire debt and pay dividends in amounts necessary to maintain a
common equity position of about 45%, including short-term debt.
The payment of dividends out of capital surplus will not be
detrimental to the financial integrity or working capital of
either the Company or its Parents, nor will it adversely affect
the protections due debt security holders.
M-69
Allegheny Generating Company
An Allegheny Energy internal money pool accommodates intercompany
short-term borrowing needs to the Company to the extent that
Allegheny Energy and the Company's Parents have funds available.
To the extent funds are not available from the money pool, the
Company borrows from external sources.
SIGNIFICANT CONTINUING ISSUES
Proposed Merger with DQE
Allegheny Energy, Inc., (Allegheny Energy) parent of the
Company's parents, believes that DQE's basis for seeking to
terminate the merger (described in Note B to the financial
statements) is without merit. Accordingly, Allegheny Energy
continues to seek the remaining regulatory approvals from the
Department of Justice and the SEC. It is not likely either
agency will act on the requests unless Allegheny Energy obtains
judicial relief requiring DQE to move forward.
Year 2000 Readiness Disclosure
The Company and its Parents have spent considerable time and
effort over the past several years on the issue of the Year 2000
(Y2K) software compliance, and the effort is continuing. Certain
software has already been made year 2000 compliant by upgrades
and replacement, and analysis is continuing on others, in
accordance with a schedule planned to permit the Company and its
Parents to process information in the year 2000 and beyond
without significant problems. Expenditures for year 2000
compliance are not expected to have a material effect on the
Company's results of operations or financial position.
As described in the second paragraph under Liquidity and Capital
Requirements above, the Company's results of operations are
primarily related to recovery of fixed capital costs under
contract with its Parents and therefore are not affected by the
operation, or non-operation, of the Bath County station and
related transmission facilities.
M-70
48
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
Index
Monon- Potomac West
AE gahela Edison Penn AGC
Report of Independent Accountants F- 1 F-26 F-41 F-56 F-77
Statement of Income for
the three years ended
December 31, 1998 F- 2 F-27 F-42 F-57 F-78
Statement of Retained Earnings
for the three years ended
December 31, 1998 - F-27 F-42 F-57 F-78
Statement of Cash Flows for
the three years ended
December 31, 1998 F- 3 F-28 F-43 F-58 F-79
Balance Sheet at December 31,
1998 and 1997 F- 4 F-29 F-44 F-59 F-80
Statement of Capitalization at
December 31, 1998 and 1997 F- 5 F-30 F-45 F-60 F-80
Statement of Common Equity for
the three years ended
December 31, 1998 F- 6 - - - -
Notes to financial statements F- 7 F-31 F-46 F-61 F-81
Financial Statement Schedules -
Schedules for the three years
ended December 31, 1998 49 49 49 49 49
II Valuation and qualifying
accounts S-1 S-2 S-3 S-4 -
Allegheny Energy, Inc.
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders
of Allegheny Energy, Inc.
In our opinion, the accompanying consolidated balance sheet,
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, 1998 and 1997, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1998, in conformity with generally accepted
accounting principles. 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 generally accepted auditing standards 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 4, 1999
F-1
Allegheny Energy, Inc.
Consolidated Statement of Income
Year ended December 31 1998 1997 1996
(Thousands of Dollars Except Per Share Data)
Operating Revenues:
Utility $ 2,329,450 $ 2,283,697 $ 2,326,902
Nonutility 246,986 85,794 747
Total Operating Revenues 2,576,436 2,369,491 2,327,649
Operating Expenses:
Operation:
Fuel 566,453 559,939 513,210
Purchased power and exchanges, net 388,758 219,837 184,357
Deferred power costs, net (6,639) (22,916) 15,621
Other 337,440 308,991 299,817
Maintenance 217,559 230,602 243,314
Internal restructuring charges and asset write-off 103,865
Depreciation 270,379 265,750 263,246
Taxes other than income taxes 194,583 186,978 185,373
Federal and state income taxes 168,396 168,073 127,992
Total Operating Expenses 2,136,929 1,917,254 1,936,795
Operating Income 439,507 452,237 390,854
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction 1,553 4,393 3,157
Other income, net 8,180 18,016 4,370
Total Other Income and Deductions 9,733 22,409 7,527
Income Before Interest Charges and
Preferred Dividends 449,240 474,646 398,381
Interest Charges and Preferred Dividends:
Interest on long-term debt 161,057 173,568 166,387
Other interest 19,395 14,409 15,398
Allowance for borrowed funds used during construction (3,471) (3,907) (2,731)
Dividends on preferred stock of subsidiaries 9,251 9,280 9,280
Total Interest Charges and Preferred Dividends 186,232 193,350 188,334
Consolidated Income Before Extraordinary Charge 263,008 281,296 210,047
Extraordinary Charge, Net (275,426)
Consolidated Net (Loss) Income $ (12,418) $ 281,296 $ 210,047
Common Stock Shares Outstanding (Average) 122,436,317 122,208,465 121,141,446
Basic and Diluted Earnings Per Average Share:
Consolidated income before extraordinary charge $ 2.15 $2.30 $1.73
Extraordinary charge, net $(2.25)
Consolidated Net (Loss) Income $ (.10) $2.30 $1.73
See accompanyiong notes to consolidated financial statements.
F-2
Allegheny Energy, Inc.
Consolidated Statement of Cash Flows
Year ended December 31 1998 1997 1996
(Thousands of Dollars)
Cash Flows from Operations:
Consolidated net (loss) income $ (12,418) $ 281,296 $ 210,047
Extraordinary charge, net of taxes 275,426
Consolidated income before extraordinary charge 263,008 281,296 210,047
Depreciation 270,379 265,750 263,246
Deferred investment credit and income taxes, net 20,998 66,362 20,887
Deferred power costs, net (6,639) (22,916) 15,621
Allowance for other than borrowed funds
used during construction (1,553) (4,393) (3,157)
Internal restructuring liability (5,504) (50,597) 55,544
PURPA project buyout (48,000)
Changes in certain current assets and liabilities:
Accounts receivable, net 15,365 (6,052) 19,570
Materials and supplies (12,852) (1,385) 15,507
Accounts payable 23,118 (17,172) 1,739
Taxes accrued 14,312 (3,653) (181)
Other, net 10,550 19,386 (7,902)
591,182 478,626 590,921
Cash Flows from Investing:
Utility construction expenditures
(less allowance for other than borrowed
funds used during construction) (227,809) (280,255) (286,297)
Nonutility construction expenditures and investments (6,205) (829) (180,245)
(234,014) (281,084) (466,542)
Cash Flows from Financing:
Sale of common stock 16,706 33,847
Issuance of long-term debt 211,952 160,000
Retirement of long-term debt (419,780) (46,892) (54,143)
Short-term debt, net 52,436 49,971 (43,988)
Cash dividends on common stock (210,591) (210,195) (204,720)
(365,983) (190,410) (109,004)
Net Change in Cash and Temporary Cash Investments (8,815) 7,132 15,375
Cash and Temporary Cash Investments at January 1 26,374 19,242 3,867
Cash and Temporary Cash Investments at December 31 $ 17,559 $ 26,374 $ 19,242
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized) $ 171,719 $ 178,121 $ 169,200
Income taxes 145,053 108,519 132,037
See accompanying notes to consolidated financial statements.
F-3
Allegheny Energy, Inc.
Consolidated Balance Sheet
As of December 31 1998 1997
(Thousands of Dollars)
Assets
Property, Plant, and Equipment:
At original cost, including $166,330
and $229,785 under construction $ 8,629,733 $ 8,451,424
Accumulated depreciation (3,395,603) (3,155,210)
5,234,130 5,296,214
Investments and Other Assets:
Subsidiaries consolidated-excess of cost
over book equity at acquisition 15,077 15,077
Benefit plans' investments 87,468 79,474
Nonutility investments 9,361 4,992
Other 1,566 1,559
113,472 101,102
Current Assets:
Cash and temporary cash investments 17,559 26,374
Accounts receivable:
Electric service, net of $18,011 and
$17,191 uncollectible allowance 276,866 296,082
Other, net 16,163 12,312
Materials and supplies-at average cost:
Operating and construction 99,439 80,836
Fuel 57,610 63,361
Prepaid taxes 56,658 51,724
Other, including current portion of
regulatory assets 30,788 24,005
555,083 554,694
Deferred Charges:
Regulatory assets 704,506 586,125
Unamortized loss on reacquired debt 48,671 49,550
Other 91,931 66,406
845,108 702,081
Total $ 6,747,793 $ 6,654,091
Capitalization and Liabilities
Capitalization:
Common stock, other paid-in capital,
and retained earnings $ 2,033,889 $ 2,256,898
Preferred stock 170,086 170,086
Long-term debt and QUIDS 2,179,288 2,193,153
4,383,263 4,620,137
Current Liabilities:
Short-term debt 258,837 206,401
Long-term debt due within one year 185,400
Accounts payable 153,107 129,989
Taxes accrued:
Federal and state income 17,442 10,453
Other 62,751 55,428
Interest accrued 35,945 40,000
Deferred income taxes 18,718
Adverse power purchase commitments 47,173
Other 101,239 74,170
695,212 701,841
Deferred Credits and Other Liabilities:
Unamortized investment credit 125,396 133,316
Deferred income taxes 842,193 1,031,236
Regulatory liabilities 80,354 91,178
Adverse power purchase commitments 538,745
Other 82,630 76,383
1,669,318 1,332,113
Commitments and Contingencies (Note N)
Total $ 6,747,793 $ 6,654,091
See accompanying notes to consolidated financial statements.
F-4
Allegheny Energy, Inc.
Consolidated Statement of Capitalization
(Thousands of Dollars) (Capitalization Ratios)
As of December 31 1998 1997 1998 1997
Common Stock:
Common stock of Allegheny Energy, Inc.-
$1.25 par value per share, 260,000,000 shares
authorized, 122,436,317 shares outstanding $ 153,045 $ 153,045
Other paid-in capital 1,044,085 1,044,085
Retained earnings 836,759 1,059,768
Total 2,033,889 2,256,898 46.4% 48.8%
Preferred Stock of Subsidiaries-cumulative, par value
$100 per share, authorized 9,975,688 shares:
December 31, 1998
Shares Regular Call Price
Series Outstanding Per Share
3.60%-4.80% 650,861 $102.205 to $110.00 65,086 65,086
$5.88-$7.73 650,000 $102.85 to $102.86 65,000 65,000
Auction 3.95%-4.12% 400,000 $100.00 40,000 40,000
Total (annual dividend
requirements $9,254) 170,086 170,086 3.9% 3.7%
Long-Term Debt and QUIDS of Subsidiaries:
First mortgage bonds: December 31, 1998
Maturity Interest Rate-%
1998-2000 5 5/8-5 7/8 140,000 242,000
2002-2004 6 3/8-7 7/8 175,000 175,000
2006-2007 7 1/4-8 120,000 120,000
2021-2025 7 5/8-8 7/8 810,000 925,000
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 2002-2024 4.70-6.875 368,300 368,300
Unsecured notes due 2002-2012 4.35-5.10 23,695 24,995
Installment purchase obligations
due 2003 4.50 19,100 19,100
Medium-term debt due 2001-2003 5.56-6.18 237,025 220,000
Unamortized debt discount and
premium, net (19,289) (21,299)
Total (annual interest
requirements $154,039) 2,179,288 2,378,553
Less current maturities (185,400)
Total 2,179,288 2,193,153 49.7% 47.5%
Total Capitalization $4,383,263 $ 4,620,137 100.0% 100.0%
See accompanying notes to consolidated financial statements.
F-5
Consolidated Statement of Common Equity
(Thousands of Dollars)
Other Retained Total
Shares Common Paid-In Earnings Common
Year ended December 31 Outstanding Stock Capital (Note G) Equity
Balance at January 1, 1996 120,700,809 $150,876 $ 995,701 $ 983,340 $2,129,917
Add:
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
Purchase Plan and Employee Stock
Ownership and Savings Plan 1,139,518 1,424 32,423 33,847
Consolidated net income 210,047 210,047
Deduct:
Dividends on common stock of the
Company (cash) 204,720 204,720
Balance at December 31, 1996 121,840,327 $152,300 $1,028,124 $ 988,667 $2,169,091
Add:
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
Deduct:
Dividends on common stock of the
Company (cash) 210,195 210,195
Balance at December 31, 1997 122,436,317 $153,045 $1,044,085 $1,059,768 $2,256,898
Deduct:
Consolidated net loss 12,418 12,418
Dividends on common stock of the
Company (cash) 210,591 210,591
Balance at December 31, 1998 122,436,317 $153,045 $1,044,085 $ 836,759 $2,033,889
See accompanying notes to consolidated financial statements.
F-6
Allegheny Energy, Inc.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial
statements.)
Note A: Summary of Significant Accounting Policies
Allegheny Energy, Inc. (the Company) is an electric utility
holding company that derives substantially all of its income from
the electric utility operations of its regulated subsidiaries,
Monongahela Power Company (Monongahela Power), The Potomac Edison
Company (Potomac Edison), and West Penn Power Company (West
Penn). These subsidiaries jointly own Allegheny Generating
Company (AGC), which owns and sells to its parents 840 megawatts
(MW) of pumped-storage generating capacity. The markets for the
subsidiaries' regulated electric retail sales are in the states
of Pennsylvania, West Virginia, Maryland, Virginia, and Ohio. In
1998, revenues from the 50 largest electric utility customers
provided approximately 17% of the consolidated retail revenues.
The Company also has a wholly owned nonutility subsidiary, AYP
Capital, Inc. (AYP Capital), formed in 1994, which, along with
its subsidiaries, is involved primarily in energy-related
services, development of nonutility power generation, wholesale
and retail electricity sales to deregulated markets,
telecommunications, and other energy-related businesses.
The Company and its subsidiaries are subject to regulation
by the Securities and Exchange Commission, including the Public
Utility Holding Company Act of 1935 (PUHCA). The regulated
subsidiaries are subject to regulation by various state bodies
having jurisdiction and by the Federal Energy Regulatory
Commission (FERC). See Note B for significant changes in the
Pennsylvania regulatory environment. 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 by recording an estimate for unbilled revenues for
services provided from the meter reading date to the end of the
accounting period. Revenues from nonregulated activities are
recorded in the period earned.
F-7
Allegheny Energy, Inc.
Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs,
and revenues from sales to other utilities and power marketers,
including transmission services, are deferred until they are
either recovered from or credited to customers under fuel and
energy cost-recovery procedures in West Virginia, Maryland,
Virginia, and Ohio. West Penn discontinued this practice in
Pennsylvania, effective May 1, 1997.
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 (AFUDC) 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.
Allowance for Funds Used During Construction
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
regulated subsidiaries as a cost of utility property, plant, and
equipment with offsetting credits to other income and interest
charges. Rates used by the subsidiaries for computing AFUDC in
1998, 1997, and 1996 averaged 7.78%, 8.59%, and 8.41%,
respectively. AFUDC is not included in the cost of construction
by the nonutility business or by the utility businesses when the
cost of financing the construction is being recovered through
rates.
As discussed in Note B, as a result of a Pennsylvania Order,
West Penn has 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 electric generation
operations and has adopted SFAS No. 101, "Accounting for the
Discontinuation of Application of FASB Statement No. 71."
Starting in July 1998, West Penn stopped accruing AFUDC for
generation construction projects and adopted SFAS No. 34,
"Capitalizing Interest Costs," to capitalize interest during the
period of construction of generation construction projects.
Capitalized interest, recognized by West Penn as a cost of
property, plant, and equipment with offsetting credits to
interest charges, is reported in the statement of income as
allowance for borrowed funds used
F-8
Allegheny Energy, Inc.
during construction. Since adoption in July 1998, rates
used by West Penn for capitalizing interest on generation
construction projects averaged 7.45%.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives of
depreciable properties and amounted to approximately 3.3% of
average depreciable property in each of the years 1998 and 1997,
and 3.5% in 1996. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged
principally to operating expenses.
Nonutility Property
Nonutility property is stated at original cost and is
depreciated by the straight-line method over its estimated useful
life.
Investments
The investment in subsidiaries consolidated represents the
excess of acquisition cost over book equity (goodwill) prior to
1966. Goodwill is not being amortized because, in management's
opinion, there has been no reduction in its value.
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. Payment of future
premiums will fully fund these benefits.
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 based
on 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. For the regulated subsidiaries, differences
between income tax expense, computed on the basis of financial
accounting income and taxes payable based on taxable income, are
accounted for substantially in accordance with the accounting
procedures followed for ratemaking purposes. Deferred tax assets
and liabilities represent the tax effect of temporary differences
between the
F-9
financial statement and tax basis of assets and
liabilities computed using the most current tax rates.
Provisions for federal income tax were reduced in previous
years by investment credits, and amounts equivalent to such
credits were charged to income with concurrent credits to a
deferred account. These balances are being 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.
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. The
funding plan for these costs 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.
Capitalized Software Costs
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.
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
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 are
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
F-10
Allegheny Energy, Inc.
included a plan for recovery of transition costs (sometimes
referred to as stranded costs) through a Competitive
Transition Charge (CTC).
Transition costs are costs incurred under a regulated
environment, which may not be recoverable in a competitive
market. The amount of transition costs has been a key issue in
the restructuring proceedings. Since the installed costs of
utility facilities are known, the key variable in transition cost
determinations in Pennsylvania was the projection of market
prices of electricity in future periods. West Penn's
restructuring plan filing included its determination of its
transition costs based on its projection of future market prices.
West Penn's recoverable transition costs were limited to $1.2
billion by rate caps mandated by the Customer Choice Act.
On May 29, 1998, the Pennsylvania PUC issued an Order
authorizing West Penn recovery of approximately $595 million (or
$525 million in the event of the merger) in transition costs,
with a return, based on alternative projections of future market
prices. On June 26, 1998, the Pennsylvania PUC denied, except for
minor corrections, a request by West Penn for reconsideration of
the May 29 Order. On that same day, West Penn filed a formal
appeal in state court and an action in federal court challenging
the Pennsylvania PUC's restructuring Order.
As a result of the May 29, 1998, Order, West Penn determined
that it was required to discontinue the application of SFAS No.
71 for electric generation operations and adopt SFAS No. 101. In
doing so, West Penn also determined that, under the provisions of
SFAS No. 101, an extraordinary charge of $450.6 million ($265.4
million after taxes) was required to reflect adverse power
purchase commitments and deferred costs that are not recoverable
from customers under the Pennsylvania PUC's Order.
While pursuing its litigation, West Penn participated in
settlement discussions with interested parties regarding issues
related to the restructuring Order. A negotiated settlement was
achieved, and, on November 19, 1998, the Pennsylvania PUC granted
final approval to West Penn's restructuring settlement agreement.
The settlement agreement includes the following provisions:
- - Agreement by the parties to withdraw all litigation related
to the Pennsylvania deregulation proceedings.
- - Establishment of an average shopping credit of 3.16 cents
per kilowatt-hour in 1999 for West Penn customers who shop
for the generation portion of electricity services.
- - Two-thirds of West Penn's customers have the option of
selecting a generation supplier on January 2, 1999, with all
customers able to shop on January 2, 2000.
- - Requires 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.
F-11
Allegheny Energy, Inc.
- - Provides that customers will 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.
- - Prohibits complaints challenging West Penn's regulated
transmission and distribution rates through 2005.
- - Provides about $15 million of West Penn funding for the
development and use of renewable energy and clean energy
technologies, energy conservation, energy efficiency, etc.
- - Permits recovery of $670 million in transition costs plus
return over 10 years beginning in January 1999 for West
Penn. In the event that the merger of Allegheny Energy, Inc.
and DQE, Inc. (DQE), parent company of Duquesne Light
Company in Pittsburgh, Pa., is consummated, the transition
costs will be adjusted to $630 million plus return to
provide a sharing of merger synergy savings with customers.
- - Allows 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.
- - Grants West Penn's application to issue bonds to securitize
up to $670 million (or $630 million in the event of the
merger) in transition costs and to provide 75% of the
associated savings to customers with 25% to shareholders.
- - Authorizes 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.
- - If West Penn is forced to divest some generating assets or
chooses to divest all of its generation before 2002, the CTC
will be adjusted, either up or down, based on the results of
such divestiture.
As a result of the November 19, 1998, settlement agreement,
the extraordinary charge was increased by $16.3 million ($10.0
million after taxes) to $466.9 million ($275.4 million after
taxes), and additional charges of $40.3 million ($23.7 million
after taxes) related to the West Penn revenue refund and energy
program payments were also recorded. See Note C for additional
details. Pursuant to Pennsylvania PUC Orders, starting in 1999,
West Penn is unbundling its rates to reflect separate prices for
the supply charge, the CTC, and transmission and distribution
charges. While supply will be open to competition, West Penn will
continue to provide regulated transmission and distribution
services to customers in its service area at Pennsylvania PUC-
and FERC-regulated rates and will be the electricity provider of
last resort for those customers who decide not to choose another
electricity supplier.
F-12
Allegheny Energy, Inc.
As stated above, West Penn made its filing concerning its
transition cost requirements based on its early 1997 projection
of market prices. The Pennsylvania PUC issued its May 29, 1998,
Order to West Penn, as well as its 1998 orders to all other
Pennsylvania electric utilities, based on alternative
projections. Current prices, which the Company believes are being
influenced, among other things, by price volatility in the summer
of 1998, are equal to and in some cases higher than the
projections adopted by the Pennsylvania PUC in its deregulation
orders issued to West Penn and other utilities in the state. If
the Pennsylvania PUC's projections are correct, West Penn
believes that the transition costs provided will be sufficient to
permit it to recover its embedded costs, with a return, during
the transition from regulation to deregulation of electricity
generation.
The West Penn settlement agreement authorizes West Penn to
create a CTC regulatory asset for specified CTC revenues in 1999
through 2002 to be amortized in 2005 through 2008. The regulatory
asset booking of CTC revenue acts to accelerate recognition of
transition cost recovery. In addition, the settlement agreement
specifies how CTC revenues will be allocated between return on
and recovery of transition costs. Amortization of regulatory
assets in 1999 through 2008 under the Pennsylvania PUC-approved
settlement agreement results in smaller amortization expense in
the early years of the transition period which favorably affects
earnings in those years.
Also pursuant to the Customer Choice Act, all electric
utilities in Pennsylvania were required 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 $6.5 million.
West Penn attempted to mitigate 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
revenue losses as a regulatory asset subject to review and
potential rate recovery. Because sales prices were low and
margins were commensurately thin, West Penn was unable to
completely offset its pilot losses with new revenues.
Accordingly, West Penn deferred the net revenue losses as a
regulatory asset.
Note C: Accounting for the Effects of Price Deregulation
In 1997, the FASB, through its Emerging Issues Task Force
(EITF), issued EITF No. 97-4, "Deregulation of the Pricing of
Electricity-Issues Related to the Application of FASB Statement
Numbers 71 and 101." In EITF 97-4, 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. West Penn believes
that the Pennsylvania PUC Order dated May 29, 1998, as described
in Note B which begins on page 50, provides
F-13
Allegheny Energy, Inc.
sufficient details
regarding the deregulation of West Penn's electric generation
operations to require discontinuation of the application of SFAS
No. 71 for its electric generation operations. Effective June 30,
1998, West Penn adopted the provisions of SFAS No. 101 for its
electric generation operations. West Penn determined 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 in the Pennsylvania PUC's May
29, 1998, Order, as revised by the Pennsylvania PUC-approved
November 19, 1998, settlement agreement. The write-off reflects
adverse power purchase commitments and deferred costs that are
not recoverable 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
AGC pumped storage capacity contract 165.6 97.7
Other 103.8 61.2
Total extraordinary charge $466.9 $275.4
In 1985, West Penn entered into a contract with Applied
Energy Services (AES) Corporation for the purchase of energy from
AES's Beaver Valley generating plant in Pennsylvania pursuant to
the requirements of the Public Utility Regulatory Policies Act of
1978 (PURPA).
