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 (Fee Required)
For the fiscal year ended December 31, 1995
Registrant; I.R.S. Employer
Commission State of Incorporation; Identification
File Number Address; and Telephone Number Number
1-267 ALLEGHENY POWER SYSTEM, INC. 13-5531602
(A Maryland Corporation)
12 East 49th Street
New York, New York 10017
Telephone (212) 752-2121
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 (412) 837-3000
0-14688 ALLEGHENY GENERATING COMPANY 13-3079675
(A Virginia Corporation)
12 East 49th Street
New York, New York 10017
Telephone (212) 752-2121
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]
<PAGE>
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Registrant Title of each class on which registered
Allegheny Power System, 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 Company Cumulative Preferred
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
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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
February 1, 1996 February 1, 1996
Allegheny Power System, Inc. $3,621,024,270 120,700,809
($1.25 par value)
Monongahela Power Company None. (a) 5,891,000
($50 par value)
The Potomac Edison Company None. (a) 22,385,000
(no par value)
West Penn Power Company None. (a) 24,361,586
(no par value)
Allegheny Generating Company None. (b) 1,000
($1.00 par value)
(a) All such common stock is held by Allegheny Power System, 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.
<PAGE>
CONTENTS
PART I: Page
ITEM 1. Business 1
Competition 3
Restructuring 5
Sales 7
Electric Facilities 12
Allegheny Power Map 16
Research and Development 18
Capital Requirements and Financing 19
Fuel Supply 23
Rate Matters 24
Environmental Matters 26
Air Standards 27
Water Standards 29
Hazardous and Solid Wastes 31
Emerging Environmental Issues 31
Regulation 32
ITEM 2. Properties 37
ITEM 3. Legal Proceedings 37
ITEM 4. Submission of Matters to a Vote of Security
Holders 43
Executive Officers of the Registrants 44
PART II:
ITEM 5. Market for the Registrants' Common Equity
and Related Stockholder Matters 46
ITEM 6. Selected Financial Data 47
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 48
ITEM 8. Financial Statements and Supplementary Data 49
ITEM 9. Changes in and Disagreements with Accountants on 56
Accounting and Financial Disclosure
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CONTENTS (Cont'd)
Page
PART III:
ITEM 10. Directors and Executive Officers of the
Registrants 56
ITEM 11. Executive Compensation 57
ITEM 12. Security Ownership of Certain Beneficial Owners
and Management 68
ITEM 13. Certain Relationships and Related Transactions 69
PART IV:
ITEM 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 69
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1
THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY POWER SYSTEM, 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 Power System, Inc. (APS), incorporated in Maryland in 1925,
is an electric utility holding company which owns directly and indirectly
various regulated subsidiaries (collectively, Allegheny Power), and a
nonutility subsidiary, AYP Capital, Inc. (AYP Capital). APS derives
substantially all of its income from the electric utility operations of its
direct and indirect subsidiaries, Monongahela Power Company (Monongahela), The
Potomac Edison Company (Potomac Edison), West Penn Power Company (West Penn),
and Allegheny Generating Company (AGC) (collectively, the Subsidiaries). The
properties of the 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 (Operating
Subsidiaries). APS has no employees. Its officers are employed by Allegheny
Power Service Corporation (APSC), a wholly owned subsidiary of APS. On
December 31, 1995, Allegheny Power had 5,905 employees.
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 347,600 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. On
December 31, 1995, Monongahela had 1,921 employees. Its 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 368,800
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. On December 31, 1995, Potomac Edison had 1,097
employees. Its 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.
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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. West Penn serves about 660,000
customers in a service area of about 9,900 square miles with a population of
about 1,399,000. The 10 largest communities served have populations ranging
from 11,200 to 38,900. On December 31, 1995, West Penn had 1,981 employees.
Its 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 two municipal electric distribution systems in its service area,
which purchase their power requirements from West Penn, and five rural
electric cooperative associations, located partly within the area, which
purchase virtually all of their power through a pool supplied by West Penn and
other nonaffiliated utilities.
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).
APSC, incorporated in Maryland in 1963, is a wholly owned subsidiary of
APS which provides various technical, engineering, accounting, administrative,
purchasing, computing, managerial, operational, and legal services to the
Subsidiaries and AYP Capital at cost. On December 31, 1995, APSC had 906
employees.
AYP Capital, incorporated in Delaware in 1994, is a wholly owned
nonutility subsidiary of APS. AYP Capital was formed in an effort to meet the
challenges of the new competitive environment in the industry. AYP Capital
has no employees. However, as of February 1, 1996, 10 APSC employees are
dedicated to AYP Capital activities on a full-time basis. Other APSC
employees provide services to AYP Capital as required. AYP Capital reimburses
APSC for the use of its employees. APS' total investment in AYP Capital was
$1.8 million as of December 31, 1995. APS is currently committed to invest up
to an additional $10 million in AYP Capital to fund AYP Capital's investment
in two limited partnerships. AYP Capital has agreed to purchase a 50%
interest (276 MW) in a generating unit for approximately $170 million. AYP
Capital has also formed a limited liability company (APS Cogenex) with EUA
Cogenex, a nonutility subsidiary of Eastern Utilities Associates. (See ITEM
1. COMPETITION, for a further description of AYP Capital's activities.)
Allegheny Power has in the past and may in the future experience some
of the more significant problems common to electric utilities in general.
These include increases in operating and other expenses, difficulties in
obtaining adequate and timely rate relief, restrictions on construction and
operation of facilities due to regulatory requirements and environmental and
health considerations, including the requirements of the Clean Air Act
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3
Amendments of 1990 (CAAA), which among other things, require a substantial
annual reduction in emissions of sulfur dioxides (SO[2]) and nitrogen oxides
(NO[x]).
Additional concerns include proposals to restructure and to deregulate
portions of the industry and to increase competition. (See ITEM 1.
COMPETITION.) Further concerns of the industry include possible restrictions
on carbon dioxide emissions, uncertainties in demand due to economic
conditions, energy conservation, market competition, weather, and
interruptions in fuel supply because of weather. (See ITEM 1. CAPITAL
REQUIREMENTS AND FINANCING, RATE MATTERS, and ENVIRONMENTAL MATTERS for
information concerning the effect on the Subsidiaries of the CAAA.)
COMPETITION
Competitive forces within the electric utility industry continued to
increase in 1995 due to a variety of influences including legislative and
regulatory proceedings. Difficult questions including stranded investment
recovery, responsibility for service and service reliability, the obligation
to serve, recovery of environmental and other social costs, tax implications,
and the effect of competition on all classes of customers are being debated.
Large industrial users of electricity remain the principal nongovernmental
advocates of increased competition, including retail wheeling. In response to
the competitive environment that has evolved following the passage of the
National Energy Policy Act of 1992 (EPACT), Allegheny Power has developed, and
is continuing to develop, a number of strategies to retain and continue to
serve its existing customers and to expand its customer base.
In 1995, Allegheny Power began to restructure its operations in an
effort to control costs by making more efficient use of resources and
streamlining processes. Although certain initiatives have been completed, the
process is continuing. (See ITEM 1. RESTRUCTURING for a description of the
Allegheny Power reorganization efforts.) In addition, Allegheny Power
established and staffed in 1995 a Major Accounts Program to enhance the
working relationship between Allegheny Power and its largest customers. In-
depth knowledge from the Major Accounts Program is already providing
opportunities for potential business ventures and is enhancing Allegheny
Power's reputation as an efficient, low cost provider of energy services.
Various states in the Allegheny Power service area have initiated
investigations concerning competition, but, except for Maryland, definitive
conclusions have not been reached. (See ITEM 1. REGULATION for a discussion of
the competitive investigations in Maryland, Ohio, Pennsylvania, and Virginia.)
To help meet the challenges of the new competitive environment and the
new opportunities presented in EPACT, AYP Capital was formed in 1994. Its
purpose is to pursue and develop new opportunities in unregulated markets to
strengthen the long-term competitiveness and profitability of APS. During
1995, AYP Capital funded several investments. They include EnviroTech
Investment Fund I, L.P. (EnviroTech), a limited partnership formed to invest
in emerging electrotechnologies that promote the efficient use of electricity
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4
and improve the environment. AYP Capital has committed to invest up to $5
million in EnviroTech. AYP Capital has also invested 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 has committed to invest up to $5 million in FONDELEC. 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.
AYP Capital offers engineering consulting services and project management for
transmission and distribution facilities. AYP Capital has also invested in
APS Cogenex, a limited liability company formed jointly with EUA Cogenex, a
nonutility subsidiary of Eastern Utilities Associates. APS Cogenex provides
energy services to improve the energy efficiency of consumer facilities in the
five states in which Allegheny Power provides electric service, plus the
District of Columbia. AYP Capital intends to provide financing to consumers
that undertake capital improvements necessary to achieve energy efficiency.
AYP Capital is moving into the wholesale unregulated power generation
market with its agreement to purchase Duquesne Light Company's (Duquesne) 50%
interest in Unit No. 1 of the Fort Martin Power Station for about $170
million. AYP Capital intends to utilize its share of the unit as an exempt
wholesale generator and sell the output at market price. Obtaining the
necessary regulatory approvals will likely take several months. AYP Capital
expects a closing in 1996. AYP Capital is also pursuing other opportunities.
In addition, management continues to explore methods of marketing and
pricing its core services - electric energy and the transmission thereof - in
new and competitive ways, such as bulk sales of each type of service to
nonaffiliates, incentive pricing to traditional utility customers, and
repackaging of services in nontraditional ways. It is also attempting to
reduce costs, particularly capital expenditures, to position Allegheny Power
in a more competitive mode.
Fully meeting challenges in the emerging competitive environment will
be difficult 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 Power is a member of the PURPA Reform Group, an ad hoc group
of utilities seeking repeal or reform of PURPA on the grounds that it is
obsolete, anticompetitive and it results in utility customers paying above-
market prices for power. This Group supports legislation which has been
introduced in both houses of Congress to repeal or reform PURPA. (See ITEM 3.
LEGAL PROCEEDINGS for information concerning PURPA-related litigation.)
Allegheny Power, along with the other registered electric public
utility holding companies under PUHCA, advocates repeal of PUHCA. PUHCA
prevents or significantly disadvantages regulated holding companies from
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5
diversifying into utility-related or nonutility businesses within or outside
their service territories, except under limited circumstances. Exempt
companies as well as other competitors, on the other hand, can diversify into
other types of businesses with generally no greater limitations than any other
domestic company. Legislation has been introduced in Congress to repeal PUHCA
and grant utility oversight responsibility to the Federal Energy Regulatory
Commission (FERC). The Securities and Exchange Commission (SEC) has also
recommended repeal of PUHCA. If the problems with PUHCA are not resolved
through legislation, restructuring of Allegheny Power to reduce or eliminate
the effect of PUHCA is an alternative.
RESTRUCTURING
In the late 1960's and early 1970's, Allegheny Power was one of the
first public utility holding company systems to establish a service company,
APSC, to increase efficiencies and savings through centralization. APSC was
organized into two groups - Bulk Power Supply (BPS) and Central Services.
That structure served Allegheny Power and its customers well and is one of the
reasons that its electric rates are among the lowest in the region.
The competitive environment emerging in the electric utility industry,
however, is requiring Allegheny Power to restructure many of its functions to
strengthen its competitive position and improve its cost structure.
The restructuring process is initiated by core teams consisting of
selected employees chosen to evaluate existing processes and recommend
changes. The core teams receive guidance from review groups, senior
management, and consultants. Recommendations are implemented following
acceptance by senior management and, in some cases, the Board of Directors.
BPS has been reengineered from its functional groups - Planning,
Engineering, Construction, and Operating - to Generation, Transmission, and
Planning and Compliance Business Units. Reengineering of the Transmission and
Planning and Compliance Business Units has been completed, and process
redesign and restructuring now under way in the power stations will complete
the reengineering of the Generation Business Unit.
The Business Unit concept adopted in BPS and planned for other parts of
Allegheny Power is designed to improve Allegheny Power's ability to compete
and to respond to customers. The Business Unit organization is structured to
make extensive use of teams including individuals from other Business Units or
from other areas of Allegheny Power.
The Generation Business Unit will be responsible for ensuring that
adequate generation is available to serve the native load customers of
Allegheny Power by employing Allegheny Power generating facilities and third-
party generation obtained through its marketing efforts. Its primary
responsibilities include ensuring the cost-effective operation and maintenance
of Allegheny Power's generating units and providing the most economic mix of
generation by available Allegheny Power generating units and off-system
purchases and sales.
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6
The Transmission Business Unit will be responsible for ensuring that
adequate high voltage network facilities are available and on line to convey
power produced from the power production operations run by, or procured by,
the Generation Business Unit to serve native load and to engage in wholesale
transmission sales to nonaffiliates. It will also engage in marketing efforts
for sales of bundled and unbundled transmission services to nonaffiliates and
will be responsible for accommodating requests for transmission service
submitted by nonaffiliates who qualify as customers for that service under
federal regulations. Finally, the Transmission Business Unit will be
responsible for maintaining the optimal economic balance on a real time basis
between native customer load and the output of the generation resources
supplied by the Generation Business Unit.
The Planning and Compliance Business Unit will provide strategic
resource planning and engineering analysis of alternate transmission and
generation resource options, environmental and regulatory issues management,
environmental compliance oversight, research and development, and emerging
technology development for Allegheny Power. Much of the work of this Business
Unit will be accomplished through multi-functional, cross-organizational teams
yielding a more balanced, multiple perspective solution to strategic problems.
Reorganization in the Operating Subsidiaries began early in 1995 and
has resulted in a single management team. There are now 18 operating
divisions compared with 23 at the beginning of 1995, and functions such as
engineering, construction, construction services, as well as marketing
functions have been consolidated. An effort is currently under way to
redesign all the processes in the Operating Subsidiaries.
In 1995, the Engineering and Construction Departments (E&C) of the
Operating Subsidiaries completed a partial reorganization in conjunction with
the restructuring of BPS. Some functions in E&C were transferred to the new
Business Units, while functions in BPS involving land management,
communications, standards, and nonnetwork planning were transferred to E&C.
The Construction Services Division of E&C consolidated its General Stores
function into two locations and developed a Material Transportation System to
serve all locations of the Operating Subsidiaries. Repair and testing of
electrical equipment were consolidated. The balance of E&C is undergoing
reengineering as part of the core team evaluation of the Operating
Subsidiaries.
Corporate Services, including Accounting, Finance, Information
Services, Human Resources, and Legal, as well as other support functions, are
being reengineered along with other functions in the internal supply chain for
materials and services. The Corporate Services and supply chain restructuring
will help to eliminate internal barriers to meeting external competition. As
part of the restructuring, Allegheny Power consolidated two data processing
centers, which resulted in the closing of one center.
As of January 1, 1996, APS and APSC began using the common name,
"Allegheny Power." The Operating Subsidiaries will also begin using the
"Allegheny Power" name by September 1996, to reflect Allegheny Power's unified
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7
mission and one-company concept. For legal purposes, APS and the Subsidiaries
will retain their formal names.
By late 1996, the corporate headquarters of Allegheny Power will move
from New York City to Washington County, Maryland. The move will situate
Allegheny Power's headquarters in the service territory of the Operating
Subsidiaries.
It is currently anticipated that all of the reengineering now under way
will be completed by the end of 1996, although Allegheny Power will continue
to identify ways to increase efficiencies.
Downsizing was not a specific goal of Allegheny Power's reorganization
and reengineering efforts, but as a consequence of process redesign and
elimination of duplicate positions, approximately 200 employees have been
placed in a staffing force thus far. Employees in the staffing force on
January 1, 1996 were offered a separation package. Employees who did not
elect to accept the separation package and who are not placed in a regular
employment position will be laid-off at the end of 12 months.
In addition, it is currently estimated that about 130 fewer employees
will be required in the power station work force by the end of 1997. Employee
reductions are also likely to result from reengineering in the Operating
Subsidiaries and support functions.
SALES
In 1995, consolidated kilowatt-hour (kWh) sales to the Operating
Subsidiaries' retail customers increased 3.9% from those of 1994 as a result
of increases of 3.0%, 4.7%, and 4.2% in residential, commercial, and
industrial sales, respectively. The increased kWh sales in 1995 reflect both
growth in number of customers and higher use. Consolidated revenues from
residential, commercial, and industrial sales increased 7.3%, 7.5%, and 5.8%,
respectively, primarily because of rate increases (See ITEM 1. RATE MATTERS)
and increased kWh sales.
Consolidated kWh sales to and revenues from nonaffiliates under
buy/resale agreements increased 36.3% and 16.1%, respectively, due primarily
to increased sales of power purchased from nonaffiliated utilities and power
brokers, and transmitted through our system to others. Consolidated sales
under the Standard Transmission Service Tariff increased from 0.5 billion kWh
to 1.5 billion kWh and revenues increased from $3.2 million to $5.6 million.
Allegheny Power's all-time peak load of 7,500 MW, which was higher than
that forecast, occurred on February 5, 1996. The peak load in 1995 and 1994
was 7,280 MW and 7,153 MW, respectively. The average System load (yearly net
power supply divided by number of hours in the year) was 4,969 MW and 4,776 MW
in 1995 and 1994, respectively. More information concerning sales may be
found in the statistical sections. (See also ITEM 7. MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.)
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Consolidated electric operating revenues for 1995 were derived as
follows: Pennsylvania, 44.6%; West Virginia, 28.3%; Maryland, 20.6%; Virginia,
5.0%; Ohio, 1.5% (residential, 35.0%; commercial, 18.7%; industrial, 29.1%;
nonaffiliated utilities, 14.5%; and other, 2.7%). The following percentages
of such revenues were derived from these industries: iron and steel, 6.2%;
fabricated products, 3.4%; chemicals, 3.3%; aluminum and other nonferrous
metals, 3.1%; coal mines, 3.0%; cement, 1.7%; and all other industries, 8.4%.
Revenues from each of 19 industrial customers exceeded $5 million, including
one coal customer of both Monongahela and West Penn providing total revenues
exceeding $23 million, three steel customers providing revenues exceeding $31
million each, and one aluminum customer providing revenues exceeding $67
million.
During 1995, Monongahela's kWh sales to retail customers increased 4.5%
as a result of increases of 5.0%, 6.5%, and 3.5% in residential, commercial,
and industrial sales, respectively. Revenues from residential, commercial and
industrial customers increased 9.5%, 7.1%, and 5.1%, respectively, and
revenues from kWh sales to affiliated and nonaffiliated utilities increased
3.9%. Monongahela's all-time peak load of 1,825 MW occurred on August 17,
1995.
Monongahela's electric operating revenues were derived as follows: West
Virginia, 94.6% and Ohio, 5.4% (residential, 28.9%; commercial, 17.2%;
industrial, 29.4%; nonaffiliated utilities, 12.6%; and other, 11.9%).
Revenues from each of five industrial customers exceeded $11 million,
including one steel customer providing revenues exceeding $31 million and one
coal customer providing revenues exceeding $20 million.
During 1995, Potomac Edison's kWh sales to retail customers increased
3.3% as a result of increases of 3.9%, 3.6%, and 2.7% in residential,
commercial, and industrial sales, respectively. Revenues from such customers
increased 7.0%, 6.7%, and 3.0%, respectively, and revenues from kWh sales to
affiliated and nonaffiliated utilities increased 17.1%. Potomac Edison's all-
time peak load of 2,595 MW occurred on January 19, 1994.
Potomac Edison's electric operating revenues were derived as follows:
Maryland, 66.9%; West Virginia 16.9% and Virginia, 16.2%; (residential, 38.7%;
commercial, 17.7%; industrial, 24.5%; nonaffiliated utilities, 15.4%; and
other, 3.7%). Revenues from one industrial customer, the Eastalco aluminum
reduction plant near Frederick, Maryland, amounted to $67.4 million (8.2% 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 $20.3 million in 1995. This agreement may be cancelled before the year
2000 upon 90 days notice of a governmental decision resulting in a material
modification of the agreement.
During 1995, West Penn's kWh sales to retail customers increased 4.0%
as a result of increases of 1.4%, 4.4% and 5.8% in residential, commercial,
and industrial sales, respectively. Revenues from residential, commercial,
and industrial customers increased 6.5%, 8.2%, and 7.9%, respectively, and
revenues from kWh sales to affiliated and nonaffiliated utilities increased
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17.6%. West Penn's all-time peak load of 3,242 MW occurred on February 5,
1996.
West Penn's electric operating revenues were derived as follows:
Pennsylvania, 100% (residential, 32.7%; commercial, 18.3%; industrial, 29.1%;
nonaffiliated utilities, 13.7%; and other, 6.2%). Revenues from each of four
industrial customers exceeded $11 million, including two steel customers
providing revenues exceeding $36 million each.
On average, the Operating Subsidiaries are the lowest or among the
lowest cost suppliers of electricity in their respective states with fixed
costs being very low and incremental costs being about average. Therefore,
the Operating Subsidiaries' delivered power prices should compete favorably
with those of potential alternate suppliers who use cost-based pricing.
However, the Operating Subsidiaries face increased competition from utilities
with excess generation that may be willing to sell at prices only slightly in
excess of variable costs. At the same time, the Operating Subsidiaries are
experiencing higher costs due to compliance with the CAAA and purchases from
PURPA projects. (See page 12 for a discussion of PURPA projects, and ITEM 3.
LEGAL PROCEEDINGS for a description of litigation and regulatory proceedings
concerning PURPA capacity.)
In 1995, the Operating Subsidiaries provided approximately 15.4 billion
kWh of energy to nonaffiliated companies, of which 0.78 billion kWh were
generated by the Subsidiaries and the rest were transmitted from electric
systems located primarily to the west. These sales included a long-term
transaction under which the Operating Subsidiaries purchased 450 MW of firm
capacity and its associated energy from Ohio Edison Company for resale to
Potomac Electric Power Company, both nonaffiliates. The transaction began in
mid-1987 and will continue through 2005, unless terminated earlier.
Sales to nonaffiliated companies vary with the needs of those companies
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. Although
increases occurred in both sales of power purchased from and transmission
services with nonaffiliates in 1995, sales of power generated by Allegheny
Power decreased relative to 1994 primarily because of stagnant demand,
increased Operating Subsidiaries' native load, and increased number of and
willingness of other suppliers to make sales at lower prices. Further
decreases in sales by Allegheny Power of power generated from rate-based
assets to nonaffiliates are expected in 1996 and beyond. For 1995,
substantially all of the benefits of power and transmission service sales to
nonaffiliates were passed on to retail customers and as a result have little
effect on net income.
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 during each December, January, and
February, at least through February 1998. Thereafter, specific amounts of
annual diversity exchanges beyond those currently established are to be
<PAGE>
10
mutually determined no less than 34 months prior to each year for which an
exchange is to take place. Negotiations are currently under way to reach an
agreement on an amount of diversity exchange beyond February 1998. The total
number of megawatt-hours (MWh) to be delivered by each utility to the other
over the term of the arrangement is expected to be the same.
Pursuant to an exchange arrangement with Duquesne which will continue
through February 1999 and may be extended beyond that date, the Operating
Subsidiaries supply 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 supplies the Operating Subsidiaries with up to
100 MW, generally during each December, January, and February. The total
number of MWh to be delivered by each utility to the other over the term of
the arrangement is expected to be the same.
West Penn supplies power to the Borough of Tarentum (Tarentum) using in
part distribution facilities leased from Tarentum under a 30-year lease
agreement terminating in 1996. In June 1993, Tarentum, which in that year
provided a load of 6.5 MW and revenues of $1.8 million, notified West Penn of
its intention to exercise its option to end the lease agreement and re-enter
the retail electric business. The termination of the lease agreement and
resulting transfer and sale by West Penn of electric facilities installed by
West Penn will result in Tarentum becoming a municipal customer which will
purchase electricity on a wholesale basis from West Penn or another supplier.
Tarentum has agreed to purchase wholesale electricity from West Penn until at
least March 16, 1999. West Penn's sale of electric facilities and
discontinuance of its electric service to customers in Tarentum will require
Pennsylvania Public Utility Commission (Pennsylvania PUC) approval.
EPACT permits wholesale generators, utility-owned and otherwise, and
wholesale consumers to request from owners of bulk power transmission
facilities a commitment to supply transmission services. In 1995, the FERC
continued to develop new policies and procedures to implement EPACT and
requested comments on the following: a Notice of Proposed Rulemaking on open
access nondiscriminatory transmission services (Mega-NOPR), a Supplemental
Notice of Proposed Rulemaking on recovery of stranded costs, a Request for
Comments and subsequent Notice of Proposed Rulemaking on Real-Time Information
Networks and Standards of Conduct, and an Inquiry concerning alternative power
pooling arrangements. Of particular significance to public utilities, on
March 29, 1995, the FERC issued the Mega-NOPR with the stated intent of
stimulating wholesale (sale for resale) competition among electric utilities
and nonregulated electricity generators. The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power without undue discrimination,
as long as sufficient transmission capacity is available to provide service
without impairing reliability. To meet the objective of providing
nondiscriminatory or comparable wholesale transmission services, the Mega-
NOPR, if adopted as proposed, requires that utilities functionally unbundle.
Accordingly, the proposed rule if adopted will require separation of public
utility systems' operations and marketing functions and will require that
wholesale transmission services purchased by the transmission owner must be
taken under its filed open access tariffs. In addition, the Mega-NOPR
<PAGE>
11
proposes pro forma open access tariffs containing the terms and conditions for
these transmission services. The Mega-NOPR also states that electric
utilities would be able to collect stranded costs (costs of facilities made
uneconomic by wholesale transmission access) and that it is up to the states
to decide if retail wheeling should be adopted and, if so, to address retail
stranded costs. FERC has received public input to the Mega-NOPR and is
currently reviewing that information before issuing a final rule. (See ITEM
1. REGULATION for a further discussion of the Mega-NOPR.)
In response to both the Mega-NOPR and the continuing evolution of the
wholesale power and transmission service markets, Allegheny Power implemented
reorganization of its existing wholesale marketing function into separate
transmission and generation marketing functions. (See ITEM 1. RESTRUCTURING
for further discussion of the restructuring of Bulk Power Supply.) Through
rulings issued in various cases, the FERC has expanded the definition of
nondiscriminatory service to require a utility to provide transmission service
comparable to the service it provides itself. (See ITEM 3. LEGAL PROCEEDINGS
for a discussion of the FERC proceeding wherein Duquesne has requested firm
transmission service over Allegheny Power's transmission facilities.)
Through 1995, the Operating Subsidiaries provided wholesale
transmission services under their FERC-approved Standard Transmission Service
Tariff. The tariff stipulated that such service was subordinate in priority
to native load and reliability requirements of interconnected systems to avoid
adverse effects on regional and Operating Subsidiaries' reliability.
Transmission services requiring special arrangements or long-term commitments
were provided through specially negotiated, mutually acceptable bilateral
agreements that were consistent with and accommodated the Standard
Transmission Service Tariff. Effective in 1996 and consistent with the
intentions of the FERC under the Mega-NOPR, Allegheny Power submitted a filing
to FERC of a set of two new transmission service tariffs which qualify as open
access filings pursuant to the Mega-NOPR. As of December 6, 1995, the FERC
accepted for filing a Network Transmission Service Tariff and a Point-to-Point
Transmission Service Tariff under which the Operating Subsidiaries will sell
comparable open access transmission services to eligible wholesale customers.
Customers may choose from a range of services that extend from broad use of
the transmission network on a firm basis for the life of a customer facility
to a fully interruptible energy only service that is available for a one-hour
term. The tariffs were accepted subject to modification pending the outcome
of the Final Rule in the Mega-NOPR proceeding. The FERC acceptance for filing
set the tariffs for hearing during the summer of 1996; in the interim, the
Operating Subsidiaries may sell transmission services under the tariffs,
subject to refund. With this filing, the need for and applicability of the
Standard Transmission Service Tariff was eliminated for new service
transactions. Substantially all of the revenues from transmission service
sales now arise from transactions with customers located outside the service
territory of the Operating Subsidiaries and are passed through to retail
customers. As a result, they presently have little effect on net income. In
addition, the Operating Subsidiaries have a Standard Generation Service Rate
Schedule tariff on file with and accepted by the FERC under which the
Operating Subsidiaries make available bundled, nonfirm generation services
with associated System transmission services to any customer who executes an
<PAGE>
12
agreement under such tariff. Revenues from this tariff are also passed
through to retail customers.
In conjunction with the Mega-NOPR, on December 16, 1995, the FERC
issued a notice of proposed rulemaking on Real-Time Information Networks and
Standards of Conduct to ensure the separation of service directed by the
functional unbundling of wholesale services required by the Mega-NOPR and to
assure that all buyers and sellers of transmission services will have equal
and timely access to the information needed to transact business. Allegheny
Power commented on this proposed rulemaking.
Under PURPA, certain municipalities and private developers have
installed, are installing or are proposing to install hydroelectric and other
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. Allegheny Power's
total generating capacity includes 299 MW of on-line PURPA capacity. Payments
for PURPA capacity and energy in 1995 totaled approximately $129 million at an
average cost to Allegheny Power of 5.5 cents/kWh, as compared to Allegheny
Power's own generating cost of about 3 cents/kWh. Allegheny Power projects an
additional 180 MW (Warrior Run) of PURPA capacity to come on-line in 1999. It
is expected that the Warrior Run project will result in increased costs for
Potomac Edison's customers. Eighty MW (Burgettstown) of PURPA capacity has
been removed from Allegheny Power's projections due to a PURPA project that
expired when the project failed to meet its financing closing deadline. (See
ITEM 3. LEGAL PROCEEDINGS for a description of the Washington Power lawsuit
filed by the Burgettstown developer against West Penn and APS concerning this
project.) Lapsed purchase agreements totaling 203 MW (Burgettstown,
Shannopin, and Milesburg) and other PURPA related complaints totaling 470 MW
(MidAtlantic and South River) are the subject of ongoing litigation and are
not included in Allegheny Power's current planning strategy. (See ITEM 3.
LEGAL PROCEEDINGS concerning an agreement to resovle the Shannopin lawsuit and
for a description of litigation and regulatory proceedings in Pennsylvania and
West Virginia.)
ELECTRIC FACILITIES
The following table shows Allegheny Power's December 31, 1995, generating
capacity, based on the maximum monthly normal seasonal operating capacity of
each unit. Allegheny Power's capacity totaled 8,070 MW, of which 7,090 MW (88%)
are coal-fired, 840 MW (10%) are pumped-storage, 82 MW (1%) are oil-fired, and
58 MW (1%) are hydroelectric. 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 Allegheny Power's steam stations shown on the
following page, based on generating capacity at December 31, 1995, was about
<PAGE>
13
25.6 years. In 1995, their average heat rate was 9,970 Btu's/kWh, and their
availability factor was 82.3%.
<PAGE>
<TABLE>
<CAPTION>
14
Allegheny Power Stations
Maximum Generating Capacity
(Megawatts) (a)
Dates When
Station Monon- Potomac West Service
Station Units Total gahela Edison Penn Commenced (b)
Coal-fired (steam):
<S> <C> <C> <C> <C> <C> <C>
Albright 3 292 216 76 1952-4
Armstrong 2 352 352 1958-9
Fort Martin 2 831 249 304 278 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 2 114 114 1947-58
Willow Island 2 243 243 1949-60
Oil-Fired (steam):(a)
Mitchell 1 82 82 1948
Pumped-Storage
and Hydro:
Bath County 6 840 227(c) 235(c) 378(c) 1985
Lake Lynn(d) 4 52 52 1926
Potomac
Edison(d) 21 6 6 Various
Total Allegheny Power
Capacity 54 8,070 2,326 2,072 3,672
</TABLE>
<TABLE>
<CAPTION>
Nonutility Generation
Maximum Generating Capacity
(Megawatts)(e)
Contract
Project Monon- Potomac West Commencement
Project Total gahela Edison Penn Date
Coal-fired:
<S> <C> <C> <C> <C> <C>
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
Nonutility Capacity 299 161 0(f) 138
Total Maximum Allegheny Power
Generating Capacity (a) 8,369 2,487 2,072 3,810
</TABLE>
<PAGE>
15
(a) Excludes 207 MW of West Penn oil-fired capacity at Springdale Power
Station and 77 MW of the total MW at Mitchell Power Station, which were
placed on cold reserve status as of June 1, 1983. Current plans call for
the reactivation of these units in about five years. On December 31,
1994, 82 MW of the total MW at Mitchell Power Station were reactivated.