West Penn owns 45% of AGC, which owns an undivided 40%
interest in the 2,100-MW pumped-storage hydroelectric station in
Bath County, Va. West Penn buys AGC's capacity in the station
priced under a cost of service formula wholesale rate schedule
approved by the FERC.
Under both of these contracts, West Penn has purchase
commitments at costs in excess of the market value of energy from
the plants. Because of utility restructuring under the Customer
Choice Act, these commitments have been determined to be adverse
purchase commitments requiring accrual as loss contingencies
pursuant to SFAS No. 5, "Accounting for Contingencies." The
extraordinary charge before taxes for these contracts is the net
result of such excess cost accruals (recorded as adverse power
purchase commitments) less estimated revenue recoveries
authorized in the Pennsylvania PUC Order (recorded as regulatory
assets) as follows:
AES AGC
(Millions of Dollars) Beaver Valley Pumped Storage
Projected costs in excess of market value of energy $351.5 $234.5
Estimated recovery via a CTC (regulatory asset) 154.0 68.9
Net unrecoverable extraordinary charge $197.5 $165.6
Various assumptions and estimates were made in determining
the extraordinary charge to income discussed on page 52. The most
significant relate to future electricity prices. To the extent
that future electricity prices differ from the Company's
estimates, adjustments to the reserve for adverse power purchase
commitments may be required.
The other $103.8 million of extraordinary charges represents
$55.0 million of deferred unrecovered expenditures for previous
PURPA buyouts,
F-14
Allegheny Energy, Inc.
$13.5 million for an abandoned generating plant,
and $35.3 million of other generation-related regulatory assets,
primarily related to SFAS No. 109, "Accounting for Income Taxes."
The Consolidated Balance Sheet includes the amounts listed
below for generation assets not subject to SFAS No. 71.
December December
(Thousands of Dollars) 1998 1997
Property, plant, and equipment at original cost $1,969,636 $1,951,066
Amounts under construction included above 39,227 51,715
Accumulated depreciation (870,777) (793,166)
In addition to the extraordinary charge and as a result of
the settlement agreement, a fourth quarter charge to earnings of
$40.3 million ($23.7 million after taxes) resulted from the
required West Penn refund throughout 1999 from 1998 revenues of
about $25 million and a $15 million provision for energy
programs.
The Company's other utility subsidiaries could be subjected
to retail electric supply competition in four additional states-
West Virginia, Maryland, Virginia, and Ohio. Additional charges
of the sort incurred in connection with Pennsylvania deregulation
could result from such proceedings.
Note D: Proposed Merger
On April 7, 1997, the Company and DQE, parent company of
Duquesne Light Company in Pittsburgh, Pa., announced that they
had agreed to merge in a tax-free, stock-for-stock transaction.
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 Public Service Commission 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. The Company
believes DQE's action was without basis and was a breach of the
merger agreement. 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 Company also filed
motions for preliminary injunctive relief against DQE.
On October 28, 1998, the District Court denied the Company's
motions for preliminary injunctive relief. The District Court did
not rule on the merits of the lawsuit for specific performance or
damages. On October 30, 1998, the Company appealed the District
Court's Order to the United States Court of Appeals for the Third
Circuit. The Company cannot predict the outcome of this
litigation.
F-15
Allegheny Energy, Inc.
All of the Company's incremental costs of the merger process
($17.6 million through December 31, 1998) are being deferred. The
accumulated merger costs will be written off by the combined
company when the merger occurs or by the Company if it is
determined that the merger will not occur.
Note E: Internal Restructuring Charges and Asset Write-Off
In 1996, the Company and its subsidiaries completed their
internal restructuring activities initiated in 1994, simplifying
the management structure and streamlining operations. During
1996, restructuring activities included consolidating operating
divisions, customer services, and other functions.
In 1996, the subsidiaries recorded restructuring charges of
$93.1 million ($56.2 million after tax) in operating expenses,
including all restructuring charges associated with the
reorganization. These charges reflected liabilities and payments
for severance, employee termination costs, and other
restructuring costs. The current portion of the restructuring
liability, reflected in other current liabilities, excluding
benefit plans curtailment adjustments to postretirement
liabilities (which are primarily recorded in other deferred
credits), consists of:
(Thousands of Dollars) 1998 1997
Restructuring liability:
Balance at beginning of period $ 5,504 $ 56,101
Less payments and accrual reversals (5,504) (50,597)
Balance at end of period $ - $ 5,504
In 1996, the utility subsidiaries wrote off $10.8 million
($6.3 million after tax) of previously accumulated costs related
to a proposed transmission line. In the industry's more
competitive environment, it was no longer reasonable to assume
future recovery of these costs in rates.
Note F: Income Taxes
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes-current:
Federal $114,319 $ 87,394 $ 83,456
State 33,385 23,960 26,004
Total 147,704 111,354 109,460
Income taxes-deferred, net of amortization 28,920 74,565 29,129
Income taxes-deferred, extraordinary charge (191,480)
Amortization of deferred investment credit (7,922) (8,203) (8,242)
Total income taxes (22,778) 177,716 130,347
Income taxes-charged to other income and
deductions (306) (9,643) (2,355)
Income taxes-credited to extraordinary
charge 191,480
Income taxes-charged to operating income $168,396 $168,073 $127,992
F-16
Allegheny Energy, Inc.
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) 1998 1997 1996
Income before preferred dividends,
income taxes, and extraordinary charge $440,655 $458,649 $347,319
Amount so produced $154,229 $160,527 $121,562
Increased (decreased) for:
Tax deductions for which deferred tax
was not provided:
Lower tax depreciation 6,700 14,200 12,600
Plant removal costs (2,400) (1,700) (1,900)
State income tax, net of federal income
tax benefit 20,200 11,700 14,100
Amortization of deferred investment credit (7,922) (8,203) (8,242)
Other, net (2,411) (8,451) (10,128)
Total $168,396 $168,073 $127,992
The provision for income taxes for the extraordinary charge
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) 1998
Extraordinary charge before income taxes $466,905
Amount so produced $163,417
Increased for state income tax, net of federal
income tax benefit 28,063
Total $191,480
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
F-17
Allegheny Energy, Inc.
At December 31, the deferred tax assets and liabilities
consisted of the following:
(Thousands of Dollars) 1998 1997
Deferred tax assets:
CTC recovery $ 154,530
Unamortized investment tax credit 77,213 $ 83,818
Tax interest capitalized 35,375 35,954
Postretirement benefits other than
pensions 31,047 21,986
Contributions in aid of construction 23,643 22,980
Unbilled revenue 13,380 13,657
Revenue refund 10,301
Deferred power costs, net 8,736 10,598
Other 47,782 38,578
402,007 227,571
Deferred tax liabilities:
Book vs. tax plant basis differences, net 1,174,453 1,142,035
Other 88,465 104,415
1,262,918 1,246,450
Total net deferred tax liabilities 860,911 1,018,879
Portion above included in current
(liabilities) assets (18,718) 12,357
Total long-term net deferred
tax liabilities $ 842,193 $1,031,236
Note G: Dividend Restriction
Supplemental indentures relating to certain outstanding
bonds of Monongahela Power and West Penn contain dividend
restrictions under the most restrictive of which $121,015,000 of
the Company's consolidated retained earnings at December 31,
1998, is not available for cash dividends on their common stocks,
except that a portion thereof may be paid as cash dividends where
concurrently an equivalent amount of cash is received by a
subsidiary as a capital contribution or as the proceeds of the
issue and sale of shares of such subsidiary's common stock.
Note H: 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, a portion of
which (about 25% to 30%) was charged to plant construction,
included the following components:
Postretirement Benefits
Pension Benefits Other Than Pensions
(Thousands of Dollars) 1998 1997 1996 1998 1997 1996
Components of net periodic (credit) cost:
Service cost $14,316 $12,435 $14,881 $ 2,566 $ 2,619 $ 2,930
Interest cost 46,743 43,060 41,500 14,346 15,244 14,251
Expected return on plan assets (61,280) (57,404) (54,268) (6,163) (4,705) (3,666)
Amortization of unrecognized transition
(asset) obligation (3,146) (3,146) (3,146) 6,433 6,433 7,272
Amortization of prior service cost 2,360 1,441 1,140
Periodic (credit) cost (1,007) (3,614) 107 17,182 19,591 20,787
Reversal of previous deferrals 760 760 760 1,975
Net periodic (credit) cost $ (247) $(2,854) $ 867 $17,182 $19,591 $22,762
F-18
Allegheny Energy, Inc.
The discount rates and rates of compensation increases used
in determining the benefit obligations at September 30, 1998,
1997, and 1996, and the expected long-term rate of return on
assets in each of the years 1998, 1997, and 1996 were as follows:
1998 1997 1996 1998 1997 1996
Discount rate 7.00% 7.25% 7.50% 7.00% 7.25% 7.50%
Expected return on plan
assets 9.00% 9.00% 9.00% 8.25% 8.25% 8.25%
Rate of compensation increase 4.00% 4.25% 4.50% 4.00% 4.25% 4.50%
For postretirement benefits other than pensions measurement
purposes, a health care cost trend rate of 6% for 1999 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:
1-Percentage-Point 1-Percentage-Point
(Thousands of Dollars) Increase Decrease
Effect on total of service and interest cost components $ 575 $ (596)
Effect on postretirement benefit obligation $5,092 $ (5,054)
The amounts (prepaid) accrued at December 31,
using a measurement date of September 30, included
the following components:
Postretirement Benefits
Pension Benefits Other Than Pensions
(Thousands of Dollars) 1998 1997 1998 1997
Change in benefit obligation:
Benefit obligation at beginning of year $ 664,695 $ 586,473 $ 202,274 $206,229
Service cost 14,316 12,435 2,566 2,619
Interest cost 46,743 43,060 14,346 15,244
Plan amendments 360 18,105
Actuarial loss (gain) 8,573 44,029 (14,296) (15,243)
Benefits paid (41,750) (39,407) (8,608) (6,575)
Benefit obligation at December 31 692,937 664,695 196,282 202,274
Change in plan assets:
Fair value of plan assets at
beginning of year 786,159 691,063 73,363 55,802
Actual return on plan assets 49,091 134,503 965 12,230
Employer contribution 7,848 2,451 5,331
Benefits paid (41,750) (39,407) (2,006)
Fair value of plan assets at December 31 801,348 786,159 74,773 73,363
Plan assets (in excess of) less than
benefit obligation (108,411) (121,464) 121,509 128,911
Unrecognized transition asset (obligation) 6,298 9,444 (90,060) (96,493)
Unrecognized net actuarial gain 108,366 129,129 21,453 12,355
Unrecognized prior service cost due to plan
amendments (22,814) (24,814)
Fourth quarter contributions and benefit
payments (5,227) (4,025)
(Prepaid) accrued at December 31 $ (16,561) $ (7,705) $ 47,675 $ 40,748
F-19
Allegheny Energy, Inc.
Note I: Regulatory Assets and Liabilities
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:
(Thousands of Dollars) 1998 1997
Long-Term Assets (Liabilities), Net:
Income taxes, net $305,415 $417,382
CTC recovery 292,718
PURPA project buyout 48,000
Demand-side management 8,157 14,204
Pennsylvania pilot deferred revenue 6,726
Postretirement benefits 6,229 7,053
Storm damage 2,101 3,537
Deferred power costs, net (reported in other
deferred charges/credits) (2,455) 4,051
Other, net 2,806 4,771
Subtotal 621,697 498,998
Current Assets (Liabilities), Net:
CTC recovery 17,372
Income taxes, net 1,847 1,847
Deferred power costs, net (reported in other
current assets/liabilities) 7,211 2,198
Subtotal 26,430 4,045
Net Regulatory Assets $648,127 $503,043
F-20
Allegheny Energy, Inc.
Deregulation/competition proceedings in West Virginia,
Virginia, Maryland, and Ohio may in the future result in less
than full recovery of costs incurred to serve customers. This
would then require additional charges of the type recorded in
1998 for West Penn as discussed in Notes B and C starting on
pages 50 and 52, respectively, in connection with Pennsylvania's
deregulation proceedings. Such charges, if any, are not estimable
at this time.
Note J: Fair Value of Financial Instruments
The carrying amounts and estimated fair value of
financial instruments at December 31 were as follows:
1998 1997
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Assets:
Temporary cash investments $ 882 $ 882 $ 5,863 $ 5,863
Life insurance contracts 87,468 87,468 79,474 79,474
Liabilities:
Short-term debt 258,837 258,837 206,401 206,401
Long-term debt and QUIDS 2,198,577 2,307,081 2,399,852 2,517,863
Interest rate swap 1,528 3,831 3,244
Option contract for interest rate swap 5,717 5,717
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 carrying amount of the swap represents a
liability associated with the refinancing transaction which
occurred in January 1998. The Company has no financial
instruments held or issued for trading purposes.
Note K: Capitalization
Preferred Stock
All of the preferred stock is entitled on voluntary
liquidation to its then current call price and on involuntary
liquidation to $100 a share. The holders of West Penn's market
auction preferred stock are entitled to dividends at a rate
determined quarterly by an auction process.
Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for
the next five years are: 1999, none; 2000, $140,000; 2001,
$160,000; 2002, $63,810; and 2003, $254,075. Substantially all of
the properties of the subsidiaries are held subject to the lien
securing each subsidiary's first mortgage bonds. Some properties
are also subject to a second lien securing certain pollution
control and solid waste disposal notes.
F-21
Allegheny Energy, Inc.
In October 1996, AYP Energy, Inc. (AYP Energy), a subsidiary
of AYP Capital, borrowed $160 million for five years from a
syndicate of eight banks priced at the London Interbank Offering
Rate (LIBOR) plus a spread. AYP Energy also entered into a
floating-to-fixed interest rate swap to hedge against
fluctuations in interest rates. The swap plus the spread on the
underlying financing fixed the interest rate to AYP Energy at
6.78%. In January 1998, the swap was refinanced in exchange for
the counterparty's right to exercise an option to extend the swap
until 2006. The new swap plus the spread on the underlying
financing lowered the interest rate to AYP Energy to 6.18%.
During 1998, the Company recorded a mark-to-market loss of $2.3
million related to this option.
Note L: 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, 1998, unused lines of credit with banks were
$300 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 1998 and 1997
consisted of:
(Thousands of Dollars) 1998 1997
Balance and interest rate at end of year:
Commercial paper $208,837-5.40% $166,401-6.14%
Notes payable to banks 50,000-5.40% 40,000-6.75%
Average amount outstanding and interest
rate during the year:
Commercial paper 171,393-5.60% 100,572-5.62%
Notes payable to banks 44,789-5.62% 13,022-5.60%
Note M: Business Segments
In June 1997, the FASB issued SFAS No. 131, "Disclosures
about Segments of an Enterprise and Related Information," to
establish standards for reporting information about operating
segments in financial statements. The Company's principal
business segments are utility and nonutility operations. The
utility subsidiaries, doing business as Allegheny Power, include
the generation, purchase, transmission, distribution, and sale of
electric energy. Allegheny Power derives substantially all of its
income from operations of its utility subsidiaries, Monongahela
Power, Potomac Edison, and West Penn. Nonutility operations
consists of AYP Capital, a wholly owned subsidiary, formed in an
effort to meet the challenges of the new competitive environment
in the electric industry. AYP Capital has three wholly owned
subsidiaries, AYP Energy, Allegheny Communications Connect, Inc.
(ACC), and Allegheny Energy Solutions, Inc. (Allegheny Energy
Solutions). AYP Energy is a power marketer. ACC is an exempt
telecommunications company under the PUHCA. Allegheny Energy
Solutions was formed to market electric energy to retail
customers in deregulated markets. Because of organizational
F-22
Allegheny Energy, Inc.
efficiencies available in an alternate corporate structure,
Allegheny Energy Solutions no longer competes in deregulated
markets. Rather, that role has been assumed by the Energy Supply
Division of the Supply Business of West Penn, acting under the
name Allegheny Energy Supply. AYP Capital, in its own name, also
markets various services related to the electric industry and has
investments in two limited energy partnerships.
Business segment information for 1998, 1997, and 1996 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.
(Thousands of Dollars) 1998 1997 1996
Operating Revenues:
Utility $2,330,261 $2,286,175 $2,326,902
Nonutility 246,986 85,794 747
Eliminations (811) (2,478)
Federal and State Income Taxes:
Utility 178,929 177,581 129,877
Nonutility (10,533) (9,508) (1,885)
Operating Income:
Utility 449,762 457,267 391,081
Nonutility (10,255) (5,030) (227)
Interest Charges and Preferred Dividends:
Utility 176,073 182,564 186,260
Nonutility 10,159 10,786 2,074
Consolidated Income Before Extraordinary Charge:
Utility 283,323 295,653 212,914
Nonutility (20,315) (14,357) (2,867)
Extraordinary Charge, Net:
Utility 275,426
Nonutility
Identifiable Assets:
Utility 6,534,375 6,442,512 6,410,789
Nonutility 213,418 211,579 207,721
Depreciation:
Utility 264,609 259,145 263,235
Nonutility 5,770 6,605 11
Capital Expenditures:
Utility 229,362 284,648 289,454
Nonutility 6,205 829 180,245
The 1998 utility extraordinary charge, net, reflects a write-
off of certain disallowances in the Pennsylvania PUC's May 29,
1998, restructuring Order and resulting November 19, 1998,
settlement agreement with regard to West Penn as described in
Notes B and C, starting on pages 50 and 52, respectively.
F-23
Allegheny Energy, Inc.
Note N: Commitments and Contingencies
Construction Program
The subsidiaries have entered into commitments for their
construction programs, for which expenditures are estimated to be
$315 million for 1999 and $294 million for 2000. Construction
expenditure levels in 2001 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 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.
Market Risk
The Company's utility subsidiaries and AYP Energy, one of
the Company's nonutility subsidiaries, supply power in the bulk
power market. At December 31, 1998, the marketing books for such
operations consisted primarily of fixed-priced, forward-purchase
and/or sale contracts which require settlement by physical
delivery of electricity. These transactions result in market
risk, which occurs when the market price of a particular
obligation or entitlement varies from the contract price.
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. This policy requires
continuous monitoring for conformity to policies which limit
value at risk and market risk associated with the credit standing
of trading counterparties. Such credit standing must be within
the guidelines established by the Company's Risk Control Policy.
The Company's exposure to volatility in the price of electricity
and other energy commodities is maintained within approved policy
limits, but has increased as a result of Pennsylvania
restructuring, which created retail access to a deregulated
electric supply market.
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
F-24
Allegheny Energy, Inc.
amount that is precisely set by the EPA on a state-by-state basis.
The final SIP call rule requires that all state-adopted NOx
reduction measures must be incorporated into SIPs by September 24,
1999, and must be implemented by May 1, 2003. The Company's
compliance with these requirements would require the installation
of post-combustion control technologies on most, if not all, of
its power stations at a cost of approximately $360 million. The
Company continues to work with other coal-burning utilities
and other affected constituencies in coal-producing states
to challenge this EPA action.
The utility subsidiaries previously reported that the EPA
had identified them 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
subsidiaries' share of the remediation costs based on the amount
of materials sent to the site. The regulated subsidiaries have
also been named as defendants along with multiple other
defendants in pending asbestos cases involving one or more
plaintiffs. The utility subsidiaries believe that provisions for
liabilities and insurance recoveries are such that final
resolution of these claims will not have a material effect on
their financial position.
F-25
Monongahela Power Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholder
of Monongahela Power Company
In our opinion, the accompanying balance sheet, statement of
capitalization and the related statements of income, of retained
earnings and of cash flows present fairly, in all material
respects, the financial position of Monongahela Power Company (a
subsidiary of Allegheny Energy, Inc.) at December 31, 1998 and
1997, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles. 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 generally accepted
auditing standards 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 4, 1999
F-26
Monongahela Power Company
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1998 1997 1996
Electric Operating Revenues:
Residential..................................................... $200,896 $199,931 $206,033
Commercial...................................................... 126,464 118,825 121,631
Industrial...................................................... 208,613 196,716 200,970
Wholesale and other, including affiliates....................... 89,396 95,579 86,474
Bulk power transactions, net.................................... 19,753 17,260 17,363
Total Operating Revenues...................................... 645,122 628,311 632,471
Operating Expenses:
Operation:
Fuel.......................................................... 143,993 141,340 135,833
Purchased power and exchanges, net............................ 95,617 98,266 101,593
Deferred power costs, net..................................... (8,452) (10,027) (3,051)
Other......................................................... 82,637 75,908 76,105
Maintenance..................................................... 67,033 70,561 74,735
Internal restructuring charges.................................. 24,299
Depreciation.................................................... 58,610 56,593 55,490
Taxes other than income taxes................................... 44,742 38,776 40,418
Federal and state income taxes.................................. 49,456 47,519 34,496
Total Operating Expenses...................................... 533,636 518,936 539,918
Operating Income.............................................. 111,486 109,375 92,553
Other Income and Deductions:
Allowance for other than borrowed funds used during
construction.................................................. 376 570 313
Other income, net............................................... 6,049 8,498 6,831
Total Other Income and Deductions............................. 6,425 9,068 7,144
Income Before Interest Charges................................ 117,911 118,443 99,697
Interest Charges:
Interest on long-term debt...................................... 32,363 36,076 36,654
Other interest.................................................. 3,790 2,654 1,950
Allowance for borrowed funds used during construction........... (667) (816) (359)
Total Interest Charges........................................ 35,486 37,914 38,245
Net Income......................................................... $82,425 $ 80,529 $ 61,452
STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $243,939 $215,221 $208,761
Add:
Net income...................................................... 82,425 80,529 61,452
326,364 295,750 270,213
Deduct:
Dividends on capital stock:
Preferred stock............................................... 5,037 5,037 5,037
Common stock.................................................. 48,129 46,774 49,955
Total Deductions............................................ 53,166 51,811 54,992
Balance at December 31............................................ $273,198 $243,939 $215,221
See accompanying notes to financial statements.
F-27
Monongahela Power Company
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1998 1997 1996
Cash Flows from Operations:
Net income...................................................... $ 82,425 $ 80,529 $ 61,452
Depreciation.................................................... 58,610 56,593 55,490
Deferred investment credit and income taxes, net................ 14,827 18,139 7,739
Deferred power costs, net....................................... (8,452) (10,027) (3,051)
Unconsolidated subsidiaries' dividends in excess of earnings.... 9,301 988 3,100
Allowance for other than borrowed funds used during
construction.................................................. (376) (570) (313)
Internal restructuring liability................................ (236) (13,761) 13,734
Changes in certain current assets and liabilities:
Accounts receivable, net...................................... (8,907) (80) 4,356
Materials and supplies........................................ (3,929) 1,878 5,123
Accounts payable.............................................. 15,324 (11,453) (9,970)
Other, net...................................................... 2,198 (5,100) 8,998
160,785 117,136 146,658
Cash Flows from Investing:
Construction expenditures (less allowance for other than
borrowed funds used during construction)...................... (72,419) (77,569) (72,264)
Cash Flows from Financing:
Issuance of long-term debt...................................... 85,918
Retirement of long-term debt.................................... (111,690) (15,500) (18,500)
Short-term debt, net............................................ (7,829) 28,590 1,271
Notes payable to affiliates..................................... (1,450) (1,450)
Dividends on capital stock:
Preferred stock............................................... (5,037) (5,037) (5,037)
Common stock.................................................. (48,129) (46,774) (49,955)
(88,217) (40,171) (72,221)
Net Change in Cash and Temporary Cash Investments................. 149 (604) 2,173
Cash and temporary cash investments at January 1.................. 1,686 2,290 117
Cash and temporary cash investments at December 31................ $ 1,835 $ 1,686 $ 2,290
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 33,041 $ 36,776 $ 37,190
Income taxes.................................................. 33,361 28,282 31,064
See accompanying notes to financial statements.