(b) 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.
(c) Capacity entitlement through ownership of AGC, 27%, 28% and 45% by
Monongahela, Potomac Edison and West Penn, respectively.
(d) The FERC issued a new license with a 30-year term for Lake Lynn on
December 27, 1994. Certain terms of said license are being appealed
but do not affect its validity. Potomac Edison's license for
hydroelectric facilities Dam #4 and Dam #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.
(e) Nonutility generating capacity available through state utility commission
approved arrangements pursuant to PURPA.
(f) The Warrior Run project of 180 MW has completed its financial closing,
is under construction, and is planned to begin providing capacity and
energy to Potomac Edison in 1999.
<PAGE>
16
ALLEGHENY POWER 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 Pennsylvania,
Ohio, West Virginia, Maryland and 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 capcity from 138kV to 765kV.
Additionally, interconnections with other utilities are displayed.
<PAGE>
17
The following table sets forth the existing miles of tower and pole
transmission and distribution lines and the number of substations of the
Subsidiaries as of December 31, 1995:
<TABLE>
<CAPTION>
Above Ground Transmission and
Distribution Lines (a) and Substations
Portion of Total Transmission and
Representing Distribution
Total 500-Kilovolt (kV) Lines Substations(b)
<S> <C> <C> <C>
Monongahela 19,912 281 229
Potomac Edison 17,413 202 205
West Penn 21,940 273 532
AGC(c) 85 85 1
Total 59,350 841 967
</TABLE>
(a) Allegheny Power has a total of 5,831 miles of underground
distribution lines.
(b) The substations have an aggregate transformer capacity of
39,207,919 kilovoltamperes.
(c) Total Bath County transmission lines, of which AGC owns
an undivided 40% interest and Virginia Power owns the
remainder.
Allegheny Power has 11 extra-high-voltage (345 kV and above) (EHV) and 29
lower-voltage interconnections with neighboring utility systems. The
interregional EHV transmission system, including System facilities,
historically has operated near reliability limits because of frequent periods
of heavy power flows, predominantly in a west-to-east direction. In 1994 and
early 1995, use of the transmission system in aggregate declined and the west-
to-east power flows decreased to more comfortable levels. However, in the
later months of 1995, west-to-east transfers began to increase, although not
to the critical levels commonly seen earlier in the decade. If transfers and
customer load continue to increase, along with coincident parallel flows,
interregional EHV transmission facilities, including Allegheny Power
facilities, will again operate nearer to reliability limits, at which time
restrictions on transfers may become necessary.
Under certain provisions of EPACT, wholesale generators and wholesale
customers may seek from owners of bulk power transmission facilities a
commitment to supply transmission services. (See discussion under ITEM 1.
SALES and REGULATION.) Such demand on Allegheny Power's transmission
facilities may add to heavy power flows on Allegheny Power's facilities.
The Operating Subsidiaries have, to date, provided managed contractual
access to Allegheny Power's transmission facilities via the provisions of
their Standard Transmission Service Tariff, or the terms and conditions of
bilateral contracts. As described earlier, for new agreements starting in
1996, managed access will also be governed by the provisions of the Allegheny
Power open access tariffs recently accepted provisionally by FERC.
<PAGE>
18
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $9.0 million, $7.7 million, and $4.6
million in 1995, 1994, and 1993, respectively, for research programs. Of
these amounts, $6.2 million, $5.9 million, and $3.2 million were for Electric
Power Research Institute (EPRI) dues in 1995, 1994, and 1993, respectively.
EPRI is an industry-sponsored research and development institution. The
Operating Subsidiaries plan to spend approximately $8.5 million for research
in 1996, with EPRI dues representing $5.5 million of that total.
Independent research conducted by the Operating Subsidiaries concentrated
on environmental protection (CAAA and permit mandates), generating unit
performance, future generating technologies, delivery systems, and customer-
related research. Clean power technology focused on power quality and load
management devices and techniques for customer and delivery equipment.
Research is also being directed to help address major issues facing
Allegheny Power including electric and magnetic field (EMF) assessment of
employee exposure within the work environment, waste disposal and discharges,
greenhouse gases, client-server information system prospects, Internet,
renewable resources, fuel cells, new combustion turbines and cogeneration
technologies. In addition, there is continuing evaluation of technical
proposals from outside sources and monitoring of developments in industry-
related literature, law, litigation, and standards.
As Allegheny Power continues in its effort to comply with the NOx control
requirements of the CAAA, it has entered into a 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 in the Ozone Transport Region (See
page 28). With reference to alleged global climate change, a Participation
Accord was entered into on behalf of the Operating Subsidiaries with the
Department of Energy (DOE) to participate in the DOE's Climate Challenge
Program.
Electric vehicle (EV) research included participation in the Ford Ecostar
Demonstration Program, EV America and the Electric Transportation Coalition,
as well as the development of appropriate wiring and building code standards
to accommodate electric vehicles.
Research is being directed into communication systems to develop and
demonstrate a high speed advanced power line communication system utilizing
existing utility wires to service information needs of the Operating
Subsidiaries' customers.
Allegheny Power, in cooperation with the Pennsylvania Department of
Environmental Protection and the West Virginia Division of Environmental
Protection, continued to investigate the feasibility and cost-effectiveness of
injecting fly ash from Allegheny Power's power stations into abandoned
underground mine sites in Pennsylvania and West Virginia to reduce acid mine
<PAGE>
19
drainage and mine surface subsidence. The project cost is anticipated to be
shared with EPRI as part of a Tailored Collaboration Agreement with EPRI.
An additional collaborative effort in which Allegheny Power participated
through West Penn in 1995 was the Pennsylvania Electric Energy Research
Council (PEERC). PEERC was formed in 1987 as a partnership of Pennsylvania
based electric utilities to promote technological advancements related to the
electric utility industry.
The Operating Subsidiaries also made research grants to regional colleges
and universities to encourage the development of technical resources related
to current and future utility problems.
CAPITAL REQUIREMENTS AND FINANCING
Construction expenditures by the Subsidiaries in 1995 amounted to
$318.9 million and for 1996 and 1997 are expected to aggregate $278.6 million
and $305.2 million, respectively. In 1995, these expenditures included $36.4
million for compliance with the CAAA. The 1996 and 1997 estimated
expenditures include $6.7 million and $19.7 million, respectively, to cover
the costs of compliance with the CAAA. Expenditures to cover the costs of
compliance with the CAAA were much more significant in prior years and may be
again in future years if required for Phase II compliance.
<PAGE>
<TABLE>
<CAPTION>
20
Construction Expenditures
1995 1996 1997
Millions of Dollars
(Actual) (Estimated)
Monongahela
<S> <C> <C> <C>
Generation Business Unit $ 22.1 $ 29.6 $ 37.7
Transmission Business Unit 19.3 3.4 4.6
Distribution Unit 34.1 32.5 32.5
Total* $ 75.5 $ 65.5 $ 74.8
Potomac Edison
Generation Business Unit $ 26.0 $ 26.1 $ 24.8
Transmission Business Unit 19.2 16.0 32.7
Distribution Unit 47.0 45.4 45.6
Total* $ 92.2 $ 87.5 $ 103.1
West Penn
Generation Business Unit $ 83.6 $ 51.9 $ 65.6
Transmission Business Unit 14.6 22.5 11.3
Distribution Unit 48.6 48.1 47.8
Other 2.3 2.6 1.6
Total* $ 149.1 $ 125.1 $ 126.3
AGC
Generation Business Unit $ 2.1 $ .5 $ 1.0
Total Construction Expenditures $ 318.9 $ 278.6 $ 305.2
</TABLE>
* Includes allowance for funds used during construction (AFUDC) for 1995,
1996 and 1997 of: Monongahela $1.4, $1.0 and $2.0; Potomac Edison $1.8,
$1.9 and $2.5; and West Penn $5.0, $3.0 and $2.9.
These construction expenditures include major capital projects at
existing generating stations, upgrading distribution lines and substations,
and the strengthening of the transmission and subtransmission systems. The
Harrison scrubber project was completed on schedule and the scrubbers were
declared available for service on November 16, 1994. The final cost is
expected to be $555 million, which is approximately 24% below the original
budget. Primary factors that contributed to the reduced cost were: a)
favorable rulings of state commissions allowing the inclusion of carrying
costs of construction in rates in lieu of AFUDC; b) the absence of any major
construction problems; and c) financing, material and equipment costs lower
than expected.
On a collective basis for the Operating Subsidiaries, total
expenditures for 1995, 1996, and 1997 include $76 million, $48 million, and
$71 million, respectively, for construction of environmental control
technology. Outages for construction, CAAA compliance work and other
<PAGE>
21
environmental work is, and will continue to be coordinated with planned
outages.
Allegheny Power continues to study ways to reduce or meet future
increases in customer demand, including aggressive 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 Power generating facilities, reducing internal
electrical use and transmission and distribution losses, and, where feasible
and economical, acquisition of reliable, long-term capacity from other
electric systems and from nonutility developers.
The Operating Subsidiaries are implementing demand-side management
activities. Potomac Edison and West Penn are engaged in state commission
supported or ordered evaluations of demand-side management programs. (See ITEM
1. REGULATION for a further discussion of these programs.)
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 of 1.56% and 1.57%,
respectively, in the period 1996-2006. After considering the reactivation of
West Penn capacity in cold reserve (see page 15), peak diversity exchange
arrangements described in ITEM 1. SALES above, demand-side management and
conservation programs, and contracted PURPA capacity, it is anticipated that
new Allegheny Power generating capacity will not be required until the year
2000 or beyond. If future customer demand materially exceeds that forecast,
anticipated supply-side resources do not become available, demand-side
management efforts do not succeed, or in the event of extremely adverse
weather conditions, the Operating Subsidiaries may be unable at times to meet
all of their customers' requirements for electric service.
In connection with their construction and demand-side management
programs, the Operating Subsidiaries must make estimates of the availability
and cost of capital as well as the future demands of their 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. As a result, future plans of the Operating
Subsidiaries are subject to continuing review and substantial change.
The Subsidiaries have financed their construction programs through
internally generated funds, first mortgage bond, debenture, medium-term note,
subordinated debt, and preferred stock issues, pollution control and solid
waste disposal notes, installment loans, long-term lease arrangements, equity
investments by APS (or, in the case of AGC, by the Operating Subsidiaries),
and, where necessary, interim short-term debt. The future ability of the
Subsidiaries to finance their construction programs by these means depends on
many factors, including creditworthiness, rate levels sufficient to provide
internally generated funds and adequate revenues to produce a satisfactory
return on the common equity portion of the Subsidiaries' capital structures
<PAGE>
22
and to support their issuance of senior and other securities. The
creditworthiness of the Operating Subsidiaries in the future may be affected
by increased concern of rating agencies that purchased power contracts are a
risk factor deserving consideration. APS obtains most of the funds for equity
investments in the Operating Subsidiaries through the issuance and sale of its
common stock publicly and through its Dividend Reinvestment and Stock Purchase
Plan and its Employee Stock Ownership and Savings Plan.
AYP Capital has agreed to purchase Duquesne's 50% ownership interest
(276 MW) in Fort Martin Unit No. 1 for approximately $170 million. Various
financing alternatives for this acquisition are being considered.
In 1995, the Operating Subsidiaries refunded an aggregate of $493.4
million of securities. The securities issued for the refunding had interest
rates ranging from 6.05% to 8.00%. Preferred stock issues totaling $155.5
million were refunded with Quarterly Income Debt Securities (QUIDS). QUIDS
are subordinated debt instruments which permit deferral of interest payments
under certain circumstances for up to 20 consecutive quarters.
In May 1995, the Operating Subsidiaries issued $245 million of first
mortgage bonds having interest rates between 7-5/8% and 7-3/4% to refund like
securities having interest rates from 8-7/8% to 9-5/8%. Monongahela sold $70
million of 7-5/8% 30-year first mortgage bonds to refund a $70 million 8-7/8%
issue due in 2019. Potomac Edison sold $65 million of 7-3/4% 30-year first
mortgage bonds to refund a $65 million 9-1/4% issue due in 2019 and $80
million of 7-5/8% 30-year first mortgage bonds to refund an $80 million 9-5/8%
issue due in 2020. West Penn sold $30 million of 7-3/4% 30-year first
mortgage bonds to refund a $30 million 9% issue due in 2019.
In June 1995, the Operating Subsidiaries issued $92.9 million of tax-
exempt bonds having interest rates from 6.05% to 6.15% to refund like
securities having interest rates from 6.95% to 9-3/8%. Monongahela sold $25
million of 6.15% 20-year tax-exempt bonds to refund a $25 million 7-3/4%
issue. Potomac Edison sold $21 million of 6.15% 20-year tax-exempt bonds to
refund a $21 million 7.3% issue. West Penn sold $31.5 million of 6.15% 20-
year tax-exempt bonds to refund a $20 million 7% issue and an $11.5 million
6.95% issue. West Penn also sold $15.4 million of 6.05% 19-year tax-exempt
bonds to refund a $15.4 million 9-3/8% issue.
In June 1995, the Operating Subsidiaries issued QUIDS to refund an
aggregate of $155.5 million of preferred stock. Monongahela sold $40 million
of 8% 30-year QUIDS to refund $40 million of preferred stock with rates
between 7.36% and 8.8%. Potomac Edison sold $45.5 million of 8% 30-year QUIDS
to refund $45.5 million of preferred stock with rates between 7% and 8.32%.
West Penn sold $70 million of 8% 30-year QUIDS to refund $70 million of
preferred stock with rates between 7% and 8.2%.
In 1995, APS sold 1,407,855 shares of its common stock for $34.6
million through its Dividend Reinvestment and Stock Purchase Plan and its
Employee Stock Ownership and Savings Plan.
<PAGE>
23
During 1995, 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 4.75%, 4.71%, 4.249% and 4.292%. The rate set at auction on January 12,
1996, was 4.185%.
At December 31, 1995, short-term debt was outstanding in the following
amounts: APS $78.7 million, Monongahela $29.9 million, Potomac Edison $21.6
million, and West Penn $70.2 million, respectively. At December 31, 1995, AGC
had $30.6 million of commercial paper outstanding.
The Subsidiaries' ratios of earnings to fixed charges for the year
ended December 31, 1995, were as follows: Monongahela, 3.68; Potomac Edison,
3.27; West Penn, 3.58; and AGC, 3.22.
Allegheny Power's consolidated capitalization ratios as of December
31, 1995, were: common equity, 46.6%; preferred stock, 3.7%; and long-term
debt, 49.7%, including QUIDS (3.3%). Allegheny Power's long-term objective is
to maintain the common equity portion above 45%.
During 1996, the Operating Subsidiaries currently anticipate meeting
their capital requirements through a combination of internally generated
funds, cash on hand, and short-term borrowing as necessary. APS plans to
continue selling common stock through its Dividend Reinvestment and Stock
Purchase Plan and Employee Stock Ownership and Savings Plan.
FUEL SUPPLY
Allegheny Power-operated stations burned approximately 15.9 million
tons of coal in 1995. Of that amount, 88% was either cleaned (5.2 million
tons) or used in stations equipped with scrubbers (8.8 million tons). The use
of desulfurization equipment and the cleaning and blending of coal make
burning local higher-sulfur coal practical. In 1995 about 97% of the coal
received at Allegheny Power-operated stations came from mines in West
Virginia, Pennsylvania, Maryland, and Ohio. The Operating Subsidiaries do 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, subject to price change, are in effect and
will provide for approximately 11 million tons of coal in 1996. The Operating
Subsidiaries will depend on short-term arrangements and spot purchases for
their remaining requirements. Through the year 1999, the total coal
requirements of present Allegheny Power-operated stations are expected to be
met with coal acquired under existing contracts or from known suppliers.
For each of the years 1991 through 1994, the average cost per ton of
coal burned was $36.74, $36.31, $36.19 and $35.88, respectively. For the year
1995, the cost per ton decreased to $32.68.
Long-term arrangements, subject to price change, are in effect and
will provide for the lime requirements of scrubbers at Allegheny Power's
scrubbed stations.
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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 fly ash and bottom ash
for beneficial uses and thereby reduce landfill requirements. (See also ITEM
1. RESEARCH AND DEVELOPMENT.) In 1995, the Operating Subsidiaries received
approximately $459,000 for the sale of 206,609 tons of fly ash and 31,014 tons
of bottom ash for various uses including cement replacement, mine grouting,
oil well grouting, soil extenders and anti-skid material.
The Operating Subsidiaries own coal reserves estimated to contain
about 125 million tons of high-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
Rate case decisions were issued for Monongahela, Potomac Edison and
AGC in 1995.
Monongahela Power
As previously reported, on January 18, 1994, Monongahela filed an
application with the Public Service Commission of West Virginia (West Virginia
PSC) for a base rate increase designed to produce $61.3 million in additional
annual revenues which included recovery of the remaining carrying charges on
investment, depreciation, and all operating costs required to comply with
Phase I of the CAAA, and other increasing levels of expense. On November 9,
1994 the West Virginia PSC affirmed the recommended decision of the
Administrative Law Judge (ALJ) which provided for a rate increase of $23.5
million and a 10.85% return on equity (ROE) effective November 16, 1994. This
amount was in addition to $6.9 million of CAAA recovery granted effective July
1, 1994, in the Expanded Net Energy Cost (ENEC) recovery proceeding which had
been included in Monongahela's $61.3 million request. The West Virginia PSC
invited all parties to file petitions for reconsideration which resulted in a
second order issued on March 17, 1995. The March 17, 1995 order deferred some
of CAAA issues to the 1995 ENEC proceeding. The net result of both the March
17, 1995 base rate order and the ENEC order decreased the previously allowed
increase to base rates adopted in the November 9, 1994 order by $1.1 million
to $22.4 million and maintained the ROE of 10.85%. The ENEC order permits
Monongahela to apply for review of its post-1994 scrubber operation and
maintenance expense levels and CAAA investment during the 1996 ENEC
proceeding. Monongahela filed a Petition for Appeal with the West Virginia
Supreme Court of Appeals challenging the March 17 order. The court declined
to hear the appeal.
On January 31, 1995, Monongahela filed an application with The Public
Utilities Commission of Ohio (Ohio PUC) for a base rate increase designed to
produce $7.0 million in additional annual revenues which included recovery of
carrying charges on investment, depreciation, and all operating costs required
to comply with Phase I of the CAAA, and other increasing levels of expense.
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25
On October 20, 1995, a stipulation was submitted by all of the parties to the
Ohio PUC. The Ohio PUC approved the stipulation on November 9, 1995 providing
for an annual revenue increase of $6.0 million effective November 9, 1995.
Potomac Edison
On January 14, 1994, Potomac Edison filed an application with the West
Virginia PSC for a base rate increase of $12.2 million which included recovery
of the remaining carrying charges on investment, depreciation, and all
operating costs required to comply with Phase I of the CAAA, and other
increasing levels of expense. On November 9, 1994, the West Virginia PSC
affirmed the recommended decision of the ALJ providing for a rate increase of
$1.5 million and an ROE of 10.85% effective November 11, 1994. This increase
was in addition to $1.9 million of CAAA recovery granted effective July 1,
1994, which had been included in Potomac Edison's original request for $12.2
million. The West Virginia PSC invited all parties to file petitions for
reconsideration which resulted in a second order issued on March 17, 1995.
This order deferred some of the CAAA issues to the 1995 ENEC proceeding. The
net result of both the March 17, 1995 base rate order and the ENEC order
reduced the original $1.5 million increase in base rates adopted in the
November 9, 1994 order by $1.1 million to $.4 million. The ROE was maintained
at 10.85%. The order permits Potomac Edison to apply for review of its post-
1994 scrubber operation and maintenance expense levels and CAAA investment
during the 1996 ENEC proceeding. Potomac Edison filed a Petition for Appeal
with the West Virginia Supreme Court of Appeals challenging the March 17
order. The court declined to hear the appeal.
On June 25, 1995, Potomac Edison implemented two FERC-approved
settlement agreements covering wholesale rates in effect for its municipal,
co-op, and borderline agreement customers subject to the jurisdiction of the
FERC. Each agreement included recovery of the remaining carrying charges on
investment, depreciation, as well as all operating costs required to comply
with Phase I of the CAAA, and other increasing levels of expense. The first
agreement, with all but one of Potomac Edison's FERC customers, provides for a
three-year term of service with an increase in annual revenues of $2.12
million. During this period, a moratorium on further rate changes, except for
changes based on fuel costs, taxes, and environmental statutes or regulations,
is in effect. This agreement also allows Potomac Edison to seek legitimate
and verifiable stranded costs from any customer who terminates service under
the tariff. The second agreement, with the one remaining Potomac Edison FERC
customer not included under the first agreement, provides for service until
January 1, 1997, (approximately eighteen months) with an increase in annual
rates of $.15 million. A moratorium on rate increases is also in effect for
this time period. However, this agreement contains no provision for recovery
of stranded costs from the customer should service be terminated.
AGC
AGC's rates are set by a formula filed with and previously accepted by
FERC. The only component which changes is the ROE. In December 1991, AGC
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filed for a continuation of the existing ROE of 11.53% and other interested
parties filed to reduce the ROE to 10%. Hearings were held and a
recommendation was issued by an ALJ on December 21, 1993, for an ROE of
10.83%. Exceptions to this recommendation were filed by all parties for
consideration by the FERC. On January 28, 1994, a complaint was filed jointly
by several parties with the FERC against AGC claiming that both the existing
ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and
unreasonable. A recommendation was issued by an ALJ on December 22, 1994, to
dismiss the joint complaint. A settlement agreement for both cases was filed
with FERC on January 12, 1995, which would reduce AGC's ROE from 11.53% to
11.13% for the period from March 1, 1992 through December 31, 1994, and
increase AGC's ROE to 11.2% for the period from January 1, 1995 through
December 31, 1995. This settlement was approved by FERC on March 23, 1995.
Refunds were made by AGC of any revenues collected between March 1, 1992 and
March 23, 1995 in excess of these levels. A second settlement has been
negotiated to address AGC's ROE after 1995. On December 21, 1995, AGC
submitted the new settlement to the FERC and action is pending. The
interested parties representing less than 2% of AGC's eventual revenues have
filed exceptions to the settlement. Under the terms of the settlement, AGC's
ROE for 1996 would be 11%. For 1997 and 1998 the ROE would be set by a
formula based upon the yields of 10-year constant maturity U.S. Treasury
securities. However, the change in ROE from the previous year's value cannot
exceed 50 basis points.
Through a filing completed on October 31, 1994, AGC sought FERC
approval to add a prior tax payment of approximately $12 million to rate base
which would produce about $1.4 million in additional annual revenues. The
FERC accepted AGC's filing and ordered the increase to become effective June
1, 1995.
ENVIRONMENTAL MATTERS
The operations of the Subsidiaries 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.
Meeting known environmental standards is estimated to cost the
Subsidiaries about $199 million in capital expenditures over the next three
years. Additional legislation or regulatory control requirements, if enacted,
may require modifying, supplementing, or replacing equipment at existing
stations at substantial additional cost.
Air Standards
Allegheny Power currently meets applicable standards as to
particulates and opacity at the 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 fuel operations, are experienced and are accommodated by the
regulatory process.
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On July 17, 1995, the West Virginia Division of Environmental
Protection (WVDEP), Office of Air Quality (OAQ), issued a Notice of Violation
(NOV) regarding the accidental release of particulate matter that occurred on
June 17, 1995, at the Pleasants Power Station. Allegheny Power responded on
August 11, 1995, and stated that the accidental release of particulate matter
was not due to a failure of any of the pollution control equipment, but was a
side effect of testing a further reduction of the sulfur dioxide (SO[2])
emissions from the power station. Subsequently, on November 16, 1995, the
WVDEP issued a Cease and Desist Order pertaining to the release. In order to
minimize the risk of future releases, the station intends to increase the
frequency of scheduled stack washing. Also, a consultant has been retained to
determine whether any operational or equipment changes can be implemented to
reduce the risk of releases in the future.
Allegheny Power meets current emission standards as to SO[2] 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, require an annual reduction in total
utility emissions within the United States of 10 million tons of SO[2] and two
million tons of nitrogen oxides (NO[x]) from 1980 emission levels, to be
completed in two phases, Phase I and Phase II. Five coal-fired Allegheny
Power plants are affected in Phase I and the remaining plants and units
reactivated in the future will be affected in Phase II. Installation of
scrubbers at the Harrison Power Station was the strategy undertaken by
Allegheny Power to meet the required SO[2] emission reductions for Phase I
(1995-1999). Continuing studies will determine the compliance strategy for
Phase II (2000 and beyond). Studies to evaluate cost effective options to
comply with Phase II SO[2] limits, including those which may be available from
the use of Allegheny Power's banked emission allowances and from the emission
allowance trading market, are continuing. It is expected that burner
modifications at possibly all Allegheny Power stations will satisfy the NO[x]
emission reduction requirements for the acid rain (Title IV) provisions of the
CAAA. Additional post-combustion controls may be mandated in Maryland and
Pennsylvania 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 SO[2] emission allowances. An allowance is defined as an
authorization to emit one ton of SO[2] into the atmosphere. Subject to
regulatory limitations, allowances (including bonus and extension allowances)
may be sold or banked for future use or sale. Allegheny Power 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 of approximately 356,000 per year
during the Phase I years. Ownership of these allowances permits Allegheny
Power to operate in compliance with Phase I, as well as to postpone a decision
on its compliance strategy for Phase II. As part of its compliance strategy,
Allegheny Power 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.
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In a case brought by the electric utility industry which disputed the
EPA's inclusion of overfire air equipment as well as low NO[x] burners in its
definition of "low NO[x] burner technology," the District of Columbia Circuit
Court of Appeals on November 29, 1994 vacated and remanded to the EPA the
Title IV NO[x] rule. As a result, the January 1, 1995, Phase I NO[x]
compliance deadline under Title IV is no longer applicable. On April 13,
1995, the EPA published the revised NO[x] regulation which redefined low NO[x]
burner technology as "burners only" and changed the Phase I compliance date
from January 1, 1995, to January 1, 1996.
Pursuant to an option in the CAAA and in order to avoid the potential
for more stringent NO[x] limits in Phase II, Allegheny Power chose to treat
seven Phase II Group 1 boilers (tangential- and wall-fired) as Phase I
affected units (Substitution Units) as of January 1, 1995. Additionally, the
four Phase II, Group 2 boilers (top- and cyclone-fired) were also made
Substitution Units for 1995. The status of all Substitution Units will be
evaluated on an annual basis to ascertain the financial benefits. As a result
of being Phase I affected, these Substitution Units will also be required to
comply with the Phase I SO[2] limits for each year that they are accorded
substitution status by Allegheny Power. Phase I NO[x] and SO[2] compliance
for these units should not require additional capital or operating
expenditures.
Title I of the CAAA established an ozone transport region (OTR)
consisting of the District of Columbia, the northern part of Virginia and 11
northeast states including Maryland and Pennsylvania. On October 11, 1995,
Pennsylvania petitioned the EPA to remove western Pennsylvania from the OTR.
The EPA has not acted on the request. Sources within the OTR will be required
to reduce NO[x] 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 NO[x] burners) at all Pennsylvania and Maryland stations
has been completed. This is essentially compatible with Title IV NO[x]
reduction requirements.
The Ozone Transport Commission (OTC), formed by the states in the OTR
and Washington, DC, has determined that Allegheny Power will be required to
make additional NO[x] reductions beyond RACT in order for the ozone transport
region to meet the ozone NAAQS. Under terms of a Memorandum of Understanding
(MOU) among the OTR states, Allegheny Power's power stations located in
Maryland and Pennsylvania will be required to reduce NO[x] emissions by 55%
from the 1990 baseline emissions, with a compliance date of May 1999. Further
reductions of 75% from the 1990 baseline will be required by May 2003, unless
the results of modeling studies due to be completed by 1998, indicate
otherwise. If Allegheny Power has to make reductions of 75%, it could be very
expensive and would depend upon further technological advances. Both Maryland
and Pennsylvania must promulgate regulations to implement the terms of the
MOU.
During 1995, the Environmental Council of States (ECOS) and the EPA
established the Ozone Transport Assessment Group (OTAG) to develop
recommendations for the regional control of NO[x] and Volatile Organic
Compounds (VOC's) in 31 states east of and bordering the west bank of the
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29
Mississippi River plus Texas. OTAG appears to be similar to the OTC in
purpose and organization. OTAG could lead to additional NO[x] controls on
certain Allegheny Power generating facilities in West Virginia. There is no
assurance that NO[x] control for non-OTR states will be limited to RACT. What
occurs in the non-OTR states could also affect whether Allegheny Power
generating facilities in Maryland and Pennsylvania would need post-RACT
controls. OTAG plans to issue recommendations by the end of 1996.
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 status of Monongahela's Rivesville Station with
ambient standards for SO[2]. 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 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 over $13 million with the expectation that EPA's reclassification
of Armstrong County to "attainment status" under NAAQS for SO[2] 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.
Water Standards
Under the National Pollutant Discharge Elimination System (NPDES),
permits for all of Allegheny Power's stations and disposal sites are in place.
However, NPDES permit renewals for several West Virginia disposal sites
contain what Allegheny Power believes are overly stringent discharge
limitations. The WVDEP has temporarily stayed the stringent permit
limitations while Allegheny Power continues to work with WVDEP and EPA in
order to scientifically justify less stringent limits. Where this is not
possible, installation of wastewater treatment facilities may become
necessary. The cost of such facilities, if required, cannot be predicted at
this time.
The stormwater permitting program required under the 1987 Amendments
to the Clean Water Act required implementation in two phases. In Phase I, the
EPA and state agencies implemented stormwater runoff regulations for
controlling discharges from industrial and municipal sources as well as
construction sites. Stormwater discharges have been identified and included
in NPDES permit renewals, but controls have not yet been required. Since the
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current round of permit renewals began in 1993, monitoring requirements have
been imposed, with pollution reduction plans and additional control of some
discharges anticipated.
In April 1995, EPA promulgated the Phase II stormwater rule which
establishes a two-tiered application process for discharges composed entirely
of stormwater. Under the rule, sources determined to be significant
contributors to water quality problems will be required to apply for a
discharge permit within 180 days of receiving notice. The remaining sources
are required to apply for permits within six years of the rule's effective
date or August 2, 2001 under yet-to-be proposed application requirements.
Pursuant to the National Groundwater Protection Strategy, West
Virginia adopted a Groundwater Protection Act in 1991. This law establishes a
statewide antidegradation policy which could require Allegheny Power to
undertake reconstruction of existing landfills and surface impoundments as
well as groundwater remediation, and may affect herbicide use for right-of-way
maintenance in West Virginia. Groundwater protection standards were approved
and implemented in 1993 (based on EPA drinking water criteria) which
established compliance limits. Pursuant to the groundwater protection
standards variance provision, on October 26, 1994, Allegheny Power jointly
filed with American Electric Power Company, Inc. (AEP) and Virginia Power, a
Notice of Intent (NOI) to request class or source variances from the
groundwater standards for steam electric operating facilities in West
Virginia. Additionally, each of the companies filed individual NOIs.
Technical and socio-economic justification to support the variance requests
are being developed and the costs shared through EPRI by all participants,
including Allegheny Power. While the justification for the variance requests
is being developed, Allegheny Power is protected from any enforcement action.
Because variance requests must ultimately be approved by the West Virginia
legislature, it is not possible to predict the outcome.
The Pennsylvania Department of Environmental Protection (PADEP)
developed a Groundwater Quality Protection Strategy which established a goal
of nondegradation of groundwater quality. However, the strategy recognizes
that there are technical and economic limitations to immediately achieving the
goal and further recognizes that some groundwaters need greater protection
than others. PADEP is beginning to implement the strategy by promulgating
changes to the existing rules that heretofore did not consider the
nondegradation goal. The full extent of the impact of the strategy on
Allegheny Power cannot be predicted.
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, 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.
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Allegheny Power 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 operating in compliance with their permits.
Significant costs were incurred during 1995 for expansion of existing
coal combustion by-product disposal sites due to requirements for installation
of liners on new sites and assessment of groundwater impacts through routine
groundwater monitoring and specific hydrogeological studies. Existing sites
may not meet the current regulatory criteria and groundwater remediation may
be required at some of Allegheny Power's facilities. Allegheny Power
continues to work with regulatory agencies to resolve outstanding issues.
Additional and substantial costs may be incurred by the Operating Subsidiaries
if remediation of existing sites is necessary.
Allegheny Power 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.
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 in central Pennsylvania. (See ITEM 3.
LEGAL PROCEEDINGS for a description of this superfund case.)
Emerging Environmental Issues
Title III of the CAAA requires EPA to conduct studies of toxic air
pollutants from electric utility plants to determine if emission controls are
necessary. EPA's reports are expected to be submitted to Congress in early
1996. If air toxic emission controls are recommended by EPA, final
regulations are not likely to be promulgated prior to the year 2000. The
impact of Title III on Allegheny Power is unknown at this time.
Reauthorization of the Clean Water Act, CERCLA and the RCRA are
currently pending. When reauthorization does occur, it is anticipated that
EPA will likely continue to regulate coal combustion by-product wastes and
their leachates as nonhazardous.
Pursuant to RCRA, EPA began reviewing the electric utility industry's
disposal practices of pyrites and pyritic material in 1995. Concerns over the
production of low pH waters from pyrites may cause reclassification of ash or
flue-gas desulfurization by-product disposal areas containing pyrites to that
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of special handling waste, or even possibly hazardous waste. Any change in
classification would result in substantially increased costs for either
retrofitting existing disposal sites or designing new disposal sites. A final
determination is scheduled for 1998.
An additional issue which could impact Allegheny Power and which is
undergoing intense study, is the health effect, if any, of electric and
magnetic fields. The financial impact of this issue on Allegheny Power, if
any, cannot be assessed at this time.
In connection with President Clinton's Climate Change Action Plan
concerning greenhouse gases, Allegheny Power expressed by letter to DOE in
August 1993, its willingness to work with the DOE on implementing voluntary,
cost-effective courses of action that reduce or avoid emission of greenhouse
gases. Such courses of action must take into account the unique circumstances
of each participating company, such as growth requirements, fuel mix and other
circumstances. Furthermore, they must be consistent with Allegheny Power's
integrated resource planning process and must not have an adverse effect on
its competitive position in terms of costs and rates, or be unacceptable to
its regulators. Some 63 other electric utility systems submitted similar
letters.
On April 27, 1994, the DOE and the Edison Electric Institute, on
behalf of member utilities, signed the Climate Challenge Program Memorandum of
Understanding which established the principles DOE and utilities will operate
under to reduce or avoid emission of greenhouse gases. A company-specific
agreement was entered into on behalf of the Operating Subsidiaries and DOE in
February 1995.
The EPA is required by law to regularly review the National Ambient
Air Quality Standards for criteria pollutants. Recent court orders due to
litigation by the American Lung Association have expedited these reviews. The
EPA is currently reviewing the standards for ozone, SO[2], NO[x], and
particulate matter. The impact on Allegheny Power of any revision to these
standards is unknown at this time.
REGULATION
Allegheny Power and AYP Capital are subject to the broad jurisdiction
of the SEC under PUHCA. APS, as a Maryland corporation, is also subject to
the jurisdiction of the Maryland PSC as to certain of its activities. The
Subsidiaries are regulated as to substantially all of their operations by
regulatory commissions in the states in which they operate and also by the
DOE. The Subsidiaries and AYP Capital are regulated by the FERC. In
addition, they are subject to numerous other city, county, 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. A
bill has been introduced in Congress to repeal PUHCA. However, Allegheny Power
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cannot predict what changes, if any, will be made to PUHCA as a result of
these activities.
On March 29, 1995, the FERC issued a Notice of Proposed Rulemaking on
open access nondiscriminatory transmission service which came to be known as
the "Mega-NOPR" due to its size and scope. If adopted by the FERC, the Mega-
NOPR will lead to a fundamental restructuring of the business of transmitting
wholesale electric power and could potentially influence the future of retail
electric sales as well. The FERC's stated objective was to ensure development
of a competitive market for wholesale power buyers and sellers while
preventing anti-competitive or discriminatory transmission practices. The
Mega-NOPR requires all public or investor-owned utilities that own
transmission systems and are under FERC's jurisdiction to file
nondiscriminatory, open access transmission tariffs available to all wholesale
buyers and sellers of electricity and apply these open access tariffs to their
own wholesale purchases and sales of electricity. The Mega-NOPR also permits
such utilities to recover stranded costs that may result from restructuring of
the wholesale electric industry. In a separate notice, FERC proposed the
development of a standardized, real-time electronic information network to
provide all potential users of a utility's transmission system equal access to
information regarding transmission capability and pricing. Allegheny Power
has numerous concerns regarding the Mega-NOPR, including the issue of stranded
costs, reliability of service and the development of a real-time electronic
information network.
The requirements of the Mega-NOPR, if adopted by FERC, would force
utilities to functionally unbundle their transmission and generation assets to
operate independently of one another, in order to promote nondiscriminatory
behavior. In response to the Mega-NOPR and in conjunction with Allegheny
Power's reengineering of its Bulk Power Supply functions, Allegheny Power has
established separate business units to operate and manage its generation and
transmission assets. (See ITEM 1. REORGANIZATION for further discussion of
the formation of business units.) Allegheny Power cannot predict when FERC
will issue final regulations, nor the specifics thereof, regarding
nondiscriminatory open access transmission services and related issues.
Allegheny Power founded and continues to participate in, along with
other utilities, an organization (General Agreement on Parallel Paths) whose
primary purpose is to develop a mutually acceptable method of resolving the
inequities imposed on transmission network owners by parallel power flows.
Section 111 of EPACT requires state utility commissions to institute
proceedings to investigate and determine the feasibility of adopting proposed
federal standards regarding three regulatory policy issues related to
integrated resource planning, rate recovery methods for investments in demand-
side management programs, and rates to encourage investments in cost-effective
energy efficiency improvements to generation, transmission and distribution
facilities. In 1994, Maryland, Pennsylvania, Virginia, and West Virginia
initiated investigations to determine whether to adopt the federal standards,
while Ohio summarily issued a final order. Allegheny Power submitted comments
in all proceedings. Maryland, Ohio, Virginia and West Virginia have issued
final orders. All four states declined to adopt the federal standards,
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concluding that existing state regulations adequately address the issues. The
outcome in Pennsylvania cannot be predicted.
On December 30, 1995, the Pennsylvania PUC issued its regulations
regarding future competitive bidding for purchase of capacity and energy. The
regulations specify the rules an electric utility must follow to competitively
bid the long-term purchase of capacity and energy.
In November 1993, while awaiting the new competitive bidding
regulations, West Penn filed a petition with the Pennsylvania PUC requesting
an order that, pending the adoption of new state regulations requiring
competitive bidding for PURPA, any proceedings or orders regarding purchase by
West Penn of capacity from a qualifying facility under PURPA shall be based on
competitive bidding. On June 3, 1994, the Pennsylvania PUC granted the West
Penn petition. However, the Pennsylvania PUC reserved judgment on the
applicability of the competitive bidding process to the South River project
and provided that the question would be addressed in the South River complaint
proceeding. By March 1995, all appeals to the June 1994 order were withdrawn
and the order became final.
On October 8, 1993, the West Virginia PSC issued proposed regulations
concerning bidding procedures for capacity additions for electric utilities
and invited comment by December 7, 1993. A number of interested parties,
including Monongahela and Potomac Edison, filed comments. In May 1994, the
West Virginia PSC held hearings on the proposed regulations. The West
Virginia PSC has yet to issue an Order.
On December 17, 1992, the Ohio PUC issued proposed rules concerning
competitive bidding for supply-side resources, transmission access for winning
bidders, and incentives for the recovery of the cost of purchased power. The
Ohio PUC invited comments and a number of interested parties, including
Monongahela, submitted comments. The Ohio PUC has taken no further action
following the filing of comments.
As part of its investigation into market competition and regulatory
policies, the Maryland PSC has declared that all new capacity needs in the
state will be subject to competitive bidding unless a utility can demonstrate
why a particular capacity need should not be bid.
Virginia has not mandated compulsory competitive bidding for capacity
additions.
On September 20, 1994, the Maryland PSC instituted a proceeding for
the purpose of examining regulatory and competitive issues affecting electric
service in Maryland. On November 1, 1994, the Maryland PSC staff described
the issues on which they requested comment by the utilities and interested
persons. Potomac Edison submitted comments. After legislative hearings were
held and comments were filed, the Maryland PSC issued an order. In its order
dated August 18, 1995 the Commission found that while competition in the
electric wholesale market should be encouraged, retail competition is not in
the public interest at this time. The Commission also announced in its order
that in the future it would be flexible and allow utilities to implement
<PAGE>
35
special rates and contracts including cost-based economic development rates as
appropriate.
By order dated September 18, 1995, the Virginia State Corporation
Commission began an investigation reviewing Commission policy regarding
restructuring of and competition in the electric utility industry. The
Commission staff has been directed to investigate and file a report on
competitive issues by March 29, 1996. Comments by utilities and other
interested persons on the staff report are due by May 31.
The Ohio PUC has initiated informal roundtable discussions on issues
concerning competition in the electric utility industry and promoting
increased competitive options for Ohio businesses. These discussions are
being undertaken pursuant to an Ohio Energy Strategy issued in April 1994.
The Ohio PUC is pursuing an incremental approach to competition by holding
roundtable meetings. As a first step, the meetings have resulted in a set of
guidelines on interruptible rates which are now pending before the Ohio PUC.
The Pennsylvania PUC instituted an investigation into electric power
competition on May 10, 1994, requesting responses from interested persons on
several broad areas of inquiry, such as retail wheeling, treatment of stranded
investments, consumer protection and utility financial health. Comments and
reply comments have been filed. The Pennsylvania PUC staff issued a report
advising against instituting retail wheeling at this time. Thereafter, the
Pennsylvania PUC held hearings in December 1995, January 1996, and February
1996. The Pennsylvania PUC has set a target of April 1996 to issue a final
report to the Governor and the Pennsylvania Legislature.
In August 1994, the Pennsylvania PUC instituted a proposed rulemaking
relating to Pennsylvania PUC review of siting and construction of electric
transmission lines. In connection with the proposed rulemaking, the
Pennsylvania PUC propounded a list of questions, including questions regarding
electric and magnetic fields. In December 1994, West Penn filed responses to
the questions. West Penn cannot predict the outcome of this proposed
rulemaking.
In October 1995, the Staff of the Maryland PSC issued draft
regulations concerning the construction of generating stations and overhead
transmission lines by nonutility generators (NUGS), applications covering
modifications of electric generating stations by utilities and by NUGs, and
changes to current regulations relating to whether certificates of public
convenience and necessity must be obtained prior to modifying existing
overhead transmission lines. Potomac Edison commented on the proposed changes
in November 1995, and cannot predict what, if any, modifications might be made
to current regulations.
In October 1990, the Pennsylvania PUC ordered Pennsylvania's major
electric utilities, including West Penn, to file programs for demand-side
management designed to reduce customer demand for electricity and to reduce
the need for additional generating capacity. The Pennsylvania PUC also
instituted a proceeding to formalize incentive ratemaking treatment for
successful demand-side management activities. On December 13, 1993, the
<PAGE>
36
Pennsylvania PUC entered an order allowing Pennsylvania utilities to recover
the costs of demand-side management activities, to recover revenues lost as a
result of the activities, and to recover a performance incentive for
successful activities. A group of industrial customers appealed the order to
the Pennsylvania Commonwealth Court. On January 9, 1995, the Court held that
utilities could recover demand-side management expenditures, but held that the
Pennsylvania PUC had incorrectly allowed recovery of lost revenues and
performance incentives. The Pennsylvania PUC has appealed the case to the
Pennsylvania Supreme Court.
During 1995, Potomac Edison continued its participation in the
Collaborative Process for demand-side management in Maryland. Potomac Edison's
two programs, the Commercial and Industrial Lighting Rebate Program and the
Power Saver/Comfort Home Program for new residential construction continued.
Through December 31, 1995, Potomac Edison had approved applications for $15.2
million in rebates related to the commercial lighting program and $2.6 million
in rebates related to the residential new construction program. The peak
demand reductions from these two programs through the end of 1995 should
reduce future generation requirements by about 18.4 and 3.3 MW respectively.
Program costs (including rebates) which are being amortized over a seven-year
period, lost revenues, and a performance based shared savings incentive
(shareholder bonus) are being recovered through an Energy Conservation
Surcharge. Potomac Edison filed a request to change the method used to
allocate demand-side management costs to customers as part of the surcharge.
The requested change was denied by a Hearing Examiner but has been appealed to
the full Commission. Potomac Edison is awaiting the Commission's decision on
this allocation issue.
West Penn implemented a two-year Low Income Payment and Usage
Reduction Pilot Program in 1994. This program will assist up to 2,000 low
income customers. The program allows a customer to enter into a payment
agreement with West Penn which results in a reduced monthly payment based on
income. The difference between the amount of the actual bill and the
customer's payment is paid by Federal Assistance Grants and West Penn. The
program is administered by the Dollar Energy Fund, a nonprofit, charitable
organization.
West Penn also implemented a Customer Assistance and Referral
Evaluation Service Program in 1994 for customers with special needs. West
Penn representatives work with customers who are experiencing temporary
hardship in an attempt to solve their problems and maximize their ability to
pay their bills. West Penn representatives utilize a variety of internal and
external resources to address the needs of such customers.
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 properties are also subject to a second lien securing certain
solid waste disposal and pollution control notes. The indenture under which
<PAGE>
37
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, 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 POWER MAP.)
ITEM 3. LEGAL PROCEEDINGS
On September 16, 1994, Duquesne Light Company (Duquesne) initiated a
proceeding before the FERC by filing a request for an order requiring the
Operating Subsidiaries to provide 300 MW of transmission service at parity
with native load customers from interconnection points with Allegheny Power to
Allegheny Power's points of interconnection with the Pennsylvania-New Jersey-
Maryland Interconnection. On May 16, 1995, the FERC issued a preliminary
order directing the Operating Subsidiaries to provide 300 MW of transmission
service as requested by Duquesne. The order established further procedures
for the development of rates, terms, and conditions of service by the parties.
The parties have completed the procedural schedule and await a final order
from the FERC. On October 6, 1995, the Operating Subsidiaries filed open
access tariffs under which they intend to provide comparable wholesale
transmission services to all potential customers, including Duquesne.
Consequently, on October 23, 1995, the Operating Subsidiaries filed a motion
asking FERC to suspend further proceedings in the Duquesne docket and to
consolidate it with the open access docket. The FERC has chosen not to
consolidate the proceedings for the present time.
In 1979, National Steel Corporation (National Steel) filed suit
against APS and certain Subsidiaries in the Circuit Court of Hancock County,
West Virginia, 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 APS 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. APS and the Subsidiaries
believe the motion is without merit; however, they cannot predict the outcome
of this case.
In 1987, West Penn entered into separate Electric Energy Purchase
Agreements (EEPAs) with developers of three PURPA projects: Milesburg (43
MW), Burgettstown (80 MW), and Shannopin (80 MW). The EEPAs provided for the
purchase of each project's power over 30 years or more at rates generally
approximating West Penn's estimated avoided cost at the time the EEPAs were
<PAGE>
38
negotiated. Each EEPA was subject to prior Pennsylvania PUC approval. In
1987 and 1988, West Penn filed a separate petition with the Pennsylvania PUC
for approval of each EEPA. Thereafter the Pennsylvania PUC issued orders that
significantly modified the EEPAs. Since that time, all three EEPAs as
modified have been, in varying degrees, the subject of complex and continuing
regulatory and judicial proceedings. On various dates in 1994, West Penn and
its two largest industrial customers, Armco Advanced Materials Company and
Allegheny Ludlum Corporation, filed joint petitions with the U.S. Supreme
Court for writs of certiorari (Cert) in the Milesburg, Burgettstown, and
Shannopin cases. On October 11, 1994, the U.S. Supreme Court denied these
requests for appeal.
After denial of Cert, the Pennsylvania PUC, acting upon a pending
petition of Shannopin, entered an order calculating capacity costs to be paid
to the project. West Penn and its two largest industrial customers appealed
this order to the Pennsylvania Commonwealth Court. On July 20, 1995, the
Pennsylvania Commonwealth Court reversed part of the PUC order by reducing the
maximum avoided capacity cost rate to be paid to the project from 8.0151 cents
per kWh to 5.5933 cents per kWh. On October 23, 1995, West Penn filed a
Petition for Allowance of Appeal with the Pennsylvania Supreme Court. A cross
petition for Allowance of Appeal was subsequently filed by Shannopin. These
appeals are pending.
West Penn and the developers of the Shannopin project reached an
agreement on January 25, 1996, which provides that West Penn will buy out the
Shannopin EEPA and terminate the project and all pending litigation associated
with the Shannopin project. The agreement provides for a buy out price of $31
million. The buy out agreement is subject to Pennsylvania PUC approval of
West Penn's full pass through of the buy out price to West Penn's customers
through the energy cost rate by no later than March 31, 1999. Once the
Pennsylvania PUC order is final and no longer subject to appeal, both parties
will withdraw their pending Pennsylvania Supreme Court appeals. Because the
buy out agreement is conditioned on full pass through of the buy out price to
customers, it will not have a material effect on West Penn's net income.
However, the buy out will significantly aid West Penn's customers by
eliminating a requirement to purchase unneeded, above market cost power for 30
years. The agreement was filed with the Pennsylvania PUC on February 13,
1996, along with a request for expedited approval.
On February 27, 1995, the Milesburg developers filed with the
Pennsylvania PUC a Petition for Recalculation of capacity cost to be paid to
the project in accordance with the July 1990 order of the Commonwealth Court.
These matters have since been stayed at the request of Milesburg and West Penn
for the purpose of pursuing settlement discussions.
The Pennsylvania PUC orders relating to recalculated rates and
adjusted milestone dates for Burgettstown became final and no longer subject
to appeal as of November 8, 1994.
In November 1994, West Penn filed a complaint with the Pennsylvania
PUC regarding Burgettstown, Shannopin, and Milesburg, requesting the
Pennsylvania PUC to rescind its orders regarding these projects because they
<PAGE>
39
were not in accord with PURPA and were no longer in the public interest. On
December 16, 1994, the Pennsylvania PUC dismissed the complaint. West Penn
appealed the order to the Pennsylvania Commonwealth Court. By order entered
May 25, 1995, the Pennsylvania Commonwealth Court affirmed the Pennsylvania
PUC order.
In November 1994, Washington Power (I), Inc. and Air Products and
Chemicals, Inc., trading as Washington Power Company, L.P. (Washington Power),
the developer of Burgettstown, filed a complaint against West Penn in the
Court of Common Pleas of Washington County, Pennsylvania. The complaint
requested equitable relief in the form of specific performance, declaratory
and injunctive relief, and also sought monetary damages for breach of contract
and for tortious interference with Burgettstown's contractual relations with
others. The Court set April 3, 1995 as the trial date for the specific
performance remedy only. The trial was cancelled at the request of Washington
Power. On May 5, 1995, at the request of Washington Power, the Court entered
an order discontinuing the case without prejudice.
On March 10, 1995, West Penn filed a petition for issuance of a
declaratory order with FERC. This petition sought a declaration that the
orders of the Pennsylvania PUC requiring West Penn to purchase capacity from
Burgettstown at rates and pursuant to the terms in the Pennsylvania PUC Orders
violated PURPA and FERC's PURPA regulations and thus West Penn had no
obligation to purchase capacity from Burgettstown. On May 8, 1995, FERC
denied the petition.
The Burgettstown EEPA automatically terminated in accordance with its
terms, as the financing closing had not occurred by May 8, 1995, as required
by the Pennsylvania PUC orders. Burgettstown did not request an extension.
On May 2, 1995, Washington Power filed a complaint against West Penn,
APS and APSC in the United States District Court for the Western District of
Pennsylvania asserting claims of treble damages for monopolization and
attempts to monopolize in violation of the federal antitrust laws, unfair
competition, breach of contract, intentional interference with contract and
interference with prospective business relations. West Penn, APS and APSC
cannot predict the outcome of this litigation.
In October 1993, South River Power Partners, L.P. (South River) filed
a complaint against West Penn with the Pennsylvania PUC. The complaint seeks
to require West Penn to purchase 240 MW of power from a proposed coal-fired
PURPA project to be built in Fayette County, Pennsylvania. West Penn is
opposing this complaint as the power is not needed and the price proposed by
South River is in excess of avoided cost. The Pennsylvania Consumer Advocate,
the Small Business Advocate, the Pennsylvania PUC Trial Staff and various
industrial customers intervened in opposition to the complaint. On August 2,
1995, these proceedings, with the exception of discovery, were stayed due to
South River's appeal to the Commonwealth Court of an order of the Pennsylvania
PUC requiring South River to bear the cost associated with providing notice of
the proceedings to West Penn's customers. West Penn cannot predict the
outcome of this proceeding.
<PAGE>
40
Two previously reported complaints had been filed with the West
Virginia PSC by developers of PURPA cogeneration projects in Marshall County,
West Virginia (MidAtlantic) and Barbour County, West Virginia, seeking to
require Monongahela and Potomac Edison to purchase capacity from the projects.
Following a meeting in February, 1994, and an exchange of
correspondence in the spring and summer of 1994, no further contact was had
with the developers of the Barbour County project until, following a request
by the PSC for a status report, Barbour County reported it was ready to go
forward and discuss substantial modifications to the project. Potomac Edison
and Monongahela responded on May 8, 1995, recommending the West Virginia PSC
require evidence that a new project would be a qualifying facility (QF) under
PURPA, that Barbour County provide a plan for resolving its QF status, and
that any meeting with Staff be open to representatives of all parties. By
Order dated June 15, 1995, the West Virginia PSC dismissed the Barbour County
complaint on the basis that the project was undefined and contrary to the
public interest.
The developers of the MidAtlantic project contacted Potomac Edison and
Monongahela in September 1994 proposing a new, two-phased gas turbine
facility. Following an exchange of letters, on January 10, 1995 MidAtlantic
filed with the West Virginia PSC a Motion to Compel Potomac Edison to enter
into an agreement, alleging bad faith negotiations. Potomac Edison and
Monongahela filed a response on January 30, 1995, denying bad faith and noting
numerous problems with MidAtlantic's new proposed project, including its plan
to have West Virginia customers pay 100% of costs of the first phase, contrary
to an order entered by the West Virginia PSC on March 5, 1993. On March 20,
1995 the West Virginia PSC issued an order rejecting MidAtlantic's plan to
charge 100% of its Phase I project to West Virginia customers; directing
MidAtlantic to obtain from FERC a resolution of its QF status; and requiring
MidAtlantic to advise the West Virginia PSC within 30 days if it intended to
pursue its complaint.
MidAtlantic filed a response to the West Virginia PSC order on April
19, 1995, together with a motion for extension of time to respond to the
question whether it would continue with the project, citing withdrawal of its
financial partner (Babcock and Wilcox) from the project. Following a grant of
an extension of time, on June 26, 1995, MidAtlantic filed a letter informing
the West Virginia PSC that it would not pursue its project further, blaming
APS for its inability to obtain a financial partner. The West Virginia PSC
dismissed the MidAtlantic complaint by order dated June 29, 1995.
On September 7, 1995, MidAtlantic sued Monongahela, Potomac Edison,
and APS in state court in Marshall County, West Virginia for failure to comply
with PURPA regulations in refusing to purchase capacity and energy from the
proposed project; interference with MidAtlantic's contract with Babcock and
Wilcox; causing and/or aiding Babcock and Wilcox in breaching a fiduciary
duty; defamation; and undermining PURPA in an anti-competitive civil
conspiracy with Babcock and Wilcox. The MidAtlantic suit was also filed
against Babcock and Wilcox for breach of contract, breach of fiduciary duty,
and conspiring with Allegheny Power to undermine PURPA. MidAtlantic seeks
compensatory and punitive damages. Monongahela, Potomac Edison and APS filed
<PAGE>
41
an answer on October 24, 1995, and Babcock and Wilcox filed an answer,
counterclaim and motion for summary judgment, alleging that MidAtlantic had
released Babcock and Wilcox from all obligations arising from their
development agreement. The court heard oral argument on the summary judgment
motion on January 19, 1996. Monongahela, Potomac Edison and APS cannot
predict the outcome of this litigation.
On August 24, 1995, American Bituminous Power Partners, L.P. (ABPP),
owner and operator of the Grant Town project, an operating 80 MW waste coal
PURPA project located in Marion County, West Virginia (see page 14), filed a
Petition to Reopen and for Emergency Interim Relief with the West Virginia PSC
against Monongahela. ABPP seeks modifications to the EEPA that will result in
an unspecified increase in the cap of the Tracking Account and a retroactive
restoration of the price for project energy to 1.9 cents/kWh. The West
Virginia PSC issued an order on November 29, 1995, which set a schedule for
briefing of issues. In its brief, ABPP advised for the first time that the
modifications it is seeking are only for interim relief and that if such
relief is granted, it intends to petition the West Virginia PSC to further
amend the EEPA to permanently increase the avoided energy cost. On December
20, 1995, ABPP requested additional briefing to clarify the relief sought. On
January 5, 1996, the West Virginia PSC granted ABPP's request and set a
schedule for additional briefs which concluded on January 26, 1996.
Monongahela cannot predict the outcome of this proceeding.
As previously reported, effective March 1, 1989, West Virginia enacted
a new method for calculating the Business and Occupation Tax
(B & O Tax) on electricity generated in that state, which disproportionately
increased the B & O Tax on shipments of electricity to other states. In 1989,
West Penn, the Pennsylvania Consumer Advocate, and several West Penn
industrial customers filed a joint complaint in the Circuit Court of Kanawha
County, West Virginia seeking to have the B & O Tax declared illegal and
unconstitutional on the grounds that it violates the Interstate Commerce
Clause and the Equal Protection Clause of the federal Constitution and certain
provisions of federal law that bar the states from imposing or assessing taxes
on the generation or transmission of electricity that discriminate against
out-of-state entities. In 1991, West Penn amended the complaint to include a
1990 increase in the rate of the B & O Tax. The trial was held in July 1993,
and briefs were filed. Effective June 1, 1995, West Virginia enacted a new
method of calculating the B & O Tax, assessing the tax on a capacity rather
than a generation basis and effective January 31, 1996, included a lower rate
for generating units with flue-gas desulfurization systems (scrubbers). As a
result of these changes, this litigation ended.
As of March 8, 1996, Monongahela has been named as a defendant
along with multiple other defendants in a total of 5,564 pending asbestos
cases involving one or more plaintiffs. Potomac Edison and West Penn have
been named as defendants along with multiple other defendants in a total of
2,749 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-
<PAGE>
42
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. Because there are multiple defendants, the Operating Subsidiaries
believe their relative percentage of potential liability is a small percentage
of the total amount of the damages sought. A total of 94 cases have been
previously settled and/or dismissed as 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 June 10, 1994, Allegheny Power filed a declaratory judgment action
in the Superior Court of New Jersey 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. On January 27, 1995, the
Court granted the CGL insurers' motion which dismissed the complaint, without
prejudice, on procedural grounds. On the same day, Allegheny Power
recommenced action in the Court of Common Pleas of Westmoreland County,
Pennsylvania where it is currently pending. To date, two insurers have
settled. However, the final outcome of this proceeding cannot be predicted.
On December 13, 1995, APSC, Monongahela, and Potomac Edison filed a
civil complaint in the Court of Common Pleas of Westmoreland County,
Pennsylvania against Industrial Risk Insurers (IRI) seeking damages in excess
of $5 million for breach of an insurance contract covering physical damage to
property at Unit No. 1 of Fort Martin Power Station. IRI previously denied
coverage under an all risk insurance policy in effect at the time of the
property damage. The outcome of the litigation or the amount of damages, if
any, that may be recovered 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 875 other PRPs involved. A Remedial
Investigation/Feasibility Study (RI/FS) prepared by the EPA indicates remedial
alternatives which range as high as $113 million, to be shared by all
responsible parties. A PRP Group has been formed and has submitted an
addendum to the RI/FS which proposes a substantially less expensive cleanup
remedy. The EPA has not yet selected which remedial alternatives it will use,
<PAGE>
43
nor has it issued a Proposed Plan and Record of Decision. The Operating
Subsidiaries cannot predict the outcome of this proceeding.
After protracted litigation concerning the Operating Subsidiaries'
application for a license to build a 1,000-MW energy-storage facility near
Davis, West Virginia, 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 decision
has been appealed and negotiations are ongoing to settle this matter. The
Operating Subsidiaries cannot predict the outcome of this proceeding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
APS, Monongahela, West Penn and AGC did not submit any matters to a vote
of shareholders during the fourth quarter of 1995.
The holder of all the outstanding common stock of Potomac Edison
consented in writing on October 23, 1995, to the amendment of the Charter of the
Corporation to reclassify shares that had been purchased pursuant to a mandatory
sinking fund.
<PAGE>
<TABLE>
<CAPTION>
44
Executive Officers of the Registrants
The names of the executive officers of each company, their ages, the positions
they hold and their business experience during the past five years appears below:
Position (a) and Period of Service
<S> <C> <C> <C> <C> <C> <C> <C>
Name Age APS APSC MP PE WP AGC
Charles S. Ault 57 V.P.
(1990- )
Thomas A. Barlow(b) 61 V.P.
(1987-95)
Eileen M. Beck 54 Secretary Secretary Secretary Secretary Secretary Secretary
(1988- ) (1988- ) (1995- ) (1996- ) (1996- ) (1982- )
Asst. Treas. Asst. Treas. Asst. Treas. Previously, Previously,
(1979- ) (1979- ) (1981- ) Asst. Sec. Asst. Sec.
Previously, (1988-95) (1988-95)
Asst. Sec.
(1988-94)
Klaus Bergman 64 CEO CEO Chrm., CEO Chrm., CEO Chrm., CEO Dir. (1982- )
& Dir. & Dir. & Dir. & Dir. & Dir. Pres. & CEO
(1985- ) (1985- ) (1985- ) (1985- ) (1985- ) (1985- )
Chairman Chairman
(1994- ) (1994- )
Previously, Previously,
Pres. Pres.
(1985-94) (1985-94)
Marvin W. Bomar 55 V.P.