F-28
Monongahela Power Company
BALANCE SHEET
(Thousands of Dollars)
DECEMBER 31
1998 1997
ASSETS
Property, Plant, and Equipment:
At original cost, including $43,657 and
$55,588 under construction........... $2,007,876 $1,950,478
Accumulated depreciation............... (883,915) (840,525)
1,123,961 1,109,953
Investments:
Allegheny Generating Company--common
stock at equity....................... 44,624 53,888
Other.................................. 231 268
44,855 54,156
Current Assets:
Cash................................... 1,835 1,686
Accounts receivable:
Electric service, net of $2,516 and
$2,176 uncollectible allowance...... 68,293 68,143
Affiliated and other................. 19,674 10,917
Materials and supplies--at average cost:
Operating and construction........... 21,942 18,716
Fuel................................. 16,588 15,885
Prepaid taxes.......................... 19,627 17,287
Other, including current portion
of regulatory assets.................. 9,652 3,559
157,611 136,193
Deferred Charges:
Regulatory assets...................... 154,882 164,260
Unamortized loss on reacquired debt.... 17,826 14,338
Other.................................. 19,893 14,354
192,601 192,952
Total.................................... $1,519,028 $1,493,254
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital,
and retained earnings................. $ 570,188 $ 540,930
Preferred stock........................ 74,000 74,000
Long-term debt and QUIDS............... 453,917 455,088
1,098,105 1,070,018
Current Liabilities:
Short-term debt........................ 49,000 56,829
Long-term debt due within one year..... 20,100
Notes payable to affiliates............ 1,450
Accounts payable....................... 13,080 5,910
Accounts payable to affiliates......... 13,958 5,804
Taxes accrued:
Federal and state income............. 6,277 5,046
Other................................ 23,192 18,935
Interest accrued....................... 7,692 7,877
Other.................................. 13,362 13,470
126,561 135,421
Deferred Credits and Other Liabilities:
Unamortized investment credit.......... 16,155 18,297
Deferred income taxes.................. 242,805 235,291
Regulatory liabilities................. 15,476 16,973
Other.................................. 19,926 17,254
294,362 287,815
Commitments and Contingencies (Note L)
Total................................... $1,519,028 $1,493,254
See accompanying notes to financial statements
F-29
Monongahela Power Company
STATEMENT OF CAPITALIZATION
DECEMBER 31
1998 1997 1998 1997
(Thousands of Dollars) (Capitalization Ratios)
Common Stock:
Common stock--par value $50 per share, authorized
8,000,000 shares, outstanding 5,891,000 shares.... $ 294,550 $ 294,550
Other paid-in capital............................... 2,441 2,441
Retained earnings................................... 273,197 243,939
Total........................................... 570,188 540,930 51.9% 50.6%
Preferred Stock:
Cumulative preferred stock--par value $100 per share,
authorized 1,500,000 shares, outstanding as follows:
December 31, 1998
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
4.40% .... 90,000 $106.50 1945 9,000 9,000
4.80% B... 40,000 105.25 1947 4,000 4,000
4.50% C... 60,000 103.50 1950 6,000 6,000
$6.28 D... 50,000 102.86 1967 5,000 5,000
$7.73 L... 500,000 100.00 1994 50,000 50,000
Total (annual dividend requirements $5,037) 74,000 74,000 6.8 6.9
Long-Term Debt and QUIDS:
First mortgage Date of Date Date
bonds: Issue Redeemable Due
5-5/8% ... 1993 2000 2000 65,000 65,000
7-3/8% ... 1992 2002 2002 25,000 25,000
7-1/4% ... 1992 2002 2007 25,000 25,000
8-5/8% ... 1991 2001 2021 50,000 50,000
8-1/2% ... 1992 1998 2022 65,000
8-3/8% ... 1992 2002 2022 40,000 40,000
7-5/8% ... 1995 2005 2025 70,000 70,000
December 31, 1998
Interest Rate
Quarterly Income Debt Securities
due 2025...................... 8.00% 40,000 40,000
Secured notes due 2002-2024..... 4.70%-6.875% 74,050 74,050
Unsecured notes due 2002-2012... 4.35%-5.10% 6,060 6,560
Installment purchase
obligations due 2003.......... 4.50% 19,100 19,100
Medium-term debt due 2003....... 5.56%-5.71% 43,475
Unamortized debt discount and premium, net.......... (3,768) (4,522)
Total (annual interest requirements $31,498) 453,917 475,188
Less current maturities............................. (20,100)
Total........................................... 453,917 455,088 41.3 42.5
Total Capitalization.................................. $1,098,105 $1,070,018 100.0% 100.0%
See accompanying notes to financial statements.
F-30
Monongahela Power Company
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Monongahela Power Company (the Company) is a wholly owned
subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a
part of the Allegheny Energy integrated electric utility system
(the System). The Company and its utility affiliates, The
Potomac Edison Company and West Penn Power Company, do business
as Allegheny Power.
The Company is subject to regulation by the Securities and
Exchange Commission (SEC), by various state bodies having
jurisdiction, and by the Federal Energy Regulatory Commission
(FERC). Significant accounting policies of the Company are
summarized below.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.
Revenues
Revenues, including amounts resulting from the application of
fuel and energy cost adjustment clauses, are recognized in the
same period in which the related electric services are provided
to customers by recording an estimate for unbilled revenues for
services provided from the meter reading date to the end of the
accounting period.
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.
Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated affiliates in the System, are stated at original cost,
less contributions in aid of construction, except for capital
leases, which are recorded at present value. Costs include
direct labor and material; allowance for funds used during
construction (AFUDC) on property for which construction work in
progress is not included in rate base; and indirect costs such as
administration, maintenance, and depreciation of transportation
and construction equipment, postretirement benefits, taxes, and
other benefits related to employees engaged in construction.
The cost of depreciable property units retired, plus removal
costs less salvage, are charged to accumulated depreciation.
Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including
"the net cost for the period of construction of borrowed funds
used for construction purposes and a reasonable rate on other
funds when so used." AFUDC is recognized as a cost
F-31
Monongahela Power Company
of property, plant, and equipment with offsetting credits to
other income and interest charges. Rates used for computing
AFUDC in 1998, 1997, and 1996 were 6.56%, 7.55%, and 7.90%,
respectively. AFUDC is not included in the cost of construction
when the cost of financing the construction is being recovered
through rates.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives of
depreciable properties and amounted to approximately 3.1% of
average depreciable property in each of the years 1998, 1997, and
1996. The cost of maintenance and of certain replacements of
property, plant, and equipment is charged principally to
operating expenses.
Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash
investments with original maturities of three months or less,
generally in the form of commercial paper, certificates of
deposit, and repurchase agreements, are considered to be the
equivalent of cash.
Regulatory Assets and Liabilities
In accordance with the Financial Accounting Standards Board's
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements include certain assets and
liabilities based on cost-based ratemaking regulation.
Income Taxes
The Company joins with its parent and affiliates in filing a
consolidated federal income tax return. The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.
Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period. Differences between income tax expense,
computed on the basis of financial accounting income and taxes
payable based on taxable income, are accounted for substantially
in accordance with the accounting procedures followed for
ratemaking purposes. 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.
Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to income with concurrent credits to a deferred
account. These balances are being amortized over the estimated
service lives of the related properties.
Postretirement Benefits
The Company participates with affiliated companies of Allegheny
Energy, Inc. in 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.
F-32
Monongahela Power Company
The Company and its affiliates 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. The
funding plan for these costs 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.
Capitalized Software Costs
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.
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
financial statements. The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.
Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company's principal business segment is utility operations
which includes the generation, purchase, transmission,
distribution, and sale of electricity.
NOTE B: PROPOSED MERGER
On April 7, 1997, the Company's parent, Allegheny Power System,
Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
announced that they had agreed to merge in a tax-free, stock-for-
stock transaction.
At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger. Allegheny Energy
and DQE made all necessary regulatory filings. Since then,
Allegheny Energy and DQE received approval of the merger from the
Nuclear Regulatory Commission, the Pennsylvania Public Utility
Commission (Pennsylvania PUC), and the FERC. The Pennsylvania
PUC and the FERC approvals were subject to conditions acceptable
to Allegheny Energy. In addition, while not required, the
Maryland Public Service Commission and the Public Utilities
Commission of Ohio have indicated their approval.
On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger. Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement. In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief. The District Court
did not rule on the merits of the lawsuit for specific
performance or damages. On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States
F-33
Monongahela Power Company
Court of Appeals for the Third Circuit. Allegheny Energy cannot
predict the outcome of this litigation.
All of the Company's incremental costs of the merger process
($4.4 million through December 31, 1998) are being deferred. The
accumulated merger costs will be written off by the Company when
the merger occurs or if it is determined that the merger will not
occur.
NOTE C: INTERNAL RESTRUCTURING CHARGES
In 1996, the System, including the Company, completed its
internal restructuring activities initiated in 1994, simplifying
the management structure and streamlining operations. During
1996, restructuring activities included consolidating operating
divisions, customer services, and other functions.
In 1996, the Company recorded restructuring charges of $24.3
million ($14.6 million after tax) in operating expenses,
including its share of all restructuring charges associated with
the reorganization. These charges reflected liabilities and
payments for severance, employee termination costs, and other
restructuring costs. The current portion of the restructuring
liability, reflected in other current liabilities, excluding
benefit plans curtailment adjustments to postretirement
liabilities (which are primarily recorded in other deferred
credits), consists of:
(Thousands of Dollars) 1998 1997
Internal restructuring liability:
Balance at beginning of period.................... $ 236 $13,997
Less payments and accrual reversals............... (236) (13,761)
Balance at end of period............................ $ - $ 236
As part of the reorganization, the Company and its utility
affiliates in 1996 expanded the intercompany use of each other's
employees to optimize the use of their skills. In 1997 virtually
all the employees in the System, including all of the Company's
employees, were transferred to Allegheny Power Service
Corporation (APSC) to facilitate the intercompany use of
personnel. APSC was formed in 1963 pursuant to the Public
Utility Holding Company Act of 1935 to perform certain functions
common to all companies in the System. APSC bills each company
at its cost (without profit) based on the work performed and
services provided to each company.
F-34
Monongahela Power Company
NOTE D: INCOME TAXES
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes--current:
Federal............................. $26,457 $21,812 $19,412
State............................... 8,135 7,455 7,317
Total............................. 34,592 29,267 26,729
Income taxes--deferred, net of
amortization........................ 16,971 20,287 9,883
Amortization of deferred
investment credit................... (2,144) (2,148) (2,145)
Total income taxes................ 49,419 47,406 34,467
Income taxes--credited to other
income and deductions............... 37 113 29
Income taxes--charged to operating
income.............................. $49,456 $47,519 $34,496
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) 1998 1997 1996
Income before income taxes............ $131,881 $128,048 $ 95,948
Amount so produced.................... $ 46,158 $ 44,817 $ 33,582
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation.......... 1,800 5,000 4,300
Plant removal costs............. (2,600) (2,400) (2,200)
State income tax, net of federal
income tax benefit................ 4,400 3,600 4,000
Amortization of deferred
investment credit................. (2,144) (2,148) (2,145)
Equity in earnings of subsidiaries.. (2,100) (3,000) (2,500)
Other, net.......................... 3,942 1,650 (541)
Total............................. $ 49,456 $ 47,519 $ 34,496
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
F-35
Monongahela Power Company
At December 31, the deferred tax assets and liabilities consisted
of the following:
(Thousands of Dollars) 1998 1997
Deferred tax assets:
Unamortized investment tax credit............... $ 10,779 $ 12,275
Tax interest capitalized........................ 4,269 4,500
Contributions in aid of construction............ 2,810 2,619
Advances for construction....................... 2,097 2,087
Internal restructuring.......................... 1,810 53
Deferred power costs, net....................... 1,266
Other........................................... 14,358 12,090
36,123 34,890
Deferred tax liabilities:
Book vs. tax plant basis differences, net....... 244,432 236,962
Other........................................... 38,420 33,865
282,852 270,827
Total net deferred tax liabilities................ 246,729 235,937
Portion above included in current liabilities..... (3,924) (646)
Total long-term net deferred tax liabilities.... $242,805 $235,291
NOTE E: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $76,384,000 of the Company's retained
earnings at December 31, 1998, is not available for cash
dividends on common stock, except that a portion thereof may be
paid as cash dividends where concurrently an equivalent amount of
cash is received by the Company as a capital contribution or as
the proceeds of the issue and sale of shares of its common stock.
NOTE F: ALLEGHENY GENERATING COMPANY
The Company owns 27% of the common stock of Allegheny Generating
Company (AGC), and affiliates of the Company own the remainder.
AGC is reported by the Company in its financial statements using
the equity method of accounting. AGC owns an undivided 40%
interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.
AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and a
return on its investment under a wholesale rate schedule approved
by the FERC. AGC's rates are set by a formula filed with and
previously accepted by the FERC. The only component which
changes is the return on equity (ROE). Pursuant to a settlement
agreement filed April 4, 1996, with the FERC, AGC's ROE was set
at 11% for 1996 and will continue until the time any affected
party seeks renegotiation of the ROE.
F-36
Monongahela Power Company
Following is a summary of financial information for AGC:
December 31
(Thousands of Dollars) 1998 1997
Balance sheet information:
Property, plant, and equipment............... $618,608 $635,485
Current assets............................... 5,857 11,876
Deferred charges............................. 14,993 16,559
Total assets............................... $639,458 $663,920
Total capitalization......................... $314,105 $348,258
Current liabilities.......................... 75,849 70,540
Deferred credits............................. 249,504 245,122
Total capitalization and liabilities....... $639,458 $663,920
Year Ended December 31
(Thousands of Dollars) 1998 1997 1996
Income statement information:
Electric operating revenues......... $73,816 $76,458 $83,402
Operation and maintenance expense... 4,592 4,877 5,165
Depreciation........................ 16,949 17,000 17,160
Taxes other than income taxes....... 4,662 4,835 4,801
Federal income taxes................ 10,959 11,213 13,297
Interest charges.................... 13,987 15,391 16,193
Other income, net................... (86) (9,126) (3)
Net income........................ $22,753 $32,268 $26,789
The Company's share of the equity in earnings was $6.1 million,
$8.7 million, and $7.2 million for 1998, 1997, and 1996,
respectively, and is included in other income, net, on the
Company's Statement of Income. Dividends received from AGC in
1998 approximated $15 million which reflects an effort to reduce
AGC equity to about 45% of total capitalization and short-term
debt.
NOTE G: POSTRETIREMENT BENEFITS
As described in Note A, the Company and its affiliates
participate in a pension plan and medical and life insurance
plans for eligible employees and dependents. The Company is
responsible for its proportional share of the costs (credits) and
the assets or liabilities of the plans. As described in Note C,
in 1997 the Company transferred all of its employees to APSC.
The Company's share of the costs (credits) of these plans, a
portion of which (about 25% to 35%) was charged to plant
construction, is as follows:
(Thousands of Dollars) 1998 1997 1996
Pension................................ $ (356) $(1,754) $ 78
Medical and life insurance............. $5,421 $ 3,706 $5,461
F-37
Monongahela Power Company
NOTE H: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS
No. 71. Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered
from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers
through the ratemaking process. Regulatory assets, net of
regulatory liabilities, reflected in the Balance Sheet at
December 31 relate to:
(Thousands of Dollars) 1998 1997
Long-Term Assets (Liabilities), Net:
Income taxes, net.............................. $130,878 $137,056
Postretirement benefits........................ 4,937 4,937
Storm damage................................... 1,047 2,211
Other, net..................................... 2,544 3,083
Subtotal..................................... 139,406 147,287
Current Assets (Liabilities), Net:
Income taxes, net (reported in other
current assets).............................. 1,847 1,847
Deferred power costs, net...................... 6,878 (484)
Subtotal..................................... 8,725 1,363
Net Regulatory Assets...................... $148,131 $148,650
Deregulation/competition proceedings in West Virginia and Ohio
may in the future result in less than full recovery of costs
incurred to serve customers. Such deregulation and transition to
a competitive environment could adversely affect the Company's
results of operations, cash flows, and capitalization. Such
charges, if any, are not estimable at this time.
NOTE I: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:
1998 1997
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Liabilities:
Short-term debt....... $ 49,000 $ 49,000 $ 58,279 $ 58,279
Long-term debt and
QUIDS............... 457,685 483,695 479,710 528,155
The carrying amount of short-term debt approximates the fair
value because of the short maturity of those instruments. The
fair value of long-term debt and QUIDS was estimated based on
actual market prices or market prices of similar issues. The
Company has no financial instruments held or issued for trading
purposes.
F-38
Monongahela Power Company
NOTE J: CAPITALIZATION
Preferred Stock
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share.
Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the
next five years are: 1999, none; 2000, $65,000; 2001, none; 2002,
$27,060; and 2003, $62,575. Substantially all of the properties
of the Company are held subject to the lien securing its first
mortgage bonds. Some properties are also subject to a second
lien securing certain pollution control and solid waste disposal
notes. Certain first mortgage bonds series are not redeemable by
certain refunding until dates established in the respective
supplemental indentures.
NOTE K: SHORT-TERM DEBT
To provide interim financing and support for outstanding
commercial paper, the System companies have established lines of
credit with several banks. The Company has SEC authorization for
total short-term borrowings of $106 million, including money pool
borrowings described below. The Company has fee arrangements on
all of its lines of credit and no compensating balance
requirements. In addition to bank lines of credit, an Allegheny
Energy internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated
companies have funds available. Short-term debt outstanding for
1998 and 1997 consisted of:
(Thousands of Dollars) 1998 1997
Balance and interest rate
at end of year:
Commercial Paper................... $56,829-6.50%
Notes Payable to Banks............. $49,000-5.40%
Money Pool......................... 1,450-5.96%
Average amount outstanding and
interest rate during the year:
Commercial Paper................... 12,900-5.66% 1,651-5.76%
Notes Payable to Banks............. 21,793-5.60% 7,307-5.56%
Money Pool......................... 3,764-5.46% 9,300-5.44%
NOTE L: COMMITMENTS AND CONTINGENCIES
Construction Program
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $76 million
for 1999 and $79 million for 2000. Construction expenditure
levels in 2001 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 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.
F-39
Monongahela Power Company
Market Risk
The Company supplies power in the bulk power market. At December
31, 1998, the marketing books for such operations consisted
primarily of fixed-priced, forward-purchase and/or sale contracts
which require settlement by physical delivery of electricity.
Allegheny Energy has a Corporate Energy Risk Control Policy
adopted by the Board of Directors and monitored by an Exposure
Management Committee of senior management. This policy requires
continuous monitoring for conformity to policies which limit
value at risk and market risk associated with the credit standing
of counterparties. Such credit standing must be within the
guidelines established by Allegheny Energy's Risk Control Policy.
The Company's exposure to volatility in the price of electricity
and other energy commodities is maintained within approved policy
limits.
Environmental Matters and Litigation
System 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 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations
at a cost of approximately $96 million. The Company continues to
work with other coal-burning utilities and other affected
constituencies in coal-producing states to challenge this EPA
action.
The Company previously reported that the EPA had identified it
and its regulated affiliates as potentially responsible parties,
along with approximately 175 others, in a Superfund site subject
to cleanup. A final determination has not been made for the
Company's share of the remediation costs based on the amount of
materials sent to the site. The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs. The Company believes that provisions for liabilities
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.
F-40
The Potomac Edison Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders
of The Potomac Edison Company
In our opinion, the accompanying balance sheet and statement of
capitalization and the related statements of income, of retained
earnings and of cash flows present fairly, in all material
respects, the financial position of The Potomac Edison Company (a
subsidiary of Allegheny Energy, Inc.) at December 31, 1998 and
1997, and the results of its operations and its cash flows for
each of the three years in the period ended December 31, 1998, in
conformity with generally accepted accounting principles. 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 generally accepted
auditing standards 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 4, 1999
F-41
The Potomac Edison Company
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1998 1997 1996
Electric Operating Revenues:
Residential..................................................... $309,058 $299,876 $324,120
Commercial...................................................... 156,973 148,287 146,432
Industrial...................................................... 206,638 198,174 196,813
Wholesale and other, including affiliates....................... 38,426 38,857 34,901
Bulk power transactions, net.................................... 26,399 23,587 24,494
Total Operating Revenues...................................... 737,494 708,781 726,760
Operating Expenses:
Operation:
Fuel.......................................................... 143,124 140,206 137,310
Purchased power and exchanges, net............................ 138,277 140,183 141,027
Deferred power costs, net..................................... 1,812 (4,944) 5,040
Other......................................................... 86,785 83,905 89,756
Maintenance..................................................... 52,186 56,815 62,248
Internal restructuring charges.................................. 26,094
Depreciation.................................................... 74,344 71,763 71,254
Taxes other than income taxes................................... 49,567 47,585 45,809
Federal and state income taxes.................................. 52,603 44,496 34,132
Total Operating Expenses...................................... 598,698 580,009 612,670
Operating Income.............................................. 138,796 128,772 114,090
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction........................................... 597 1,716 1,409
Other income, net............................................... 9,297 13,976 11,791
Total Other Income and Deductions............................. 9,894 15,692 13,200
Income Before Interest Charges................................ 148,690 144,464 127,290
Interest Charges:
Interest on long-term debt...................................... 46,010 47,659 47,982
Other interest.................................................. 2,177 2,164 2,215
Allowance for borrowed funds used during construction........... (979) (1,114) (1,082)
Total Interest Charges........................................ 47,208 48,709 49,115
Net Income........................................................ $101,482 $ 95,755 $ 78,175
STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $239,391 $227,726 $216,852
Add:
Net income...................................................... 101,482 95,755 78,175
340,873 323,481 295,027
Deduct:
Dividends on capital stock:
Preferred stock............................................... 818 818 818
Common stock.................................................. 27,533 83,272 66,483
Total deductions............................................ 28,351 84,090 67,301
Balance at December 31............................................ $312,522 $239,391 $227,726
See accompanying notes to financial statements.
F-42
The Potomac Edison Company
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1998 1997 1996
Cash Flows from Operations:
Net income...................................................... $ 101,482 $ 95,755 $ 78,175
Depreciation.................................................... 74,344 71,763 71,254
Deferred investment credit and income taxes, net................ 8,682 5,984 5,157
Deferred power costs, net....................................... 1,812 (4,944) 5,040
Unconsolidated subsidiaries' dividends in excess of earnings.... 9,607 1,058 3,211
Allowance for other than borrowed funds used during
construction.................................................. (597) (1,716) (1,409)
Internal restructuring liability................................ (1,187) (13,783) 15,801
Changes in certain current assets and liabilities:
Accounts receivable, net...................................... 4,472 9,450 (2,016)
Materials and supplies........................................ (4,462) (764) 6,768
Accounts payable.............................................. 17,529 (1,994) 4,184
Other, net...................................................... 4,138 10,485 (2,686)
215,820 171,294 183,479
Cash Flows from Investing:
Construction expenditures (less allowance for other
than borrowed funds used during construction)................. (59,928) (76,582) (84,847)
Cash Flows from Financing:
Issuance of long-term debt...................................... 33,200
Retirement of long-term debt.................................... (86,655) (800) (18,700)
Short-term debt, net............................................ (7,497) (14,140)
Notes receivable from affiliates................................ (7,850) (1,450)
Notes receivable from subsidiary................................ (66,750)
Dividends on capital stock:
Preferred stock............................................... (818) (818) (818)
Common stock.................................................. (27,533) (83,272) (66,483)
156,406) (93,837) (100,141)
Net Change in Cash and Temporary Cash Investments................. (514) 875 (1,509)
Cash and temporary cash investments at January 1.................. 2,319 1,444 2,953
Cash and temporary cash investments at December 31................ $ 1,805 $ 2,319 $ 1,444
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 46,770 $ 47,642 $ 47,580
Income taxes.................................................. 41,132 36,705 37,694
See accompanying notes to financial statements.