(9/95- )
Charles V. Burkley(c) 64 Controller
(1984-12/95)
Nancy L. Campbell 56 V.P. V.P. Treasurer Treasurer Treasurer Treas. &
(1994- ) (1993- ) (1995- ) (1996- ) (1996- ) Asst. Sec.
Treas. Treas. & Asst. Sec. (1988- )
(1988- ) (1988- ) (1988- )
Previously,
Asst. Treas.
(1988-95)
Richard J. Gagliardi 45 V.P. V.P. Asst. Sec. Asst. Treas.
(1991- ) (1990- ) (1990- ) (1982- )
Stanley I. Garnett (d) 52 Senior Senior Dir. Dir. Dir. Dir. & V.P.
V.P. - Fin. V.P. - Fin. (1990-95) (1990-95) (1990-95) (1990-95)
(9/94-95) (9/94-95) V.P.
& Asst. Sec. & Asst. Sec. (1985-95)
(1982-95) (1982-95)
Previously, Previously,
V.P. - Fin. V.P. - Fin.
(1990-9/94) (1990-9/94)
Nancy H. Gormley(e) 63 V.P. V.P. - Legal V.P. Asst. Sec.
(1991-95) & Regulatory (1992-95) & Asst. Treas.
(1990-95) (1990-95)
</TABLE>
(a) All officers and directors are elected annually.
(b) Retired effective September 1, 1995.
(c) Retired effective December 1, 1995.
(d) Resigned effective December 1, 1995.
(e) Retired effective January 1, 1996.
<PAGE>
<TABLE>
<CAPTION>
45
Position (a) and Period of Service
<S> <C> <C> <C> <C> <C> <C> <C>
Name Age APS APSC MP PE WP AGC
Thomas K. Henderson 55 V.P. Legal V.P. V.P. V.P.
(1996- ) (1995- ) (1995- ) (1985- )
Previously,
Asst. V.P.
(9/95-12/95)
Kenneth M. Jones 58 V.P. & V.P. Dir. & V.P.
Controller (1991- ) (1991- )
(1991- ) Controller
(1976-5/95)
Thomas J. Kloc 43 Controller Controller Controller Controller Controller
(5/95- ) (1996- ) (1988- ) (12/95- ) (1988- )
James D. Latimer 57 V.P. V.P. V.P.
(12/95- ) (12/95- ) (12/95- )
Previously,
Executive V.P.
(6/94-12/95)
V.P.
(1988-6/94)
Kenneth D. Mowl 56 Asst. Sec. & Asst. Treas. Asst. Sec. &
Asst. Treas. (1996- ) Asst. Treas.
(1996- ) (1996- )
Previously,
Sec. & Treas.
(1986-95)
Richard E. Myers(b) 59 Controller
(1980-95)
Alan J. Noia 48 Pres., COO Pres., COO Dir. Dir. Dir. Dir. & V.P.
& Dir. & Dir. (9/94- ) (1990- ) (9/94- ) (9/94- )
(9/94- ) (9/94- ) Previously,
Pres.
(1990-94)
Jay S. Pifer 58 Senior V.P. Senior V.P. Pres. & Dir. Pres. & Dir. Pres.
(1996- ) (1995- ) (1995- ) (1995- ) (1990- )
& Dir.
(1992- )
Richard A. Roschli 61 V.P.
(6/94- )
Previously,
Asst. V.P.
(5/94-6/94);
Div. Mgr.
(1988-5/94)
Peter J. Skrgic 54 Senior V.P. Senior V.P. Dir. Dir. & V.P. Dir. Dir. & V.P.
(9/94- ) (9/94- ) (1990- ) (1990- ) (1990- ) (1989- )
Previously, Previously,
V.P. V.P.
(1989-94) (1989-94)
Robert R. Winter 52 V.P. V.P. V.P.
(1987- ) (1995- ) (9/95- )
Dale F. Zimmerman(b) 62 Asst. Sec. & Sec. & Treas.
Asst. Treas. (1990 -1995)
(1995)
</TABLE>
(a) All officers and directors are elected annually.
(b) Retired effective January 1, 1996.
<PAGE>
46
PART II
ITEM 5. MARKET FOR THE REGISTRANTS' COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
APS.
AYP is the trading symbol of the common stock of APS 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, 1995,
there were 63,290 holders of record of APS' common stock.
The tables below show the dividends paid and the high and low sale
prices of the common stock for the periods indicated:
<TABLE>
<CAPTION>
1995 1994
Dividend High Low Dividend High Low
<S> <C> <C> <C> <C> <C> <C>
1st Quarter 41 cents $24-3/8 $21-1/2 41 cents $26-1/2 $22-3/8
2nd Quarter 41 cents $25-1/8 $22-3/4 41 cents $24 $20-1/8
3rd Quarter 41 cents $26 $22-7/8 41 cents $22-3/4 $19-3/4
4th Quarter 42 cents $29-1/4 $25-1/2 41 cents $22 $19-3/4
</TABLE>
The high and low prices through February 1, 1996 were $30-1/2 and $28.
The last reported sale on that date was at $30.
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 APS.
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.
<PAGE>
47
ITEM 6. SELECTED FINANCIAL DATA
Page No.
APS 48
Monongahela 51
Potomac Edison 53
West Penn 55
AGC 57
<PAGE>
<TABLE>
<CAPTION>
48
APS
Consolidated Statistics
Year ended December 31
1995 1994 1993 1992 1991 1990 1985
Summary of Operations
(Millions of Dollars)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $2,647.8 $2,451.7 $2,331.5 $2,306.7 $2,282.2 $2,301.9 $1,833.4
Operation expense 1,373.8 1,284.9 1,208.4 1,252.0 1,252.2 1,338.6 1,049.0
Maintenance 256.6 241.9 231.2 210.9 204.2 182.0 148.8
Depreciation 256.3 223.9 210.4 197.8 189.7 180.9 125.0
Taxes other than income 184.8 183.1 178.8 174.6 167.5 152.5 105.9
Taxes on income 154.2 129.7 128.1 115.4 119.1 106.4 119.3
Allowance for funds used
during construction (8.2) (19.6) (21.5) (17.5) (7.9) (7.2) (46.5)
Interest charges and
preferred dividends 196.8 184.2 180.3 171.3 165.0 161.1 159.5
Other income and
deductions (6.2) 3.8 (1.3) (1.6) (3.8) (6.0)
Consolidated income before
cumulative effect
of accounting change $ 239.7 $ 219.8 $ 215.8 $ 203.5 $ 194.0 $ 191.4 $ 178.4
Cumulative effect of
accounting change,
net[a] 43.4
Consolidated
net income $ 239.7 $ 263.2 $ 215.8 $ 203.5 $ 194.0 $ 191.4 $ 178.4
Common Stock Data[b]
Shares outstanding
(Thousands) 120,701 119,293 117,664 113,899 108,451 106,984 100,513
Average shares
outstanding
(Thousands) 119,864 118,272 114,937 111,226 107,548 106,102 99,437
Earnings per average share:
Consolidated income
before cumulative
effect of accounting
change $2.00 $1.86 $1.88 $1.83 $1.80 $1.80 $1.79
Cumulative effect of
accounting change[a] .37
Consolidated net income $2.00 $2.23 $1.88 $1.83 $1.80 $1.80 $1.79
Dividends paid per share $1.65 $1.64 $1.63 $1.605 $1.585 $1.58 $1.35
Dividend payout ratio[c] 82.5% 88.3% 86.9% 88.3% 87.8% 87.6% 75.2%
Stockholders 63,280 66,818 63,396 63,918 62,095 63,201 81,680
Market price range per share:
High 29 1/4 26 1/2 28 7/16 24 3/8 23 1/4 21 1/16 17 3/16
Low 21 1/2 19 3/4 23 7/16 20 3/4 17 7/16 17 14 1/16
Book value
per share $17.65 $17.26 $16.62 $16.05 $15.54 $15.26 $12.87
Return on average
common equity[c] 11.35% 10.96% 11.40% 11.45% 11.59% 11.78% 14.10%
<PAGE>
49
Capitalization Data
(Millions of Dollars)
Common stock $2,129.9 $2,059.3 $1,955.8 $1,827.8 $1,685.6 $1,632.3 $1,293.1
Preferred stock:
Not subject to
mandatory
redemption 170.1 300.1 250.1 250.1 235.1 235.1 240.1
Subject to
mandatory
redemption 25.2 26.4 28.0 29.3 30.6 79.0
Long-term debt
and QUIDS 2,273.2 2,178.5 2,008.1 1,951.6 1,747.6 1,642.2 1,600.7
Total capitalization $4,573.2 $4,563.1 $4,240.4 $4,057.5 $3,697.6 $3,540.2 $3,212.9
Capitalization ratios:
Common stock 46.6% 45.1% 46.1% 45.0% 45.6% 46.1% 40.2%
Preferred stock:
Not subject to
mandatory
redemption 3.7 6.6 5.9 6.2 6.3 6.6 7.5
Subject to
mandatory
redemption .6 .6 .7 .8 .9 2.5
Long-term debt
and QUIDS 49.7 47.7 47.4 48.1 47.3 46.4 49.8
Total Assets
(Millions of Dollars) $6,447.3 $6,362.2 $5,949.2 $5,039.3 $4,855.0 $4,561.3 $4,059.3
Property Data
(Millions of Dollars)
Gross property $7,812.7 $7,586.8 $7,176.9 $6,679.9 $6,255.7 $5,986.2 $4,916.8
Accumulated
depreciation (2,700.1) (2,529.4) (2,388.8) (2,240.0) (2,093.7) (1,946.1) (1,275.6)
Net property $5,112.6 $5,057.4 $4,788.1 $4,439.9 $4,162.0 $4,040.1 $3,641.2
Gross additions
during year $ 319.1 $ 508.3 $ 574.0 $ 487.6 $ 337.7 $ 321.8 $ 520.4
Ratio of provisions
for depreciation to
depreciable property 3.50% 3.32% 3.37% 3.31% 3.28% 3.27% 3.17%
Revenues
(Millions of Dollars)
Residential $ 927.0 $ 863.7 $ 818.4 $ 734.9 $ 708.3 $ 649.5 $ 513.3
Commercial 493.7 459.3 430.2 391.9 375.4 343.0 267.5
Industrial 770.2 728.0 673.4 637.7 600.2 571.5 504.9
Nonaffiliated utilities 385.0 331.6 346.7 465.5 525.0 679.9 501.0
Other 71.9 69.1 62.8 76.7 73.3 58.0 46.7
Total revenues $2,647.8 $2,451.7 $2,331.5 $2,306.7 $2,282.2 $2,301.9 $1,833.4
<PAGE>
50
Sales-GWh
Residential 13,003 12,630 12,514 11,746 11,755 11,264 9,309
Commercial 7,963 7,607 7,440 7,071 7,003 6,670 5,396
Industrial 18,457 17,708 16,967 16,910 16,430 16,511 14,927
Nonaffiliated utilities 13,517 9,915 12,388 17,753 18,211 21,796 16,914
Other 1,304 1,275 1,240 1,186 1,146 1,101 964
Total sales 54,244 49,135 50,549 54,666 54,545 57,342 47,510
Output-GWh
Steam generation 39,174 38,959 38,247 40,373 42,307 41,933 39,000
Hydro and pumped-
storage generation 1,234 1,390 1,233 1,204 1,654 1,426 214
Pumped-storage
input (1,390) (1,564) (1,385) (1,340) (1,907) (1,568) (65)
Purchased power and
exchanges, net 18,031 12,965 15,245 17,279 15,321 17,924 11,171
Losses and system uses (2,805) (2,615) (2,791) (2,850) (2,830) (2,373) (2,810)
Total sales as above 54,244 49,135 50,549 54,666 54,545 57,342 47,510
Energy Supply
Generating capability-MW
System-owned 8,070 8,070 7,991 7,991 7,992 7,991 7,938
Nonutility contracts[d] 299 299 292 212 162 160
Maximum hour peak-MW 7,280 7,153 6,678 6,530 6,238 6,070 6,035
Load factor 68.3% 66.8% 70.0% 69.3% 71.7% 71.3% 63.3%
Heat rate-Btu's per kWh 9,970 9,927 10,020 9,910 9,956 9,944 10,016
Fuel costs-cents
per million Btu's 130.20 141.50 142.12 141.93 143.19 140.97 154.21
Customers
(Thousands)
Residential 1,204.4 1,189.7 1,176.6 1,161.5 1,146.6 1,133.4 1,053.3
Commercial 146.0 143.0 140.1 137.4 134.7 132.2 115.9
Industrial 24.6 24.2 23.8 23.6 23.1 22.8 20.8
Other 1.3 1.3 1.2 1.2 1.3 1.3 1.1
Total customers 1,376.3 1,358.2 1,341.7 1,323.7 1,305.7 1,289.7 1,191.1
Average Annual Use-kWh per customer
Residential-APS 10,865 10,682 10,715 10,181 10,316 10,011 8,868
Residential-National 9,451e 9,378e 9,394 8,949 9,280 9,056 8,487
All retail service-APS 28,908 28,205 27,800 27,259 27,205 26,996 25,060
Average Rate-cents per kWh
Residential-APS 7.13 6.84 6.54 6.26 6.03 5.77 5.51
Residential-National 8.84e 8.83e 8.73 8.63 8.46 8.17 7.79
All retail service-APS 5.58 5.43 5.23 4.96 4.80 4.56 4.36
</TABLE>
[a] To record unbilled revenues, net of income taxes.
[b] Reflects a two-for-one common stock split effective November 4, 1993.
[c] Excludes the cumulative effect of the accounting change in 1994.
[d] Capability available through contractual arrangements with nonutility
generators.
[e] Preliminary.
<PAGE>
<TABLE>
<CAPTION>
51
Monongahela
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
1995 1994 1993 1992 1991 1990
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential.......................... $209,065 $190,861 $185,141 $169,589 $163,757 $151,658
Commercial........................... 124,457 116,201 110,762 102,709 97,849 90,095
Industrial........................... 212,427 202,181 187,669 186,442 177,688 169,654
Nonaffiliated utilities.............. 90,916 79,701 86,032 119,628 140,029 177,573
Other, including affiliates.......... 85,617 91,186 72,240 53,595 45,803 41,348
Total.............................. 722,482 680,130 641,844 631,963 625,126 630,328
Operation expense...................... 413,858 394,438 364,027 372,002 364,968 379,663
Maintenance............................ 74,418 69,389 67,770 62,909 64,035 57,768
Depreciation........................... 57,864 57,952 56,056 53,865 51,903 50,433
Taxes other than income................ 38,551 40,404 34,076 33,207 35,378 34,310
Taxes on income........................ 41,834 30,712 33,612 27,919 31,173 31,005
Allowance for funds used
during construction.................. (1,393) (2,946) (5,780) (3,908) (1,341) (1,559)
Interest charges....................... 39,872 38,156 37,588 36,013 33,494 33,264
Other income, net...................... (9,235) (7,911) (7,203) (8,388) (8,573) (9,505)
Income before cumulative effect
of accounting change................. 66,713 59,936 61,698 58,344 54,089 54,949
Cumulative effect of accounting
change, net (a)...................... 7,945
Net income............................. $ 66,713 $ 67,881 $ 61,698 $ 58,344 $ 54,089 $ 54,949
Return on average common equity (b).... 11.92% 10.66% 11.83% 11.96% 11.43% 11.84%
</TABLE>
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
<PAGE>
<TABLE>
<CAPTION>
52
Monongahela
FINANCIAL AND OPERATING STATISTICS
Year ended December 31
1995 1994 1993 1992 1991 1990
PROPERTY, PLANT, AND EQUIPMENT
(Thousands of Dollars):
<S> <C> <C> <C> <C> <C> <C>
Gross.............................. $1,821,613 $1,763,533 $1,684,322 $1,567,252 $1,458,643 $1,389,906
Accumulated depreciation........... (747,013) (701,271) (664,947) (628,595) (590,311) (550,104)
Net.............................. $1,074,600 $1,062,262 $1,019,375 $ 938,657 $ 868,332 $ 839,802
GROSS ADDITIONS TO PROPERTY
(Thousands of Dollars)............... $ 75,458 $ 103,975 $ 140,748 $ 126,422 $ 84,515 $ 74,575
TOTAL ASSETS (Thousands of Dollars). $1,480,591 $1,476,483 $1,407,453 $1,166,410 $1,091,287 $1,054,497
CAPITALIZATION:
Amount (Thousands of Dollars):
Common stock....................... $ 505,752 $ 495,693 $ 483,030 $ 475,628 $ 428,855 $ 425,016
Preferred stock.................... 74,000 114,000 64,000 64,000 69,000 69,000
Long-term debt and QUIDS........... 489,995 470,131 460,129 444,506 372,618 367,871
Total $1,069,747 $1,079,824 $1,007,159 $ 984,134 $ 870,473 $ 861,887
Ratios:
Common stock....................... 47.3% 45.9% 48.0% 48.3% 49.3% 49.3%
Preferred stock.................... 6.9 10.6 6.3 6.5 7.9 8.0
Long-term debt and QUIDS........... 45.8 43.5 45.7 45.2 42.8 42.7
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY-- kW
Company-owned...................... 2,326,300 2,326,300 2,325,300 2,325,300 2,325,300 2,325,300
Nonutility contracts*.............. 161,000 161,000 159,000 79,000 29,000 27,000
KILOWATT-HOURS IN THOUSANDS:
Sales:
Residential........................ 2,807,135 2,674,664 2,689,830 2,527,247 2,581,628 2,430,539
Commercial......................... 1,967,473 1,846,791 1,825,127 1,742,469 1,744,881 1,656,961
Industrial......................... 5,114,126 4,942,388 4,656,921 4,872,126 4,905,715 4,868,551
Nonaffiliated utilities............ 3,182,827 2,383,531 3,082,715 4,578,187 4,877,930 5,634,908
Other, including affiliates........ 1,734,537 1,925,450 1,565,561 824,393 584,677 590,920
Total sales...................... 14,806,098 13,772,824 13,820,154 14,544,422 14,694,831 15,181,879
Output:
Steam generation................... 10,620,003 10,743,934 10,194,794 10,593,059 11,512,714 11,247,964
Pumped-storage generation.......... 257,284 290,586 263,329 260,155 375,500 306,470
Pumped-storage input............... (330,915) (373,116) (337,737) (332,989) (475,898) (389,467)
Purchased power and exchanges, net. 4,981,345 3,784,421 4,381,916 4,705,418 3,969,954 4,618,564
Losses and system uses............. (721,619) (673,001) (682,148) (681,221) (687,439) (601,652)
Total sales as above............. 14,806,098 13,772,824 13,820,154 14,544,422 14,694,831 15,181,879
CUSTOMERS:
Residential.......................... 303,568 300,465 297,865 294,595 291,578 288,990
Commercial........................... 35,793 35,268 34,626 34,005 33,484 33,107
Industrial........................... 8,085 8,029 8,014 8,005 7,994 7,946
Other................................ 170 171 170 172 172 170
Total customers.................... 347,616 343,933 340,675 336,777 333,228 330,213
RESIDENTIAL SERVICE:
Average use-
kWh per customer................... 9,306 8,957 9,093 8,636 8,905 8,457
Average revenue-
dollars per customer............... 693.11 639.16 625.87 579.51 564.87 527.70
Average rate-
cents per kWh...................... 7.45 7.14 6.88 6.71 6.34 6.24
</TABLE>
*Capability available through contractual arrangements with nonutility
generators.
<PAGE>
<TABLE>
<CAPTION>
53
Potomac Edison
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
1995 1994 1993 1992 1991 1990
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential.......................... $316,714 $296,090 $274,358 $243,413 $227,851 $213,165
Commercial........................... 145,096 135,937 124,667 111,506 104,642 97,902
Industrial........................... 200,890 195,089 175,902 157,304 147,654 148,632
Nonaffiliated utilities.............. 125,890 107,027 108,132 141,120 161,720 210,710
Other, including affiliates.......... 30,429 25,222 29,526 34,544 32,210 27,135
Total.............................. 819,019 759,365 712,585 687,887 674,077 697,544
Operation expense...................... 487,833 448,527 413,145 414,939 423,489 460,546
Maintenance............................ 62,147 58,624 64,376 53,141 49,766 45,035
Depreciation........................... 68,826 59,989 56,449 53,446 50,578 47,547
Taxes other than income................ 47,629 46,740 46,813 45,791 43,937 38,527
Taxes on income........................ 36,936 33,163 30,086 28,422 24,194 25,132
Allowance for funds used
during construction.................. (1,752) (5,874) (7,134) (5,368) (3,366) (2,908)
Interest charges....................... 51,179 46,456 43,802 39,392 36,831 33,049
Other income, net...................... (12,044) (10,243) (8,419) (9,352) (9,593) (10,964)
Income before cumulative effect
of accounting change................. 78,265 81,983 73,467 67,476 58,241 61,580
Cumulative effect of accounting
change, net (a)...................... 16,471
Net income............................. $ 78,265 $ 98,454 $ 73,467 $ 67,476 $ 58,241 $ 61,580
Return on average common equity (b).... 11.34% 11.86% 11.63% 11.85% 11.04% 12.31%
</TABLE>
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
<PAGE>
<TABLE>
<CAPTION>
54
Potomac Edison
FINANCIAL AND OPERATING STATISTICS
Year Ended December 31
1995 1994 1993 1992 1991 1990
PROPERTY, PLANT, AND EQUIPMENT
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Gross.................................. $2,050,835 $1,978,396 $1,857,961 $1,698,711 $1,557,695 $1,454,250
Accumulated depreciation............... (729,653) (673,853) (632,269) (591,378) (546,867) (504,168)
Net.................................. $1,321,182 $1,304,543 $1,225,692 $1,107,333 $1,010,828 $ 950,082
GROSS ADDITIONS TO PROPERTY
(Thousands of Dollars)................... $ 92,240 $ 142,826 $ 179,433 $ 153,485 $ 116,589 $ 116,627
TOTAL ASSETS (Thousands of Dollars)........ $1,654,444 $1,629,535 $1,519,763 $1,355,385 $1,256,712 $1,140,623
CAPITALIZATION:
Amount (Thousands of Dollars):
Common stock........................... $ 667,242 $ 658,146 $ 626,467 $ 567,826 $ 480,931 $ 453,761
Preferred stock:
Not subject to mandatory redemption.. 16,378 36,378 36,378 36,378 56,378 56,378
Subject to mandatory redemption...... 25,200 26,400 28,005 29,280 30,555
Long-term debt and QUIDS............... 628,854 604,749 517,910 511,801 453,584 399,518
Total $1,312,474 $1,324,473 $1,207,155 $1,144,010 $1,020,173 $ 940,212
Ratios:
Common stock........................... 50.8% 49.7% 51.9% 49.6% 47.1% 48.3%
Preferred stock:
Not subject to mandatory redemption.. 1.3 2.7 3.0 3.2 5.5 6.0
Subject to mandatory redemption...... 1.9 2.2 2.5 2.9 3.2
Long-term debt and QUIDS............... 47.9 45.7 42.9 44.7 44.5 42.5
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--kW 2,072,292 2,072,292 2,076,592 2,076,592 2,077,192 2,076,292
KILOWATT-HOURS (Thousands)
Sales:
Residential............................ 4,377,416 4,214,997 4,144,958 3,822,387 3,753,884 3,561,824
Commercial............................. 2,213,052 2,136,081 2,091,930 1,954,025 1,912,848 1,818,789
Industrial............................. 5,485,220 5,339,737 5,194,909 4,979,219 4,881,835 4,928,433
Nonaffiliated utilities................ 4,420,313 3,194,580 3,860,791 5,394,006 5,649,050 6,818,528
Other, including affiliates............ 656,539 653,614 649,636 616,711 615,604 593,548
Total sales.......................... 17,152,540 15,539,009 15,942,224 16,766,348 16,813,221 17,721,122
Output:
Steam generation....................... 10,410,118 10,464,607 10,103,411 10,713,987 11,192,300 11,094,016
Hydro and pumped-storage generation.... 395,315 426,550 368,834 351,035 502,302 430,500
Pumped-storage input................... (452,151) (506,213) (433,885) (407,393) (593,879) (489,243)
Purchased power and exchanges, net..... 7,565,505 5,896,492 6,691,792 6,937,037 6,517,575 7,387,314
Losses and system uses................. (766,247) (742,427) (787,928) (828,318) (805,077) (701,465)
Total sales as above................. 17,152,540 15,539,009 15,942,224 16,766,348 16,813,221 17,721,122
CUSTOMERS
Residential.............................. 321,813 315,309 309,096 302,559 295,564 289,695
Commercial............................... 41,759 40,927 40,173 39,236 38,522 37,708
Industrial............................... 4,733 4,595 4,509 4,435 4,283 4,132
Other.................................... 543 524 510 510 501 471
Total customers........................ 368,848 361,355 354,288 346,740 338,870 332,006
RESIDENTIAL SERVICE:
Average use-
kWh per customer....................... 13,729 13,506 13,562 12,766 12,822 12,463
Average revenue-
dollars per customer................... 993.35 948.76 897.70 812.96 778.25 745.90
Average rate-
cents per kWh.......................... 7.24 7.02 6.62 6.37 6.07 5.98
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
55
West Penn
SUMMARY OF OPERATIONS
Year Ended December 31
(Thousands of Dollars)
1995 1994 1993 1992 1991 1990
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential.......................... $ 401,186 $ 376,776 $ 358,900 $ 321,871 $ 316,685 $ 284,691
Commercial........................... 224,144 207,165 194,773 177,697 172,924 154,999
Industrial........................... 356,937 330,739 309,847 293,910 274,896 253,184
Nonaffiliated utilities.............. 168,215 144,829 152,541 204,743 223,225 291,636
Other, including affiliates.......... 75,859 68,733 68,916 78,620 83,073 74,342
Total.............................. 1,226,341 1,128,242 1,084,977 1,076,841 1,070,803 1,058,852
Operation expense...................... 675,953 647,963 625,269 647,989 649,422 684,508
Maintenance............................ 118,162 111,841 96,706 93,067 87,717 77,516
Depreciation........................... 112,334 88,935 80,872 73,469 70,334 66,122
Taxes other than income................ 89,694 87,224 89,249 87,300 80,630 72,114
Taxes on income........................ 61,745 50,385 51,529 44,078 47,846 33,867
Allowance for funds used
during construction.................. (5,041) (10,777) (8,566) (8,276) (3,224) (2,729)
Interest charges....................... 67,902 60,274 60,585 55,592 51,977 49,268
Asset write-off, net................... 5,179
Other income, net...................... (12,287) (13,797) (12,728) (14,534) (15,077) (15,067)
Consolidated income before cumulative
effect of accounting change.......... 117,879 101,015 102,061 98,156 101,178 93,253
Cumulative effect of accounting
change, net (a)...................... 19,031
Consolidated net income................ $ 117,879 $ 120,046 $ 102,061 $ 98,156 $ 101,178 $ 93,253
Return on average common equity (b).... 11.46% 9.94% 11.49% 11.53% 12.66% 12.07%
</TABLE>
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
<PAGE>
<TABLE>
<CAPTION>
56
West Penn
FINANCIAL AND OPERATING STATISTICS
Year Ended December 31
1995 1994 1993 1992 1991 1990
PROPERTY, PLANT, AND EQUIPMENT
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Gross.................................. $3,097,522 $3,013,777 $2,803,811 $2,581,641 $2,409,005 $2,312,425
Accumulated depreciation............... (1,063,399) (1,009,565) (962,623) (904,906) (857,999) (809,674)
Net.................................. $2,034,123 $2,004,212 $1,841,188 $1,676,735 $1,551,006 $1,502,751
GROSS ADDITIONS TO PROPERTY
(Thousands of Dollars)................... $ 149,122 $ 260,366 $ 251,017 $ 204,409 $ 134,443 $ 128,762
TOTAL ASSETS (Thousands of Dollars)........ $2,771,164 $2,731,858 $2,544,763 $2,083,127 $2,006,309 $1,842,766
CAPITALIZATION:
Amount (Thousands of Dollars)
Common stock........................... $ 973,188 $ 955,482 $ 893,969 $ 782,341 $ 774,707 $ 723,567
Preferred stock........................ 79,708 149,708 149,708 149,708 109,708 109,708
Long-term debt and QUIDS............... 904,669 836,426 782,369 759,005 621,906 563,378
Total $1,957,565 $1,941,616 $1,826,046 $1,691,054 $1,506,321 $1,396,653
Ratios:
Common stock........................... 49.7% 49.2% 49.0% 46.3% 51.4% 51.8%
Preferred stock........................ 4.1 7.7 8.2 8.8 7.3 7.9
Long-term debt and QUIDS............... 46.2 43.1 42.8 44.9 41.3 40.3
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY-- kW:
Company-owned.......................... 3,671,408 3,671,408 3,589,408 3,589,408 3,589,408 3,589,408
Nonutility contracts (*)............... 138,000 138,000 133,000 133,000 133,000 133,000
KILOWATT-HOURS (THOUSANDS):
Sales:
Residential............................ 5,818,838 5,740,028 5,679,746 5,396,533 5,419,150 5,271,390
Commercial............................. 3,782,250 3,624,117 3,522,566 3,374,355 3,345,255 3,194,141
Industrial............................. 7,857,689 7,426,267 7,114,765 7,058,895 6,643,238 6,713,824
Nonaffiliated utilities................ 5,913,320 4,337,106 5,444,798 7,780,654 7,683,817 9,342,543
Other, including affiliates............ 1,621,745 1,530,853 1,821,189 2,247,844 2,485,366 2,426,414
Total sales.......................... 24,993,842 22,658,371 23,583,064 25,858,281 25,576,826 26,948,312
Output:
Steam generation....................... 18,143,822 17,750,267 17,949,335 19,066,445 19,602,129 19,590,731
Hydro and pumped-storage generation.... 581,353 673,195 600,497 592,895 775,798 688,517
Pumped-storage input................... (606,953) (684,715) (613,290) (599,729) (836,700) (689,186)
Purchased power and exchanges, net..... 8,192,623 6,119,757 6,967,752 8,139,496 7,373,185 8,428,158
Losses and system uses................. (1,317,003) (1,200,133) (1,321,230) (1,340,826) (1,337,586) (1,069,908)
Total sales as above................. 24,993,842 22,658,371 23,583,064 25,858,281 25,576,826 26,948,312
CUSTOMERS:
Residential.............................. 578,983 573,963 569,601 564,300 559,444 554,716
Commercial............................... 68,500 66,842 65,337 64,212 62,674 61,396
Industrial............................... 11,801 11,563 11,218 11,138 10,826 10,687
Other.................................... 598 586 576 569 692 680
Total customers........................ 659,882 652,954 646,732 640,219 633,636 627,479
RESIDENTIAL SERVICE:
Average use-
kWh per customer....................... 10,096 10,041 10,025 9,608 9,733 9,550
Average revenue-
dollars per customer................... 696.06 659.07 633.48 573.07 568.76 515.75
Average rate-
cents per kWh.......................... 6.89 6.56 6.32 5.96 5.84 5.40
</TABLE>
(*) Capability available through contractual arrangements with nonutility
generators.
<PAGE>
<TABLE>
<CAPTION>
57
AGC
STATISTICS
Year Ended December 31
SUMMARY OF OPERATIONS
(Thousands of Dollars)
1995 1994 1993 1992 1991 1990
<S> <C> <C> <C> <C> <C> <C>
Electric operating revenues............ $ 86,970 $ 91,022 $ 90,606 $ 96,147 $100,505 $104,482
Operation and maintenance expense...... 5,740 6,695 6,609 6,094 6,774 5,974
Depreciation........................... 17,018 16,852 16,899 16,827 16,778 16,756
Taxes other than income taxes.......... 5,091 5,223 5,347 5,236 4,563 4,712
Federal income taxes................... 13,552 14,737 13,262 14,702 15,455 16,458
Interest charges....................... 18,361 17,809 21,635 22,585 24,030 26,883
Other income, net...................... (16) (11) (328) (21) (24) (17)
Net Income........................... $ 27,224 $ 29,717 $ 27,182 $ 30,724 $ 32,929 $ 33,716
Return on average common equity........ 12.46% 13.14% 11.72% 12.79% 13.09% 12.78%
PROPERTY, PLANT, AND EQUIPMENT
(Thousands of Dollars):
Gross.............................. $836,894* $824,714 $824,904 $825,493 $822,332 $821,424
Accumulated depreciation........... (159,037) (143,965) (128,375) (114,684) (97,915) (81,514)
Net.............................. $677,857 $680,749 $696,529 $710,809 $724,417 $739,910
GROSS ADDITIONS TO PROPERTY
(Thousands of Dollars)............... $ 14,165* $ 1,065 $ 2,729 $ 3,251 $ 1,391 $ 1,214
TOTAL ASSETS (Thousands of Dollars).... $710,287 $714,236 $735,929 $727,820 $742,223 $757,084
CAPITALIZATION at Dec. 31:
Amount (Thousands of Dollars):
Common stock....................... $214,153 $222,729 $228,512 $235,530 $244,593 $254,664
Long-term debt..................... 249,709 267,165 277,196 287,139 299,502 311,461
Total $463,862 $489,894 $505,708 $522,669 $544,095 $566,125
Ratios:
Common stock....................... 46.2% 45.5% 45.2% 45.1% 45.0% 45.0%
Long-term debt..................... 53.8 54.5 54.8 54.9 55.0 55.0
Total 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
KILOWATT-HOURS (THOUSANDS):
Pumping energy supplied by parents... 1,390,019 1,564,044 1,384,912 1,340,111 1,906,477 1,567,896
Pumped-storage generation............ 1,081,112 1,218,446 1,079,985 1,047,015 1,504,310 1,233,782
</TABLE>
*Reflects a balance sheet reclassification of $12 million from deferred
charges to plant for a prior tax payment.
<PAGE>
58
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Page No.
APS 59
Monongahela 68
Potomac Edison 77
West Penn 87
AGC 95
<PAGE>
59
APS
Management Discussion & Analysis of Financial Condition
and Results of Operations
Review of Utility Operations
Earnings
Earnings in 1995 increased to $240 million ($2.00 per share) compared with
$220 million ($1.86 per share) in 1994, excluding in 1994 the cumulative
effect of an accounting change to record unbilled revenues. The increase
resulted primarily from additional retail revenues due to increased kilowatt--
hour (kWh) sales and previously reported rate increases. These revenue
increases were offset in part by restructuring charges and inventory write-offs
in 1995 of $14.1 million after tax ($.12 per share) and higher expenses.
Earnings in 1994 included a charge of $5.3 million after tax ($.05 per share)
related to asset write-offs. Consolidated net income in 1993 was $216 million
($1.88 per share). Consolidated net income in 1994 also reflects higher retail
revenues from increased kWh sales and rate increases, offset in part by higher
expenses.
Restructuring activities in 1995 were initiated by the System in response to
the competitive environment emerging in the electric utility industry. The
subsidiaries are restructuring many of their functions to strengthen their
competitive position and improve their cost structure. During 1995, reenginee-
ring of the Bulk Power Supply department was substantially completed and
process redesign is expected to be substantially completed in 1996 for the
remainder of the System. Downsizing was not a specific goal of the restructur-
ing efforts but, as a consequence of process redesign and elimination of
duplicate positions, approximately 200 employees have been placed in a
staffing force pending reassignment or layoff. In addition, about 130 fewer
employees will be required in the power station work force by the end of 1997,
and employee reductions are also likely to result from reengineering in other
areas. The charges recorded in 1995 in connection with restructuring activi-
ties reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs. These costs will be recovered
through future cost savings.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial
customers are shown on page 50. Such kWh sales increased 3.9% and 2.8% in 1995
and 1994, respectively. The increases in revenues from sales to residential,
commercial, and industrial customers resulted from the following:
Changes from Prior Year
(Millions of Dollars) 1995 1994
Increased kWh sales $ 56.2 $ 23.6
Rate changes:
Pennsylvania 50.2 22.7
Maryland 17.7 11.9
West Virginia 19.3 9.7
Virginia (1.8) 8.5
Ohio .5
85.9 52.8
Fuel and energy cost
adjustment clauses* (2.8) 48.3
Other .6 4.3
$139.9 $129.0
* Changes in revenues from fuel and energy cost adjustment clauses have little
effect on consolidated net income.
<PAGE>
60
The increase in kWh sales in 1995 was largely attributable to industrial and
commercial sales. Industrial sales increased 4.2% and 4.4% in 1995 and 1994,
respectively. The 4.7% increase in commercial sales in 1995 and the 2.2%
increase in 1994 reflect growth in the number of customers and in 1995 also
reflects increased customer usage. These increases continue to reflect a trend
of economic growth in the service territory. In 1995 the subsidiaries
implemented a new Major Accounts Program which focuses on enhancing the
working relationships with the System's largest customers. The goal of the
program is to assure, through superior service, that Allegheny Power remains
the energy supplier for these major customers.
Residential kWh sales increased 3% in 1995 and .9% in 1994. The rate of
growth in the number of residential customers has remained constant at 1.2%
annually in 1995, 1994, and 1993. However, the impact of weather on customer
usage continues to produce fluctuations in residential sales. In 1995,
decreased sales due to mild weather in the first and second quarters were more
than offset by extremely hot summer weather and cooler than normal winter
weather in November and December as compared to 1994. The 1994 residential use
was down slightly from 1993 levels reflecting a decrease in both heating and
cooling degree days.
Rate case decisions in all jurisdictions, representing revenue increases in
excess of $125 million on an annual basis, have been obtained, most of them
effective in late 1994. These included recovery of the remaining carrying
charges on investment, depreciation, and all operating costs required to
comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other
increasing levels of expenses. Additional base rate increases are not expected
to be necessary for the next several years. However, future purchased power
expenses related to a qualified facility under the Public Utility Regulatory
Policies Act of 1978 (PURPA), to be completed in late 1999, may make it
necessary to increase rates at that time.
KWh sales to and revenues from nonaffiliated utilities are comprised of the
following items:
<TABLE>
<CAPTION>
1995 1994 1993
KWh sales (Billions):
<S> <C> <C> <C>
From subsidiaries' generation .5 1.1 1.2
From purchased power 13.0 8.8 11.2
13.5 9.9 12.4
Revenues (Millions):
From subsidiaries' generation $ 13.0 $ 29.0 $ 28.5
From sales of purchased power 372.0 302.6 318.2
$385.0 $331.6 $346.7
</TABLE>
Sales from subsidiaries' generation in 1995 decreased because of growth in
kWh sales to retail customers, which reduced the amount available for sale,
and because of continuing price competition. The generation tax imposed in
West Virginia, which in prior years was a significant factor affecting the
subsidiaries' ability to compete in the market for sales to nonaffiliated
utilities, was favorably amended effective in June 1995 to change the basis of
the tax from generation to generating capacity. Sales of purchased power vary
depending on the availability of other utilities' generating equipment, demand
for energy, and price competition. In the future, some of these transactions
may be made under new transmission tariffs described below. About 95% of the
aggregate benefits from sales to nonaffiliated utilities are passed on to
retail customers and have little effect on consolidated net income.
<PAGE>
61
The increase in other revenues in 1995 and 1994 resulted primarily from
increased revenues from wholesale customers (cooperatives and municipalities
who own their own distribution systems and who buy all or part of their bulk
power needs from the subsidiaries under regulation by the Federal Energy
Regulatory Commission). Under the National Energy Policy Act of 1992, these
customers obtained the ability to choose the bulk power supplier of their
choice by the requirement that transmission-owning utilities must provide
transmission service. In 1995, rate cases for wholesale customers were
completed with the result that such customers, with revenues representing
about 97% of the $46 million in annual wholesale revenues, agreed to negotiat-
ed rate increases and signed contracts to remain as System customers for
periods ranging from three to seven years. One customer representing the
remaining 3% of annual revenues selected an 18-month contract at higher rates.
In the event that this customer selects another supplier, the subsidiaries
would retain transmission revenues with the result that any reduction in
consolidated net income would not be significant.
Other revenues in 1995 also reflect an increase in standard transmission
service revenues. See page 66 under Competition in Core Business for informa-
tion about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the Federal
Energy Regulatory Commission (FERC) in 1995. Effective in 1996, pursuant to
the intentions of the Mega-NOPR, the subsidiaries eliminated their Standard
Transmission Service tariff for new service transactions, and began using two
new transmission service tariffs which qualify as required open access tariffs
- - a Network tariff and a Point-to-Point tariff. The FERC accepted the filing
of the new tariffs subject to hearings in the summer of 1996 and modification
pending final Mega-NOPR rules. The subsidiaries are using the new tariffs in
the interim, subject to refund. In addition, the subsidiaries have a Standard
Generation Service tariff accepted by the FERC under which the subsidiaries
make available bundled, nonfirm generation services with associated transmis-
sion services. Substantially all of the benefits of these sales of transmis-
sion and generation services to customers outside the service territory are
passed through to retail customers and, as a result, have little effect on
consolidated net income. While this procedure will continue to apply to
similar sales under the new tariffs, the subsidiaries may petition to revise
the procedure in the future.
Operating Expenses
The 7% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers. Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the consolidated financial statements, with the result that
changes in fuel expenses have little effect on consolidated net income.
"Purchased power and exchanges, net" represents power purchases from and
exchanges with other utilities and purchases from qualified facilities under
PURPA, and is comprised of the following items:
<TABLE>
<CAPTION>
(Millions of Dollars) 1995 1994 1993
Purchased power:
<S> <C> <C> <C>
For resale to other utilities $332.9 $267.1 $280.9
From PURPA generation 129.3 134.0 105.2
Other 48.8 40.4 33.8
Total power purchased 511.0 441.5 419.9
Power exchanges, net (.3) ( .6) (2.5)
$510.7 $440.9 $417.4
</TABLE>
The amount of power purchased from other utilities for use by subsidiaries
and for resale to other utilities depends upon the availability of subsidiar-
ies' generating equipment, transmission capacity, and fuel, and their cost of
<PAGE>
62
generation and the cost of operations of other utilities from which such
purchases are made. The primary reason for the fluctuations in purchases for
resale to other utilities is described under Sales and Revenues above. The
decrease in purchases from PURPA generation in 1995 was due primarily to a
contractual reduction in the energy rate effective in June 1995 for the Grant
Town PURPA project. American Bituminous Power Partners, L.P., the developer of
the Grant Town project, has filed an emergency petition with the Public
Service Commission of West Virginia for interim relief to have its former
energy rate reinstated. Monongahela Power has filed objections to this
petition. The increase in purchases from PURPA generation in 1994 reflects
generation from the Grant Town PURPA project beginning in late 1993. As
reported under Sales and Revenues, an agreement has been reached with a
proposed facility to commence purchasing generation in 1999. This project and
others may significantly increase the costs of power purchases passed on to
customers. None of the subsidiaries' purchased power contracts is capitalized
since there are no minimum payment requirements absent associated kWh
generation. Other purchased power continued to increase in 1995 because of
increased sales to retail customers and the availability of more economic
energy. The cost of power purchased for use by the subsidiaries, including
power from PURPA generation, is mostly recovered from customers currently
through the regular fuel and energy cost recovery procedures followed by the
subsidiaries' regulatory commissions, and is primarily subject to deferred
power cost procedures with the result that changes in such costs have little
effect on consolidated net income.
In January 1996, West Penn and the developers of a proposed Shannopin PURPA
project reached agreement to terminate the project and all pending litigation,
at a buy out price of $31 million. The agreement is subject to Pennsylvania
Public Utility Commission (PUC) approval of recovery of the buy out price by
West Penn by no later than March 31, 1999. The agreement was filed with the
PUC in February 1996 along with a request for expedited approval.
The increase in other operation expense in 1995 resulted primarily from
restructuring charges which are described in Note B to the consolidated
financial statements on page 112. Additional restructuring charges will be
incurred in 1996 as the subsidiaries complete their reengineering process.
Other operation expense in 1996 and thereafter is expected to reflect the
benefits of savings related to the restructuring activities. The 1994 increase
in other operation expense resulted primarily from a decision to increase the
allowances for uncollectible accounts ($9 million), increases in salaries and
wages ($5 million) and employee benefit costs, primarily pension expense ($6
million) and other postretirement benefits ($3 million), and provisions for
environmental liabilities ($3 million). Allowances for uncollectible accounts
were increased in 1994 due to an increase in aged outstanding receivables
caused primarily by Pennsylvania rate regulations which make it difficult if
not impossible to curtail service to non-paying customers. It is expected that
the allowance for these uncollectible accounts will be increased in the future
because of increasing accounts receivables in arrears. The increase in pension
expense occurred because the subsidiaries in 1994 discontinued the practice of
deferring pension expense in Pennsylvania and West Virginia to reflect rate
case decisions in those states. Pension expense in 1994 also includes a charge
of $3.1 million for write-off of prior deferrals in West Virginia because
recovery of those deferrals was denied.
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. The
subsidiaries are also experiencing, and expect to continue to experience,
increased expenditures due to the aging of their power stations. 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. Maintenance expense in 1995
includes a charge of about $7 million for inventory write-offs described in
<PAGE>
63
Note B to the consolidated financial statements on page 112 and $3 million due
to maintenance expense for the Harrison scrubbers which went into service in
late 1994. Maintenance expense for the scrubbers is expected to increase since
the warranty period has expired.
Depreciation expense increases resulted primarily from additions to electric
plant. The subsidiaries began depreciating the Harrison scrubbers in mid-Nove-
mber 1994, amounting to $32 million annually. Future depreciation expense
increases for utility operations are expected to be less than historical
increases because of reduced levels of proposed capital expenditures.
The increase in taxes other than income in 1995 and 1994 was due primarily
to increases in gross receipts taxes resulting from higher revenues from
retail customers. In 1995 this increase was offset in part by a decrease in
West Virginia Business and Occupation (B&O) taxes resulting from an amendment
in the B&O tax law effective June 1995, which changed the basis for this tax
from generation to generating capacity.
The net increase of $24 million in federal and state income taxes in 1995
resulted primarily from an increase in income before taxes ($16 million) and
an increase in reversals of prior year depreciation benefits for which
deferred taxes were not then provided ($6 million). The net increase in 1994
of $2 million resulted primarily from an increase in income before taxes. Note
C to the consolidated financial statements provides a further analysis of
income tax expenses.
The combined decreases in allowances for funds used during construction in
1995 and 1994 of $11 million and $2 million, respectively, reflect decreases
in construction expenditures upon substantial completion of the compliance
program for Phase I of the CAAA. The increase in other income, net, of $5
million in 1995 was due primarily to income from demand-side management
programs. During 1995, Potomac Edison continued its participation in the
collaborative process for demand-side management in Maryland. Program costs,
including lost revenues and rebates, are deferred as a regulatory asset and
are being recovered through an energy conservation surcharge over a seven-year
period. The balance in the regulatory asset for this program is $16 million as
of December 31, 1995. Other income, net, in 1994 reflects the write-off of
$5.3 million net of income taxes of previously accumulated costs related to
future facilities which are no longer considered meaningful in the industry's
more competitive environment.
In 1995 interest on long-term debt increased $14 million due primarily to
the new security issues in 1994 and the timing of the refinancing of $245
million of first mortgage bonds and $93 million of pollution control revenue
notes in 1995. Dividends on preferred stock decreased $5 million in 1995 due
primarily to the redemption of preferred stock issues refinanced with $155.5
million of Quarterly Income Debt Securities. Other interest expense reflects
changes in the levels of short-term debt maintained by the companies through-
out the year, as well as the associated interest rates.
Environmental and Other Issues
In the normal course of business, the subsidiaries are subject to various
contingencies and uncertainties relating to their operations and construction
programs, including cost recovery in the regulatory process, laws, regulations
and uncertainties related to environmental matters, and legal actions.
Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements. The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide and two million tons of nitrogen oxides (NOx)
from 1980 emission levels, to be completed in two phases, Phase I and Phase
II. Five coal-fired System plants are affected in Phase I and the remaining
plants and units reactivated in the future will be affected in Phase II.
Installation of scrubbers at the Harrison Power Station was the strategy
undertaken to meet the required SO[2] emission reductions for Phase I
(1995-1999). Continuing
<PAGE>
64
studies will determine the compliance strategy for Phase II (2000 and beyond).
Studies to evaluate cost effective options to comply with Phase II SO[2]
limits, including those which may be available from the use of the subsidiaries'
banked emission allowances and from the emission allowance trading market,
are continuing. It is expected that burner modifications at possibly all
stations will satisfy the NOx emission reduction requirements for the acid
rain (Title IV) provisions of the CAAA. Additional post-combustion controls
may be mandated in Maryland and Pennsylvania for ozone nonattainment (Title I)
reasons. Continuous emission monitoring equipment has been installed on all
Phase I and Phase II units.
The subsidiaries previously reported that the Environmental Protection
Agency had identified them and approximately 875 others as potentially
responsible parties in a Superfund site subject to cleanup. The subsidiaries
have also been named as defendants along with multiple other defendants in
pending asbestos cases involving one or more plaintiffs. The 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.
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective
in 1996. SFAS No. 121 establishes standards for the impairment of long-lived
assets and certain identifiable intangibles and requires companies to
recognize an impairment loss if the expected future undiscounted cash flows
are less than the carrying amount of an asset. The Company and its subsidiar-
ies do not believe at this time that adoption of this standard will have a
materially adverse effect on their financial position.
Financial Condition and Requirements
Liquidity and Capital Requirements
To meet the System companies' need for cash 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 internal-
ly 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 financing depend upon
the financial health of the companies seeking those funds.
Construction expenditures of the regulated subsidiaries in 1995 were $319
million and for 1996 and 1997 are estimated at $279 million and $305 million,
respectively. In 1995, these expenditures included $36 million for compliance
with the CAAA. The 1996 and 1997 estimated expenditures include $7 million and
$20 million, respectively, for additional CAAA compliance costs. The Harrison
scrubbers, which were constructed for compliance with Phase I of the CAAA,
were completed on schedule in late 1994 and the final cost was approximately
24% below the original budget. Expenditures in the future to cover the costs
of compliance with Phase II of the CAAA may be significant. Based on current
forecasts and considering the reactivation of capacity in cold reserve, peak
diversity exchange arrangements, demand-side management and conservation
programs, and contracted PURPA capacity, it is not anticipated that the
regulated subsidiaries will require new generating capacity until the year
2000 or beyond. The regulated subsidiaries also have additional capital
requirements for debt maturities (see Note H to the consolidated financial
statements). The Company will have additional capital requirements in the
future related to nonutility investments of AYP Capital which are described
under Nonutility Business on page 67.
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65
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $281 million in 1995 compared with $246 million in
1994. Because of the new rate case authorizations effective in late 1994 and
1995 and reduced levels of capital expenditures, the regulated subsidiaries
were able to finance approximately 88% of their capital expenditure program
through internal cash generation in 1995, as compared to 48% in 1994. This
ratio is expected to continue to increase over the next several years for
utility investments. See page 67 for a description of future nonutility
investments. Dividends paid on common stock in 1995 increased to $1.65 per
share compared with $1.64 in 1994. However, the dividend payout ratio
decreased from 88%, excluding the cumulative effect of the accounting change
in 1994, to 83% in 1995.
As capital-intensive electric utilities, the regulated subsidiaries are
affected by the rate of inflation. The inflation rate over the past several
years has been relatively low and has not materially affected their financial
position. However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years.
Fuel inventory provided a source of cash in 1995 ($12 million), primarily
related to lower fuel prices attained through renegotiations of fuel contracts
effective in January 1995 and the ability to use lower-cost, high-sulfur coal
at the Harrison Power Station because of the new scrubbers. In 1994, fuel
inventory represented a use of cash ($13 million) as it returned to a higher
level after selective mine shutdowns during contract renegotiations in 1993.
The decrease in operating and construction inventory in 1995 resulted from the
write-off of obsolete and slow-moving inventory. In connection with ongoing
restructuring activities and consolidation of facilities, the subsidiaries are
reevaluating inventory management objectives to take advantage of centralized
storerooms serving several facilities and to improve turnover ratios.
Financings
During 1995, the Company issued 1,407,855 shares of common stock under its
Dividend Reinvestment and Stock Purchase Plan (DRISP), and Employee Stock
Ownership and Savings Plan (ESOSP) for $35.0 million. The subsidiaries
refinanced $338 million of debt securities with new debt securities having
lower interest rates and refinanced preferred stock issues totaling $155.5
million with Quarterly Income Debt Securities (QUIDS). Under certain circum-
stances the interest payments on QUIDS may be deferred for a period of up to
20 consecutive quarters. Debt redemption costs of refinancings are amortized
over the life of the associated new securities. Due to the significant number
of refinancings which have occurred over the past four years, this balance is
now $57 million. Reduced future interest expense will more than offset these
expenses. Preferred stock redemption costs of $5.5 million were charged
directly to retained earnings.
Short-term debt is used to meet temporary cash needs until the timing is
considered appropriate to issue long-term securities. Short-term debt
increased $74 million to $200 million in 1995. At December 31, 1995, unused
lines of credit with banks were $173 million. In addition, a multi-year credit
program established in 1994 provides the subsidiaries with the ability to
borrow on a standby revolving credit basis up to $300 million. After the
initial three-year term, the program agreement provides that the maturity date
may be extended in one-year increments. There were no borrowings under this
facility in 1995. During 1996, the subsidiaries anticipate meeting their
capital requirements through a combination of internally generated funds, cash
on hand, and short-term borrowing as necessary. The Company plans to continue
DRISP/ESOSP common stock sales. The subsidiaries anticipate that they will be
able to meet their future cash needs through internal cash generation and
external financings, as they have in the past. See page 67 for information on
financing requirements for proposed nonutility investments.
<PAGE>
66
Changes in the Electric Utility Industry
Competitive forces within the electric utility industry continued to
increase in 1995. As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory. Electric utilities must also compete with suppliers
of other forms of energy. Growing competitive challenges due to legislative,
economic, and technological changes, and Allegheny Power's ability to meet
these challenges, have been a major focal point in 1995.
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by the
National Energy Policy Act of 1992 (EPACT), which permits wholesale genera-
tors, utility-owned and otherwise, and wholesale customers to request from
owners of bulk power transmission facilities a commitment to supply transmis-
sion services. EPACT is the first legislative action to permit wholesale
customers within a utility's franchised service territory to seek alternative
providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995 which
intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators. The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power. The Mega-NOPR provides that
electric utilities would be able to recover stranded costs (costs of facili-
ties made uneconomic by wholesale transmission access). The FERC has not yet
issued a final rulemaking on these issues.
State regulators in Ohio, Pennsylvania, and Virginia are in various stages
of proceedings to evaluate the feasibility of retail competition. The Maryland
commission has completed its investigation and issued an order which found
that while competition in the electric wholesale market should be encouraged,
retail competition is not in the public interest at this time. The regulated
subsidiaries have filed responses in these proceedings which emphasize the
need to move cautiously toward retail competition in order to protect the
reliability of service to retail customers, and to insure that utilities
without excess generating capacity, like the regulated subsidiaries, are not
placed at a competitive disadvantage by permitting utilities with excess
capacity to dump energy at low marginal cost while keeping their own customers
captive through high stranded investment fees. Attempts at variations of
retail wheeling have been authorized in some states, and various municipali-
ties around the country that are not wholesale customers are exploring ways to
become wholesale customers to obtain the ability to choose their electric
supplier. In 1995, the Department of Defense proposed that it be granted
competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale markets and
the increasing possibility of retail competition have created greater planning
uncertainty and risks for the Company. In response, the Company is continuing
to develop a number of strategies to retain its existing customers and to
expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost status
by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
5. Expanding core business into nonutility activities (see below)
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67
The Company believes it is taking necessary actions to position itself to
meet current and future competitive challenges.
Nonutility Business
To help meet the challenges of the competitive environment in the electric
utility industry, Allegheny Power is broadening its operations into nonutility
businesses. In 1994, AYP Capital was formed to pursue opportunities in
unregulated markets in order to strengthen the long-term competitiveness and
profitability of the Company. AYP Capital's primary objectives are to develop
new energy-related services businesses and to pursue wholesale unregulated
power generation. The most significant project is an agreement with Duquesne
Light Company to purchase for about $170 million its 50% interest (276
megawatts) in Unit No. 1 of the Fort Martin Power Station. The rest of the
station is owned by the Company's regulated subsidiaries. AYP Capital intends
to operate its share of the unit as an exempt wholesale generator and sell the
output at market rates. After necessary approvals, AYP Capital expects a
closing by late 1996. Various financing alternatives for this acquisition are
being considered. Upon commencement of operations, AYP Capital will incur
depreciation expense and other operating expenses related to Fort Martin.
AYP Capital has also committed to invest up to $10 million in two limited
partnerships. AYP Capital has also invested in APS Cogenex, a joint venture
limited liability company which provides services to improve the energy
efficiency of consumer facilities in the five states in which Allegheny Power
provides electric service plus the District of Columbia. AYP Capital intends
to provide financing to consumers that undertake capital improvements
necessary to achieve energy efficiency. AYP Capital will continue to evaluate
investment opportunities with potentially significant additional capital
investments in the future. AYP Capital's total investments as of December 31,
1995, were $1.1 million.
Although nonutility investments offer the potential for earning returns in
excess of regulated investments, they generally involve a higher degree of
risk. AYP Capital intends to manage these risks by diversifying its invest-
ments and by investing where there is an appropriate balance of risk and
reward.
The ability of AYP Capital to engage and compete in nonutility businesses
will be impeded unless the Public Utility Holding Company Act of 1935 (PUHCA)
is repealed or revised. PUHCA prevents or significantly disadvantages the
Company and other non-exempt holding companies from diversifying into
utility-related or nonutility businesses, a disadvantage not imposed on exempt
holding companies and other competitors. The Company has been active in
seeking repeal or reform of this law.
<PAGE>
68
Monongahela
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income in 1995 increased to $66.7 million compared with $59.9 million in
1994, excluding in 1994 the cumulative effect of an accounting change to
record unbilled revenues. The increase resulted primarily from additional
retail revenues due to increased kilowatt-hour (kWh) sales and previously
reported rate increases. These revenue increases were offset in part by
restructuring charges and inventory write-offs in 1995 of $3.3 million after
tax and higher expenses. Net income in 1993 was $61.7 million. The decrease
in 1994 resulted primarily from higher expenses, including taxes, pension
expense, and depreciation.
Restructuring activities in 1995 were initiated by the System in
response to the competitive environment emerging in the electric utility
industry. The System, including the Company, is restructuring many of its
functions to strengthen its competitive position and improve its cost
structure. During 1995, reengineering of the Bulk Power Supply department in
the affiliated Allegheny Power Service Corporation was substantially completed
and process redesign is expected to be substantially completed in 1996 for the
remainder of the System. Downsizing was not a specific goal of the restruc-
turing efforts, but as a consequence of process redesign and elimination of
duplicate positions, approximately 200 System employees have been placed in a
staffing force pending reassignment or layoff. In addition, about 130 fewer
System employees will be required in the power station work force by the end
of 1997, and employee reductions are also likely to result from reengineering
in other areas. The charges recorded in 1995 in connection with restructuring
activities reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs. It is expected that these
costs will be recovered through future cost savings.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial
customers are shown on pages 51 and 52. Such kWh sales increased 4.5% and
3.2% in 1995 and 1994, respectively. The increases in revenues from sales to
residential, commercial, and industrial customers resulted from the following:
Changes
from Prior Year
1995 1994
(Millions of Dollars)
Increased kWh sales.............................. $21.6 $ 3.8
Rate increases:
West Virginia.................................. 17.1 7.9
Ohio........................................... .5
17.6 7.9
Fuel and energy cost adjustment clauses*......... (3.1) 13.0
Other............................................ .6 1.0
$36.7 $25.7
*Changes in revenues from fuel and energy cost adjustment clauses have little
effect on net income.
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69
The increase in kWh sales in 1995 was largely attributable to
commercial and industrial sales. Industrial sales increased 3.5% and 6.1% in
1995 and 1994, respectively. The 6.5% increase in commercial sales in 1995
and the 1.2% increase in 1994 reflect growth in the number of customers and in
1995 also increased customer usage. These increases continue to reflect a
trend of economic growth in the service territory. In 1995, the Company
implemented a new Major Accounts Program which focuses on enhancing the
working relationships with its largest customers. The goal of the program is
to assure, through superior service, that the Company remains the energy
supplier for these major customers.
Residential kWh sales increased 5.0% in 1995 and decreased .6% in
1994. The rate of growth in the number of residential customers has remained
constant at 1% annually in 1995, 1994, and 1993. However, the impact of
weather on customer usage continues to produce fluctuations in residential
sales. In 1995, decreased sales due to mild weather in the first and second
quarters were more than offset by extremely hot summer weather and cooler than
normal winter weather in November and December as compared to 1994. The 1994
residential use was down slightly from 1993 levels reflecting a decrease in
both heating and cooling degree days.
Rate case decisions in all jurisdictions, representing revenue
increases in excess of $35 million on an annual basis, have been obtained.
About $29 million became effective in 1994 and $6 million in Ohio became
effective on November 9, 1995. These included recovery of the remaining
carrying charges on investment, depreciation, and all operating costs required
to comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and
other increasing levels of expenses. Additional base rate increases are not
expected to be necessary for the next several years.
KWh sales to and revenues from nonaffiliated utilities are comprised
of the following items:
1995 1994 1993
KWh sales (Billions):
From Company generation................. .1 .3 .3
From purchased power.................... 3.1 2.1 2.8
3.2 2.4 3.1
Revenues (Millions):
From Company generation................. $ 2.7 $ 7.7 $ 8.4
From sales of purchased
power................................. 88.2 72.0 77.6
$90.9 $79.7 $86.0
Sales to nonaffiliated companies from the Company's generation in 1995
decreased because of growth in kWh sales to retail customers which reduced the
amount available for sale and because of continuing price competition. The
generation tax imposed in West Virginia, which in prior years was a signifi-
cant factor affecting the Company's ability to compete in the market for sales
to nonaffiliated companies, was favorably amended effective in June 1995 to
change the basis of the tax from generation to generating capacity. Sales of
purchased power vary depending on the availability of other companies'
<PAGE>
70
generating equipment, demand for energy, and price competition. In the
future, some of these transactions may be made under new transmission tariffs
described below. About 90% of the aggregate benefits from sales to nonaffili-
ated companies and to affiliates included in other revenues described below,
are passed on to retail customers and have little effect on net income.
The decrease in other revenues in 1995 resulted primarily from a
decrease in sales of energy and spinning reserve to affiliated companies,
offset in part by increased revenues from wholesale customers (cooperatives
and municipalities who own their own distribution systems and who buy all or
part of their bulk power needs from the Company under regulation by the
Federal Energy Regulatory Commission). Under the National Energy Policy Act
of 1992, these customers obtained the ability to choose the bulk power
supplier of their choice by the requirement that transmission-owning utilities
must provide transmission service. In 1994, a rate case for wholesale
customers was completed with the result that such customers, representing
about $4.5 million in annual wholesale revenues, agreed to negotiated rate
increases and signed contracts to remain as the Company's customers for five
years. The increase in 1994 resulted from continued increases in sales of
capacity, energy, and spinning reserve to affiliated companies because of
additional capacity and energy available from qualified facilities under the
Public Utility Regulatory Policies Act of 1978 (PURPA).