F-43
The Potomac Edison Company
BALANCE SHEET
(Thousands of Dollars)
DECEMBER 31
ASSETS 1998 1997
Property, Plant, and Equipment:
At original cost, including $46,353
and $55,702 under construction........ $2,249,716 $2,196,262
Accumulated depreciation............... (926,840) (859,076)
1,322,876 1,337,186
Investments and Other Assets:
Allegheny Generating Company--common
stock at equity...................... 46,277 55,847
Other.................................. 473 529
46,750 56,376
Current Assets:
Cash................................... 1,805 2,319
Accounts receivable:
Electric service, net of $2,203 and
$1,683 uncollectible allowance..... 77,170 83,431
Affiliated and other................. 7,091 5,302
Notes receivable from affiliate........ 9,300 1,450
Notes receivable from subsidiary....... 66,750
Materials and supplies--at average cost:
Operating and construction........... 29,922 23,715
Fuel................................. 14,098 15,843
Prepaid taxes.......................... 15,727 15,052
Other.................................. 1,092 4,716
222,955 151,828
Deferred Charges:
Regulatory assets...................... 66,792 80,651
Unamortized loss on reacquired debt.... 19,012 17,094
Other.................................. 23,742 17,512
109,546 115,257
Total.................................... $1,702,127 $1,660,647
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital,
and retained earnings................ $ 762,912 $ 689,781
Preferred stock........................ 16,378 16,378
Long-term debt and QUIDS............... 578,817 627,012
1,358,107 1,333,171
Current Liabilities:
Long-term debt due within one year..... 1,800
Accounts payable....................... 35,572 29,125
Accounts payable to affiliates......... 31,011 19,929
Deferred income taxes.................. 11,311
Taxes accrued:
Federal and state income............. 6,430 2,106
Other................................ 18,922 11,461
Interest accrued....................... 7,193 9,487
Payrolls accrued....................... 6,353
Other.................................. 8,770 10,553
119,209 90,814
Deferred Credits and Other Liabilities:
Unamortized investment credit.......... 19,592 21,470
Deferred income taxes.................. 170,349 178,529
Regulatory liabilities................. 11,233 12,424
Other.................................. 23,637 24,239
224,811 236,662
Commitments and Contingencies (Note K)
Total.................................... $1,702,127 $1,660,647
See accompanying notes to financial statements.
F-44
The Potomac Edison Company
STATEMENT OF CAPITALIZATION
DECEMBER 31
1998 1997 1998 1997
(Thousands of Dollars) (Capitalization Ratios)
Common Stock:
Common stock--no par value, authorized 23,000,000
shares, outstanding 22,385,000 shares............ $ 447,700 $ 447,700
Other paid-in capital.............................. 2,690 2,690
Retained earnings.................................. 312,522 239,391
Total.......................................... 762,912 689,781 56.2% 51.8%
Preferred Stock:
Cumulative preferred stock--par value $100 per share,
authorized 5,378,611 shares, outstanding as follows:
December 31, 1998
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
3.60% .... 63,784 $103.75 1946 6,378 6,378
$5.88 C... 100,000 102.85 1967 10,000 10,000
Total (annual dividend requirements $818)...... 16,378 16,378 1.2 1.2
Long-Term Debt and QUIDS:
First mortgage Date of Date Date
bonds: Issue Redeemable Due
5-7/8% ...... 1993 2000 2000 75,000 75,000
8 % ...... 1991 2001 2006 50,000 50,000
8-7/8% ...... 1991 1998 2021 50,000
8 % ...... 1992 2002 2022 55,000 55,000
7-3/4% ...... 1993 2003 2023 45,000 45,000
8 % ...... 1994 2004 2024 75,000 75,000
7-5/8% ...... 1995 2005 2025 80,000 80,000
7-3/4% ...... 1995 2005 2025 65,000 65,000
December 31, 1998
Interest Rate
Quarterly Income Debt Securities
due 2025.............................. 8.00% 45,457 45,457
Secured notes due 2007-2024............. 4.70%-6.875% 91,700 91,700
Unsecured note due 2002................. 4.35% 3,200 4,000
Unamortized debt discount............... (6,540) (7,345)
Total (annual interest requirements
$42,525).......................... 578,817 628,812
Less current maturities................. (1,800)
Total..................................... 578,817 627,012 42.6 47.0
Total Capitalization...................... $1,358,107 $1,333,171 100.0% 100.0%
See accompanying notes to financial statements.
F-45
The Potomac Edison Company
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
The Potomac Edison Company (the Company) is a wholly owned
subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a
part of the Allegheny Energy integrated electric utility system
(the System). The Company and its utility affiliates,
Monongahela Power Company and West Penn Power Company, do
business as Allegheny Power.
The Company is subject to regulation by the Securities and
Exchange Commission (SEC), by various state bodies having
jurisdiction, and by the Federal Energy Regulatory Commission
(FERC). Significant accounting policies of the Company are
summarized below.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.
Revenues
Revenues, including amounts resulting from the application of
fuel and energy cost adjustment clauses, are recognized in the
same period in which the related electric services are provided
to customers by recording an estimate for unbilled revenues for
services provided from the meter reading date to the end of the
accounting period. Revenues of $65 million from one industrial
customer were 9% of total electric operating revenues in 1998.
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.
Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated affiliates in the System, are stated at original cost,
less contributions in aid of construction. Costs include direct
labor and material; allowance for funds used during construction
(AFUDC) on property for which construction work in progress is
not included in rate base; and such indirect costs as
administration, maintenance, and depreciation of transportation
and construction equipment, postretirement benefits, taxes, and
other benefits related to employees engaged in construction.
The cost of depreciable property units retired, plus removal
costs less salvage, are charged to accumulated depreciation.
F-46
The Potomac Edison Company
Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including
"the net cost for the period of construction of borrowed funds
used for construction purposes and a reasonable rate on other
funds when so used." AFUDC is recognized as a cost of property,
plant, and equipment with offsetting credits to other income and
interest charges. Rates used for computing AFUDC in 1998, 1997,
and 1996 were 9.83%, 9.75%, and 9.32%, respectively. AFUDC is
not included in the cost of construction when the cost of
financing the construction is being recovered through rates.
AFUDC is not recorded for construction applicable to the state of
Virginia, where construction work in progress is included in rate
base.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives of
depreciable properties and amounted to approximately 3.5% of
average depreciable property in each of the years 1998 and 1997,
and 3.6% in 1996. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged
principally to operating expenses.
Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash
investments with original maturities of three months or less,
generally in the form of commercial paper, certificates of
deposit, and repurchase agreements, are considered to be the
equivalent of cash.
Regulatory Assets and Liabilities
In accordance with the Financial Accounting Standards Board's
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements include certain assets and
liabilities based on cost-based ratemaking regulation.
Income Taxes
The Company joins with its parent and affiliates in filing a
consolidated federal income tax return. The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.
Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period. Differences between income tax expense,
computed on the basis of financial accounting income and taxes
payable based on taxable income, are accounted for substantially
in accordance with the accounting procedures followed for
ratemaking purposes. 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.
Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to
F-47
The Potomac Edison Company
income with concurrent credits to a deferred account. These
balances are being amortized over the estimated service lives
of the related properties.
Postretirement Benefits
The Company participates with affiliated companies of Allegheny
Energy, Inc. in 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.
The Company and its affiliates 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. The
funding plan for these costs 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.
Capitalized Software Costs
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.
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
financial statements. The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.
Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company's principal business segment is utility operations
which includes the generation, purchase, transmission,
distribution, and sale of electricity.
NOTE B: PROPOSED MERGER
On April 7, 1997, the Company's parent, Allegheny Power System,
Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
announced that they had agreed to merge in a tax-free, stock-for-
stock transaction.
At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger. Allegheny Energy
and DQE made all necessary regulatory filings. Since then,
Allegheny Energy and DQE received approval of the merger from the
Nuclear Regulatory Commission, the Pennsylvania Public Utility
Commission (Pennsylvania PUC), and the FERC. The Pennsylvania
PUC and the FERC approvals were subject to conditions acceptable
to Allegheny Energy. In addition, while not required, the
Maryland Public
F-48
The Potomac Edison Company
Service Commission and the Public Utilities Commission of Ohio
have indicated their approval.
On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger. Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement. In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief. The District Court
did not rule on the merits of the lawsuit for specific
performance or damages. On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States Court of
Appeals for the Third Circuit. Allegheny Energy cannot predict
the outcome of this litigation.
All of the Company's incremental costs of the merger process
($5.2 million through December 31, 1998) are being deferred. The
accumulated merger costs will be written off by the Company when
the merger occurs or if it is determined that the merger will not
occur.
NOTE C: INTERNAL RESTRUCTURING CHARGES
In 1996, the System, including the Company, completed its
internal restructuring activities initiated in 1994, simplifying
the management structure and streamlining operations. During
1996, restructuring activities included consolidating operating
divisions, customer services, and other functions.
In 1996, the Company recorded restructuring charges of $26.1
million ($16.5 million after tax) in operating expenses,
including its share of all restructuring charges associated with
the reorganization. These charges reflected liabilities and
payments for severance, employee termination costs, and other
restructuring costs. The current portion of the restructuring
liability, reflected in other current liabilities, excluding
benefit plans curtailment adjustments to postretirement
liabilities (which are primarily recorded in other deferred
credits) consists of:
(Thousands of Dollars) 1998 1997
Internal restructuring liability:
Balance at beginning of period.................... $1,187 $14,970
Less payments and accrual reversals............... (1,187) (13,783)
Balance at end of period............................ $ - $ 1,187
As part of the reorganization, the Company and its utility
affiliates in 1996 expanded the intercompany use of each other's
employees to optimize the use of their skills. In 1997 virtually
all the employees in the System, including virtually all of the
Company's employees, were transferred to Allegheny Power Service
Corporation (APSC) to facilitate the intercompany use
F-49
The Potomac Edison Company
of personnel. APSC was formed in 1963 pursuant to the Public
Utility Holding Company Act of 1935 to perform certain functions
common to all companies in the System. APSC bills each company
at its cost (without profit) based on the work performed and
services provided to each company.
NOTE D: INCOME TAXES
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes--current:
Federal.............................. $40,003 $36,126 $26,651
State................................ 5,569 5,264 4,833
Total.............................. 45,572 41,390 31,484
Income taxes--deferred, net of
amortization......................... 10,559 8,136 7,351
Amortization of deferred investment
credit............................... (1,877) (2,152) (2,194)
Total income taxes................. 54,254 47,374 36,641
Income taxes--charged to other
income and deductions................ (1,651) (2,878) (2,509)
Income taxes--charged to operating
income............................... $52,603 $44,496 $34,132
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) 1998 1997 1996
Income before income taxes............. $154,085 $140,251 $112,305
Amount so produced..................... $ 53,930 $ 49,088 $ 39,307
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation........... 2,800 2,900 4,300
Plant removal costs............. (800) (700) (1,800)
State income tax, net of federal
income tax benefit................. 5,100 4,400 1,300
Amortization of deferred investment
credit............................. (1,878) (2,152) (2,194)
Equity in earnings of subsidiaries... (2,200) (3,100) (2,600)
Other, net........................... (4,349) (5,940) (4,181)
Total.............................. $ 52,603 $ 44,496 $ 34,132
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
F-50
The Potomac Edison Company
At December 31, the deferred tax assets and liabilities consisted
of the following:
(Thousands of Dollars) 1998 1997
Deferred tax assets:
Contributions in aid of construction............ $ 13,845 $ 13,841
Tax interest capitalized........................ 12,096 12,234
Unamortized investment tax credit............... 11,442 12,518
Postretirement benefits other than pensions..... 5,770 3,998
Unbilled revenue................................ 3,492 3,492
Internal restructuring.......................... 2,344 1,239
Advances for construction....................... 914 1,194
Other........................................... 3,685 3,436
53,588 51,952
Deferred tax liabilities:
Book vs. tax plant basis differences, net....... 218,434 211,837
Other........................................... 16,814 17,600
235,248 229,437
Total net deferred tax liabilities................ 181,660 177,485
Portion above included in current (liabilities)
assets.......................................... (11,311) 1,044
Total long-term net deferred tax liabilities.. $170,349 $178,529
NOTE E: ALLEGHENY GENERATING COMPANY
The Company owns 28% of the common stock of Allegheny Generating
Company (AGC), and affiliates of the Company own the remainder.
AGC is reported by the Company in its financial statements using
the equity method of accounting. AGC owns an undivided 40%
interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.
AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and a
return on its investment under a wholesale rate schedule approved
by the FERC. AGC's rates are set by a formula filed with and
previously accepted by the FERC. The only component which
changes is the return on equity (ROE). Pursuant to a settlement
agreement filed April 4, 1996, with the FERC, AGC's ROE was set
at 11% for 1996 and will continue until the time any affected
party seeks renegotiation of the ROE.
F-51
The Potomac Edison Company
Following is a summary of financial information for AGC:
December 31
(Thousands of Dollars) 1998 1997
Balance sheet information:
Property, plant, and equipment............... $618,608 $635,485
Current assets............................... 5,857 11,876
Deferred charges............................. 14,993 16,559
Total assets............................... $639,458 $663,920
Total capitalization......................... $314,105 $348,258
Current liabilities.......................... 75,849 70,540
Deferred credits............................. 249,504 245,122
Total capitalization and liabilities....... $639,458 $663,920
Year Ended December 31
(Thousands of Dollars) 1998 1997 1996
Income statement information:
Electric operating revenues......... $73,816 $76,458 $83,402
Operation and maintenance expense... 4,592 4,877 5,165
Depreciation........................ 16,949 17,000 17,160
Taxes other than income taxes....... 4,662 4,835 4,801
Federal income taxes................ 10,959 11,213 13,297
Interest charges.................... 13,987 15,391 16,193
Other income, net................... (86) (9,126) (3)
Net income........................ $22,753 $32,268 $26,789
The Company's share of the equity in earnings was $6.4 million,
$9.0 million, and $7.5 million for 1998, 1997, and 1996,
respectively, and is included in other income, net, on the
Company's Statement of Income. Dividends received from AGC in
1998 approximated $16 million which reflects an effort to reduce
AGC equity to about 45% of total capitalization and short-term
debt.
At December 31, 1998 the Company had an outstanding short-term
loan to AGC of $66.8 million at 4.80% through the Allegheny
Energy money pool.
NOTE F: POSTRETIREMENT BENEFITS
As described in Note A, the Company and its affiliates
participate in a pension plan and medical and life insurance
plans for eligible employees and dependents. The Company is
responsible for its proportional share of the costs (credits) and
the assets or liabilities of the plans. As described in Note C,
in 1997 the Company transferred virtually all of its employees to
APSC. The Company's share of the costs (credits) of these plans,
a portion of which (about 25% to 35%) was charged to plant
construction, is as follows:
(Thousands of Dollars) 1998 1997 1996
Pension................................ $ (323) $(1,745) $ (201)
Medical and life insurance............. $4,893 $ 4,007 $5,831
F-52
The Potomac Edison Company
NOTE G: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS
No. 71. Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered
from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers
through the ratemaking process. Regulatory assets, net of
regulatory liabilities, reflected in the Balance Sheet at
December 31 relate to:
(Thousands of Dollars) 1998 1997
Long-Term Assets (Liabilities), Net:
Income taxes, net............................. $45,847 $52,231
Demand-side management........................ 8,157 14,204
Postretirement benefits....................... 1,292 1,292
Deferred power costs (reported in other
deferred credits)........................... (2,455) (2,949)
Other, net.................................... 263 500
Subtotal.................................... 53,104 65,278
Current Assets (Liabilities), Net:
Deferred power costs (reported in
other current assets)....................... 333 2,682
Net Regulatory Assets..................... $53,437 $67,960
Deregulation/competition proceedings in Maryland, Virginia, and
West Virginia may in the future result in less than full recovery
of costs incurred to serve customers. Such deregulation and
transition to a competitive environment could adversely affect
the Company's results of operations, cash flows, and
capitalization. Such charges, if any, are not estimable at this
time.
NOTE H: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:
1998 1997
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Liabilities:
Long-term debt and
QUIDS................ $585,357 $607,726 $636,157 $672,198
The fair value of long-term debt and QUIDS was estimated based on
actual market prices or market prices of similar issues. The
Company has no financial instruments held or issued for trading
purposes.
F-53
The Potomac Edison Company
NOTE I: CAPITALIZATION
Preferred Stock
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share.
Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the
next five years are: 1999, none; 2000, $75,000; 2001, none;
2002, $3,200; and 2003, none. Substantially all of the
properties of the Company are held subject to the lien securing
its first mortgage bonds. Some properties are also subject to a
second lien securing certain pollution control and solid waste
disposal notes. Certain first mortgage bond series are not
redeemable by certain refunding until dates established in the
respective supplemental indentures.
NOTE J: SHORT-TERM DEBT
To provide interim financing and support for outstanding
commercial paper, the System companies have established lines of
credit with several banks. The Company has SEC authorization for
total short-term borrowings of $130 million, including money pool
borrowings described below. The Company has fee arrangements on
all of its lines of credit and no compensating balance
requirements. In addition to bank lines of credit, an Allegheny
Energy internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated
companies have funds available. Short-term debt outstanding for
1998 and 1997 consisted of:
(Thousands of Dollars) 1998 1997
Average amount outstanding and
interest rate during the year:
Commercial Paper..................... _ $137-5.63%
Notes Payable to Banks............... _ $189-5.37%
NOTE K: COMMITMENTS AND CONTINGENCIES
Construction Program
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $86 million
for 1999 and $98 million for 2000. Construction expenditure
levels in 2001 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.
Market Risk
The Company supplies power in the bulk power market. At December
31, 1998, the marketing books for such operations consisted
primarily of fixed-priced,
F-54
The Potomac Edison Company
forward-purchase and/or sale contracts which require settlement
by physical delivery of electricity.
Allegheny Energy has a Corporate Energy Risk Control Policy
adopted by the Board of Directors and monitored by an Exposure
Management Committee of senior management. This policy requires
continuous monitoring for conformity to policies which limit
value at risk and market risk associated with the credit standing
of counterparties. Such credit standing must be within the
guidelines established by Allegheny Energy's Risk Control Policy.
The Company's exposure to volatility in the price of electricity
and other energy commodities is maintained within approved policy
limits.
Environmental Matters and Litigation
System 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 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations
at a cost of approximately $103 million. The Company continues
to work with other coal-burning utilities and other affected
constituencies in coal-producing states to challenge this EPA
action.
The Company previously reported that the EPA had identified it
and its regulated affiliates as potentially responsible parties,
along with approximately 175 others, in a Superfund site subject
to cleanup. A final determination has not been made for the
Company's share of the remediation costs based on the amount of
materials sent to the site. The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs. The Company believes that provisions for liabilities
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.
F-55
West Penn Power Company
and Subsidiaries
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors and the Shareholder
of West Penn Power Company
In our opinion, the accompanying consolidated balance sheet and
consolidated statement of capitalization and the related
consolidated statements of income, of retained earnings and of
cash flows present fairly, in all material respects, the
financial position of West Penn Power Company (a subsidiary of
Allegheny Energy, Inc.) and its subsidiaries at December 31, 1998
and 1997, and the results of their operations and their cash
flows for each of the three years in the period ended December
31, 1998, in conformity with generally accepted accounting
principles. 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
generally accepted auditing standards 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 4, 1999
F-56
West Penn Power Company
and Subsidiaries
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
(Thousands of Dollars)
1998 1997 1996
Electric Operating Revenues:
Residential............................ $ 370,636 $ 393,036 $ 402,083
Commercial............................. 217,954 223,347 224,663
Industrial............................. 338,254 352,730 355,120
Wholesale and other, including
affiliates........................... 82,982 72,459 74,328
Bulk power transactions, net........... 68,901 40,590 32,930
Total Operating Revenues............. 1,078,727 1,082,162 1,089,124
Operating Expenses:
Operation:
Fuel................................. 258,199 254,210 239,337
Purchased power and exchanges, net... 121,286 120,005 126,908
Deferred power costs, net............ (7,944) 13,635
Other................................ 173,029 157,780 151,642
Maintenance............................ 91,724 98,252 104,211
Internal restructuring charges
and asset write-off.................. 53,343
Depreciation........................... 114,709 113,793 119,066
Taxes other than income taxes.......... 88,722 90,140 90,132
Federal and state income taxes......... 64,526 73,279 47,455
Total Operating Expenses............. 912,195 899,515 945,729
Operating Income..................... 166,532 182,647 143,395
Other Income and Deductions:
Allowance for other than borrowed
funds used during construction....... 581 2,107 1,434
Other income, net...................... 11,325 17,562 13,439
Total Other Income and Deductions.... 11,906 19,669 14,873
Income Before Interest Charges....... 178,438 202,316 158,268
Interest Charges:
Interest on long-term debt.............. 61,727 64,990 64,988
Other interest.......................... 5,913 4,639 6,084
Allowance for borrowed funds used
during construction................... (1,822) (1,978) (1,289)
Total Interest Charges................ 65,818 67,651 69,783
Consolidated income before
extraordinary charge................... 112,620 134,665 88,485
Extraordinary charge, net................. (275,426)
Consolidated Net (Loss) Income............ $(162,806) $ 134,665 $ 88,485
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Balance at January 1..................... $ 475,558 $ 441,283 $ 451,719
Add:
Consolidated net (loss) income......... (162,806) 134,665 88,485
312,752 575,948 540,204
Deduct:
Dividends on capital stock
of the Company:
Preferred stock...................... 3,396 3,430 3,423
Common stock......................... 98,664 96,960 95,498
Total Deductions................... 102,060 100,390 98,921
Balance at December 31................... $ 210,692 $ 475,558 $ 441,283
See accompanying notes to consolidated financial statements.
F-57
West Penn Power Company
and Subsidiaries
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1998 1997 1996
Cash Flows from Operations:
Consolidated net (loss) income......... $(162,806) $134,665 $ 88,485
Extraordinary charge, net of taxes..... 275,426
Consolidated income before
extraordinary charge................ 112,620 134,665 88,485
Depreciation........................... 114,709 113,793 119,066
Deferred investment credit
and income taxes, net................. (1,511) 31,381 2,022
Deferred power costs, net.............. (7,944) 13,635
Unconsolidated subsidiaries' dividends
in excess of earnings................ 15,484 1,702 5,191
Allowance for other than borrowed
funds used during construction........ (581) (2,107) (1,434)
Internal restructuring liability....... (4,082) (23,052) 25,879
PURPA project buyout................... (48,000)
Changes in certain current assets
and liabilities:
Accounts receivable, net............. 5,866 (12,382) 23,671
Materials and supplies............... (3,851) (3,421) 8,847
Accounts payable..................... 21,953 7,507 (14,809)
Other, net............................. (7,105) 11,532 1,714
253,502 203,674 272,267
Cash Flows from Investing:
Construction expenditures (less allowance
for other than borrowed funds used during
construction).......................... (95,394) (125,947) (129,172)
Cash Flows from Financing:
Issuance of long-term debt.............. 92,834
Retirement of long-term debt............ (161,435)
Short-term debt, net.................... 3,720 18,659 (36,831)
Notes payable to affiliates............. 9,300
Notes receivable from affiliates........ 2,900 (2,900)
Dividends on capital stock:
Preferred stock....................... (3,396) (3,430) (3,423)
Common stock.......................... (98,664) (96,960) (95,498)
(157,641) (78,831) (138,652)
Net Change in Cash and Temporary
Cash Investments....................... 467 (1,104) 4,443
Cash and Temporary Cash Investments at
January 1.............................. 4,056 5,160 717
Cash and Temporary Cash Investments
at December 31......................... $4,523 $ 4,056 $ 5,160
Supplemental Cash Flow Information:
Cash paid during the year for:
Interest (net of amount
capitalized)......................... $ 62,711 $ 64,594 $ 65,149
Income taxes......................... 73,653 43,297 57,126
See accompanying notes to consolidated financial statements.
F-58
West Penn Power Company
and Subsidiaries
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars)
DECEMBER 31
1998 1997
ASSETS
Property, Plant, and Equipment:
At original cost, including
$75,725 and $117,588 under
construction............................ $3,365,784 $3,293,039
Accumulated depreciation................ (1,362,413) (1,254,900)
2,003,371 2,038,139
Investments and Other Assets:
Allegheny Generating Company--common
stock at equity ..................... 74,374 89,783
Other.................................. 646 721
75,020 90,504
Current Assets:
Cash and temporary cash investments.... 4,523 4,056
Accounts receivable:
Electric service, net of $13,211
and $13,326 uncollectible
allowance.......................... 119,175 128,348
Affiliated and other, net............ 24,832 21,525
Materials and supplies--at average cost:
Operating and construction........... 43,167 34,212
Fuel................................. 24,363 29,467
Deferred income taxes.................. 11,959
Prepaid taxes.......................... 14,534 11,738
Regulatory assets...................... 17,372
Other.................................. 2,261 2,252
250,227 243,557
Deferred Charges:
Regulatory assets...................... 475,776 333,235
Unamortized loss on reacquired debt.... 4,065 9,725
Other.................................. 34,610 31,999
514,451 374,959
Total.................................... $2,843,069 $2,747,159
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital,
and retained earnings................ $ 732,161 $ 997,027
Preferred stock........................ 79,708 79,708
Long-term debt and QUIDS............... 837,725 802,319
1,649,594 1,879,054
Current Liabilities:
Short-term debt........................ 55,766 52,046
Notes payable to affiliate............. 9,300
Long-term debt due within one year..... 103,500
Accounts payable....................... 77,815 73,584
Accounts payable to affiliates......... 33,859 16,137
Taxes accrued:
Federal and state income............. 1,002 1,605
Other................................ 16,711 22,728
Interest accrued....................... 15,681 15,817
Refunds payable........................ 28,151
Adverse power purchase commitments..... 47,173
Other.................................. 15,393 28,457
300,851 313,874
Deferred Credits and Other Liabilities:
Unamortized investment credit.......... 42,630 45,206
Deferred income taxes.................. 260,477 450,390
Regulatory liabilities................. 28,325 34,326
Adverse power purchase commitments..... 538,745
Other.................................. 22,447 24,309
892,624 554,231
Commitments and Contingencies (Note N)
Total.................................... $2,843,069 $2,747,159
See accompanying notes to consolidated financial statements.
F-59
West Penn Power Company
and Subsidiaries
CONSOLIDATED STATEMENT OF CAPITALIZATION
DECEMBER 31
1998 1997 1998 1997
(Thousands of Dollars) (Capitalization Ratios)
Common Stock of the Company:
Common stock--no par value, authorized 28,902,923
shares, outstanding 24,361,586 shares............. $ 465,994 $ 465,994
Other paid-in capital............................... 55,475 55,475
Retained earnings................................... 210,692 475,558
Total........................................... 732,161 997,027 44.4% 53.1%
Preferred Stock of the Company:
Cumulative preferred stock--par value $100 per share,
authorized 3,097,077 shares, outstanding as follows:
December 31, 1998
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
4-1/2% .. 297,077 $110.00 1939 29,708 29,708
4.20% B.. 50,000 102.205 1948 5,000 5,000
4.10% C.. 50,000 103.50 1949 5,000 5,000
Auction
3.95%-4.12% 400,000 100.00 1992 40,000 40,000
Total (annual dividend requirements $3,400) 79,708 79,708 4.8 4.2
Long-Term Debt and QUIDS:
First mortgage
bonds: Date of Date Date
Issue Redeemable Due
5-1/2% JJ.... 1993 1998 1998 102,000
6-3/8% KK.... 1993 2003 2003 80,000 80,000
7-7/8% GG.... 1991 2001 2004 70,000 70,000
7-3/8% HH.... 1992 2002 2007 45,000 45,000
8-7/8% FF.... 1991 2001 2021 100,000 100,000
7-7/8% II.... 1992 2002 2022 135,000 135,000
8-1/8% LL.... 1994 2004 2024 65,000 65,000
7-3/4% MM.... 1995 2005 2025 30,000 30,000
December 31, 1998
Interest Rate
Quarterly Income Debt Securities
due 2025........................ 8.00% 70,000 70,000
Secured notes due 2003-2024....... 4.70%-6.875% 202,550 202,550
Unsecured notes due 2007.......... 4.75% 14,435 14,435
Medium-term debt due 2002......... 5.56%-5.66% 33,550
Unamortized debt discount........................... (7,810) (8,166)
Total (annual interest requirements $60,440).... 837,725 905,819
Less current maturities............................. (103,500)
Total........................................... 837,725 802,319 50.8 42.7
Total Capitalization.................................. $1,649,594 $1,879,054 100.0% 100.0%
See accompanying notes to consolidated financial statements.
F-60
West Penn Power Company
and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial
statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
West Penn Power Company (the Company) is a wholly owned
subsidiary of Allegheny Energy, Inc. (Allegheny Energy) and is a
part of the Allegheny Energy integrated electric utility system
(the System). The Company and its utility affiliates,
Monongahela Power Company and The Potomac Edison Company, do
business as Allegheny Power.
The Company is subject to regulation by the Securities and
Exchange Commission (SEC), by various state bodies having
jurisdiction, and by the Federal Energy Regulatory Commission
(FERC). Significant accounting policies of the Company are
summarized below.
Consolidation
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries (the 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 are recognized in the same period in which the related
electric services are provided to customers by recording an
estimate for unbilled revenues for services provided from the
meter reading date to the end of the accounting period.
Deferred Power Costs, Net
Prior to May 1, 1997, the costs of fuel, purchased power, and
certain other costs, and revenues from sales to other companies
and power marketers, including transmission services, were
deferred until they were either recovered from or credited to
customers under fuel and energy cost-recovery procedures. The
Company discontinued this practice effective May 1, 1997.
Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated affiliates in the System, are stated at original cost,
less contributions in aid of construction, except for capital
leases, which are recorded at present value. Costs include
direct labor and material; allowance for funds used during
construction (AFUDC) on regulated utility property for which
construction work in progress is not included in rate base;
capitalized interest on generation projects; and indirect costs
such as administration, maintenance, and depreciation of
transportation and construction equipment, postretirement
benefits, taxes, and other benefits related to employees engaged
in construction.
The cost of depreciable property units retired, plus removal
costs less salvage, are charged to accumulated depreciation.
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West Penn Power Company
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Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including
"the net cost for the period of construction of borrowed funds
used for construction purposes and a reasonable rate on other
funds when so used." AFUDC is recognized as a cost of property,
plant, and equipment with offsetting credits to other income and
interest charges. Rates used for computing AFUDC in 1998, 1997,
and 1996 were 7.17%, 8.30%, and 7.83%, respectively. AFUDC is
not included in the cost of construction when the cost of
financing the construction is being recovered through rates.
As discussed in Note B, as a result of a Pennsylvania Order, the
Company has 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 electric generation
operations and has adopted SFAS No. 101, "Accounting for the
Discontinuation of Application of FASB Statement No. 71."
Starting in July 1998, the Company stopped accruing AFUDC for
generation construction projects and adopted SFAS No. 34,
"Capitalizing Interest Costs," to capitalize interest during the
period of construction of generation construction projects.
Capitalized interest, recognized as a cost of property, plant,
and equipment with offsetting credits to interest charges, is
reported in the consolidated statement of income as allowance for
borrowed funds used during construction. Since adoption in July
1998, rates used for capitalizing interest on generation
construction projects averaged 7.45%.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives of
depreciable properties and amounted to approximately 3.6%, 3.7%,
and 4.0%, of average depreciable property in 1998, 1997, and
1996, respectively. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged
principally to operating expenses.
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 based
on cost-based ratemaking regulation.
Income Taxes
The companies join with their parent and affiliates in filing a
consolidated federal income tax return. The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.
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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. Differences between income tax expense,
computed on the basis of financial accounting income and taxes
payable based on taxable income, are accounted for substantially
in accordance with the accounting procedures followed for
ratemaking purposes. 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.
Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to income with concurrent credits to a deferred
account. These balances are being amortized over the estimated
service lives of the related properties.
Postretirement Benefits
The Company participates with affiliated companies of Allegheny
Energy, Inc. in 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.
The Company and its affiliates 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. The
funding plan for these costs 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.
Capitalized Software Costs
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.
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
financial statements. The Company does not have any elements of
other comprehensive income to report in accordance with SFAS No.
130.
Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company's principal business segment is utility operations
which includes the generation, purchase, transmission,
distribution, and sale of electricity.
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West Penn Power Company
and Subsidiaries
NOTE B: INDUSTRY RESTRUCTURING
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. On
August 1, 1997, the Company 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
(sometimes referred to as stranded costs) through a Competitive
Transition Charge (CTC).
Transition costs are costs incurred under a regulated
environment, which may not be recoverable in a competitive
market. The amount of transition costs has been a key issue in
the restructuring proceedings. Since the installed costs of
utility facilities are known, the key variable in transition cost
determinations in Pennsylvania was the projection of market
prices of electricity in future periods. The Company's
restructuring plan filing included its determination of its
transition costs based on its projection of future market prices.
The Company's recoverable transition costs were limited to $1.2
billion by rate caps mandated by the Customer Choice Act.
On May 29, 1998, the Pennsylvania PUC issued an Order authorizing
the Company recovery of approximately $595 million (or $525
million in the event of the merger) in transition costs, with a
return, based on alternative projections of future market prices.
On June 26, 1998, the Pennsylvania PUC denied, except for minor
corrections, a request by the Company for reconsideration of the
May 29 Order. On that same day, the Company filed a formal
appeal in state court and an action in federal court challenging
the Pennsylvania PUC's restructuring Order.
As a result of this May 29, 1998 Order, the Company determined
that it was required to discontinue the application of SFAS No.
71 for electric generation operations and adopt SFAS No. 101. In
doing so, the Company also determined that, under the provisions
of SFAS No. 101, an extraordinary charge of $450.6 million
($265.4 million after taxes) was required to reflect adverse
power purchase commitments and deferred costs that are not
recoverable from customers under the Pennsylvania PUC's Order.
While pursuing its litigation, the Company participated in
settlement discussions with interested parties regarding issues
related to the restructuring Order. A negotiated settlement was
achieved, and, on November 19, 1998, the Pennsylvania PUC granted
final approval to the Company's restructuring settlement
agreement. The settlement agreement includes the following
provisions:
Agreement by the parties to withdraw all litigation related to
the Pennsylvania deregulation proceedings.
Establishment of an average shopping credit of 3.16 cents per
kilowatt-hour in 1999 for Company customers who shop for the
generation portion of electricity services.
Two-thirds of the Company's customers have the option of
selecting a generation supplier on January 2, 1999, with all
customers able to shop on January 2, 2000.
F-64
West Penn Power Company
and Subsidiaries
Requires a rate refund from 1998 revenues (about $25 million) via
a 2.5% rate decrease throughout 1999, accomplished by an equal
percentage decrease for each rate class.
Provides that customers will have the option of buying
electricity from the Company at capped generation rates through
2008, and that transmission and distribution rates are capped
through 2005, except that the capped rates are subject to certain
increases as provided for in the Public Utility Code.
Prohibits complaints challenging the Company's regulated
transmission and distribution rates through 2005.
Provides about $15 million of Company funding for the development
and use of renewable energy and clean energy technologies, energy
conservation, energy efficiency, etc.
Permits recovery of $670 million in transition costs plus return
over 10 years beginning in January 1999 for the Company. In the
event that the merger of Allegheny Energy, Inc. and DQE, Inc.
(DQE), parent company of Duquesne Light Company in Pittsburgh,
Pa., is consummated, the transition costs will be adjusted to
$630 million plus return to provide a sharing of merger synergy
savings with customers.
Allows 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.
Grants the Company's application to issue bonds to securitize up
to $670 million (or $630 million in the event of the merger) in
transition costs and to provide 75% of the associated savings to
customers with 25% to shareholders.
Authorizes the transfer of the Company'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.
If the Company is forced to divest some generating assets or
chooses to divest all of its generation before 2002, the CTC will
be adjusted, either up or down, based on the results of such
divestiture.
As a result of the November 19, 1998, settlement agreement, the
extraordinary charge was increased by $16.3 million ($10.0
million after taxes) to $466.9 million ($275.4 million after
taxes), and additional charges of $40.3 million ($23.7 million
after taxes) related to the Company's revenue refund and energy
program payments were also recorded. See Note C for additional
details. Pursuant to Pennsylvania PUC orders, starting in 1999,
the Company is unbundling its rates to reflect separate prices
for the supply charge, the CTC, and transmission and distribution
charges. While supply will be open to competition, the Company
will continue to provide regulated transmission and distribution
services to customers in its service area at Pennsylvania PUC-
and FERC-regulated rates and will be the electricity provider of
last resort for those customers who decide not to choose another
electricity supplier.
F-65
West Penn Power Company
and Subsidiaries
As stated above, the Company made its filing concerning its
transition cost requirements based on its early 1997 projection
of market prices. The Pennsylvania PUC issued its May 29, 1998
Order to the Company, as well as its 1998 orders to all other
Pennsylvania electric utilities, based on alternative
projections. Current prices, which the Company believes are
being influenced, among other things, by price volatility in the
summer of 1998, are equal to and in some cases higher than the
projections adopted by the Pennsylvania PUC in its deregulation
orders issued to the Company and other utilities in the state.
If the Pennsylvania PUC's projections are correct, the Company
believes that the transition costs provided will be sufficient to
permit it to recover its embedded costs, with a return, during
the transition from regulation to deregulation of electricity
generation.
The settlement authorizes the Company to create a CTC regulatory
asset for specified CTC revenues in 1999 through 2002 to be
amortized in 2005 through 2008. The regulatory asset booking of
CTC revenue acts to accelerate recognition of transition cost
recovery. In addition, the settlement agreement specifies how CTC
revenues will be allocated between return on and recovery of
transition costs. Amortization of regulatory assets in 1999
through 2008 under the Pennsylvania PUC-approved settlement
agreement results in smaller amortization expense in the early
years of the transition period which favorably affects earnings
in those years.
Also pursuant to the Customer Choice Act, all electric utilities
in Pennsylvania were required 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 the
Company's generation costs), with the result that the Company
suffered a loss of $6.5 million. The Company attempted to
mitigate the loss by competing for sales to pilot participants of
other utilities as an alternate supplier. The Pennsylvania PUC
approved the Company's pilot compliance filing and thus has
indicated its intent to treat the revenue losses as a regulatory
asset subject to review and potential rate recovery. Because
sales prices were low and margins were commensurately thin, the
Company was unable to completely offset its pilot losses with new
revenues. Accordingly, the Company deferred the net revenue
losses as a regulatory asset.
NOTE C: ACCOUNTING FOR THE EFFECTS OF PRICE DEREGULATION
In 1997, the FASB, through its Emerging Issues Task Force (EITF),
issued EITF No. 97-4, "Deregulation of the Pricing of Electricity
- - Issues Related to the Application of FASB Statement Numbers 71
and 101." In EITF 97-4, 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. The Company believes that the
Pennsylvania PUC Order dated May 29, 1998, as described in Note
B, provides sufficient details regarding the deregulation of the
Company's electric generation operations to require
discontinuation of the application of SFAS No. 71 for its
electric generation
F-66
West Penn Power Company
and Subsidiaries
operations. Effective June 30, 1998, the Company adopted the
provisions of SFAS No. 101 for its electric generation
operations. The Company determined 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 in the Pennsylvania PUC's May 29, 1998
Order, as revised by the Pennsylvania PUC-approved November 19,
1998 settlement agreement. The
write-off reflects adverse power purchase commitments and
deferred costs that are not recoverable 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
AGC pumped storage capacity contract................. 165.6 97.7
Other................................................ 103.8 61.2
Total extraordinary charge......................... $466.9 $275.4
In 1985, the Company entered into a contract with Applied Energy
Services (AES) Corporation for the purchase of energy from AES's
Beaver Valley generating plant in Pennsylvania pursuant to the
requirements of the Public Utility Regulatory Policies Act of
1978 (PURPA).
The Company owns 45% of AGC, which owns an undivided 40% interest
in the 2,100-MW pumped-storage hydroelectric station in Bath
County, Va. The Company buys AGC's capacity in the station
priced under a cost of service formula wholesale rate schedule
approved by the FERC.
Under both of these contracts, the Company has purchase
commitments at costs in excess of the market value of energy from
the plants. Because of utility restructuring under the Customer
Choice Act, these commitments have been determined to be adverse
purchase commitments requiring accrual as loss contingencies
pursuant to SFAS No. 5, "Accounting for Contingencies." The
extraordinary charge before taxes for these contracts is the net
result of such excess cost accruals (recorded as adverse power
purchase commitments) less estimated revenue recoveries
authorized in the Pennsylvania PUC Order (recorded as regulatory
assets) as follows:
AES AGC
(Millions of Dollars) Beaver Valley Pumped Storage
Projected costs in excess of market
value of energy............................. $351.5 $234.5
Estimated recovery via a CTC (regulatory
asset)...................................... 154.0 68.9
Net unrecoverable extraordinary charge.... $197.5 $165.6
Various assumptions and estimates were made in determining the
extraordinary charge to income discussed above. The most
significant relate to future electricity prices. To the extent
that future electricity prices differ from the Company's
estimates, adjustments to the reserve for adverse power purchase
commitments may be required.
F-67
West Penn Power Company
and Subsidiaries
The other $103.8 million of extraordinary charges represents
$55.0 million of deferred unrecovered expenditures for previous
PURPA buyouts, $13.5 million for an abandoned generating plant,
and $35.3 million of other generation-related regulatory assets,
primarily related to SFAS No. 109, "Accounting for Income Taxes."
The consolidated balance sheet includes the amounts listed below
for generation assets not subject to SFAS No. 71:
December December
(Thousands of Dollars) 1998 1997
Property, plant, and equipment at original cost.... $1,969,636 $1,951,066
Amounts under construction included above.......... 39,227 51,715
Accumulated depreciation........................... (870,777) (793,166)
In addition to the extraordinary charge and as a result of the
settlement agreement, a fourth quarter charge to earnings of
$40.3 million ($23.7 million after taxes) resulted from the
required refund throughout 1999 from 1998 revenues of about $25
million and a $15 million provision for energy programs.
NOTE D: PROPOSED MERGER
On April 7, 1997, the Company's parent, Allegheny Power System,
Inc. (now renamed Allegheny Energy, Inc.) and DQE, Inc. (DQE),
parent company of Duquesne Light Company in Pittsburgh, Pa.,
announced that they had agreed to merge in a tax-free, stock-for-
stock transaction.
At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger. Allegheny Energy
and DQE made all necessary regulatory filings. Since then,
Allegheny Energy 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 Allegheny Energy. In addition, while
not required, the Maryland Public Service Commission and the
Public Utilities Commission of Ohio have indicated their
approval.
On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger. Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement. In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief. The District Court
did not rule on the merits of the lawsuit for specific
performance or damages. On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States Court of
Appeals for the Third Circuit. Allegheny Energy cannot predict
the outcome of this litigation.
All of the Company's incremental costs of the merger process
($7.9 million through December 31, 1998) are being deferred. The
accumulated merger costs will be written off by the Company when
the merger occurs or by the Company if it is determined that the
merger will not occur.
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West Penn Power Company
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NOTE E: INTERNAL RESTRUCTURING CHARGES AND ASSET WRITE-OFF
In 1996, the System, including the Company, completed its
internal restructuring activities initiated in 1994, simplifying
the management structure and streamlining operations. During
1996, restructuring activities included consolidating operating
divisions, customer services, and other functions.
In 1996, the Company recorded restructuring charges of $42.6
million ($25.1 million after tax) in operating expenses,
including its share of all restructuring charges associated with
the reorganization. These charges reflected liabilities and
payments for severance, employee termination costs, and other
restructuring costs. The current portion of the restructuring
liability, reflected in other current liabilities, excluding
benefit plans curtailment adjustments to postretirement
liabilities (which are primarily recorded in other deferred
credits), consists of:
(Thousands of Dollars) 1998 1997
Internal restructuring liability:
Balance at beginning of period................. $ 4,082 $ 27,134
Less payments and accrual reversals............ (4,082) (23,052)
Balance at end of period......................... $ - $ 4,082
In 1996, the Company wrote off $10.8 million ($6.3 million after
tax) of previously accumulated costs related to a proposed
transmission line. In the industry's more competitive
environment, it was no longer reasonable to assume future
recovery of these costs in rates.
As part of the reorganization, the Company and its utility
affiliates in 1996 expanded the intercompany use of each other's
employees to optimize the use of their skills. In 1997 virtually
all the employees in the System, including all of the Company's
employees, were transferred to Allegheny Power Service
Corporation (APSC) to facilitate the intercompany use of
personnel. APSC was formed in 1963 pursuant to the Public
Utility Holding Company Act of 1935 to perform certain functions
common to all companies in the System. APSC bills each company
at its cost (without profit) based on the work performed and
services provided to each company.