Other revenues in 1995 also reflect an increase in standard transmis-
sion service revenues. See page 76 under Competition in Core Business for
information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the
Federal Energy Regulatory Commission (FERC) in 1995. Effective in 1996,
pursuant to the intentions of the Mega-NOPR, the Company eliminated its
Standard Transmission Service tariff for new service transactions, and began
using two new transmission service tariffs which qualify as required open
access tariffs - a Network tariff and a Point-to-Point tariff. The FERC
accepted the filing of the new tariffs subject to hearings in the summer of
1996 and modification pending final Mega-NOPR rules. The Company is using the
new tariffs in the interim, subject to refund. In addition, the Company has a
Standard Generation Service tariff accepted by the FERC under which the
Company makes available bundled, nonfirm generation services with associated
transmission services. About 90% of the benefits of these sales of transmis-
sion and generation services to customers outside the service territory are
passed through to retail customers and as a result have little effect on net
income. While this procedure will continue to apply to similar sales under
the new tariffs, the Company may petition to revise the procedure in the
future.
Operating Expenses
The 9% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers. Fuel expenses increased
4% in 1994 due primarily to an increase in kWh generated. Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the financial statements, with the result that changes in fuel
expenses have little effect on net income.
<PAGE>
71
"Purchased power and exchanges, net" represents power purchases from
and exchanges with nonaffiliated utilities and purchases from qualified
facilities under PURPA, capacity charges paid to Allegheny Generating
Company (AGC), an affiliate partially owned by the Company, and other
transactions with affiliates made pursuant to a power supply agreement whereby
each company uses the most economical generation available in the System at
any given time, and is comprised of the following items:
1995 1994 1993
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other companies........ $ 79.1 $ 63.7 $ 68.6
From PURPA generation................ 64.6 68.3 55.7
Other................................ 11.6 9.4 8.1
Power exchanges, net................... .1 (.2) (.6)
Affiliated transactions:
AGC capacity charges................... 20.6 20.1 23.3
Energy and spinning
reserve charges...................... .4 .5 .5
$176.4 $161.8 $155.6
The amount of power purchased from nonaffiliated companies for use by
the Company and for resale to nonaffiliated companies depends upon the
availability of the Company's generating equipment, transmission capacity, and
fuel, and its cost of generation and the cost of operations of nonaffiliated
companies from which such purchases are made. The primary
reason for the fluctuations in purchases for resale to nonaffiliated companies
is described under Sales and Revenues above. The decrease in purchases from
PURPA generation in 1995 was due primarily to a contractual reduction in the
energy rate effective in June 1995 for the Grant Town PURPA project. American
Bituminous Power Partners, L.P., the developer of the Grant Town project, has
filed an emergency petition with the Public Service Commission of West
Virginia for interim relief to have its former energy rate reinstated. The
Company has filed objections to this petition. The increase in purchases from
PURPA generation in 1994 reflects generation from the Grant Town PURPA project
beginning in late 1993. None of the Company's purchased power contracts is
capitalized since there are no minimum payment requirements absent associated
kWh generation. Other purchased power continued to increase in 1995 because
of increased sales to retail customers and the availability of more economic
energy. The cost of power and capacity purchased for use by the Company,
including power from PURPA generation and affiliated transactions, is mostly
recovered from customers currently through the regular fuel and energy cost
recovery procedures followed by the Company's regulatory commissions and is
primarily subject to deferred power cost procedures with the result that
changes in such costs have little effect on net income.
The increase in other operation expense in 1995 resulted primarily
from restructuring charges which are described in Note B to financial
statements on page 125. Additional restructuring charges will be incurred in
1996 as the Company and its affiliates complete their reengineering process.
Other operation expense in 1996 and thereafter is expected to reflect the
benefits of savings related to the restructuring activities. The 1994
increase in other operation expense resulted primarily from increases in
pension expense ($4 million), allowance for uncollectible accounts ($1
million), and salaries and wages ($1 million). The increase in pension
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72
expense occurred because the Company in 1994 discontinued the practice of
deferring pension expense in West Virginia to reflect a rate case decision in
that state, and wrote off $2.5 million of prior deferrals in West Virginia
because recovery of those deferrals was denied.
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.
The Company is also experiencing, and expects to continue to experience,
increased expenditures due to the aging of its power stations. 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. Maintenance expense in 1995
includes a charge of about $1.4 million for inventory write-offs described in
Note B to the financial statements on page 125. Maintenance expense for the
Harrison scrubbers which went into service in late 1994 is expected to
increase since the warranty period has expired.
The depreciation expense decrease in 1995 was the net result of a
decrease in depreciation rates in West Virginia concurrent with the West
Virginia base rate case effective in November 1994, offset by additions to
electric plant. The Company began depreciating the Harrison scrubbers in mid-
November 1994 amounting to approximately $8 million annually. A further
reduction of about $4 million annually, effective in January 1996, will result
in depreciation rates for the Company which are comparable to those of other
electric utilities, particularly those providing service in West Virginia.
The decrease in taxes other than income in 1995 was primarily due to a
decrease in West Virginia Business and Occupation Taxes (B&O) resulting from
an amendment in the B&O tax law effective June 1995, which changed the basis
for this tax from generation to generating capacity. The 1994 increase in
taxes other than income was primarily due to an increase in B&O taxes
resulting from prior period adjustments recorded in 1993.
The net increase of $11 million in federal and state income taxes in
1995 resulted from an increase in income before taxes ($7 million) and changes
in the provisions for prior years ($4 million). The net decrease in 1994 of $3
million resulted primarily from a decrease in income before taxes. Note C to
the financial statements provides a further analysis of income tax expenses.
The combined decreases in allowances for borrowed and other than
borrowed funds used during construction (AFUDC) in 1995 and 1994 of $2 million
and $3 million, respectively, reflect decreases in construction expenditures
upon substantial completion of the compliance program for Phase I of the CAAA.
The increase in other income, net, of $1 million in 1995 reflects an increase
in the deferral of carrying charges on CAAA expenditures in Ohio until the
base rate increase became effective in November 1995, proceeds from the sale
of timber, and interest income on a tax refund. The changes in other income,
<PAGE>
73
net, in 1994 resulted primarily from the Company's share of earnings of AGC
(see Note E to the financial statements).
In 1995, interest on long-term debt increased $2 million due primarily
to the new security issues in 1994 and the timing of the refinancing of $70
million of first mortgage bonds and $25 million of pollution control revenue
notes in 1995. The increase also reflects interest on $40 million of
Quarterly Income Debt Securities issued in 1995 to refund preferred stock
issues. 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.
Environmental and Other Issues
In the normal course of business, the Company is subject to various
contingencies and uncertainties relating to its operations and construction
programs, including cost recovery in the regulatory process, laws, regulations
and uncertainties related to environmental matters, and legal actions.
Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements. The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides
(NOx) from 1980 emission levels, to be completed in two phases, Phase I and
Phase II. Four coal-fired Company 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 to meet the required SO[2]
emission reductions for Phase I (1995-1999). Continuing studies will
determine the compliance strategy for Phase II (2000 and beyond). Studies to
evaluate cost effective options to comply with Phase II SO[2] limits,
including those which may be available from the use of the Company's banked
emission allowances and from the emission allowance trading market, are
continuing. It is expected that burner modifications at possibly all stations
will satisfy the NOx emission reduction requirements for the acid rain (Title
IV) provisions of the CAAA. Additional post-combustion controls may be
mandated in Pennsylvania (where the Company has ownership in a station) for
ozone nonattainment (Title I) reasons. Continuous emission monitoring
equipment has been installed on all Phase I and Phase II units.
The Company previously reported that the Environmental Protection
Agency had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup. The Company has also been named as a defendant along with multiple
other affiliated and nonaffiliated defendants in pending asbestos cases
involving one or more plaintiffs. The Company believes that provisions for
liabilities and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of," effective in 1996. SFAS No. 121 establishes standards for the
impairment of long-lived assets and certain identifiable intangibles and
<PAGE>
74
requires companies to recognize an impairment loss if the expected future
undiscounted cash flows are less than the carrying amount of an asset. The
Company does not believe at this time that adoption of this standard will have
a materially adverse effect on its financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash 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 financing depend upon
the financial health of the companies seeking those funds.
Construction expenditures in 1995 were $75 million and for 1996 and
1997 are estimated at $66 million and $75 million, respectively. In 1995,
these expenditures included $8 million for compliance with the CAAA. The 1996
and 1997 estimated expenditures include $2 million and $7 million, respective-
ly, for additional CAAA compliance costs. The Harrison scrubbers, which were
constructed for compliance with Phase I of the CAAA, were completed on
schedule in late 1994 and the final cost was approximately 24% below the
original budget. Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant. Based on current forecasts and
considering peak diversity exchange arrangements, demand-side management and
conservation programs, a power supply agreement with affiliates, and contract-
ed PURPA capacity, it is not anticipated that the Company will require new
generating capacity until the year 2000 or beyond. The Company also has
additional capital requirements for debt maturities (see Note I to the
financial statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $93 million in 1995 compared with $67 million in
1994. Because of the new rate case authorizations effective in late 1994 and
1995 and reduced levels of capital expenditures, the Company was able to
finance 100% of its capital expenditure program through internal cash
generation in 1995, as compared to 64% in 1994. This ratio is expected to
remain close to 100% over the next several years.
As a capital-intensive electric utility, the Company is affected by
the rate of inflation. The inflation rate over the past several years has
been relatively low and has not materially affected the Company's financial
position. However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years.
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75
Fuel inventory provided a source of cash in 1995 ($3 million),
primarily related to lower fuel prices attained through renegotiations of fuel
contracts effective in January 1995 and the ability to use lower-cost, high-
sulfur coal at the Harrison Power Station because of the new scrubbers. In
1994, fuel inventory represented a use of cash ($4 million) as it returned to
a higher level after selective mine shutdowns during contract renegotiations
in 1993. The decrease in operating and construction inventory in 1995
resulted from the write-off of obsolete and slow-moving inventory. In
connection with ongoing restructuring activities and consolidation of
facilities, the Company is reevaluating inventory management objectives to
take advantage of centralized storerooms serving several facilities and to
improve turnover ratios.
Financings
During 1995, the Company refinanced $95 million of debt securities
with new debt securities having lower interest rates and refinanced preferred
stock issues totaling $40 million with Quarterly Income Debt Securities
(QUIDS). Under certain circumstances the interest payments on QUIDS may be
deferred for a period of up to 20 consecutive quarters. Debt redemption costs
of refinancings are amortized over the life of the associated new securities.
Due to the significant number of refinancings which have occurred over the
past four years, this balance is now $16 million. Reduced future interest
expense will more than offset these expenses. Preferred stock redemption
costs of $1.4 million were charged directly to retained earnings.
Short-term debt is used to meet temporary cash needs until the timing
is considered appropriate to issue long-term securities. Short-term debt,
including notes payable to affiliates under the money pool, decreased $7
million to $30 million in 1995. At December 31, 1995, the Company had SEC
authorization to issue up to $100 million of short-term debt. The Company and
its affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of the
companies have funds available. In addition, a multi-year credit program
established in 1994 provides the Company with the ability to borrow on a
standby revolving credit basis up to $81 million. After the initial three-
year term, the program agreement provides that the maturity date may be
extended in one-year increments. There were no borrowings under this facility
in 1995. During 1996, the Company anticipates meeting its capital require-
ments through a combination of internally generated funds, cash on hand, and
short-term borrowing as necessary. The Company anticipates that it will be
able to meet its future cash needs through internal cash generation and
external financings, as it has in the past.
CHANGES IN THE ELECTRIC UTILITY INDUSTRY
Competitive forces within the electric utility industry continued to
increase in 1995. As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory. Electric utilities must also compete with suppliers
of other forms of energy. Growing competitive challenges due to legislative,
economic, and technological changes, and the ability to meet these challenges,
have been a major focal point in 1995.
<PAGE>
76
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by
the National Energy Policy Act of 1992 (EPACT), which permits wholesale
generators, utility-owned and otherwise, and wholesale customers to request
from owners of bulk power transmission facilities a commitment to supply
transmission services. EPACT was the first legislative action to permit
wholesale customers within a utility's franchised service territory to seek
alternative providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995
which intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators. The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power. The Mega-NOPR provides that
electric utilities will be able to recover stranded costs (costs of facilities
made uneconomic by wholesale transmission access). The FERC has not yet
issued a final rulemaking on these issues.
The Public Utilities Commission of Ohio has initiated proceedings to
evaluate the feasibility of retail competition. The Company has filed a
response in this proceeding which emphasizes the need to move cautiously
towards retail competition in order to protect the reliability of service to
retail customers, and to insure that utilities without excess generating
capacity, like the Company, are not placed at a competitive disadvantage by
permitting utilities with excess capacity to dump energy at low marginal cost
while keeping its own customers captive through high stranded investment fees.
Attempts at variations of retail wheeling have been authorized in some states,
and various municipalities around the country that are not wholesale customers
are exploring ways to become wholesale customers to obtain the ability to
choose their electric supplier. In 1995, the Department of Defense proposed
that it be granted competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale
markets and the increasing possibility of retail competition have created
greater planning uncertainty and risks for the Company. In response, the
Company is continuing to develop a number of strategies to retain its existing
customers and to expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost
status by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
The Company believes it is taking necessary actions to position itself
to meet current and future competitive challenges.
<PAGE>
77
Potomac Edison
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income was $78.3 million in 1995 compared with $82.0 million in
1994, excluding in 1994 the cumulative effect of an accounting change to
record unbilled revenues. The decrease resulted primarily from restructuring
charges and inventory write-offs in 1995 of $4.3 million after tax and higher
expenses offset in part by increased kilowatt-hour (kWh) sales and previously
reported rate increases. Net income in 1993 was $73.5 million. The increase
in 1994 resulted from an increase in kWh sales and revenue increases, offset
in part by higher expenses.
Restructuring activities in 1995 were initiated by the System in
response to the competitive environment emerging in the electric utility
industry. The System, including the Company, is restructuring many of its
functions to strengthen its competitive position and improve its cost
structure. During 1995, reengineering of the Bulk Power Supply department in
the affiliated Allegheny Power Service Corporation was substantially completed
and process redesign is expected to be substantially completed in 1996 for the
remainder of the System. Downsizing was not a specific goal of the restruc-
turing efforts, but as a consequence of process redesign and elimination of
duplicate positions, approximately 200 System employees have been placed in a
staffing force pending reassignment or layoff. In addition, about 130 fewer
System employees will be required in the power station work force by the end
of 1997, and employee reductions are also likely to result from reengineering
in other areas. The charges recorded in 1995 in connection with restructuring
activities reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs. It is expected that these
costs will be recovered through future cost savings.
<PAGE>
78
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial
customers are shown on pages 53 and 54. Such kWh sales increased 3.3% and
2.3% in 1995 and 1994, respectively. The increases in revenues from sales to
residential, commercial, and industrial customers resulted from the following:
Changes
from Prior Year
1995 1994
(Millions of Dollars)
Increased kWh sales.............................. $17.3 $10.3
Rate changes:
Maryland....................................... 17.7 11.9
Virginia....................................... (1.8) 8.5
West Virginia.................................. 2.2 1.9
18.1 22.3
Fuel and energy cost
adjustment clauses*............................ 3.2 18.6
Other............................................ (3.0) 1.0
$35.6 $52.2
*Changes in revenues from fuel and energy cost adjustment clauses have little
effect on net income.
The increase in kWh sales in 1995 was in part attributable to
industrial and commercial sales. Industrial sales increased 2.7% and 2.8% in
1995 and 1994, respectively. The 3.6% increase in commercial sales in 1995
and the 2.1% increase in 1994 reflect growth in the number of customers and in
1995 also increased customer usage. These increases continue to reflect a
trend of economic growth in the service territory. In 1995 the Company
implemented a new Major Accounts Program which focuses on enhancing the
working relationships with its largest customers. The goal of the program is
to assure, through superior service, that the Company remains the energy
supplier for these major customers.
Residential kWh sales increased 3.9% in 1995 and 1.7% in 1994. The
rate of growth in the number of residential customers has remained constant at
about 2.1% annually in 1995, 1994, and 1993. However, the impact of weather
on customer usage continues to produce fluctuations in residential sales. In
1995, decreased sales due to mild weather in the first and second quarters
were more than offset by extremely hot summer weather and cooler than normal
winter weather in November and December as compared to 1994. The 1994
residential use was down slightly from 1993 levels reflecting a decrease in
both heating and cooling degree days.
Rate case decisions in all jurisdictions, representing revenue
increases in excess of $35 million on an annual basis, have been obtained,
most of them in late 1994. These included recovery of the remaining carrying
charges on investment, depreciation, and all operating costs required to
comply with Phase I of the Clean Air Act Amendments of 1990 (CAAA), and other
<PAGE>
79
increasing levels of expenses. Additional base rate increases are not
expected to be necessary for the next several years.
However, future purchased power expenses related to a qualified facility under
the Public Utility Regulatory Policies Act of 1978 (PURPA), to be completed in
late 1999, may make it necessary to increase rates at that time.
KWh sales to and revenues from nonaffiliated utilities are comprised
of the following items:
1995 1994 1993
KWh sales (Billions):
From Company generation............... .2 .3 .4
From purchased power.................. 4.2 2.9 3.5
4.4 3.2 3.9
Revenues (Millions):
From Company generation............... $ 4.6 $ 8.9 $ 8.6
From sales of purchased
power............................... 121.3 98.1 99.5
$125.9 $107.0 $108.1
Sales to nonaffiliated companies from the Company's generation in 1995
decreased because of growth in kWh sales to retail customers which reduced the
amount available for sale and because of continuing price competition. The
generation tax imposed in West Virginia, which in prior years was a signifi-
cant factor affecting the Company's ability to compete in the market for sales
to nonaffiliated companies, was favorably amended effective in June 1995 to
change the basis of the tax from generation to generating capacity. Sales of
purchased power vary depending on the availability of other companies'
generating equipment, demand for energy, and price competition. In the
future, some of these transactions may be made under new transmission tariffs
described below. About 95% of the aggregate benefits from sales to nonaffili-
ated companies are passed on to retail customers and have little effect on net
income.
The increase in other revenues in 1995 resulted primarily from
provisions recorded for rate refunds in 1994 and increased revenues from
wholesale customers (cooperatives and municipalities who own their own
distribution systems and who buy all or part of their bulk power needs from
the Company under regulation by the Federal Energy Regulatory Commission).
Under the National Energy Policy Act of 1992, these customers obtained the
ability to choose the bulk power supplier of their choice by the requirement
that transmission-owning utilities must provide transmission service. In June
1995, rate cases for wholesale customers were completed with the result that
such customers, with revenues representing about 94% of the $23.4 million in
annual wholesale revenues, agreed to negotiated rate increases of about $2.1
million, and signed three-year contracts to remain as Company customers. One
customer representing the remaining 6% of annual revenues selected an 18-month
contract at higher rates. In the event that this customer was to select
another supplier, the Company would retain transmission revenues with the
result that any reduction in net income would not be significant. The
decrease in other revenues in 1994 resulted from provisions for rate refunds
recorded in 1994 for the 1993 and 1994 Virginia base rate increase requests,
collected from customers subject to refund. The refunds were completed in
1995.
<PAGE>
80
Other revenues in 1995 also reflect an increase in standard transmis-
sion service revenues. See page 85 under Competition in Core Business for
information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the
Federal Energy Regulatory Commission (FERC) in 1995. Effective in 1996,
pursuant to the intentions of the Mega-NOPR, the Company eliminated its
Standard Transmission Service tariff for new service transactions, and began
using two new transmission service tariffs which qualify as required open
access tariffs - a Network tariff and Point-to- Point tariff. The FERC
accepted the filing of the new tariffs subject to hearings in the summer of
1996 and modification pending final Mega-NOPR rules. The Company is using the
new tariffs in the interim, subject to refund. In addition, the Company has a
Standard Generation Service tariff accepted by the FERC under which the
Company makes available bundled, nonfirm generation services with associated
transmission services. About 95% of the benefits of these sales of transmis-
sion and generation services to customers outside the service territory are
passed through to retail customers and as a result have little effect on net
income. While this procedure will continue to apply to similar sales under
the new tariffs, the Company may petition to revise the procedure in the
future.
Operating Expenses
The 7% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers. Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the financial statements, with the result that changes in fuel
expenses have little effect on net income.
"Purchased power and exchanges, net" represents power purchases from
and exchanges with nonaffiliated utilities, capacity charges paid to Allegheny
Generating Company (AGC), an affiliate partially owned by the Company, and
other transactions with affiliates made pursuant to a power supply agreement
whereby each company uses the most economical generation available in the
System at any given time, and is comprised of the following items:
1995 1994 1993
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other companies........ $108.5 $ 86.5 $ 87.9
Other................................ 15.4 12.7 10.5
Power exchanges, net................... (.2) (.2) (.8)
Affiliated transactions:
AGC capacity charges................... 28.1 29.4 28.0
Other affiliated capacity charges...... 45.6 37.6 28.4
Energy and spinning
reserve charges...................... 48.2 51.1 51.1
$245.6 $217.1 $205.1
The amount of power purchased from nonaffiliated companies for use by
the Company and for resale to nonaffiliated companies depends upon the
availability of the Company's generating equipment, transmission capacity, and
fuel, and its cost of generation and the cost of operations of nonaffiliated
<PAGE>
81
companies from which such purchases are made. The primary reason for the
fluctuations in purchases for resale to nonaffiliated companies is described
under Sales and Revenues above. Other purchased power continued to increase
in 1995 because of increased sales to retail customers and the availability of
more economic energy. The increase in affiliated capacity in 1995 and 1994
was due to growth of kWh sales to retail customers. The cost of power
purchased from nonaffiliates for use by the Company, AGC capacity charges in
West Virginia, and affiliated energy and spinning reserve charges are mostly
recovered from customers currently through the regular fuel and energy cost
recovery procedures followed by the Company's regulatory commissions and is
primarily subject to deferred power cost procedures with the result that
changes in such costs have little effect on net income.
While the Company does not currently purchase generation from
qualified facilities under PURPA, it will be required to do so in 1999 because
of a PURPA facility which is then scheduled to commence operations. This
project may significantly increase the cost of power purchases passed on to
customers.
The increase in other operation expense in 1995 resulted primarily
from restructuring charges which are described in Note B to the financial
statements on page 140. Additional restructuring charges will be incurred in
1996 as the Company and its affiliates complete their reengineering process.
Other operation expense in 1996 and thereafter is expected to reflect the
benefits of savings related to the restructuring activities. The 1994
increase in other operation expense resulted primarily from demand-side
management program costs ($1 million) and cogeneration project expenses ($1
million), both of which are being recovered from customers, provisions for
environmental liabilities ($1 million), and increases in affiliated company
charges for transmission service ($2 million), salaries and wages ($1
million), and employee benefit costs ($1 million), primarily pension expense
and other postretirement benefits. The increase in pension expense occurred
because the Company in 1994 discontinued the practice of deferring pension
expense in West Virginia to reflect a rate case decision in that state, and
wrote off $.9 million of prior deferrals in Virginia and West Virginia because
recovery of those deferrals was denied.
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.
The Company is also experiencing, and expects to continue to experience,
increased expenditures due to the aging of its power stations. 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. Maintenance expense in 1995
includes a charge of about $2 million for inventory write-offs described in
Note B to the financial statements on page 140. Maintenance expense for the
Harrison scrubbers which went into service in late 1994 is expected to
increase since the warranty period has expired.
<PAGE>
82
Depreciation expense increases resulted primarily from additions to
electric plant. The Company began depreciating the Harrison scrubbers in mid-
November 1994 amounting to approximately $10 million annually. Future
depreciation expense increases for utility operations are expected to be less
than historical increases because of reduced levels of proposed capital
expenditures.
The net increase of $4 million in federal and state income taxes in
1995 resulted primarily from an increase in reversals of prior year deprecia-
tion benefits for which deferred taxes were not then provided. The net
increase of $3 million in federal and state income taxes in 1994 resulted
primarily from an increase in income before taxes. Note C to the financial
statements provides a further analysis of income tax expenses.
The combined decreases in allowances for borrowed and other than
borrowed funds used during construction (AFUDC) in 1995 and 1994 of $4 million
and $1 million, respectively, reflect decreases in construction expenditures
upon substantial completion of the compliance program for Phase I of the CAAA.
The increase in other income, net, of $2 million in 1995 was due primarily to
income from demand-side management programs. During 1995, the Company
continued its participation in the collaborative process for demand-side
management in Maryland. Program costs, including lost revenues and rebates,
are deferred as a regulatory asset and are being recovered through an energy
conservation surcharge over a seven-year period. The balance in the regulato-
ry asset for this program is $16 million as of December 31, 1995. The
increase in other income, net, in 1994 resulted primarily from the Company's
share of earnings of AGC (see Note E to the financial statements) and income
from demand-side management programs.
In 1995 interest on long-term debt increased $4 million due primarily
to the new security issues in 1994 and the timing of the refinancing of $145
million of first mortgage bonds and $21 million of pollution control revenue
notes in 1995. The increase also reflects interest on $45.5 million of
Quarterly Income Debt Securities issued in 1995 to refund preferred stock
issues. 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.
Environmental and Other Issues
In the normal course of business, the Company is subject to various
contingencies and uncertainties relating to its operations and construction
programs, including cost recovery in the regulatory process, laws, regulations
and uncertainties related to environmental matters, and legal actions.
Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements. The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides
(NOx) from 1980 emission levels, to be completed in two phases, Phase I and
Phase II. Three coal-fired Company 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 to meet the required SO[2]
emission reductions for Phase I (1995-1999). Continuing studies will
<PAGE>
83
determine the compliance strategy for Phase II (2000 and beyond). Studies to
evaluate cost effective options to comply with Phase II SO[2] limits,
including those which may be available from the use of the Company's banked
emission allowances and from the emission allowance trading market, are
continuing. It is expected that burner modifications at possibly all stations
will satisfy the NOx emission reduction requirements for the acid rain (Title
IV) provisions of the CAAA. Additional post-combustion controls may be
mandated in Maryland and Pennsylvania (where the Company has ownership in a
station) for ozone nonattainment (Title I) reasons. Continuous emission
monitoring equipment has been installed on all Phase I and Phase II units.
The Company previously reported that the Environmental Protection
Agency had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup. The Company has also been named as a defendant along with multiple
other affiliated and nonaffiliated defendants in pending asbestos cases
involving one or more plaintiffs. The Company believes that provisions for
liabilities and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996. SFAS No. 121 establishes standards for the impairment
of long-lived assets and certain identifiable intangibles and requires
companies to recognize an impairment loss if the expected future undiscounted
cash flows are less than the carrying amount of an asset. The Company does
not believe at this time that adoption of this standard will have a materially
adverse effect on its financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash 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 financing depend upon
the financial health of the companies seeking those funds.
Construction expenditures in 1995 were $92 million and for 1996 and
1997 are estimated at $87 million and $103 million, respectively. In 1995,
these expenditures included $9 million for compliance with the CAAA. The 1996
and 1997 estimated expenditures include $1 million and $2 million, respective-
ly, for additional CAAA compliance costs. The Harrison scrubbers, which were
<PAGE>
84
constructed for compliance with Phase I of the CAAA, were completed on
schedule in late 1994 and the final cost was approximately 24% below the
original budget. Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant. Based on current forecasts and
considering peak diversity exchange arrangements, demand-side management and
conservation programs, a power supply agreement with affiliates, and contract-
ed PURPA capacity, it is not anticipated that the Company will require new
generating capacity until the year 2000 or beyond. The Company also has
additional capital requirements for debt maturities (See Note I to the
financial statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $85 million in 1995 compared with $67 million in
1994. Because of the new rate case authorizations effective in late 1994 and
1995 and reduced levels of capital expenditures, the Company was able to
finance approximately 92% of its capital expenditure program through internal
cash generation in 1995, as compared to 47% in 1994. This ratio is expected
to continue to increase over the next several years.
As a capital-intensive electric utility, the Company is affected by
the rate of inflation. The inflation rate over the past several years has
been relatively low and has not materially affected the Company's financial
position. However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years.
Fuel inventory provided a source of cash in 1995 ($3 million),
primarily related to lower fuel prices attained through renegotiations of fuel
contracts effective in January 1995 and the ability to use lower-cost, high-
sulfur coal at the Harrison Power Station because of the new scrubbers. In
1994, fuel inventory represented a use of cash ($4 million) as it returned to
a higher level after selective mine shutdowns during contract renegotiations
in 1993. The decrease in operating and construction inventory in 1995
resulted from the write-off of obsolete and slow-moving inventory. In
connection with ongoing restructuring activities and consolidation of
facilities, the Company is reevaluating inventory management objectives to
take advantage of centralized storerooms serving several facilities and to
improve turnover ratios.
Financings
During 1995, the Company refinanced $166 million of debt securities
with new debt securities having lower interest rates and refinanced preferred
stock issues totaling $45.5 million with Quarterly Income Debt Securities
(QUIDS). Under certain circumstances the interest payments on QUIDS may be
deferred for a period of up to 20 consecutive quarters. Debt redemption costs
of refinancings are amortized over the life of the associated new securities.
Due to the significant number of refinancings which have occurred over the
past four years, this balance is now $19 million. Reduced future interest
expense will more than offset these expenses. Preferred stock redemption costs
of $2.0 million were charged directly to retained earnings.
<PAGE>
85
Short-term debt is used to meet temporary cash needs until the timing
is considered appropriate to issue long-term securities. Short-term debt
increased to $22 million in 1995. At December 31, 1995, the Company had SEC
authorization to issue up to $115 million of short-term debt. The Company and
its affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of the
companies have funds available. In addition, a multi-year credit program
established in 1994 provides the Company with the ability to borrow on a
standby revolving credit basis up to $84 million. After the initial three-
year term, the program agreement provides that the maturity date may be
extended in one-year increments. There were no borrowings under this facility
in 1995. During 1996, the Company anticipates meeting its capital require-
ments through a combination of internally generated funds, cash on hand, and
short-term borrowing as necessary. The Company anticipates that it will be
able to meet its future cash needs through internal cash generation and
external financings, as it has in the past.
CHANGES IN THE ELECTRIC UTILITY INDUSTRY
Competitive forces within the electric utility industry continued to
increase in 1995. As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory. Electric utilities must also compete with suppliers
of other forms of energy. Growing competitive challenges due to legislative,
economic, and technological changes, and the ability to meet these challenges,
have been a major focal point in 1995.
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by
the National Energy Policy Act of 1992 (EPACT), which permits wholesale
generators, utility-owned and otherwise, and wholesale customers to request
from owners of bulk power transmission facilities a commitment to supply
transmission services. EPACT was the first legislative action to permit
wholesale customers within a utility's franchised service territory to seek
alternative providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995
which intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators. The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power. The Mega-NOPR provides that
electric utilities will be able to recover stranded costs (costs of facilities
made uneconomic by wholesale transmission access). The FERC has not yet
issued a final rulemaking on these issues.