F-69
West Penn Power Company
and Subsidiaries
NOTE F: INCOME TAXES
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Income taxes--current:
Federal.............................. $ 47,605 $29,426 $32,778
State................................ 18,415 12,357 12,975
Total.............................. 66,020 41,783 45,753
Income taxes--deferred, net of
amortization......................... 1,069 33,961 4,602
Income taxes--deferred, extraordinary
charge............................... (191,480)
Amortization of deferred investment
credit............................... (2,580) (2,580) (2,580)
Total income taxes................. (126,971) 73,164 47,775
Income taxes--credited (charged)
to other income and deductions....... 17 115 (320)
Income taxes--credited to
extraordinary charge................. 191,480
Income taxes--charged to operating
income............................... $ 64,526 $73,279 $47,455
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) 1998 1997 1996
Income before income taxes
and extraordinary charge............. $177,146 $207,944 $135,900
Amount so produced..................... $ 62,001 $ 72,780 $ 47,565
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation........... 1,500 5,700 3,300
Plant removal costs.............. 1,000 1,400 2,100
State income tax, net of federal
income tax benefit................. 10,000 4,900 8,900
Amortization of deferred
investment credit.................. (2,580) (2,580) (2,580)
Equity in earnings of subsidiaries... (3,900) (6,300) (4,600)
Other, net........................... (3,495) (2,621) (7,230)
Total.............................. $ 64,526 $ 73,279 $ 47,455
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West Penn Power Company
and Subsidiaries
The provision for income taxes for the extraordinary charge 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) 1998
Extraordinary charge before income taxes............... $466,905
Amount so produced..................................... $163,417
Increased for state income tax, net of federal
income tax benefit................................... 28,063
Total.............................................. $191,480
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
At December 31, the deferred tax assets and liabilities consisted
of the following:
(Thousands of Dollars) 1998 1997
Deferred tax assets:
CTC recovery.................................... $154,530
Unamortized investment tax credit............... 29,674 $ 31,570
Tax interest capitalized........................ 19,010 19,220
Postretirement benefits other than pensions..... 15,610 12,857
Revenue refund.................................. 10,301
Unbilled revenue................................ 9,068 9,226
Contributions in aid of construction............ 6,988 6,520
Internal restructuring.......................... 2,954 2,709
Other........................................... 24,724 25,777
272,859 107,879
Deferred tax liabilities:
Book vs. tax plant basis differences, net....... 503,605 493,361
Other........................................... 33,214 52,949
536,819 546,310
Total net deferred tax liabilities................ 263,960 438,431
Portion above included in current (liabilities)
assets.......................................... (3,483) 11,959
Total long-term net deferred tax liabilities.. $260,477 $450,390
NOTE G: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $70,576,000 of consolidated retained
earnings at December 31, 1998, is not available for cash
dividends on common stock, except that a portion thereof may be
paid as cash dividends where concurrently an equivalent amount of
cash is received by the Company as a capital contribution or as
the proceeds of the issue and sale of shares of its common stock.
F-71
West Penn Power Company
and Subsidiaries
NOTE H: ALLEGHENY GENERATING COMPANY
The Company owns 45% of the common stock of Allegheny Generating
Company (AGC), and affiliates of the Company own the remainder.
AGC is reported by the Company in its financial statements using
the equity method of accouting. AGC owns an undivided 40%
interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.
AGC recovers from the Company and its affiliates all of its
operation and maintenance expenses, depreciation, taxes, and a
return on its investment under a wholesale rate schedule approved
by the FERC. AGC's rates are set by a formula filed with and
previously accepted by the FERC. The only component which
changes is the return on equity (ROE). Pursuant to a settlement
agreement filed April 4, 1996, with the FERC, AGC's ROE was set
at 11% for 1996 and will continue until the time any affected
party seeks renegotiation of the ROE.
Following is a summary of financial information for AGC:
December 31
(Thousands of Dollars) 1998 1997
Balance sheet information:
Property, plant, and equipment................. $618,608 $635,485
Current assets................................. 5,857 11,876
Deferred charges............................... 14,993 16,559
Total assets................................. $639,458 $663,920
Total capitalization........................... $314,105 $348,258
Current liabilities............................ 75,849 70,540
Deferred credits............................... 249,504 245,122
Total capitalization and liabilities......... $639,458 $663,920
Year Ended December 31
(Thousands of Dollars) 1998 1997 1996
Income statement information:
Electric operating revenues.......... $73,816 $76,458 $83,402
Operation and maintenance expense.... 4,592 4,877 5,165
Depreciation......................... 16,949 17,000 17,160
Taxes other than income taxes........ 4,662 4,835 4,801
Federal income taxes................. 10,959 11,213 13,297
Interest charges..................... 13,987 15,391 16,193
Other income, net.................... (86) (9,126) (3)
Net income......................... $22,753 $32,268 $26,789
The Company's share of the equity in earnings was $10.2 million,
$14.5 million, and $12.1 million for 1998, 1997, and 1996,
respectively, and is included in other income, net, on the
Company's Consolidated Statement of Income. Dividends received
from AGC in 1998 approximated $25 million which reflects an
effort to reduce AGC equity to about 45% of total capitalization
and short-term debt.
F-72
West Penn Power Company
and Subsidiaries
NOTE I: POSTRETIREMENT BENEFITS
As described in Note A, the Company and its affiliates
participate in a pension plan and medical and life insurance
plans for eligible employees and dependents. The Company is
responsible for its proportional share of the costs (credits) and
the assets or liabilities of the plans. As described in Note E,
in 1997 the Company transferred all of its employees to APSC.
The Company's share of the costs (credits) of these plans, a
portion of which (about 25% to 35%) was charged to plant
construction, is as follows:
(Thousands of Dollars) 1998 1997 1996
Pension................................ $ 919 $(3,037) $ 564
Medical and life insurance............. $6,708 $ 4,551 $9,039
NOTE J: REGULATORY ASSETS AND LIABILITIES
The Company's operations, other than electric generation, are
subject to the provisions of SFAS No. 71. As discussed in Note
B, as a result of a Pennsylvania Order, the Company has
discontinued the application of SFAS No. 71 and has adopted SFAS
No. 101 for electric generation operations. 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:
(Thousands of Dollars) 1998 1997
Long-Term Assets (Liabilities), Net:
Income taxes, net............................ $146,952 $247,574
CTC recovery................................. 292,718
PURPA project buyout......................... 48,000
Pennsylvania pilot deferred revenue.......... 6,727 84
Deferred power costs, (reported in other
deferred charges).......................... 7,000
Storm damage................................. 1,054 1,326
Postretirement benefits...................... 823
Other, net................................... 1,102
Subtotal................................... 447,451 305,909
Current Asset:
CTC recovery................................. 17,372
Net Regulatory Assets...................... $464,823 $305,909
F-73
West Penn Power Company
and Subsidiaries
NOTE K: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:
1998 1997
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Assets:
Temporary cash
investments......... $ 882 $ 882 $ 573 $ 573
Liabilities:
Short-term debt....... 65,066 65,066 52,046 52,046
Long-term debt
and QUIDS........... 845,535 902,037 913,985 953,700
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 long-term debt
and QUIDS was estimated based on actual market prices or market
prices of similar issues. The Company has no financial
instruments held or issued for trading purposes.
NOTE L: CAPITALIZATION
Preferred Stock
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share. The holders of the Company's market auction
preferred stock are entitled to dividends at a rate determined by
an auction held the business day preceding each quarterly
dividend payment date.
Long-Term Debt and QUIDS
Maturities for long-term debt in thousands of dollars for the
next five years are: 1999-2001, none; 2002, $33,550; and 2003,
$141,500. Substantially all of the properties of the Company are
held subject to the lien securing its first mortgage bonds. Some
properties are also subject to a second lien securing certain
pollution control and solid waste disposal notes. Certain first
mortgage bond series are not redeemable by certain refunding
until dates established in the respective supplemental
indentures.
NOTE M: SHORT-TERM DEBT
To provide interim financing and support for outstanding
commercial paper, the System companies have established lines of
credit with several banks. The Company has SEC authorization for
total short-term borrowings of $182 million, including money pool
borrowings described below. The Company has fee arrangements on
all of its lines of credit and no compensating balance
requirements. In addition to bank lines of credit, an Allegheny
Energy internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated
companies have funds available.
F-74
West Penn Power Company
and Subsidiaries
Short-term debt outstanding for 1998 and 1997 consisted of:
(Thousands of Dollars) 1998 1997
Balance and interest rate
at end of year:
Commercial Paper.................. $55,766-5.45% $12,046-6.50%
Notes Payable to Banks............ 40,000-6.75%
Money Pool........................ 9,300-4.80%
Average amount outstanding and
interest rate during the year:
Commercial Paper.................. $32,824-5.60% $ 3,376-5.73%
Notes Payable to Banks............ 16,885-5.60% 5,526-5.67%
Money Pool........................ 10,942-5.38% 17,628-5.48%
NOTE N: COMMITMENTS AND CONTINGENCIES
Construction Program
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $119 million
for 1999 and $106 million for 2000. Construction expenditure
levels in 2001 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 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.
Market Risk
The Company supplies power in the bulk power market. At December
31, 1998, the marketing books for such operations consisted
primarily of fixed-priced, forward-purchase and/or sale contracts
which require settlement by physical delivery of electricity.
Allegheny Energy has a Corporate Energy Risk Control Policy
adopted by the Board of Directors and monitored by an Exposure
Management Committee of senior management. This policy requires
continuous monitoring for conformity to policies which limit
value at risk and market risk associated with the credit standing
of counterparties. Such credit standing must be within the
guidelines established by Allegheny Energy's Risk Control Policy.
The Company's exposure to volatility in the price of electricity
and other energy commodities is maintained within approved policy
limits, but has increased as a result of Pennsylvania
restructuring, which created retail access to a deregulated
electric supply market.
Environmental Matters and Litigation
System 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.
F-75
West Penn Power Company
and Subsidiaries
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 24, 1999, and must be
implemented by May 1, 2003. The Company's compliance with these
requirements would require the installation of post-combustion
control technologies on most, if not all, of its power stations
at a cost of approximately $147 million. The Company continues
to work with other coal-burning utilities and other affected
constituencies in coal-producing states to challenge this EPA
action.
The Company previously reported that the EPA had identified it
and its regulated affiliates as potentially responsible parties,
along with approximately 175 others, in a Superfund site subject
to cleanup. A final determination has not been made for the
Company's share of the remediation costs based on the amount of
materials sent to the site. The Company and its regulated
affiliates have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs. The Company believes that provisions for liabilities
and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.
F-76
Allegheny Generating Company
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors and the Shareholders
of Allegheny Generating Company
In our opinion, the accompanying balance sheet and the related
statements of income, of retained earnings and of cash flows
present fairly, in all material respects, the financial position
of Allegheny Generating Company (a subsidiary of Allegheny
Energy, Inc.) at December 31, 1998 and 1997, and the results of
its operations and its cash flows for each of the three years in
the period ended December 31, 1998, in conformity with generally
accepted accounting principles. 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 generally accepted auditing
standards 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 4, 1999
F-77
Allegheny Generating Company
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1998 1997 1996
Electric Operating
Revenues.......................................$73,816 $76,458 $83,402
Operating Expenses:
Operation and maintenance expense............ 4,592 4,877 5,165
Depreciation................................. 16,949 17,000 17,160
Taxes other than income taxes................ 4,662 4,835 4,801
Federal income taxes......................... 10,959 11,213 13,297
Total Operating Expenses................... 37,162 37,925 40,423
Operating Income........................... 36,654 38,533 42,979
Other Income, net............................... 86 9,126 3
Income Before Interest Charges................36,740 47,659 42,982
Interest Charges:
Interest on long-term debt....................10,848 14,431 15,235
Other interest................................ 3,139 960 958
Total Interest Charges......................13,987 15,391 16,193
Net Income.....................................$22,753 $32,268 $26,789
STATEMENT OF RETAINED EARNINGS
Balance at January 1...........................$ 0 $ 0 $ 4,153
Add:
Net income................................... 22,753 32,268 26,789
22,753 32,268 30,942
Deduct:
Dividends on common stock.................... 22,753* 32,268* 30,942*
Balance at December 31.........................$ 0 $ 0 $ 0
*Excludes cash dividends paid from other paid-in capital.
See accompanying notes to financial statements.
F-78
Allegheny Generating Company
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
(Thousands of Dollars) 1998 1997 1996
Cash Flows from Operations:
Net income...............................$22,753 $32,268 $26,789
Depreciation............................. 16,949 17,000 17,160
Tax-related contract settlement.......... 8,835
Deferred investment credit and income
taxes, net............................. 5,305 6,329 10,898
Changes in certain current assets and
liabilities:
Accounts receivable.................... 6 1,331 3,937
Materials and supplies................. (261) 260 (43)
Accounts payable....................... (340) 5,913 206
Other, net............................... 578 28 (3,739)
44,990 71,964 55,208
Cash Flows from Investing:
Construction expenditures................ (69) (444) (178)
Cash Flows from Financing:
Retirement of long-term debt.............(60,000) (30,592) (16,943)
Notes payable to parents................. 66,750
Cash dividends on common stock...........(57,000) (35,700) (37,987)
(50,250) (66,292) (54,930)
Net Change in Cash and Temporary
Cash Investments......................... (5,329) 5,228 100
Cash and Temporary Cash Investments at
January 1................................ 5,359 131 31
Cash and Temporary Cash Investments at
December 31..............................$ 30 $ 5,359 $ 131
Supplemental Cash Flow Information
Cash paid during the year for:
Interest...............................$14,490 $14,770 $15,703
Income taxes........................... 4,828 10,313 6,256
See accompanying notes to financial statements.
F-79
Allegheny Generating Company
BALANCE SHEET
DECEMBER 31
(Thousands of Dollars) 1998 1997
ASSETS
Property, Plant, and Equipment:
At original cost, including $595 and $906
under construction...................... $828,806 $828,658
Accumulated depreciation.................. (210,198) (193,173)
618,608 635,485
Current Assets:
Cash and temporary cash investments....... 30 5,359
Accounts receivable from Parents.......... 6
Materials and supplies--at average cost... 2,093 1,832
Prepaid taxes............................. 3,569 4,442
Other..................................... 165 237
5,857 11,876
Deferred Charges:
Regulatory assets......................... 7,056 7,979
Unamortized loss on reacquired debt....... 7,768 8,393
Other..................................... 169 187
14,993 16,559
Total....................................... $639,458 $663,920
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock - $1.00 par value per share,
authorized 5,000 shares, outstanding
1,000 shares. .......................... $ 1 $ 1
Other paid-in capital..................... 165,275 199,522
165,276 199,523
Long-term debt............................ 148,829 148,735
314,105 348,258
Current Liabilities:
Notes payable to parents.................. 66,750
Long-term debt due within one year........ 60,000
Accounts payable to affiliates............ 5,795 6,135
Interest accrued.......................... 3,229 4,404
Other..................................... 75 1
75,849 70,540
Deferred Credits:
Unamortized investment credit............. 47,020 48,342
Deferred income taxes..................... 177,166 169,325
Regulatory liabilities.................... 25,318 27,455
249,504 245,122
Total....................................... $639,458 $663,920
See accompanying notes to financial statements.
F-80
Allegheny Generating Company
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
NOTE A: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Allegheny Generating Company (the Company) was incorporated in
Virginia in 1981. Its common stock is owned by Monongahela Power
Company - 27%, The Potomac Edison Company - 28%, and West Penn
Power Company - 45% (the Parents). The Parents are wholly-owned
subsidiaries of Allegheny Energy, Inc. (Allegheny Energy) and are
a part of the Allegheny Energy integrated electric utility
system. The Company is subject to regulation by the Securities
and Exchange Commission (SEC) and by the Federal Energy
Regulatory Commission (FERC). Significant accounting policies of
the Company are summarized below.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to
make estimates that affect the reported amounts of assets,
liabilities, revenues, expenses, and disclosures of contingencies
during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.
Revenues
Revenues are determined under a cost-of-service formula rate
schedule approved by the FERC. Under this arrangement, the
Company recovers in revenues all of its operation and maintenance
expense, depreciation, taxes, and a return on its investment.
All sales are made to the Company's Parents.
Property, Plant, and Equipment
Property, plant, and equipment are stated at original cost, and
consist of a 40% undivided interest in the Bath County pumped-
storage hydroelectric station and its connecting transmission
facilities. The cost of depreciable property units retired, plus
removal costs less salvage, are charged to accumulated
depreciation.
Depreciation and Maintenance
Provisions for depreciation are determined on a straight-line
method based on estimated service lives of depreciable properties
and amounted to approximately 2.1% of average depreciable
property in each of the years 1998, 1997, and 1996. The cost of
maintenance and of certain replacements of property, plant, and
equipment is charged to operating expenses.
Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash
investments with original maturities of three months or less,
generally in the form of commercial paper, certificates of
deposit, and repurchase agreements, are considered to be the
equivalent of cash.
Regulatory Assets and Liabilities
In accordance with the Financial Accounting Standards Board's
Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements include certain assets and
liabilities based on cost-based ratemaking regulation.
F-81
Allegheny Generating Company
Income Taxes
The Company joins with its Parents and affiliates in filing a
consolidated federal income tax return. The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.
Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period. Differences between income tax expense
computed on the basis of financial accounting income and taxes
payable based on taxable income are deferred. 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.
Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits
were charged to income with concurrent credits to a deferred
account. These balances are being amortized over the estimated
service lives of the related properties.
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.
Business Segments
SFAS No. 131, "Disclosures about Segments of an Enterprise and
Related Information," established standards for reporting
information about operating segments in financial statements.
The Company operates as a single business segment selling its
entire capacity to its Parents priced under a cost-of-service
wholesale rate schedule.
NOTE B: PROPOSED MERGER
On April 7, 1997, Allegheny Power System, Inc. (now renamed
Allegheny Energy, Inc.) and DQE, Inc. (DQE), parent company of
Duquesne Light Company in Pittsburgh, Pa., announced that they
had agreed to merge in a tax-free, stock-for-stock transaction.
At separate meetings held on August 7, 1997, the shareholders of
Allegheny Energy and DQE approved the merger. Allegheny Energy
and DQE made all necessary regulatory filings. Since then,
Allegheny Energy and DQE received approval of the merger from the
Nuclear Regulatory Commission, the Pennsylvania Public Utility
Commission (Pennsylvania PUC), and the FERC. The Pennsylvania
PUC and the FERC approvals were subject to conditions acceptable
to Allegheny Energy. In addition, while not required, the
Maryland Public Service Commission and the Public Utilities
Commission of Ohio have indicated their approval.
F-82
Allegheny Generating Company
On October 5, 1998, DQE notified Allegheny Energy that it had
unilaterally decided to terminate the merger. Allegheny Energy
believes DQE's action was without basis and was a breach of the
merger agreement. In response, Allegheny Energy filed with the
United States District Court for the Western District of
Pennsylvania on October 5, 1998, a lawsuit for specific
performance of the merger agreement or, alternatively, damages.
Allegheny Energy also filed motions for preliminary injunctive
relief against DQE.
On October 28, 1998, the District Court denied Allegheny Energy's
motions for preliminary injunctive relief. The District Court
did not rule on the merits of the lawsuit for specific
performance or damages. On October 30, 1998, Allegheny Energy
appealed the District Court's Order to the United States Court of
Appeals for the Third Circuit. The Company cannot predict the
outcome of this litigation.
NOTE C: INCOME TAXES
Details of federal income tax provisions are:
(Thousands of Dollars) 1998 1997 1996
Current income taxes payable.......... $ 5,700 $ 9,799 $ 2,401
Deferred income taxes--
accelerated depreciation............ 6,628 7,652 12,220
Amortization of deferred
investment credit................... (1,323) (1,323) (1,322)
Total income taxes................ 11,005 16,128 13,299
Income taxes--charged to other
income.............................. (46) (4,915) (2)
Income taxes--charged to operating
income.............................. $10,959 $11,213 $13,297
In 1998, the total provision for income taxes ($10,959) was less
than the amount produced ($11,799) by applying the federal income
tax statutory rate of 35% to financial accounting income before
income taxes ($33,712), primarily due to amortization of deferred
investment credit ($1,323).
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
At December 31, the deferred tax liabilities, net consisted of
the following:
(Thousands of Dollars) 1998 1997
Deferred tax liabilities, net:
Unamortized investment tax credit............... $(25,318) $(27,455)
Book vs. tax plant basis differences, net....... 202,484 196,780
Total long-term net deferred tax liabilities.. $177,166 $169,325
F-83
Allegheny Generating Company
NOTE D: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS
No. 71. Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered
from customers through the ratemaking process. Regulatory
liabilities represent probable future reductions in revenues
associated with amounts that are to be credited to customers
through the ratemaking process. Regulatory liabilities, net of
regulatory assets, in thousands of dollars of $18,262 in 1998 and
$19,476 in 1997 relate to income taxes.
NOTE E: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:
1998 1997
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Liabilities:
Short-term debt........ $ 66,750 $ 66,750
Long-term debt:
Debentures........... 150,000 155,658 $150,000 $144,410
Medium-term notes.... 60,000 60,000
The carrying amount of short-term debt approximates the fair
value because of the short maturity of those instruments. The
fair value of debentures and medium-term notes was estimated
based on actual market prices or market prices of similar issues.
The Company has no financial instruments held or issued for
trading purposes.
NOTE F: CAPITALIZATION
The Company systematically reduces capitalization each year as
its asset depreciates, resulting in the payment of dividends in
excess of current earnings. The SEC has approved the Company's
request to pay common dividends out of capital. Common dividends
were paid from retained earnings, reducing the account balance to
zero, and from other paid-in capital as follows:
(Thousands of Dollars) 1998 1997 1996
Retained earnings.................. $22,753 $32,268 $30,942
Other paid-in capital.............. 34,247 3,432 7,045
Total............................ $57,000 $35,700 $37,987
F-84
Allegheny Generating Company
NOTE G: LONG-TERM DEBT
The Company had long-term debt outstanding as follows:
12-31-98
Interest December 31
(Thousands of Dollars) Rate 1998 1997
Debentures due:
September 1, 2003................. 5.625% $ 50,000 $ 50,000
September 1, 2023................. 6.875% 100,000 100,000
Medium-term notes due 1998.......... 60,000
Unamortized debt discount........... (1,171) (1,265)
Total........................... 148,829 208,735
Less current maturities............. 60,000
Total........................... $148,829 $148,735
Maturities for long-term debt for the next five years are $50,000
in 2003.
NOTE H: SHORT-TERM DEBT
To provide interim financing and support for outstanding
commercial paper, the Allegheny Energy companies have established
lines of credit with several banks. The Company has SEC
authorization for total short-term borrowings of $100 million,
including money pool borrowings described below. The Company has
fee arrangements on all of its lines of credit and no
compensating balance requirements. In addition to bank lines of
credit, an Allegheny Energy internal money pool accommodates
intercompany short-term borrowing needs to the Company, to the
extent that Allegheny Energy and the Company's Parents have funds
available. At December 31, 1998, the Company had borrowings from
the Allegheny Energy money pool of $66.8 million which were
funded by The Potomac Edison Company. Short-term debt
outstanding for 1998 consisted of:
(Thousands of Dollars) 1998
Balance and interest rate at end of year:
Money pool.............................. $66,750-4.80%
Average amount outstanding and interest rate during
the year:
Commercial paper.................................. 1,725-5.46%
Notes payable to banks............................ 406-5.63%
Money pool........................................ 43,415-5.23%
F-85
S-1
SCHEDULE II
ALLEGHENY ENERGY, INC. AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E
Additions
Balance at Charged to Charged to Balance at
beginning costs and other end of
Description of period expenses accounts Deductions period
(A) (B)
Allowance for
uncollectible accounts:
Year Ended 12/31/98 $17,191,310 $15,371,602 $4,953,941 $17,956,716 $19,560,137
Year Ended 12/31/97 $15,052,494 $16,306,082 $3,869,153 $18,036,419 $17,191,310
Year Ended 12/31/96 $13,046,900 $12,970,000 $3,243,945 $14,208,351 $15,052,494
(A) Recoveries.
(B) Uncollectible accounts charged off.
S-2
SCHEDULE II
MONONGAHELA POWER COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E
Additions
Balance at Charged to Charged to Balance at
beginning costs and other end of
Description of period expenses accounts Deductions period
(A) (B)
Allowance for
uncollectible accounts:
Year Ended 12/31/98 $ 2,176,006 $ 3,951,000 $ 1,383,021 $ 4,994,278 $ 2,515,749
Year Ended 12/31/97 $ 1,949,219 $ 3,699,997 $ 1,005,246 $ 4.478,456 $ 2,176,006
Year Ended 12/31/96 $ 2,266,808 $ 1,970,000 $ 666,816 $ 2,954,405 $ 1,949.219
(A) Recoveries.
(B) Uncollectible accounts charged off.