The Virginia commission is conducting proceedings to evaluate the
feasibility of retail competition. The Maryland commission has completed its
investigation and issued an order which found that while competition in the
electric wholesale market should be encouraged, retail competition is
not in the public interest at this time. The Company has filed responses in
these proceedings which emphasize the need to move cautiously toward retail
competition in order to protect the reliability of service to retail custom-
ers, and to insure that utilities without excess generating capacity, like the
<PAGE>
86
Company, are not placed at a competitive disadvantage by permitting utilities
with excess capacity to dump energy at low marginal cost while keeping its own
customers captive through high stranded investment fees. Attempts at
variations of retail wheeling have been authorized in some states, and various
municipalities around the country that are not wholesale customers are
exploring ways to become wholesale customers to obtain the ability to choose
their electric supplier. In 1995, the Department of Defense proposed that it
be granted competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale
markets and the increasing possibility of retail competition have created
greater planning uncertainty and risks for the Company. In response, the
Company is continuing to develop a number of strategies to retain its existing
customers and to expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost
status by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
The Company believes it is taking necessary actions to position itself
to meet current and future competitive challenges.
<PAGE>
87
West Penn
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Consolidated Net Income
Consolidated net income in 1995 increased to $117.9 million compared
with $101.0 in 1994, excluding in 1994 the cumulative effect of an accounting
change to record unbilled revenues. The increase resulted primarily from
additional retail revenues due to increased kilowatt-hour (kWh) sales and
previously reported rate increases. These revenue increases were offset in
part by restructuring charges and inventory write-offs in 1995 of $6.5 million
after tax and higher expenses. Earnings in 1994 included a charge of $5.2
million after tax related to asset write-offs. Consolidated net income in
1993 was $102.1 million. Consolidated net income in 1994 reflects higher
retail revenues from increased kWh sales and rate increases, offset in part by
higher expenses.
Restructuring activities in 1995 were initiated by the System in
response to the competitive environment emerging in the electric utility
industry. The System, including the Company, is restructuring many of its
functions to strengthen its competitive position and improve its cost
structure. During 1995, reengineering of the Bulk Power Supply department in
the affiliated Allegheny Power Service Corporation was substantially completed
and process redesign is expected to be substantially completed in 1996 for the
remainder of the System. Downsizing was not a specific goal of the restruc-
turing efforts, but as a consequence of process redesign and elimination of
duplicate positions, approximately 200 System employees have been placed in a
staffing force pending reassignment or layoff. In addition, about 130 fewer
System employees will be required in the power station work force by the end
of 1997, and employee reductions are also likely to result from reengineering
in other areas. The charges recorded in 1995 in connection with restructuring
activities reflect estimated liabilities related to staffing force employees'
separation costs, inventory write-offs in connection with changes in inventory
management objectives, and certain other costs. It is expected that these
costs will be recovered through future cost savings.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and industrial
customers are shown on pages 55 and 56. Such kWh sales increased 4.0% and
2.9% in 1995 and 1994, respectively. The increases in revenues from sales to
residential, commercial, and industrial customers resulted from the following:
Changes
from Prior Year
1995 1994
(Millions of Dollars)
Increased kWh sales.............................. $17.3 $ 9.4
Rate increases................................... 50.2 22.7
Fuel and energy cost adjustment clauses*......... (2.9) 16.8
Other............................................ 3.0 2.3
$67.6 $51.2
*Changes in revenues from fuel and energy cost adjustment clauses have little
effect on consolidated net income.
<PAGE>
88
The increase in kWh sales in 1995 was largely attributable to
industrial and commercial sales. Industrial sales increased 5.8% and 4.4% in
1995 and 1994, respectively. The 4.4% increase in commercial sales in 1995
and the 2.9% increase in 1994 reflect growth in the number of customers and
increased customer usage. These increases continue to reflect a trend of
economic growth in the service territory. In 1995 the Company implemented a
new Major Accounts Program which focuses on enhancing the working relation-
ships with its largest customers. The goal of the program is to assure,
through superior service, that the Company remains the energy supplier for
these major customers.
Residential kWh sales increased 1.4% in 1995 and 1.1% in 1994 due to
growth in number of customers and higher usage. The rate of growth in the
number of residential customers has remained constant at just under 1%
annually in 1995, 1994, and 1993. However, the impact of weather on customer
usage continues to produce fluctuations in residential sales. In 1995,
decreased sales due to mild weather in the first and second quarters were more
than offset by extremely hot summer weather and cooler than normal winter
weather in November and December as compared to 1994. Residential usage
increased in 1994 despite a decrease in both heating and cooling degree days.
Rate case decisions, representing revenue increases in excess of $57
million on an annual basis, have been obtained effective in late 1994. These
included recovery of the remaining carrying charges on investment, deprecia-
tion, and all operating costs required to comply with Phase I of the Clean Air
Act Amendments of 1990 (CAAA), and other increasing levels of expenses.
Additional base rate increases are not expected to be necessary for the next
several years.
KWh sales to and revenues from nonaffiliated utilities are comprised
of the following items:
1995 1994 1993
KWh sales (Billions):
From Company generation................. .2 .5 .4
From purchased power.................... 5.7 3.8 5.0
5.9 4.3 5.4
Revenues (Millions):
From Company generation................. $ 5.7 $ 12.3 $ 11.5
From sales of purchased power........... 162.5 132.5 141.0
$168.2 $144.8 $152.5
Sales to nonaffiliated companies from the Company's generation in 1995
decreased because of growth in kWh sales to retail customers which reduced the
amount available for sale and because of continuing price competition. The
generation tax imposed in West Virginia, which in prior years was a signifi-
cant factor affecting the Company's ability to compete in the market for sales
to nonaffiliated companies, was favorably amended effective in June 1995 to
change the basis of the tax from generation to generating capacity. Sales of
purchased power vary depending on the availability of other companies'
generating equipment, demand for energy, and price competition. In the
<PAGE>
89
future, some of these transactions may be made under new transmission tariffs
described below. Most of the aggregate benefits from sales to nonaffiliated
companies and sales of energy and spinning reserve to affiliates included in
other revenues described below, are passed on to retail customers and have
little effect on consolidated net income.
The increase in other revenues in 1995 resulted primarily from an
increase in sales of capacity, energy, and spinning reserve to other affiliat-
ed companies. About $18 million of other revenues in 1995 were derived from
wholesale customers (cooperatives and municipalities who own their own
distribution systems and who buy all or part of their bulk power needs from
the Company under regulation by the Federal Energy Regulatory Commission).
Under the National Energy Policy Act of 1992, these customers obtained the
ability to choose the bulk power supplier of their choice by the requirement
that transmission-owning utilities must provide transmission service. In
1994, a rate case for wholesale customers was completed with the result that
such customers agreed to negotiated rate increases and signed seven-year
contracts to remain as Company customers.
Other revenues in 1995 also reflect an increase in standard transmis-
sion service revenues. See page 94 under Competition in Core Business for
information about a Notice of Proposed Rulemaking (Mega-NOPR) issued by the
Federal Energy Regulatory Commission (FERC) in 1995. Effective in 1996,
pursuant to the intentions of the Mega-NOPR, the Company eliminated its
Standard Transmission Service tariff for new service transactions, and began
using two new transmission service tariffs which qualify as required open
access tariffs - a Network tariff and a Point-to-Point tariff. The FERC
accepted the filing of the new tariffs subject to hearings in the summer of
1996 and modification pending final Mega-NOPR rules. The Company is using the
new tariffs in the interim, subject to refund. In addition, the Company has a
Standard Generation Service tariff accepted by the FERC under which the
Company makes available bundled, nonfirm generation services with associated
transmission services. Most of the benefits of these sales of transmission
and generation services to customers outside the service territory are passed
through to retail customers and as a result have little effect on consolidated
net income. While this procedure will continue to apply to similar sales
under the new tariffs, the Company may petition to revise the procedure in the
future.
Operating Expenses
The 6% decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices effective
in January 1995, and the ability to use lower-cost, high-sulfur coal at the
Harrison Power Station because of the new scrubbers. Fuel expenses decreased
2% in 1994 due primarily to a decrease in kWh generated. Fuel expenses are
primarily subject to deferred power cost accounting procedures, as described
in Note A to the consolidated financial statements, with the result that
changes in fuel expenses have little effect on consolidated net income.
"Purchased power and exchanges, net" represents power purchases from
and exchanges with nonaffiliated companies and purchases from qualified
facilities under the Public Utility Regulatory Policies Act of 1978 (PURPA),
capacity charges paid to Allegheny Generating Company (AGC), an affiliate
partially owned by the Company, and other transactions with affiliates made
<PAGE>
90
pursuant to a power supply agreement whereby each company uses the most
economical generation available in the System at any given time, and is
comprised of the following items:
1995 1994 1993
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other companies........ $145.4 $116.9 $124.5
From PURPA generation................ 64.7 65.7 49.6
Other................................ 21.6 18.3 15.2
Power exchanges, net................... (.1) (.2) (1.2)
Affiliated transactions:
AGC capacity charges................... 37.8 37.2 42.3
Energy and spinning
reserve charges...................... 4.6 8.6 4.7
Other affiliated capacity charges...... .7 .7 .7
$274.7 $247.2 $235.8
The amount of power purchased from nonaffiliated companies for use by
the Company and for resale to nonaffiliated companies depends upon the
availability of the Company's generating equipment, transmission capacity, and
fuel, and its cost of generation and the cost of operations of nonaffiliated
companies from which such purchases are made. The primary
reason for the fluctuations in purchases for resale to nonaffiliated companies
is described under Sales and Revenues above. The reduced level of purchases
from PURPA generation in 1993 was due to a planned generating outage at one
PURPA project. None of the Company's purchased power contracts is capitalized
since there are no minimum payment requirements absent associated kWh
generation. Other purchased power continued to increase in 1995 because of
increased sales to retail customers and the availability of more economic
energy. The cost of power purchased for use by the Company, including power
from PURPA generation and affiliated transactions, is mostly recovered from
customers currently through the regular fuel and energy cost recovery
procedures followed by the Pennsylvania Public Utility Commission (PUC), and
is primarily subject to deferred power cost procedures with the result that
changes in such costs have little effect on consolidated net income.
In January 1996, the Company and the developers of a proposed
Shannopin PURPA project reached agreement to terminate the project and all
pending litigation, at a buy out price of $31 million. The agreement is
subject to PUC approval of recovery of the buy out price by the Company by no
later than March 31, 1999. The agreement was filed with the PUC in February
1996 along with a request for expedited approval.
The increase in other operation expense in 1995 resulted primarily
from restructuring charges which are described in Note B to the consolidated
financial statements on page 157. Additional restructuring charges will be
incurred in 1996 as the Company and its affiliates complete their reengineeri-
ng process. Other operation expense in 1996 and thereafter is expected to
reflect the benefits of savings related to the restructuring activities. The
1994 increase in other operation expense resulted primarily from a decision to
increase the allowances for uncollectible accounts ($8 million), increases in
salaries and wages ($2 million) and employee benefit costs, primarily pension
expense ($1 million) and other postretirement benefits ($2 million), and
<PAGE>
91
provisions for environmental liabilities ($1 million). Allowances for
uncollectible accounts were increased in 1994 due to an increase in aged
outstanding receivables caused primarily by Pennsylvania rate regulations
which make it difficult if not impossible to curtail service to non-paying
customers. It is expected that the allowance for these uncollectible accounts
will be increased in the future because of increasing accounts receivable in
arrears. The increase in pension expense occurred because the Company in 1994
discontinued the practice of deferring pension expense to reflect a rate case
decision.
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.
The Company is also experiencing, and expects to continue to experience,
increased expenditures due to the aging of its power stations.
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. Maintenance
expense in 1995 includes a charge of about $4 million for inventory write-
offs described in Note B to the consolidated financial statements on page 157.
Maintenance expense for the Harrison scrubbers which went into service in late
1994 is expected to increase since the warranty period has expired.
Depreciation expense increases resulted primarily from additions to
electric plant and from a change in depreciation rates. The Company began
depreciating the Harrison scrubbers in mid-November 1994 amounting to
approximately $14 million annually. Future depreciation expense increases are
expected to be less than historical increases because of reduced levels of
proposed capital expenditures.
The increase in taxes other than income in 1995 was due primarily to
an increase in gross receipts taxes resulting from higher revenues from retail
customers. Taxes other than income decreased $2 million in 1994 primarily due
to a decrease in West Virginia Business and Occupation taxes (B&O taxes) ($3
million), offset in part by an increase in gross receipts taxes ($2 million).
The net increase of $11 million in federal and state income taxes in
1995 resulted primarily from an increase in income before taxes. The net
decrease in 1994 of $1 million resulted primarily from plant removal cost tax
deductions for which deferred taxes were not provided. Note C to the
consolidated financial statements provides a further analysis of income tax
expenses.
The combined decrease in allowances for borrowed and other than
borrowed funds used during construction (AFUDC) in 1995 of $6 million reflects
decreases in construction expenditures upon substantial completion of the
compliance program for Phase I of the CAAA. The increase of $2 million in
AFUDC in 1994 reflects increased construction expenditures, including those
associated with the CAAA, net of CAAA amounts included in rate base and
earning a cash return. Other income, net, in 1994 reflects the write-off of
$5.2 million net of income taxes of previously accumulated costs related to
<PAGE>
92
future facilities which are no longer considered meaningful in the industry's
more competitive environment.
In 1995, interest on long-term debt increased $6 million due primarily
to the new security issues in 1994 and the timing of the refinancing of $30
million of first mortgage bonds and $47 million of pollution control revenue
notes in 1995. The increase also reflects interest on $70 million of
Quarterly Income Debt Securities issued in 1995 to refund preferred stock
issues. 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.
Environmental and Other Issues
In the normal course of business, the Company is subject to various
contingencies and uncertainties relating to its operations and construction
programs, including cost recovery in the regulatory process, laws, regulations
and uncertainties related to environmental matters, and legal actions.
Contingencies and uncertainties related to the CAAA are discussed in
Liquidity and Capital Requirements. The CAAA, among other things, require an
annual reduction in total utility emissions within the United States of 10
million tons of sulfur dioxide (SO[2]) and two million tons of nitrogen oxides
(NO[x]) from 1980 emission levels, to be completed in two phases, Phase I and
Phase II. Four coal-fired Company plants are affected in Phase I and the
remaining plants and units reactivated in the future will be affected in Phase
II. Installation of scrubbers at the Harrison Power Station was the strategy
undertaken to meet the required SO[2] emission reductions for Phase I (1995-
1999). Continuing studies will determine the compliance strategy for Phase II
(2000 and beyond). Studies to evaluate cost effective options to comply with
Phase II SO[2] limits, including those which may be available from the use of
the Company's banked emission allowances and from the emission allowance
trading market, are continuing. It is expected that burner modifications at
possibly all stations will satisfy the NO[x] emission reduction requirements
for the acid rain (Title IV) provisions of the CAAA. Additional post-
combustion controls may be mandated in Pennsylvania for ozone nonattainment
(Title I) reasons. Continuous emission monitoring equipment has been
installed on all Phase I and Phase II units.
The Company previously reported that the Environmental Protection
Agency had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup. The Company has also been named as a defendant along with multiple
other affiliated and nonaffiliated defendants in pending asbestos cases
involving one or more plaintiffs. The Company believes that provisions for
liabilities and insurance recoveries are such that final resolution of these
claims will not have a material effect on its financial position.
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996. SFAS No. 121 establishes standards for the impairment
of long-lived assets and certain identifiable intangibles and requires
companies to recognize an impairment loss if the expected future undiscounted
<PAGE>
93
cash flows are less than the carrying amount of an asset. The Company does
not believe at this time that adoption of this standard will have a materially
adverse effect on its financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash 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 financing depend upon
the financial health of the companies seeking those funds.
Construction expenditures in 1995 were $149 million and for 1996 and
1997 are estimated at $125 million and $126 million, respectively. In 1995,
these expenditures included $19 million for compliance with the CAAA. The
1996 and 1997 estimated expenditures include $4 million and $10 million,
respectively, for additional CAAA compliance costs. The Harrison scrubbers,
which were constructed for compliance with Phase I of the CAAA, were completed
on schedule in late 1994 and the final cost was approximately 24% below the
original budget. Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant. Based on current forecasts and
considering the reactivation of capacity in cold reserve, peak diversity
exchange arrangements, demand-side management and conservation programs, a
power supply agreement with affiliates, and contracted PURPA capacity, it is
not anticipated that the Company will require new generating capacity until
the year 2000 or beyond. The Company also has additional capital requirements
for debt maturities (See Note I to the consolidated financial statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $110 million in 1995 compared with $109 million in
1994. Because of the new rate case authorizations effective in late 1994 and
reduced levels of capital expenditures, the Company was able to finance
approximately 74% of its capital expenditure program through internal cash
generation in 1995, as compared to 42% in 1994. This ratio is expected to
continue to increase over the next several years.
As a capital-intensive electric utility, the Company is affected by
the rate of inflation. The inflation rate over the past several years has
been relatively low and has not materially affected the Company's financial
position. However, since utility revenues are based on rate regulation that
generally only recognizes historical costs, cash flows based on recovery of
historical plant may not be adequate to replace plant in future years.
Fuel inventory provided a source of cash in 1995 ($6 million),
primarily related to lower fuel prices attained through renegotiations of fuel
<PAGE>
94
contracts effective in January 1995 and the ability to use lower-cost, high-
sulfur coal at the Harrison Power Station because of the new scrubbers. In
1994, fuel inventory represented a use of cash ($5 million) as it returned to
a higher level after selective mine shutdowns during contract renegotiations
in 1993. The decrease in operating and construction inventory in 1995
resulted from the write-off of obsolete and slow-moving inventory. In
connection with ongoing restructuring activities and consolidation of
facilities, the Company is reevaluating inventory management objectives to
take advantage of centralized storerooms serving several facilities and to
improve turnover ratios.
Financings
During 1995, the Company refinanced $77 million of debt securities
with new debt securities having lower interest rates and refinanced preferred
stock issues totaling $70 million with Quarterly Income Debt Securities
(QUIDS). Under certain circumstances the interest payments on QUIDS may be
deferred for a period of up to 20 consecutive quarters. Debt redemption costs
of refinancings are amortized over the life of the associated new securities.
Due to the significant number of refinancings which have occurred over the
past four years, this balance is now $12 million. Reduced future interest
expense will more than offset these expenses. Preferred stock redemption
costs of $2.2 million were charged directly to retained earnings.
Short-term debt is used to meet temporary cash needs until the timing
is considered appropriate to issue long-term securities. Short-term debt
increased to $70 million in 1995. At December 31, 1995, the Company had SEC
authorization to issue up to $170 million of short-term debt. The Company and
its affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of the
companies have funds available. In addition, a multi-year credit program
established in 1994 provides the Company with the ability to borrow on a
standby revolving credit basis up to $135 million. After the initial three-
year term, the program agreement provides that the maturity date may be
extended in one-year increments. There were no borrowings under this facility
in 1995. During 1996, the Company anticipates meeting its capital require-
ments through a combination of internally generated funds, cash on hand, and
short-term borrowings as necessary. The Company anticipates that it will be
able to meet its future cash needs through internal cash generation and
external financings, as it has in the past.
CHANGES IN THE ELECTRIC UTILITY INDUSTRY
Competitive forces within the electric utility industry continued to
increase in 1995. As in the past, utilities must compete for siting of new
industrial and commercial customers and for retaining existing customers in
the franchised territory. Electric utilities must also compete with suppliers
of other forms of energy. Growing competitive challenges due to legislative,
economic, and technological changes, and the ability to meet these challenges,
have been a major focal point in 1995.
<PAGE>
94
Competition in Core Business
Competition in the wholesale market for electricity was enhanced by
the National Energy Policy Act of 1992 (EPACT), which permits wholesale
generators, utility-owned and otherwise, and wholesale customers to request
from owners of bulk power transmission facilities a commitment to supply
transmission services. EPACT was the first legislative action to permit
wholesale customers within a utility's franchised service territory to seek
alternative providers of energy.
The FERC issued a Notice of Proposed Rulemaking (Mega-NOPR) in 1995
which intends to stimulate wholesale competition among electric utilities and
unregulated electricity generators. The Mega-NOPR encourages wholesale
competition by requiring utilities to allow their transmission facilities to
be used by sellers or buyers of wholesale power. The Mega-NOPR provides that
electric utilities will be able to recover stranded costs (costs of facilities
made uneconomic by wholesale transmission access). The FERC has not yet
issued a final rulemaking on these issues.
The Pennsylvania PUC has begun an investigation into electric power
competition. The PUC staff issued a report advising against instituting
retail wheeling at this time. The Company has filed a response to this
investigation which emphasizes the need to move cautiously toward retail
competition in order to protect the reliability of service to retail custom-
ers, and to insure that utilities without excess generating capacity, like the
Company, are not placed at a competitive disadvantage by permitting utilities
with excess capacity to dump energy at low marginal cost while keeping their
own customers captive through high stranded investment fees. Attempts at
variations of retail wheeling have been authorized in some states, and various
municipalities around the country that are not wholesale customers are
exploring ways to become wholesale customers to obtain the ability to choose
their electric supplier. In 1995, the Department of Defense proposed that it
be granted competitive procurement rights for defense facilities.
Efforts to Maintain and Improve Competitive Position
The emerging competitive environment in generation and wholesale
markets and the increasing possibility of retail competition have created
greater planning uncertainty and risks for the Company. In response, the
Company is continuing to develop a number of strategies to retain its existing
customers and to expand its retail and wholesale customer base, including:
1. Restructuring its operations to maintain its relatively low-cost
status by controlling costs and operating more efficiently
2. Implementing new marketing strategies
3. Increasing customer and energy services
4. Avoiding future rate increases
The Company believes it is taking necessary actions to position itself
to meet current and future competitive challenges.
<PAGE>
95
AGC
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Results of Operations
As described under Liquidity and Capital Requirements, revenues are
determined under a cost of service formula rate schedule. Therefore, if all
other factors remain equal, 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 1995 decreased due to a reduction in net investment and reduced operating
expenses which are described below. Revenues for 1994 increased primarily
because of the return on equity settlement which resulted in an adjustment of
prior period provisions for rate refunds.
The decrease in operating expenses in 1995 resulted from a decrease in
federal income taxes due to a decrease in income before taxes ($1.2 million)
combined with a decrease in operation and maintenance expense ($1.0 million).
The increase in operating expenses in 1994 resulted primarily from an increase
in federal income taxes due to an increase in income before taxes ($1.5
million).
The decrease in interest on long-term debt in 1994 was the combined
result of a decrease in the average amount of, and interest rates on, long-
term debt outstanding. The increase in other interest in 1995 was due to cash
needs for refunds mandated in rate case proceedings (see Liquidity and Capital
Requirements), and the increase in 1994 was due to amortization of the premium
paid to refund debentures in 1993.
In March 1995, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996. SFAS No. 121 establishes standards for the impairment
of long-lived assets and certain identifiable intangibles and requires
companies to recognize an impairment loss if the expected future undiscounted
cash flows are less than the carrying amount of an asset. The Company does
not believe at this time that adoption of this standard will have a materially
adverse effect on its financial position.
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, 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, deprecia-
tion, taxes, and a return on its investment.
<PAGE>
96
Through February 29, 1992, the Company's return on equity (ROE) was
adjusted annually pursuant to a settlement agreement approved by the FERC. In
December 1991, the Company filed for a continuation of the existing ROE of
11.53% and other parties (the Consumer Advocate Division of the Public Service
Commission of West Virginia, Maryland People's Counsel, and Pennsylvania
Office of Consumer Advocate, collectively referred to as the joint consumer
advocates or JCA) filed to reduce the ROE to 10%. Hearings were completed in
June 1992, and a recommendation was issued by an Administrative Law Judge
(ALJ) on December 21, 1993, for an ROE of 10.83%, which the JCA argued should
be further adjusted to reflect changes in capital market conditions since the
hearings. Exceptions to this recommendation were filed by all parties for
consideration by the FERC. On January 28, 1994, the JCA filed a joint
complaint with the FERC against the Company claiming that both the existing
ROE of 11.53% and the ROE recommended by the ALJ of 10.83% were unjust and
unreasonable. This new complaint requested an ROE of 8.53% with rates subject
to refund beginning April 1, 1994. Hearings were completed in November 1994
and a recommendation was issued by an ALJ on December 22, 1994, dismissing the
JCA's complaint. A settlement agreement for both cases was filed with the
FERC on January 12, 1995, which would reduce the Company's ROE from 11.53% to
11.13% for the period from March 1, 1992 through December 31, 1994, and
increase the Company's ROE to 11.2% for the period from January 1, 1995
through December 31, 1995. This settlement was approved by the FERC on March
23, 1995. Refunds were made by the Company of any revenues collected between
March 1, 1992 and March 23, 1995 in excess of these levels. A second
settlement has been negotiated to address the Company's ROE after 1995. On
December 21, 1995, the Company submitted the new settlement to the FERC and
action is pending. Interested parties representing less than 2% of the
Company's eventual revenues have filed exceptions to the settlement. Under
the terms of the settlement, the Company's ROE for 1996 would be 11%. For
1997 and 1998 the ROE would be set by a formula based upon the yields of 10-
year constant maturity U.S. Treasury securities. However, the change in ROE
from the previous year's value cannot exceed 50 basis points.
Through a filing completed on October 31, 1994, the Company sought
FERC approval to add a prior tax payment of approximately $12 million to rate
base which will produce about $1.4 million in additional annual revenues. The
FERC accepted the Company's filing and ordered the increase to become
effective June 1, 1995.
An internal money pool accommodates intercompany short-term borrowing
needs to the extent that certain of the Company's affiliates have funds
available.
<PAGE>
<TABLE>
<CAPTION>
97
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
Index
Monon- Potomac West
APS gahela Edison Penn AGC
<S> <C> <C> <C> <C> <C>
Report of Independent Accountants 98 99 100 101 102
Statement of Income for 103 119 134 152 167
the three years ended
December 31, 1995
Statement of Retained Earnings - 119 134 152 167
for the three years ended
December 31, 1995
Statement of Cash Flows for 105 120 135 153 168
the three years ended
December 31, 1995
Balance Sheet at December 31, 106 121 136 153 169
1995 and 1994
Statement of Capitalization at 107 122 137 154 -
December 31, 1995 and 1994
Statement of Common Equity for 109 - - - -
the three years ended
December 31, 1995
Notes to financial statements 110 123 138 155 170
Financial Statement Schedules -
Schedules - for the three years
ended December 31, 1995
II Valuation and qualifying
accounts S-1 S-2 S-3 S-4 -
</TABLE>
All other schedules are omitted because they are not applicable or the
required information is shown in the Financial Statements or Notes thereto.
<PAGE>
98
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
Allegheny Power System, Inc.
In our opinion, the consolidated financial statements listed in the
accompanying index present fairly, in all material respects, the financial
position of Allegheny Power System, Inc. and its subsidiaries at December 31,
1995 and 1994, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1995, 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 audit provides a reasonable basis for the opinion expressed above.
As discussed in Note A to the consolidated financial statements, the
Company changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 1, 1996
<PAGE>
99
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 Power System, Inc.) at
December 31, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995, 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.
As discussed in Note A to the financial statements, the Company
changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 1, 1996
<PAGE>
100
REPORT OF INDEPENDENT ACCOUNTANTS
The 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 Power System, Inc.) at
December 31, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995, 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.
As discussed in Note A to the financial statements, the Company
changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 1, 1996
<PAGE>
101
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 Power System,
Inc.) at December 31, 1995 and 1994, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 1995,
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.
As discussed in Note A to the consolidated financial statements, the
Company changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 1, 1996
<PAGE>
102
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 (an Allegheny Power System, Inc. affiliate) at
December 31, 1995 and 1994, and the results of its operations and its cash
flows for each of the three years in the period ended December 31, 1995, 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.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 1, 1996
<PAGE
<TABLE>
<CAPTION>
103
APS
Consolidated Statement of Income
Year ended December 31
(Thousands of Dollars Except for Per Share Data) 1995 1994 1993
Electric Operating Revenues:
<S> <C> <C> <C>
Residential $ 926,966 $ 863,725 $ 818,400
Commercial 493,696 459,303 430,202
Industrial 770,251 728,009 673,418
Nonaffiliated utilities 385,023 331,557 346,705
Other 71,872 69,090 62,801
Total Operating Revenues 2,647,808 2,451,684 2,331,526
Operating Expenses:
Operation:
Fuel 508,533 547,241 544,659
<PAGE>
104
Purchased power and exchanges, net 510,700 440,880 417,449
Deferred power costs, net (Note A) 47,796 11,805 (11,462)
Other (Note B) 306,795 285,010 257,732
Maintenance (Note B) 256,623 241,913 231,163
Depreciation 256,316 223,883 210,428
Taxes other than income taxes 184,729 183,060 178,788
Federal and state income taxes (Note C) 154,203 129,751 128,130
Total Operating Expenses 2,225,695 2,063,543 1,956,887
Operating Income 422,113 388,141 374,639
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A) 4,473 11,966 12,499
Other income (expense), net (Note B) 6,224 (3,828) (6)
Total Other Income and Deductions 10,697 8,138 12,493
Income Before Interest Charges and
Preferred Dividends 432,810 396,279 387,132
Interest Charges and Preferred Dividends:
Interest on long-term debt 167,199 153,668 157,449
Other interest 14,417 10,394 5,812
Allowance for borrowed funds used during
construction (Note A) (3,713) (7,630) (8,983)
Dividends on preferred stock of subsidiaries 15,215 20,096 17,098
Total Interest Charges and Preferred Dividends 193,118 176,528 171,376
Consolidated Income Before Cumulative Effect
of Accounting Change 239,692 219,751 215,756
Cumulative Effect of Accounting Change, net (Note A) 43,446
Consolidated Net Income $ 239,692 $ 263,197 $ 215,756
Common Stock Shares Outstanding
(average) (Note H) 119,863,753 118,272,373 114,937,032
Earnings Per Average Share (Note H):
Consolidated income before cumulative
effect of accounting change $2.00 $1.86 $1.88
Cumulative effect of accounting change, net (Note A) .37
Consolidated net income $2.00 $2.23 $1.88
See accompanying notes to consolidated financial statements.
<PAGE>
105
Consolidated Statement of Cash Flows
Year ended December 31
(Thousands of Dollars) 1995 1994 1993
Cash Flows from Operations:
Consolidated net income $239,692 $263,197 $215,756
Depreciation 256,316 223,883 210,428
Deferred investment credit and income taxes, net 27,019 25,684 (2,388)
Deferred power costs, net 47,796 11,805 (11,462)
Allowance for other than borrowed funds used
during construction (4,473) (11,966) (12,499)
Cumulative effect of accounting change before
income taxes (Note A) (72,333)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative
effect of accounting change (Note A) (63,370) 9,666 (15,393)
Materials and supplies 20,358 (20,519) 53,614
Accounts payable (45,387) 3,119 (305)
Taxes accrued 3,060 (5,792) 3,619
Interest accrued (2,326) 3,452 (2,164)
Other, net (250) 9,957 18,087
478,435 440,153 457,293
Cash Flows from Investing:
Construction expenditures (319,050) (508,254) (573,970)
Nonutility investments (1,076)
Allowance for other than borrowed funds used
during construction 4,473 11,966 12,499
(315,653) (496,288) (561,471)
Cash Flows from Financing:
Sale of common stock 34,514 34,709 99,875
Sale of preferred stock 49,635
Retirement of preferred stock (162,171) (1,190) (1,611)
Issuance of long-term debt and QUIDS 482,856 197,098 691,343
Retirement of long-term debt (392,715) (26,000) (632,000)
Short-term debt, net 73,600 (3,818) 119,431
Cash dividends on common stock (197,764) (193,951) (187,475)
(161,680) 56,483 89,563
Net Change in Cash and Temporary Cash
Investments (Note G) 1,102 348 (14,615)
Cash and Temporary Cash Investments at January 1 2,765 2,417 17,032
Cash and Temporary Cash Investments at December 31 $ 3,867 $ 2,765 $ 2,417
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized) $178,239 $148,016 $153,455
Income taxes 126,386 122,343 124,979
See accompanying notes to consolidated financial statements.