S-3
SCHEDULE II
POTOMAC EDISON COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E
Additions
Balance at Charged to Charged to Balance at
beginning costs and other end of
Description of period expenses accounts Deductions period
(A) (B)
Allowance for
uncollectible accounts:
Year Ended 12/31/98 $ 1,683,485 $ 3,731,000 $ 1,456,097 $ 4,667,910 $ 2,202,672
Year Ended 12/31/97 $ 1,579,503 $ 3,700,000 $ 1,312,074 $ 4,908,092 $ 1,683,485
Year Ended 12/31/96 $ 1,344,077 $ 2,514,000 $ 957,372 $ 3,235,946 $ 1,579,503
(A) Recoveries.
(B) Uncollectible accounts charged off.
S-4
SCHEDULE II
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1998, 1997, and 1996
Column A Column B Column C Column D Column E
Additions
Balance at Charged to Charged to Balance at
beginning costs and other end of
Description of period expenses accounts Deductions period
(A) (B)
Allowance for
uncollectible accounts:
Year Ended 12/31/98 $13,325,739 $ 7,613,934 $ 2,114,823 $ 8,294,528 $14,759,968
Year Ended 12/31/97 $11,523,772 $ 8,900,005 $ 1,551,833 $ 8,649,871 $13,325,739
Year Ended 12/31/96 $ 9,436,015 $ 8,486,000 $ 1,619,757 $ 8,018,000 $11,523,772
(A) Recoveries.
(B) Uncollectible accounts charged off.
49
Supplementary Data
Quarterly Financial Data (Unaudited)
(Dollar Amounts in Thousands Except for Per Share Data)
Electric
Operating Operating Net Earnings
Revenues Income Income* Per Share*
Quarter ended
AE
March 1998 $645 472 $124,707 $ 78 237 $ .64
June 1998 627 650 100 065 53 891 .44
September 1998 726 607 128 604 82 736 .68
December 1998 576 707 86 131 48 144 .39
March 1997 614 980 124 094 77 591 .64
June 1997 542 750 95 473 51 683 .42
September 1997 595 125 110 635 74 808 .61
December 1997 616 636 122 035 77 214 .63
Monongahela
March 1998 158 272 27 358 19 427
June 1998 153 774 24 087 16 611
September 1998 177 364 31 887 25 244
December 1998 155 712 28 154 21 143
March 1997 162 803 30 480 22 556
June 1997 144 078 23 701 16 174
September 1997 158 240 28 493 23 457
December 1997 163 190 26 701 18 342
Potomac Edison
March 1998 191 698 37 622 27 922
June 1998 177 519 30 036 20 504
September 1998 190 533 36 680 27 299
December 1998 177 744 34 458 25 757
March 1997 192 228 37 062 27 723
June 1997 164 867 26 894 18 376
September 1997 175 464 30 388 25 296
December 1997 176 222 34 428 24 360
West Penn
March 1998 280 703 52 619 39 001
June 1998 263 023 40 627 26 308
September 1998 288 272 56 248 42 835
December 1998 246 729 17 038 4 476
March 1997 282 530 47 271 36 901
June 1997 252 731 35 661 21 963
September 1997 266 746 43 865 34 333
December 1997 280 155 55 850 41 468
AGC
March 1998 18 604 9 450 5 937
June 1998 19 126 9 258 5 961
September 1998 18 303 9 297 5 625
December 1998 17 783 8 649 5 230
March 1997 20 216 10 328 6 368
June 1997 20 408 10 311 6 395
September 1997 19 664 10 230 15 396
December 1997 16 170 7 664 4 109
*For AE and West Penn - 1998 results exclude the effect of
extraordinary charges in June 1998 ($265,446, net of taxes, or
$2.17 per share) and December 1998 ($9,980, net of taxes, or $.08
per share).
50
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and the Shareholders of
Allegheny Energy, Inc.
In our opinion, the consolidated financial statements
listed in the accompanying index present fairly, in all material
respects, the financial position of Allegheny Energy, Inc. and
its subsidiaries at December 31, 1998 and 1997, and the results
of their operations and their cash flows for each of the three
years in the period ended December 31, 1998, in conformity with
generally accepted accounting principles. 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 generally accepted auditing
standards 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 4, 1999
51
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
Monongahela Power Company
In our opinion, the financial statements listed in the
accompanying index present fairly, in all material respects, the
financial position of Monongahela Power Company (a subsidiary of
Allegheny Energy, Inc.) at December 31, 1998 and 1997, and the
results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. 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 generally accepted auditing
standards 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 4, 1999
52
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
The Potomac Edison Company
In our opinion, the financial statements listed in the
accompanying index present fairly, in all material respects, the
financial position of The Potomac Edison Company (a subsidiary of
Allegheny Energy, Inc.) at December 31, 1998 and 1997, and the
results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. 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 generally accepted auditing
standards 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 4, 1999
53
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
West Penn Power Company
In our opinion, the consolidated financial statements
listed in the accompanying index present fairly, in all material
respects, the financial position of West Penn Power Company (a
subsidiary of Allegheny Energy, Inc. and its subsidiaries) at
December 31, 1998 and 1997, and the results of their operations
and their cash flows for each of the three years in the period ended
December 31, 1998, in conformity with generally accepted accounting
principles. 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 generally accepted
auditing standards 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 4, 1999
54
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
Allegheny Generating Company
In our opinion, the financial statements listed in the
accompanying index present fairly, in all material respects, the
financial position of Allegheny Generating Company (a subsidiary
of Allegheny Energy, Inc.) at December 31, 1998 and 1997, and the
results of its operations and its cash flows for each of the
three years in the period ended December 31, 1998, in conformity
with generally accepted accounting principles. 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 generally accepted auditing
standards 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 4, 1999
55
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
For AE and its subsidiaries, none.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
AE, Monongahela, Potomac Edison, West Penn, and AGC. Reference
is made to the Executive Officers of the Registrants in Part I of
this report. The names, ages as of December 31, 1998, and the
business experience during the past five years of the directors
of the System companies are set forth below:
Business Experience during Director since date shown of
Name the Past Five Years Age AE MP PE WP AGC
Eleanor Baum See below (a) 58 1988 1988 1988 1988
William L. Bennett See below (b) 49 1991 1991 1991 1991
Thomas K. Henderson Company employee (1) 58 1996
Wendell F. Holland See below (c) 46 1994 1994 1994 1994
Kenneth M. Jones Company employee (1) 61 1991
Phillip E. Lint See below (d) 69 1989 1989 1989 1989
Frank A. Metz, Jr. See below (e) 64 1984 1984 1984 1984
Michael P. Morrell Company employee (1) 50 1996 1996 1996 1996
Alan J. Noia Company employee (1) 51 1994 1994 1987 1994 1994
Jay S. Pifer Company employee (1) 61 1995 1995 1992
Steven H. Rice See below (f) 55 1986 1986 1986 1986
Gunnar E. Sarsten See below (g) 61 1992 1992 1992 1992
Peter J. Skrgic Company employee (1) 57 1990 1990 1990 1989
(1) See Executive Officers of the Registrants in Part I of this
report for further details.
(a) Eleanor Baum. Dean of The Albert Nerken School of
Engineering of The Cooper Union for the
Advancement of Science and Art. Director of
Avnet, Inc. and United States Trust Company, Chair
of the Engineering Workforce Commission, a fellow
of the Institute of Electrical and Electronic
Engineers, Chairman of Board of Governors, New
York Academy of Sciences. Formerly, President of
Accreditation Board for Engineering and Technology
and President, American Society of Engineering
Education.
(b) William L. Bennett. Vice-Chairman and Director of
HealthPlan Services Corporation, and Director of
Sylvan, Inc. Formerly, Chairman, Director and
Chief Executive Officer of Noel Group, Inc. and
Director of Belding Heminway Company, Inc.
(c) Wendell F. Holland. Vice President, American
International Water Services Company and Director
of Bryn Mawr Trust Company. Formerly, Of Counsel,
Law Firm of Reed, Smith, Shaw & McClay, Partner,
Law Firm of LeBoeuf, Lamb, Greene & MacRae, and
Commissioner of the Pennsylvania Public Utility
Commission.
(d) Phillip E. Lint. Retired. Formerly, Partner,
Price Waterhouse.
(e) Frank A. Metz, Jr. Retired. Director of Norrell
Corporation and Solutia, Inc. Formerly, Senior
Vice President, Finance and Planning, and Director
of International Business Machines Corporation and
Director of Monsanto Company.
(f) Steven H. Rice. President, LaJolla Bank, FSB,
Northeast Region and Director, LaJolla Bank, FSB.
Formerly, Chief Executive Officer and Vice
Chairman of the Board of Stamford Federal Savings
Bank, bank consultant, President and Director
of The Seamen's Bank for Savings, and Director of
Royal Group, Inc.
56
(g) Gunnar E. Sarsten. Chairman and Chief Executive
Officer of MK International. Formerly, President and
Chief Operating Officer of Morrison Knudsen
Corporation, President and Chief Executive Officer of
United Engineers & Constructors International, Inc.
(now Raytheon Engineers & Constructors), and Deputy
Chairman of the Third District Federal Reserve Bank
in Philadelphia.
ITEM 11. EXECUTIVE COMPENSATION
During 1998, and for 1997 and 1996, the annual
compensation paid by AE, Monongahela, Potomac Edison, West Penn
and AGC directly or indirectly for services in all capacities to
such companies to their Chief Executive Officer and each of the
four most highly paid executive officers of the System whose cash
compensation exceeded $100,000 was as follows:
Summary Compensation Tables (a)
AE(b), Monongahela(c), Potomac Edison(c), West Penn(c) and AGC(c)
Annual Compensation
All
Name Other
and Long-Term Compen-
Principal Annual Performance sation
Position(d) Year Salary($) Incentive($)(e) Plan($)(f) ($)(g)
Alan J. Noia, 1998 525,000 180,500 286,655 184,788
Chief Executive Officer 1997 460,000 253,000 250,657 124,495
1996 360,000 253,750 131,071 92,769
Peter J. Skrgic, 1998 280,008 123,000 204,753 50,757
Senior Vice President 1997 265,000 155,400 150,394 91,409
Supply 1996 245,000 176,300 96,119 24,830
Michael P. Morrell (h) 1998 255,000 117,000 114,870 28,599
Senior Vice President & 1997 240,000 95,200 (h) 26,068
Chief Financial Officer 1996 183,336 72,500 (h) (h)
Jay S. Pifer, 1998 250,008 66,500 131,042 41,542
Senior Vice President 1997 240,000 95,200 150,394 67,810
Delivery 1996 230,000 112,000 87,381 30,949
Richard J. Gagliardi 1998 200,016 60,400 114,662 25,345
Vice President 1997 190,000 75,600 100,263 25,340
Administration 1996 175,000 100,800 52,429 17,898
(a) The individuals appearing in this chart perform
policy-making functions for each of the
Registrants. The compensation shown is for all
services in all capacities to AE and its
subsidiaries. All salaries and bonuses of these
executives are paid by APSC.
(b) AE has no paid employees.
(c) Monongahela, Potomac Edison, West Penn, and AGC
have no paid employees.
(d) See Executive Officers of the Registrants for all
positions held.
57
(e) Incentive awards are based upon performance in the
year in which the figure appears but are paid in
the following year. The incentive award plan will
be continued for 1999.
(f) In 1994, the Board of Directors of the Company
implemented a Performance Share Plan (the "Plan")
for senior officers of the Company and its
subsidiaries which was approved by the
shareholders of AE at the annual meeting in May
1994. The first Plan cycle began on January 1,
1994 and ended on December 31, 1996. A second
cycle began on January 1, 1995 and ended on
December 31, 1997. The figure shown for 1996
represents the dollar value paid in 1997 to each
of the named executive officers who participated
in Cycle I. The figure shown for 1997 represents
the dollar value paid in 1998 to each of the named
executive officers who participated in Cycle II.
A third cycle began on January 1, 1996 and ended
on December 31, 1998. The figure shown for 1998
represents the dollar value paid in 1999 to each
of the named executives who participated in Cycle
III. A fourth cycle began on January 1, 1997 and
will end on December 31, 1999. In 1998, the Board
of Directors of AE implemented a new Long-Term
Incentive Plan, which was approved by the
shareholders of AE at the AE annual meeting in May
1998. A fifth cycle (the first three-year performance
period of this Plan) began on January 1, 1998 and
will end on December 31, 2000. After completion
of each cycle, AE stock, stock options (for Cycle
V), cash, or a combination may be paid if
performance criteria have been met.
(g) The figures in this column include the present
value of the executives' cash value at retirement
attributable to the current year's premium payment
for both the Executive Life Insurance and Secured
Benefit Plans (based upon the premium, future
valued to retirement, using the policy internal
rate of return minus the corporation's premium
payment), as well as the premium paid for the
basic group life insurance program plan and the
contribution for the Employee Stock Ownership and
Savings Plan (ESOSP) established as a non-
contributory stock ownership plan for all eligible
employees effective January 1, 1976, and amended
in 1984 to include a savings program.
Effective January 1, 1992, the basic group life
insurance provided employees was reduced from two
times salary during employment, which reduced to
one times salary after five years in retirement,
to a new plan which provides one times salary
until retirement and $25,000 thereafter. Some
executive officers and other senior managers
remain under the prior plan. In order to pay for
this insurance for these executives, during 1992
insurance was purchased on the lives of each of
them, except Mr. Morrell, who is not covered by
this plan. Effective January 1, 1993, Allegheny
started to provide funds to pay for the future
benefits due
58
under the supplemental retirement
plan (Secured Benefit Plan). To do this,
Allegheny purchased, during 1993, life insurance
on the lives of the covered executives. The
premium costs of both policies plus a factor for
the use of the money are returned to Allegheny at
the earlier of (a) death of the insured or (b) the
later of age 65 or 10 years from the date of the
policy's inception. Under the ESOSP for 1998, all
eligible employees may elect to have from 2% to
10% of their compensation contributed to the Plan
as pre-tax contributions and an additional 1% to
6% as post-tax contributions. Employees direct
the investment of these contributions into one or
more of nine available funds. Fifty percent of
the pre-tax contributions up to 6% of compensation
are matched with common stock of AE. Effective
January 1 1997, the maximum amount of any
employee's compensation that may be used in these
computations is $160,000. Employees' interests in
the ESOSP vest immediately. Their pre-tax
contributions may be withdrawn only upon meeting
certain financial hardship requirements or upon
termination of employment. For 1998, the figure
shown includes amounts representing (a) the
aggregate of life insurance premiums and dollar
value of the benefit to the executive officer of
the remainder of the premium paid on the Group
Life Insurance program and the Executive Life
Insurance and Secured Benefit Plans, and (b) ESOSP
contributions, respectively, as follows: Mr. Noia
$179,988 and $4,800; Mr. Skrgic $45,957 and
$4,800; Mr. Morrell $25,399 and $3,200; Mr. Pifer
$36,742 and $4,800; and Mr. Gagliardi $20,545 and
$4,800.
(h) Michael P. Morrell joined Allegheny on May 1,
1996, and did not receive a payment from the Long-
Term Performance Plan for the first or second Plan
cycles. His Cycle III payout is prorated for the
period May 1, 1996 - December 31, 1998.
ALLEGHENY ENERGY, INC. LONG-TERM INCENTIVE PLAN
SHARES AWARDED IN LAST FISCAL YEAR (CYCLE V)
Estimated Future Payout
Number of Performance Threshold Target Maximum
Shares Period Until Number of Number of Number of
Name Payout Shares Shares Shares
Alan J. Noia
Chief Executive Officer 8,077 1998-2000 4,846 8,077 16,154
Peter J. Skrgic
Senior Vice President 4,308 1998-2000 2,585 4,308 8,615
Michael P. Morrell
Senior Vice President 3,077 1998-2000 1,846 3,077 6,154
Jay S. Pifer
Senior Vice President 2,923 1998-2000 1,754 2,923 5,846
Richard J. Gagliardi
Vice President 2,462 1998-2000 1,477 2,462 4,923
59
The named executives were awarded the above number of
performance shares for the 1998-2000 period. Such number of
shares are only targets. As described below, no payouts will be
made unless certain criteria are met. Each executive's 1998-2000
target long-term incentive opportunity was converted into
performance shares equal to an equivalent number of shares of AE
common stock based on the price of such stock on December 31,
1997. At the end of this three-year performance period, the
performance shares attributed to the calculated award will be
valued based on the price of AE common stock on December 31, 2000
and will reflect dividends that would have been paid on such
stock during the performance period as if they were reinvested on
the date paid. If an executive retires, dies or otherwise leaves
the employment of Allegheny prior to the end of the three-year
period, the executive may still receive an award based on the
number of months worked during the period. The final value of an
executive's account, if any, will be paid to the executive in
early 2001.
The actual payout of an executive's award may range from 0
to 200% of the target amount, before dividend reinvestment. The
Management Review of Director Affairs Committee of the Board and
Directors may decide to convert the value of such performance
shares to stock options at that time or deliver cash or shares of
common stock. The payout is based upon stockholder performance
versus the peer group. The stockholder rating is then compared
to a pre-established percentile ranking chart to determine the
payout percentage of target. A ranking below 30% results in a 0%
payout. The minimum payout begins at the 30% ranking, which
results in a payout of 60% of target, ranging up to a payout of
200% if there is a 90% or higher ranking.
Retirement Plan
The Company maintains a Retirement Plan covering substantially
all employees. The Retirement Plan is a noncontributory, trusteed
pension plan designed to meet the requirements of Section 401(a) of
the Internal Revenue Code of 1986, as amended (the Code). Each
covered employee is eligible for retirement at normal retirement
date (age 65), with early retirement permitted. In addition,
executive officers and other senior managers participate in a
supplemental executive retirement plan (Secured Benefit Plan).
Pursuant to the Secured Benefit Plan, senior executives of
Allegheny companies who retire at age 60 or over with 40 or more
years of service are entitled to a supplemental retirement benefit
in an amount that, together with the benefits under the basic plan
and from other employment, will equal 60% of the executive's highest
average monthly earnings for any 36 consecutive months. The
earnings include 50% of the actual annual incentive award paid
beginning February 1, 1996 and 100% beginning February 1, 1999. The
supplemental benefit is reduced for less than 40 years service and
for retirement age from 60 to 55. It is included in the amounts
shown where applicable. To provide funds to pay such benefits,
beginning January 1, 1993, the Company purchased insurance on the
lives of the participants in the Secured Benefit Plan. If the
assumptions made as to mortality experience, policy dividends, and
other factors are realized, the Company will recover all premium
payments, plus a factor for the use of the Company's money. The
portion of the premiums for this insurance required to be deemed
"compensation" by the Securities and Exchange Commission is included
in the "All Other Compensation" column on page 56 of this Form 10-K.
All exectuive officers are participants in the Secured Benefit Plan.
It also provides for use of Average Compensation in excess of Code
maximums.
60
The following table shows estimated maximum annual benefits
payable following retirement (assuming payments on a normal life
annuity basis and not including any survivor benefit) to an employee
in specified remuneration and years of credited service
classifications. These amounts are based on an estimated Average
Compensation (defined as average total earnings during the highest-
paid 36 consecutive calendar months or, if smaller, the member's
highest rate of pay as of any July 1st), retirement at age 65 and
without consideration of any effect of various options which may be
elected prior to retirement. The benefits listed in the Pension
Plan Table are not subject to any deduction for Social Security or
any other offset amounts.
PENSION PLAN TABLE
Years of Credited Service
Average Compensation(a) 15 Years 20 Years 25 Years 30 Years 35 Years 40 Years
$ 200,000 $ 60,000 $ 80,000 $100,000 $110,000 $115,000 $120,000
250,000 75,000 100,000 125,000 137,500 143,750 150,000
300,000 90,000 120,000 150,000 165,000 172,500 180,000
350,000 105,000 140,000 175,000 192,500 201,250 210,000
400,000 120,000 160,000 200,000 220,000 230,000 240,000
450,000 135,000 180,000 225,000 247.500 258,750 270,000
500,000 150,000 200,000 250,000 275,000 287,500 300,000
550,000 165,000 220,000 275,000 302,500 316,250 330,000
600,000 180,000 240,000 300,000 330,000 345,000 360,000
650,000 195,000 260,000 325,000 357,500 373,750 390,000
700,000 210,000 280,000 350,000 385,000 402,500 420,000
750,000 225,000 300,000 375,000 412,500 431,250 450,000
800,000 240,000 320,000 400,000 440,000 460,000 480,000
(a) The earnings of Messrs. Noia, Skrgic, Pifer, Morrell and Gagliardi
covered by the plan correspond substantially to such amounts shown
for them in the summary compensation table. As of December 31,
1998, they had accrued 29, 34, 34, 2-1/2 and 20 years of credited
service, respectively, under the Retirement Plan. Pursuant to an
agreement with Mr. Morrell, at the end of ten years of employment
with the Company, Mr. Morrell will be credited with an additional
eight years of service.
Change In Control Contracts
AE has entered into Change in Control contracts with the named and
certain other Allegheny executive officers (Agreements). Each Agreement sets
forth (i) the severance benefits that will be provided to the employee in the
event the employee is terminated subsequent to a Change in Control of AE (as
defined in the Agreements), and (ii) the employee's obligation to continue his
or her employment after the occurrence of certain circumstances that could
lead to a Change in Control. The Agreements provide generally that if there
is a Change in Control, unless employment is terminated by AE for Cause,
Disability or Retirement or by the employee for Good Reason (each as defined
in the Agreements), severance benefits payable to the employee will consist of
a cash payment equal to 2.99 times the employee's base annual salary and
target short-term incentive together with AE maintaining existing benefits for
the employee and the employee's dependents for a period of three years. Each
Agreement expires on December 31, 2001, but is automatically extended for one
year periods thereafter unless either AE or the employee gives notice
otherwise. Notwithstanding the delivery of such notice, the Agreements will
continue in effect for thirty-six months after a Change in Control.
Compensation of Directors
In 1998, AE directors who were not officers or employees of System
companies received for all services to System companies (a) $16,000 in
retainer fees, (b) $800 for each committee
61
meeting attended, except Executive Committee meetings, for which fees are
$200, (c) $250 for each Board meeting of each company attended, and (d)
200 shares of AE common stock pursuant to the Restricted Stock Plan for
Outside Directors. Under an unfunded deferred compensation plan, a director
may elect to defer receipt of all or part of his or her director's fees
for succeeding calendar years to be payable with accumulated interest
when the director ceases to be such, in equal annual installments, or,
upon authorization by the Board of Directors, in a lump sum. In addition to
the fees mentioned above, the Chairperson of each of the Audit, Finance,
Management Review and Director Affairs, New Business, and Strategic
Affairs Committees receives a further fee of $4,000 per year.
In addition, a Deferred Stock Unit Plan for Outside Directors provides
for a lump sum payment (payable at the director's election in one or more
installments, including interest thereon equivalent to the dividend yield) to
directors calculated by reference to AE's common stock. Directors who serve
at least five years on the Board and leave at or after age 65, or upon death
or disability, or as otherwise directed by the Board will receive such
payments. Each year, AE credits each Outside Director's account with 275
deferred stock units.
62
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT
The table below shows the number of shares of AE common
stock that are beneficially owned, directly or indirectly,
by each director and named executive officer of AE,
Monongahela, Potomac Edison, West Penn, and AGC and by all
directors and executive officers of each such company as a
group as of December 31, 1998. To the best of the knowledge
of AE, there is no person who is a beneficial owner of more
than 5% of the voting securities of AE other than the one
shareholder shown in the chart below.
Executive Shares of
Officer or APS Percent
Name Director of Common Stock of Class
Eleanor Baum AE,MP,PE,WP 2,800* .02% or less
William L. Bennett AE,MP,PE,WP 3,570* "
Richard J. Gagliardi AE 10,541 "
Thomas K. Henderson AE,MP,PE,WP,AGC 5,761 "
Wendell F. Holland AE,MP,PE,WP 1,057* "
Kenneth M. Jones AE,AGC 11,541 "
Phillip E. Lint AE,MP,PE,WP 1,517* "
Frank A. Metz, Jr. AE,MP,PE,WP 3,355* "
Michael P. Morrell AE,MP,PE,WP,AGC 252 "
Alan J. Noia AE,MP,PE,WP,AGC 27,947 "
Jay S. Pifer AE,MP,PE,WP 14,547 "
Steven H. Rice AE,MP,PE,WP 3,640* "
Gunnar E. Sarsten AE,MP,PE,WP 6,800* "
Peter J. Skrgic AE,MP,PE,WP,AGC 16,101 "
Sanford C. Bernstein & Co., Inc. 7,948,382 6.49%
767 Fifth Avenue
New York, NY 10153
All directors and executive officers
of AE as a group (18 persons) 122,459 Less than .10%
All directors and executive officers
of MP as a group (18 persons) 115,334 "
All directors and executive officers
of PE as a group (18 persons) 115,334 "
All directors and executive officers
of WP as a group (19 persons) 121,352 .10%
All directors and executive officers
of AGC as a group (8 persons) 74,378 .06%
*Excludes the outside directors' accounts in the Deferred Stock Unit
Plan which, at March 1, 1999, were valued at the number of shares
shown: Baum 3,463; Bennett 1,720; Holland 1,578; Lint 5,084; Metz
3,732; Rice 2,270; and Sarsten 3,159.
63
All of the shares of common stock of Monongahela (5,891,000), Potomac
Edison (22,385,000), and West Penn (24,361,586) are owned by AE.
All of the common stock of AGC is owned by Monongahela (270
shares), Potomac Edison (280 shares), and West Penn (450 shares).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
(a)(1)(2) The financial statements and financial statement
schedules filed as part of this Report are set
forth under ITEM 8. and reference is made to the
index on page 48.
(b) No companies filed reports on Form 8-K during the
quarter ended December 31, 1998.
(c) Exhibits for AE, Monongahela, Potomac Edison, West
Penn, and AGC are listed in the Exhibit Index
beginning on page E-1 and are incorporated herein
by reference.
64
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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.
By: /s/ Alan J. Noia
(Alan J. Noia) Chairman,
President
and Chief Executive Officer
Date: March 4, 1999
Pursuant to the requirements of the Securities Exchange
Act of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated.
Signature Title Date
(i) Principal Executive Officer:
/s/ Alan J. Noia Chairman, President, Chief
(Alan J. Noia Executive Officer and Director 3/4/99
(ii) Principal Financial Officer:
/s/ Michael P. Morrell Senior Vice President,
(Michael P. Morrell) Finance 3/4/99
(iii) Principal Accounting Officer:
/s/ Thomas J. Vice President and
(Thomas J. Kloc) Controller 3/4/99
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Alan J. Noia
*Wendell F. Holland *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*By: /s/ Thomas K. Henderson 3/4/99
(Thomas K. Henderson)
65
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned
company shall be deemed to relate only to matters having
reference to such company and any subsidiaries thereof.
MONONGAHELA POWER COMPANY
By: /s/ Jay S. Pifer
(Jay S. Pifer) President
and Director
Date: March 4, 1999
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Signature Title Date
(i) Principal Executive Officer
/s/ Alan J. Noia Chairman of the Board, Chief
(Alan J. Noia) Executive Officer and Director 3/4/99
(ii) Principal Financial Officer:
/s/ Michael P. Morrell
(Michael P. Morrell) Vice President, Finance 3/4/99
(iii) Principal Accounting Officer:
/s/ Thomas J. Kloc
(Thomas J. Kloc) Controller 3/4/99
(iv) A Majority of the Directors:
*Eleanor Baum *Alan J. Noia
*William L. Bennett *Jay S. Pifer
*Wendell F. Holland *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Frank A. Metz, Jr. *Peter J. Skrgic
*Michael P. Morrell
*By: /s/ Thomas K. Henderson
(Thomas K. Henderson) 3/4/99
66
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned
company shall be deemed to relate only to matters having
reference to such company and any subsidiaries thereof.
THE POTOMAC EDISON COMPANY
By: /s/ Jay S. Pifer
(Jay S. Pifer) President
and Director
Date: March 4, 1999
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Signature Title Date
(i) Principal Executive Officer
/s/ Alan J. Noia Chairman of the Board, Chief
(Alan J. Noia) Executive Officer and Director 3/4/99
(ii) Principal Financial Officer:
/s/ Michael P. Morrell
(Michael P. Morrell) Vice President, Finance 3/4/99
(iii) Principal Accounting Officer:
/s/ Thomas J. Kloc
(Thomas J. Kloc) Controller 3/4/99
(iv) A Majority of the Directors:
*Eleanor Baum *Alan J. Noia
*William L. Bennett *Jay S. Pifer
*Wendell F. Holland *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Frank A. Metz, Jr. *Peter J. Skrgic
*Michael P. Morrell
*By: /s/ Thomas K. Henderson
(Thomas K. Henderson) 3/4/99
67
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned
company shall be deemed to relate only to matters having
reference to such company and any subsidiaries thereof.
WEST PENN POWER COMPANY
By: /s/ Jay S. Pifer
(Jay S. Pifer) President
and Director
Date: March 4, 1999
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Signature Title Date
(i) Principal Executive Officer
/s/ Alan J. Noia Chairman of the Board, Chief
(Alan J. Noia) Executive Officer and Director 3/4/99
(ii) Principal Financial Officer:
/s/ Michael P. Morrell
(Michael P. Morrell) Vice President, Finance 3/4/99
(iii) Principal Accounting Officer:
/s/ Thomas J. Kloc
(Thomas J. Kloc) Controller 3/4/99
(iv) A Majority of the Directors:
*Eleanor Baum *Alan J. Noia
*William L. Bennett *Jay S. Pifer
*Wendell F. Holland *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Frank A. Metz, Jr. *Peter J. Skrgic
*Michael P. Morrell
*By: /s/ Thomas K. Henderson
(Thomas K. Henderson) 3/4/99
68
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) 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. The signature of the undersigned
company shall be deemed to relate only to matters having
reference to such company and any subsidiaries thereof.
ALLEGHENY GENERATING COMPANY
By: /s/ Alan J. Noia
(Alan J. Noia)
Chief Executive Officer
Date: March 4, 1999
Pursuant to the requirements of the Securities Exchange Act
of 1934, this report has been signed below by the following
persons on behalf of the registrant and in the capacities and on
the dates indicated. The signature of each of the undersigned
shall be deemed to relate only to matters having reference to the
above-named company and any subsidiaries thereof.
Signature Title Date
(i) Principal Executive Officer
/s/ Alan J. Noia Chairman of the Board, Chief
(Alan J. Noia) Executive Officer and President 3/4/99
(ii) Principal Financial Officer:
/s/ Michael P. Morrell
(Michael P. Morrell) Vice President, Finance 3/4/99
(iii) Principal Accounting Officer:
/s/ Thomas J. Kloc
(Thomas J. Kloc) Controller 3/4/99
(iv) A Majority of the Directors:
*Thomas K. Henderson
*Thomas J. Kloc
*Michael P. Morrell
*Alan J. Noia
*Peter J. Skrgic
*By: /s/ Thomas K. Henderson
(Thomas K. Henderson) 3/4/99
69
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in
the Prospectus constituting part of Allegheny Power
System Inc.'s (now Allegheny Energy, Inc.) Registration
Statements on Form S-3 (Nos. 33-36716 and 33-57027)
relating to the Dividend Reinvestment and Stock
Purchase Plan of Allegheny Energy, Inc.; in the
Prospectus constituting part of Allegheny Power System,
Inc.'s (now Allegheny Energy, Inc.) Registration
Statement on Form S-3 (No. 33-49791) relating to the
common stock shelf registration; in the Prospectus
constituting part of Monongahela Power Company's
Registration Statements on Form S-3 (Nos. 333-31493, 33-
51301, 33-56262 and 33-59131); in the Prospectus
constituting part of The Potomac Edison Company's
Registration Statements on Form S-3 (Nos. 333-33413, 33-
51305 and 33-59493); and in the Prospectus constituting
part of West Penn Power Company's Registration
Statements on Form S-3 (Nos. 333-34511, 33-51303, 33-
56997, 33-52862, 33-56260 and 33-59133); of our reports
dated February 4, 1999 included in ITEM 8 of this Form
10-K. We also consent to the references to us under
the heading "Experts" in such Prospectuses.
PricewaterhouseCoopers, LLP
Pittsburgh, Pennsylvania
March 29, 1999
70
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the
undersigned directors of Allegheny Energy, Inc., a
Maryland corporation, Monongahela Power Company, an
Ohio corporation, The Potomac Edison Company, a
Maryland and Virginia corporation, and West Penn Power
Company, a Pennsylvania corporation, do hereby
constitute and appoint THOMAS K. HENDERSON and EILEEN
M. BECK, and each of them, a true and lawful attorney
in his or her name, place and stead, in any and all
capacities, to sign his or her name to Annual Reports
on Form 10-K for the year ended December 31, 1998 under
the Securities Exchange Act of 1934, as amended, and to
any and all amendments, of said Companies, and to cause
the same to be filed with the SEC, granting unto said
attorneys and each of them full power and authority to
do and perform any act and thing necessary and proper
to be done in the premises, as fully and to all intents
and purposes as the undersigned could do if personally
present, and the undersigned hereby ratifies and
confirms all that said attorneys or any one of them
shall lawfully do or cause to be done by virtue hereof.
Dated: March 4, 1999
/s/ Eleanor Baum /s/ Frank A. Metz, Jr.
(Eleanor Baum) (Frank A. Metz, Jr.)
/s/ William L. Bennett /s/ Alan J. Noia
(William L. Bennett) (Alan J. Noia)
/s/ Wendell F. Holland /s/ Steven H. Rice
(Wendell F. Holland) (Steven H. Rice)
/s/ Phillip E. Lint /s/ Gunnar E. Sarsten
(Phillip E. Lint) (Gunnar E. Sarsten)
71
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the
undersigned directors of Monongahela Power Company, an
Ohio corporation, The Potomac Edison Company, a
Maryland and Virginia corporation, and West Penn Power
Company, a Pennsylvania corporation, do hereby
constitute and appoint THOMAS K. HENDERSON and EILEEN
M. BECK, and each of them, a true and lawful attorney
in his name, place and stead, in any and all
capacities, to sign his or her name to the Annual
Report on Form 10-K for the year ended December 31,
1998 under the Securities Exchange Act of 1934, as
amended, and to any and all amendments, of said
Company, and to cause the same to be filed with the
SEC, granting unto said attorneys and each of them full
power and authority to do and perform any act and thing
necessary and proper to be done in the premises, as
fully and to all intents and purposes as the
undersigned could do if personally present, and the
undersigned hereby ratify and confirm all that said
attorneys or any one of them shall lawfully do or cause
to be done by virtue hereof.
Dated: March 4, 1999
/s/ Michael P. Morrell
(Michael P. Morrell)
/s/ Jay S. Pifer
(Jay S. Pifer)
/s/ Peter J. Skrgic
(Peter J. Skrgic)
72
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the
undersigned directors of Allegheny Generating Company,
a Virginia corporation, do hereby constitute and
appoint THOMAS K. HENDERSON and EILEEN M. BECK, and
each of them, a true and lawful attorney in his name,
place and stead, in any and all capacities, to sign his
or her name to the Annual Report on Form 10-K for the
year ended December 31, 1998 under the Securities
Exchange Act of 1934, as amended, and to any and all
amendments, of said Company, and to cause the same to
be filed with the SEC, granting unto said attorneys and
each of them full power and authority to do and perform
any act and thing necessary and proper to be done in
the premises, as fully and to all intents and purposes
as the undersigned could do if personally present, and
the undersigned hereby ratify and confirm all that said
attorneys or any one of them shall lawfully do or cause
to be done by virtue hereof.
Dated: March 4, 1999
/s/ Thomas K. Henderson
(Thomas K. Henderson)
/s/ Thomas J. Kloc
(Thomas J. Kloc)
/s/ Michael P. Morrell
(Michael P. Morrell)
/s/ Alan J. Noia
(Alan J. Noia)
/s/ Peter J. Skrgic
(Peter J. Skrgic)
E-1
EXHIBIT INDEX
(Rule 601(a))
Allegheny Energy, Inc.
Incorporation
Documents by Reference
3.1 Charter of the Company, Form 10-K of the Company
as amended, September 16, 1997 (1-267), December 31, 1997,
exh. 3.1
3.2 By-laws of the Company, Form 10-Q of the Company
as amended May 14, 1998 (1-267), June 30, 1998,
exh. 3.2
4 Subsidiaries' Indentures
described below
10.1 Directors' Deferred Form 10-K of the Company
Compensation Plan (1-267), December 31, 1994,
exh. 10.1
10.2 Executive Compensation Plan Form 10-K of the Company
(1-267), December 31, 1996
exh. 10.2
10.3 Allegheny Power System Incentive Form 10-K of the Company
Compensation Plan (1-267), December 31, 1996
exh. 10.3
10.4 Allegheny Power System Form 10-K of the Company
Supplemental Executive (1-267), December 31, 1996
Retirement Plan exh. 10.4
10.5 Executive Life Insurance Form 10-K of the Company
Program and Collateral (1-267), December 31, 1994,
Assignment Agreement exh. 10.5
10.6 Secured Benefit Plan Form 10-K of the Company
and Collateral Assignment (1-267), December 31, 1994,
Agreement exh. 10.6
10.7 Restricted Stock Plan
for Outside Directors
10.8 Deferred Stock Unit Plan Form 10-K of the Company
for Outside Directors (1-267), December 31, 1997,
exh. 10.8
E-1 (cont'd.)
EXHIBIT INDEX
(Rule 601(a))
Allegheny Energy, Inc.
Incorporation
Documents by Reference
10.9 Allegheny Power System Form 10-K of the Company
Performance Share Plan (1-267), December 31, 1994,
exh. 10.9
10.10 Form of Change in Control
Contract With Certain
Executive Officers Under
Age 55
10.11 Form of Change in Control
Contract With Certain
Executive Officers Over
Age 55
10.12 Allegheny Energy, Inc. Form S-8 of the Company
1998 Long-Term Incentive Plan (1-267), October 14, 1998,
exh. 4.1
11 Statement re computation of
per share earnings: Clearly
determinable from the financial
statements contained in Item 8.
21 Subsidiaries of AE:
Name of Company State of Organization
Allegheny Generating Company (a) Virginia
Allegheny Power Service Corporation Maryland
AYP Capital, Inc. Delaware
Monongahela Power Company Ohio
The Potomac Edison Company Maryland and Virginia
West Penn Power Company Pennsylvania
(a) Owned directly by Monongahela,
Potomac Edison, and West Penn.
23 Consent of Independent Accountants See page 69 herein.
24 Powers of Attorney See page 70 herein.
27 Financial Data Schedule
E-2
EXHIBIT INDEX
(Rule 601(a))
Monongahela Power Company
Incorporation
Documents by Reference
3.1 Charter of the Company, Form 10-Q of the Company
as amended (1-5164), September 1995,
exh. (a)(3)(i)
3.2 Code of Regulations, Form 10-Q of the Company
as amended (1-5164), September 1995,
exh. (a)(3)(ii)
4 Indenture, dated as of S 2-5819, exh. 7(f)
August 1, 1945, and S 2-8782, exh. 7(f)(1)
certain Supplemental S 2-8881, exh. 7(b)
Indentures of the S 2-9355, exh. 4(h)(1)
Company defining rights S 2-9979, exh. 4(h)(1)
of security holders.* S 2-10548, exh. 4(b)
S 2-14763, exh. 2(b)(i)
S 2-24404, exh. 2(c);
S 2-26806, exh. 4(d);
Forms 8-K of the Company
(1-268-2) dated November 21,
1991, July 15, 1992,
September 1, 1992, April 29,
1993 and May 23, 1995
* There are omitted the Supplemental Indentures which do no more
than subject property to the lien of the above Indentures since
they are not considered constituent instruments defining the
rights of the holders of the securities. The Company agrees to
furnish the Commission on its request with copies of such
Supplemental Indentures.
10.1 Form of Change in Control
Contract With Certain
Executive Officers Under
Age 55
10.2 Form of Change in Control
Contract With Certain
Executive Officers Over
Age 55
E-2 (cont'd.)
EXHIBIT INDEX
(Rule 601(a))
Monongahela Power Company
Incorporation
Documents by Reference
12 Computation of ratio of earnings
to fixed charges
21 Subsidiaries: Monongahela Power
Company has a 27% equity ownership
in Allegheny Generating Company,
incorporated in Virginia; and a 25%
equity ownership in Allegheny
Pittsburgh Coal Company, incorporated
in Pennsylvania.
23 Consent of Independent Accountants See page 69 herein.
24 Powers of Attorney See pages 70-71 herein.
27 Financial Data Schedule
E-3
EXHIBIT INDEX
(Rule 601(a))
The Potomac Edison Company
Incorporation
Documents by Reference
3.1 Charter of the Company, Form 10-Q of the Company
as amended (1-3376-2), September 1995,
exh. (a)(3)(i)
3.2 By-laws of the Company, Form 10-Q of the Company
as amended (1-3376-2), September 1995,
exh. (a)(3)(ii)
4 Indenture, dated as of S 2-5473, exh. 7(b); Form
October 1, 1944, and S-3, 33-51305, exh. 4(d)
certain Supplemental Forms 8-K of the Company
Indentures of the (1-3376-2) dated December 11,
Company defining rights 1991, December 15, 1992,
of security holders* February 17, 1993, March 30,
1993, June 22, 1994, May 12,
1995 and May 17, 1995
* There are omitted the Supplemental Indentures which do no more
than subject property to the lien of the above Indentures since
they are not considered constituent instruments defining the
rights of the holders of the securities. The Company agrees to
furnish the Commission on its request with copies of such
Supplemental Indentures.
10.1 Form of Change in Control
Contract With Certain
Executive Officers Under
Age 55
10.2 Form of Change in Control
Contract With Certain
Executive Officers Over
Age 55
12 Computation of ratio of earnings
to fixed charges
E-3 (cont'd.)
EXHIBIT INDEX
(Rule 601(a))
The Potomac Edison Company
Incorporation
Documents by Reference
21 Subsidiaries: The Potomac Edison
Company has a 28% equity ownership in
Allegheny Generating Company, incorporated
in Virginia and a 25% equity ownership in
Allegheny Pittsburgh Coal Company,
incorporated in Pennsylvania.
23 Consent of Independent See page 69 herein.
Accountants
24 Powers of Attorney See pages 70-71 herein.
27 Financial Data Schedule
E-4
EXHIBIT INDEX
(Rule 601(a))
West Penn Power Company
Incorporation
Documents by Reference
3.1 Charter of the Company, Form 10-Q of the Company
as amended (1-255-2), September 1995,
exh. (a)(3)(i)
3.2 By-laws of the Company, Form 10-Q of the Company
as amended (1-255-2), September 1995,
exh. (a)(3)(ii)
4 Indenture, dated as of S-3, 33-51303, exh. 4(d)
March 1, 1916, and certain S 2-1835, exh. B(1), B(6)
Supplemental Indentures of S 2-4099, exh. B(6), B(7)
the Company defining rights S 2-4322, exh. B(5)
of security holders.* S 2-5362, exh. B(2), B(5)
S 2-7422, exh. 7(c), 7(i)
S 2-7840, exh. 7(d), 7(k)
S 2-8782, exh. 7(e) (1)
S 2-9477, exh. 4(c), 4(d)
S 2-10802, exh. 4(b), 4(c)
S 2-13400, exh. 2(c), 2(d)
Form 10-Q of the Company
(1-255-2), June 1980, exh. D
Forms 8-K of the Company
(1-255-2) dated February
1991, December 1991, August
13, 1992, September 15, 1992,
June 9, 1993, August 2,
1994 and May 19, 1995
* There are omitted the Supplemental Indentures which do no more
than subject property to the lien of the above Indentures since
they are not considered constituent instruments defining the
rights of the holders of the securities. The Company agrees to
furnish the Commission on its request with copies of such
Supplemental Indentures.
10.1 Form of Employment Contract
with Certain Executive Officers
Under Age 55
E-4 (cont'd.)
EXHIBIT INDEX
(Rule 601(a))
West Penn Power Company
Incorporation
Documents by Reference
10.2 Form of Employment Contract
with Certain Executive Officers
Over Age 55
12 Computation of ratio of earnings
to fixed charges
21 Subsidiaries: West Penn Power Company
has a 45% equity ownership in Allegheny
Generating Company, incorporated in
Virginia; a 50% equity ownership in
Allegheny Pittsburgh Coal Company,
incorporated in Pennsylvania; and a 100%
equity ownership in West Virginia Power
and Transmission Company, incorporated
in West Virginia, which owns a 100%
equity ownership in West Penn West
Virginia Water Power Company,
incorporated in Pennsylvania.
23 Consent of Independent See page 69 herein.
Accountants
24 Powers of Attorney See pages 70-71 herein.
27 Financial Data Schedule
E-5
EXHIBIT INDEX
(Rule 601(a))
Allegheny Generating Company
Incorporation
Documents by Reference
3.1(a) Charter of the Company,
as amended*
3.1(b) Certificate of Amendment to
Charter, effective July 14, 1989**
3.2 By-laws of the Company, as amended, Form 10-K of the Company
effective December 23, 1996. (0-14688), December 31, 1996
4 Indenture, dated as of December 1,
1986, and Supplemental Indenture,
dated as of December 15, 1988, of the
Company defining rights of security
holders.***
10.1 APS Power Agreement-Bath County
Pumped Storage Project, as amended,
dated as of August 14, 1981, among
Monongahela Power Company, West
Penn Power Company, and The Potomac
Edison Company and Allegheny
Generating Company.****
10.2 Amendment No. 8, effective date
January 1, 1999, to the APS Power
Agreement - Bath County Pumped
Storage Project.
10.3 Operating Agreement, dated as of
June 17, 1981, among Virginia
Electric and Power Company, Allegheny
Generating Company, Monongahela Power
Company, West Penn Power Company and
The Potomac Edison Company.****
10.4 Equity Agreement, dated June 17,
1981, between and among Allegheny
Generating Company, Monongahela Power
Company, West Penn Power Company and
The Potomac Edison Company.****
E-5 (cont'd.)
EXHIBIT INDEX
(Rule 601(a))
Allegheny Generating Company
Incorporation
Documents by Reference
10.5 United States of America Before The
Federal Energy Regulatory Commission,
Allegheny Generating Company, Docket
No. ER84-504-000, Settlement Agreement
effective October 1, 1985.****
12 Computation of ratio of earnings
to fixed charges
23 Consent of Independent
Accountants See page 69 herein.
24 Powers of Attorney See page 72
herein.
27 Financial Data Schedule
__________
* Incorporated by reference to the designated exhibit to AGC's registration
statement on Form 10, File No. 0-14688.
** Incorporated by reference to Form 10-Q of the Company (0-14688)
for June 1989, exh. (a).
*** Incorporated by reference to Forms 8-K of the Company (0-14688)
for December 1986, exh. 4(A), and December 1988, exh. 4.1.
**** Incorporated by reference to Form 10-Q of the Company (0-14688)
for June 1989, exh. (a).