<PAGE>
106
APS
Consolidated Balance Sheet
As of December 31
(Thousands of Dollars) 1995 1994
Assets
Property, Plant, and Equipment:
At original cost, including $147,467,000
and $215,756,000 under construction $7,812,670 $7,586,780
Accumulated depreciation (2,700,077) (2,529,354)
5,112,593 5,057,426
Investments and Other Assets:
Subsidiaries consolidated-excess of cost over book
equity at acquisition (Note A) 15,077 15,077
Benefit plans' investments (Note A) 47,545 35,584
Other 2,981 1,950
65,603 52,611
Current Assets:
Cash and temporary cash investments (Note G) 3,867 2,765
Accounts receivable:
Electric service, net of $13,047,000 and $11,353,000
uncollectible allowance (Note A) 305,988 250,367
Other 15,924 8,175
Materials and supplies-at average cost:
Operating and construction 86,421 94,478
Fuel 71,898 84,199
Prepaid taxes 45,404 43,880
Deferred income taxes 28,655 10,916
Other 13,164 12,814
571,321 507,594
Deferred Charges:
Regulatory assets (Note C) 602,360 643,791
Unamortized loss on reacquired debt 57,255 40,991
Other 38,183 59,812
697,798 744,594
Total $6,447,315 $6,362,225
Capitalization and Liabilities
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes D and H) $2,129,917 $2,059,304
Preferred stock (Note H) 170,086 325,286
Long-term debt and QUIDS (Note H) 2,273,226 2,178,472
4,573,229 4,563,062
Current Liabilities:
Short-term debt (Note I) 200,418 126,818
Long-term debt and preferred stock due within one year (Note H) 43,575 29,200
Accounts payable 145,422 190,809
Taxes accrued:
Federal and state income 15,599 13,873
Other 54,116 52,782
Interest accrued 39,752 42,078
Deferred power costs (Note A) 26,735
Other 70,912 62,073
596,529 517,633
Deferred Credits and Other Liabilities:
Unamortized investment credit 149,759 158,018
Deferred income taxes 985,804 972,113
Regulatory liabilities (Note C) 97,970 105,076
Other 44,024 46,323
1,277,557 1,281,530
Commitments and Contingencies (Note J)
Total $6,447,315 $6,362,225
See accompanying notes to consolidated financial statements.
<PAGE>
107
</TABLE>
<TABLE>
<CAPTION>
APS
Consolidated Statement of Capitalization
As of December 31
(Thousands of Dollars) (Capitalization Ratios)
1995 1994 1995 1994
Common Stock:
Common stock of Allegheny Power System, Inc. -
$1.25 par value per share,
260,000,000 shares authorized,
outstanding 120,700,809 and
<S> <C> <C> <C> <C>
119,292,954 shares (Note H) $ 150,876 $ 149,116
Other paid-in capital 995,701 963,269
Retained earnings (Note D) 983,340 946,919
Total 2,129,917 2,059,304 46.6% 45.1%
Preferred Stock of Subsidiaries-cumulative, par value
$100 per share, authorized 9,975,688 shares (Note H):
Not subject to mandatory redemption:
December 31, 1995
Share Regular Call Price
Series Oustanding Per Share
3.60% - 4.80% 650,861 $103.75 to $110.00 65,086 65,086
$5.88 - $7.73 650,000 $102.85 to $102.86 65,000 115,000
$7.92 - $8.80 80,000
Auction
4.25% - 4.75% 400,000 $100.00 40,000 40,000
Total (annual dividend requirements $9,323,269) 170,086 300,086 3.7% 6.6%
Subject to mandatory redemption:
$7.16 26,400
Total 26,400
Less current sinking fund requirement (1,200)
Total 25,200 0.6%
Long-Term Debt and QUIDS of Subsidiaries (Note H):
First mortgage bonds: December 31, 1995
Maturity Interest Rate-%
1995 - 2000 5 1/2 - 6 1/2 293,000 320,000
2002 - 2004 6 3/8 - 7 7/8 175,000 175,000
2006 - 2007 7 1/4 - 8 120,000 120,000
2019 - 2020 245,000
2021 - 2025 7 5/8 - 8 7/8 925,000 680,000
<PAGE>
108
Debentures
due 2003 - 2023 5 5/8 - 6 7/8 150,000 150,000
Quarterly Income Debt
Securities due 2025 8.00 155,457
Secured notes
due 1998 - 2024 4.95 - 6.875 368,300 368,300
Unsecured notes
due 1996 - 2012 6.10 - 6.40 27,495 27,495
Installment purchase
obligations due 1998 6.875 19,100 19,100
Commercial paper 5.82 30,561 41,736
Medium-term notes
due 1995 - 1998 5.75 - 7.93 76,975 77,975
Unamortized debt
discount and
premium, net (24,087) (18,134)
Total
(annual interest requirements $167,534,964) 2,316,801 2,206,472
Less current maturities (43,575) (28,000)
Total 2,273,226 2,178,472 49.7% 47.7%
Total Capitalization $4,573,229 $4,563,062 100.0% 100.0%
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
109
<TABLE>
<CAPTION>
APS
Consolidated Statement of Common Equity
Year Ended December 31
(Thousands of Dollars)
Shares Other Retained Total
Outstanding Common Paid-In Earnings Common
(Note H) Stock Capital (Note D) Equity
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1993 113,898,736 $142,373 $836,038 $849,398 $1,827,809
Add:
Sale of common stock,
net of expenses:
Public offerings 2,400,000 3,000 61,057 64,057
Dividend Reinvestment
and Stock
Purchase Plan and
Employee Stock
Ownership and Savings Plan 1,364,846 1,706 34,402 36,108
Consolidated net income 215,756 215,756
Deduct:
Dividends on common stock of the
Company (cash) 187,475 187,475
Expenses related to common
stock split 290 290
Expenses related to subsidiary
companies' preferred
stock transactions 144 6 150
Balance at December 31, 1993 117,663,582 $147,079 $931,063 $877,673 $1,955,815
Add:
Sale of common stock,
net of expenses:
Dividend Reinvestment
and Stock
Purchase Plan and
Employee Stock
Ownership and Savings Plan 1,629,372 2,037 32,988 35,025
Consolidated net income 263,197 263,197
Deduct:
Dividends on common stock of
the Company (cash) 193,951 193,951
Expenses related to 1993
public offerings 79 79
Expenses related to common
stock split 237 237
Expenses related to subsidiary
companies' preferred stock
transactions 466 466
Balance at December 31, 1994 119,292,954 $149,116 $963,269 $946,919 $2,059,304
Add:
Sale of common stock,
net of expenses:
Dividend Reinvestment
and Stock
Purchase Plan and
Employee Stock
Ownership and Savings Plan 1,407,855 1,760 32,754 34,514
Consolidated net income 239,692 239,692
Deduct:
Dividends on common stock of
the Company (cash) 197,764 197,764
Expenses related to subsidiary
companies' preferred
stock transactions 322 5,507 5,829
Balance at December 31, 1995 120,700,809 $150,876 $995,701 $983,340 $2,129,917
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
110
APS
Notes to Consolidated Financial Statements
(These notes are an integral part of the consolidated financial statements.)
Note A: Summary of Significant Accounting Policies
Allegheny Power System, 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, The Potomac
Edison Company, and West Penn Power Company. The principal markets for the
System's electric sales are in the states of Pennsylvania, West Virginia,
Maryland, Virginia, and Ohio. In 1995, revenues from 50 of its largest electric
utility customers provided approximately 20% of the System's retail revenues.
The Company also has a wholly-owned nonutility subsidiary, AYP Capital, Inc.,
formed in 1994, which is involved primarily in energy-related services,
development of wholesale unregulated power generation, and other energy-related
businesses.
The Company and its subsidiaries are subject to regulation by the Securities
and Exchange Commission (SEC), including the Public Utility Holding Company Act
of 1935. The regulated subsidiaries are subject to regulation by various state
bodies having jurisdiction and by the Federal Energy Regulatory Commission
(FERC). 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:
Beginning in 1994, 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. In 1993, revenues were recorded for
billings rendered to customers, except for a portion of unbilled revenues in
West Virginia.
Deferred Power Costs, Net:
The costs of fuel, purchased power, and certain other costs, and revenues from
sales to other utilities, 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 are stated at original cost, less contributions
in aid of construction, except for capital leases which are recorded at present
value. Cost includes 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, and pensions,
taxes, and other fringe benefits related to employees engaged in construction.
The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
<PAGE>
111
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 property, plant, and equipment with
offsetting credits to other income and interest charges. Rates used by the
subsidiaries for computing AFUDC in 1995, 1994, and 1993 averaged 8.73%, 9.00%,
and 9.37%, respectively. AFUDC is not included in the cost of such 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 3.5% of average depreciable property in 1995, 3.3% in 1994, and
3.4% in 1993. The cost of maintenance and of certain replacements of property,
plant, and equipment is charged principally to operating expenses.
Investments:
The investment in subsidiaries consolidated represents the excess of acquisi-
tion 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 represent the estimated cash surrender values of
purchased life insurance on the Board of Directors and qualifying management
employees under a Directors' pension plan, and an executive life insurance plan
and a supplemental executive retirement plan. Payment of future premiums will
fully fund these benefits.
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. 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
utilizing 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 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 subsidiaries also provide partially contributory medical and life
insurance plans for eligible retirees and dependents. Medical benefits, which
comprise 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 an amount equal to the annual cost, but not
more than can be deducted for federal income tax purposes. Funding of these
benefits is made primarily into Voluntary Employee Beneficiary Association
(VEBA) trust funds in amounts up to that which can be deducted for federal
<PAGE>
112
income tax purposes. Medical benefits are self-insured; the life insurance plan
is paid through insurance premiums.
Accounting Changes:
Effective January 1, 1994, the regulated subsidiaries changed their revenue
recognition method to include the accrual of estimated unbilled revenues for
electric services. This change results in a better matching of revenues and
expenses, and is consistent with predominant utility industry practice.
Previously, in accordance with rate making procedures followed in West Virginia,
Monongahela Power Company had recorded a portion of revenues for service
rendered but unbilled at year-end. The cumulative effect of this accounting
change for years prior to 1994, which is shown separately in the consolidated
statement of income for 1994, resulted in a benefit of $43.4 million (after
related income taxes of $28.9 million), or $.37 per share of common stock. The
effect of the change on 1994 consolidated income before the cumulative effect of
accounting change, as well as 1993 consolidated net income, is not material.
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective in
1996. The Company does not believe at this time that the adoption of this
standard will have a materially adverse effect on its financial position.
Note B: Restructuring Charges and Asset Write-Offs
The System is undergoing a reorganization and reengineering process (restruc-
turing) to simplify its management structure and to increase efficiency. As a
consequence of this process, approximately 200 employees, primarily in the Bulk
Power Supply department, have been placed in a staffing force. In January 1996,
these employees were offered an option to resign immediately under a Voluntary
Separation Program (VSP) or to remain employed subject to involuntary separation
(layoff) after one year, if during that year they have not found
other employment within the System.
In 1995, the regulated subsidiaries recorded restructuring charges of $16.0
million ($9.6 million after tax) in other operation expense, for the estimated
liabilities related primarily to staffing force employees' involuntary
separation costs. Further separation costs for these employees will be recorded
in 1996 depending upon those employees who elect early separation under the VSP,
which provides enhanced separation benefits. Additional restructuring costs may
be required as the restructuring process is completed for other departments.
In connection with changes in inventory management objectives, the regulated
subsidiaries in 1995 also recorded $7.4 million ($4.5 million after tax)
primarily in maintenance expense for the write-off of obsolete and slow-moving
materials.
In 1994, the regulated subsidiaries wrote off $9.2 million ($5.3 million after
tax) in other income (expense), net, of previously accumulated costs related to
a potential future power plant site and 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 C: Income Taxes
Details of federal and state income tax provisions are:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994 1993
Income taxes-current:
<S> <C> <C> <C>
Federal $112,482 $114,263 $110,815
State 17,375 15,633 20,732
Total 129,857 129,896 131,547
<PAGE>
113
Income taxes-deferred, net of amortization 35,279 33,994 6,034
Amortization of deferred investment credit (8,260) (8,310) (8,422)
Total income taxes 156,876 155,580 129,159
Income taxes-credited (charged) to other
income and deductions (2,673) 3,058 (1,029)
Income taxes-charged to accounting change
(including state income taxes) (28,887)
Income taxes-charged to operating income $154,203 $129,751 $128,130
</TABLE>
The total provision for income taxes is different than the amount produced
by applying the federal income statutory tax rate to financial accounting
income, as set forth below:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994 1993
Financial accounting income before cumulative effect of
<S> <C> <C> <C>
accounting change, preferred dividends, and income taxes $409,110 $369,598 $360,984
Amount so produced $143,200 $129,400 $126,300
Increased (decreased) for:
Tax deductions for which deferred tax was not provided:
Lower tax depreciation 13,500 8,000 8,800
Plant removal costs (3,500) (5,600) (6,000)
State income tax, net of federal income tax benefit 16,300 11,600 15,000
Amortization of deferred investment credit (8,260) (8,310) (8,422)
Other, net (7,037) (5,339) (7,548)
Total $154,203 $129,751 $128,130
</TABLE>
Federal income tax returns through 1991 have been examined and
substantially settled.
At December 31, the deferred tax assets and liabilities were comprised of
the following:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994
Deferred tax assets:
<S> <C> <C>
Unamortized investment tax credit $ 92,715 $ 99,821
Unbilled revenue 12,187 13,043
Tax interest capitalized 35,029 33,773
Contributions in aid of construction 21,111 18,742
Postretirement benefits other than pensions 8,671 4,719
Deferred power costs, net 7,483
State tax loss carryback/carryforward 532 8,256
Other 43,142 36,208
220,870 214,562
Deferred tax liabilities:
Book vs. tax plant basis differences, net 1,108,948 1,123,763
Other 69,071 51,996
1,178,019 1,175,759
Total net deferred tax liabilities 957,149 961,197
Add portion above included in current assets 28,655 10,916
Total long-term net deferred tax liabilities $ 985,804 $ 972,113
</TABLE>
<PAGE>
114
It is expected that regulatory commissions will allow recovery of the deferred
tax liabilities in future years as they are paid, and accordingly, the regulated
subsidiaries have recorded regulatory assets of $559 million and $605 million as
of December 31, 1995 and 1994, respectively. Regulatory liabilities of $98
million and $105 million as of December 31, 1995 and 1994, respectively, have
been recorded in order to reflect the subsidiaries' obligation to pass such tax
benefits on to their customers as the benefits are realized in cash in future
years.
Note D: Dividend Restriction
Supplemental indentures relating to most outstanding bonds of the regulated
subsidiaries contain dividend restrictions under the most restrictive of which
$209,729,000 of consolidated retained earnings at December 31, 1995, 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 E: Pension Benefits
Net pension costs, a portion of which (about 25% to 30%) was charged to plant
construction, included the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994 1993
<S> <C> <C> <C>
Service cost-benefits earned $ 13,695 $14,940 $13,361
Interest cost on projected benefit obligation 39,901 38,630 37,387
Actual return on plan assets (107,972) (61) (89,680)
Net amortization and deferral 56,451 (48,983) 43,653
Pension cost 2,075 4,526 4,721
Regulatory reversal (deferral) 760 6,681 (1,509)
Net pension cost $ 2,835 $11,207 $ 3,212
</TABLE>
The benefits earned to date and funded status at December 31 using a
measurement date of September 30 were as follows:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994
Actuarial present value of accumulated benefit obligation earned
<S> <C> <C>
to date (including vested benefit of $432,922,000 and $403,610,000) $462,733 $429,998
Funded status:
Actuarial present value of projected benefit obligation $568,479 $529,411
Plan assets at market value, primarily common stocks and fixed
income securities 666,740 573,122
Plan assets in excess of projected benefit obligation (98,261) (43,711)
Add:
Unrecognized cumulative net gain from past experience different from
that assumed 94,809 52,078
Unamortized transition asset, being amortized over 14 years beginning
January 1, 1987 15,736 18,882
Less unrecognized prior service cost due to plan amendments 9,510 10,650
Pension cost liability at September 30 2,774 16,599
Fourth quarter contributions 7,800
Pension liability at December 31 $ 2,774 $ 8,799
</TABLE>
<PAGE>
115
In determining the actuarial present value of the projected benefit obligation
at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%, 7.75%,
and 7.25%, and the rates of increase in future compensation levels were 4.5%,
4.75%, and 4.75%, respectively. The expected long-term rate of return on assets
was 9% in each of the years 1995, 1994, and 1993.
Note F: Postretirement Benefits Other Than Pensions
The cost of postretirement benefits other than pensions (principally health
care and life insurance) for employees and covered dependents in 1995 and
1994, a portion of which (about 25% to 30%) was charged to plant
construction, included the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994
<S> <C> <C>
Service cost-benefits earned $ 2,919 $ 3,058
Interest cost on accumulated postretirement benefit obligation 14,736 13,732
Actual (return) loss on plan assets (6,378) 135
Amortization of unrecognized transition obligation 7,272 7,300
Other net amortization and deferral 5,163 206
Postretirement cost 23,712 24,431
Regulatory reversal (deferral) 492 (3,908)
Net postretirement cost $24,204 $20,523
</TABLE>
The benefits earned to date and funded status at December 31 using a
measurement date of September 30 were as follows:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994
Accumulated postretirement benefit obligation:
<S> <C> <C>
Retirees $115,965 $118,518
Fully eligible employees 25,994 24,791
Other employees 53,883 52,914
Total obligation 195,842 196,223
Plan assets at market value, in common stocks, fixed income securities,
and short-term investments 39,875 19,791
Accumulated postretirement benefit obligation in excess
of plan assets 155,967 176,432
Less:
Unrecognized cumulative net loss from past experience different
from that assumed 19,529 34,190
Unrecognized transition obligation, being amortized over 20 years
beginning January 1, 1993 123,628 130,900
Postretirement benefit liability at September 30 12,810 11,342
Fourth quarter contributions and benefit payments 9,313 5,826
Postretirement benefit liability at December 31 $ 3,497 $ 5,516
</TABLE>
<PAGE>
116
In determining the APBO at September 30, 1995, 1994, and 1993, the discount
rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future
compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995 expected
long-term rate of return on assets was 8.25% net of tax. For measurement
purposes, a health care trend rate of 8% for 1996, declining 1% each year
thereafter to 6.5% in the year 1998 and beyond, and plan provisions which limit
future medical and life insurance benefits, were assumed. Increasing the assumed
health care trend rate by 1% in each year would increase the APBO at
December 31, 1995, by $12.8 million and the aggregate of the service
and interest cost components of net periodic postretirement benefit
cost for 1995 by $1.3 million.
Note G: Fair Value of Financial Instruments
The carrying amounts and estimated fair value of
financial instruments at December 31 were as follows:
<TABLE>
<CAPTION>
1995 1994
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
Assets:
<S> <C> <C> <C> <C>
Temporary cash investments $ 425 $ 425 $ 73 $ 73
Life insurance contracts 47,545 47,545 35,584 33,884
Liabilities:
Short-term debt 200,418 200,418 126,818 126,818
Long-term debt and QUIDS 2,340,888 2,409,080 2,224,606 2,114,871
</TABLE>
The carrying amount of temporary cash investments, as well as short-term debt,
approximates the fair value because of the short maturity of those instruments.
The fair value of long-term debt and QUIDS was estimated based on actual market
prices or market prices of similar issues. The fair value of the life insurance
contracts in Note A was estimated based on cash surrender value. The Company
does not have any financial instruments held or issued for trading purposes.
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.
Note H: Capitalization
Common Stock:
In November 1993, the common shareholders approved a two-for-one split of the
Company's common stock effective November 4, 1993. The stock split reduced the
par value of the common stock from $2.50 per share to $1.25 per share and
increased the number of authorized shares of common stock from 130,000,000 to
260,000,000. The number of common stock shares outstanding and per share
information for all periods reflect the two-for-one split.
Preferred Stock:
In 1995, the regulated subsidiaries refunded $130 million of preferred stock
with dividend rates between 7% and 8.8%, with the proceeds from the issuance of
Quarterly Income Debt Securities (QUIDS) described below. 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 Power
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.
<PAGE>
117
Long-Term Debt and QUIDS:
Maturities for long-term debt for the next five years are: 1996, $43,575,000;
1997, $26,900,000; 1998, $185,400,000; 1999, $34,861,000; and 2000,
$145,300,000. 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.
In 1995, the regulated subsidiaries issued $155.5 million of 8% 30-year QUIDS
to refund preferred stock. Under certain circumstances the interest payments may
be deferred for a period of up to 20 consecutive quarters.
Commercial paper borrowings issuable by Allegheny Generating Company are
backed by a revolving credit agreement with a group of seven banks which
provides for loans of up to $50 million at any one time outstanding through
1999. Each bank has the option to discontinue its loans after 1999 upon three
years' prior written notice. Without such notice, the loans are automatically
extended for one year. However, to the extent that funds are available from the
Company and its regulated subsidiaries, Allegheny Generating Company borrowings
are made through an internal money pool as described in Note I.
Note I: 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, 1995, unused lines of
credit with banks were $173,350,000. In addition to bank lines of credit, an
internal money pool accommodates intercompany short-term borrowing needs, to
the extent that certain of the companies have funds available. In January 1994,
a multi-year credit program was established which provides that the regulated
subsidiaries may borrow up to $300 million on a standby revolving credit basis.
Short-term debt outstanding for 1995 and 1994 consisted
of:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1995 1994
Balance at end of year:
<S> <C> <C>
Commercial Paper $148,768 - 5.97% $103,968 - 6.06%
Notes Payable to Banks 51,650 - 5.96% 22,850 - 5.92%
Average amount outstanding during the year:
Commercial Paper 97,689 - 6.08% 67,290 - 4.25%
Notes Payable to Banks 21,134 - 6.00% 33,273 - 4.17%
</TABLE>
Note J: Commitments and Contingencies
Construction Program:
The regulated subsidiaries have entered into commitments for their
construction programs, for which expenditures are estimated to be $279
million for 1996 and $305 million for 1997. Through 1999, annual
construction expenditures are not expected to significantly exceed 1996
estimated levels. Construction expenditure levels in 2000 and beyond will
depend upon future generation requirements, as well as the strategy eventually
selected for complying with Phase II of the Clean Air Act Amendments of 1990.
Nonutility Investments:
AYP Capital, Inc. has entered into an agreement with Duquesne Light Company,
subject to regulatory approvals, to purchase its 50% interest in Unit No. 1 of
the Fort Martin Power Station for approximately $170 million. AYP Capital
intends to operate the unit as an exempt wholesale generator and sell the output
at market rates. Necessary regulatory approvals will likely take several months,
and AYP Capital expects a closing by late 1996.
<PAGE>
118
AYP Capital has committed to invest up to $10 million in two limited partner-
ships formed to invest in emerging electrotechnologies that promote the
efficient use of electricity and improve the environment, and to invest in and
develop electric energy opportunities in Latin America. As of December 31, 1995,
AYP Capital's investments totaled $1.1 million.
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 affect adversely the lead time, size, and siting of future
generating stations, increase the complexity and cost of pollution control
equipment, and otherwise add to the cost of future operations. In the normal
course of business, the companies become involved in various legal proceedings.
The companies do not believe that the ultimate outcome of these proceedings
will have a material effect on their financial position.
The regulated subsidiaries previously reported that the Environmental Protec-
tion Agency (EPA) had identified them and approximately 875 others as potential-
ly responsible parties in a Superfund site subject to cleanup. The regulated
subsidiaries have also been named as defendants along with multiple other
defendants in pending asbestos cases involving one or more plaintiffs.
The 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.
<PAGE>
<TABLE>
<CAPTION>
119
Monongahela
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential..................................................... $209,065 $190,861 $185,141
Commercial...................................................... 124,457 116,201 110,762
Industrial...................................................... 212,427 202,181 187,669
Nonaffiliated utilities......................................... 90,916 79,701 86,032
Other, including affiliates..................................... 85,617 91,186 72,240
Total Operating Revenues...................................... 722,482 680,130 641,844
Operating Expenses:
Operation:
Fuel.......................................................... 136,695 150,088 144,408
Purchased power and exchanges, net............................ 176,380 161,839 155,602
Deferred power costs, net (Note A)............................ 19,647 7,604 (2,489)
Other (Note B)................................................ 81,136 74,907 66,506
Maintenance (Note B)............................................ 74,418 69,389 67,770
Depreciation.................................................... 57,864 57,952 56,056
Taxes other than income taxes................................... 38,551 40,404 34,076
Federal and state income taxes (Note C)......................... 41,834 30,712 33,612
Total Operating Expenses...................................... 626,525 592,895 555,541
Operating Income.............................................. 95,957 87,235 86,303
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A).................................. 446 1,566 3,092
Other income, net............................................... 9,235 7,911 7,203
Total Other Income and Deductions............................. 9,681 9,477 10,295
Income Before Interest Charges................................ 105,638 96,712 96,598
Interest Charges:
Interest on long-term debt...................................... 37,244 35,187 35,555
Other interest.................................................. 2,628 2,969 2,033
Allowance for borrowed funds used during
construction (Note A)......................................... (947) (1,380) (2,688)
Total Interest Charges........................................ 38,925 36,776 34,900
Income Before Cumulative Effect of
Accounting Change............................................... 66,713 59,936 61,698
Cumulative Effect of Accounting Change,
net (Note A).................................................... 7,945
Net Income........................................................ $ 66,713 $ 67,881 $ 61,698
Monongahela
STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $198,626 $185,486 $178,084
Add:
Net income...................................................... 66,713 67,881 61,698
265,339 253,367 239,782
Deduct:
Dividends on capital stock:
Preferred stock............................................... 6,555 7,260 4,458
Common stock.................................................. 48,660 47,481 49,838
Charge on redemption of preferred stock......................... 1,363
Total Deductions............................................ 56,578 54,741 54,296
Balance at December 31 (Note D)................................... $208,761 $198,626 $185,486
See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
120
Monongahela
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income...................................................... $ 66,713 $ 67,881 $ 61,698
Depreciation.................................................... 57,864 57,952 56,056
Deferred investment credit and income taxes, net................ 3,519 3,350 6,352
Deferred power costs, net....................................... 19,647 7,604 (2,489)
Unconsolidated subsidiaries' dividends in excess of earnings.... 2,403 1,647 1,971
Allowance for other than borrowed funds used
during construction........................................... (446) (1,566) (3,092)
Cumulative effect of accounting change before
income taxes (Note A)......................................... (13,279)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative effect
of accounting change (Note A)............................... (11,222) 4,756 (8,412)
Materials and supplies........................................ 6,639 (5,944) 12,917
Accounts payable.............................................. (3,373) (2,044) 129
Taxes accrued................................................. 8,506 (950) (5,674)
Interest accrued.............................................. (2,350) 286 290
Other, net...................................................... 586 1,731 3,296
148,486 121,424 123,042
Cash Flows from Investing:
Construction expenditures....................................... (75,458) (103,975) (140,748)
Allowance for other than borrowed
funds used during construction................................ 446 1,566 3,092
(75,012) (102,409) (137,656)
Cash Flows from Financing:
Sale of preferred stock......................................... 49,635
Retirement of preferred stock................................... (41,406)
Issuance of long-term debt and QUIDS............................ 132,137 9,718 82,331
Retirement of long-term debt.................................... (99,403) (68,471)
Short-term debt, net............................................ (6,702) (26,530) 63,100
Notes payable to affiliates..................................... (2,900) 2,900 (8,030)
Dividends on capital stock:
Preferred stock............................................... (6,555) (7,260) (4,458)
Common stock.................................................. (48,660) (47,481) (49,838)
(73,489) (19,018) 14,634
Net Change in Cash and
Temporary Cash Investments (Note H)............................. (15) (3) 20
Cash and Temporary Cash Investments at January 1.................. 132 135 115
Cash and Temporary Cash Investments at December 31................ $ 117 $ 132 $ 135
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 42,394 $ 35,347 $ 33,941
Income taxes.................................................. 30,696 29,939 30,982
See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
121
Monongahela
BALANCE SHEET
DECEMBER 31
ASSETS 1995 1994
(Thousands of Dollars)
Property, Plant, and Equipment:
At original cost, including $29,443,000 and
<S> <C> <C>
$35,856,000 under construction...................................... $1,821,613 $1,763,533
Accumulated depreciation.............................................. (747,013) (701,271)
1,074,600 1,062,262
Investments:
Allegheny Generating Company--common stock
at equity (Note E).................................................. 57,821 60,137
Other................................................................. 422 509
58,243 60,646
Current Assets:
Cash.................................................................. 117 132
Accounts receivable:
Electric service, net of $2,267,000 and
$1,912,000 uncollectible allowance (Note A)....................... 71,759 62,631
Affiliated and other................................................ 11,577 9,483
Materials and supplies--at average cost:
Operating and construction.......................................... 21,297 24,563
Fuel................................................................ 20,305 23,678
Prepaid taxes......................................................... 17,778 17,599
Deferred income taxes................................................. 7,972 1,094
Other................................................................. 4,857 6,086
155,662 145,266
Deferred Charges:
Regulatory assets (Note C)............................................ 164,900 186,109
Unamortized loss on reacquired debt................................... 16,174 11,500
Other................................................................. 11,012 10,700
192,086 208,309
Total................................................................... $1,480,591 $1,476,483
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes D and I)............................................ $ 505,752 $ 495,693
Preferred stock (Note I).............................................. 74,000 114,000
Long-term debt and QUIDS (Note I)..................................... 489,995 470,131
1,069,747 1,079,824
Current Liabilities:
Short-term debt (Note J).............................................. 29,868 36,570
Long-term debt due within one year (Note I)........................... 18,500
Notes payable to affiliates (Note J).................................. 2,900
Accounts payable...................................................... 24,582 31,871
Accounts payable to affiliates........................................ 9,937 6,021
Taxes accrued:
Federal and state income............................................ 8,068 118
Other............................................................... 20,749 20,193
Deferred power costs (Note A)......................................... 14,202
Interest accrued...................................................... 8,577 10,927
Other................................................................. 16,196 16,455
150,679 125,055
Deferred Credits and Other Liabilities:
Unamortized investment credit......................................... 22,590 24,734
Deferred income taxes................................................. 206,616 216,264
Regulatory liabilities (Note C)....................................... 20,183 19,974
Other................................................................. 10,776 10,632
260,165 271,604
Commitments and Contingencies (Note K)
Total................................................................... $1,480,591 $1,476,483
See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
122
Monongahela
STATEMENT OF CAPITALIZATION
As of December 31
(Thousands of Dollars) (Capitalization Ratios)
1995 1994 1995 1994
Common Stock:
Common stock--par value $50 per share, authorized
<S> <C> <C>
8,000,000 shares, outstanding 5,891,000 shares.... $ 294,550 $ 294,550
Other paid-in capital (Note I)...................... 2,441 2,517
Retained earnings (Note D).......................... 208,761 198,626
Total........................................... 505,752 495,693 47.3% 45.9%
Preferred Stock
Cumulative preferred stock--par value $100 per share,
authorized 1,500,000 shares, outstanding as follows
(Note I):
December 31, 1995
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
$7.36 E... 1968 5,000
$8.80 G... 1971 5,000
$7.92 H... 1972 5,000
$7.92 I... 1973 10,000
$8.60 J... 1976 15,000
$7.73 L... 500,000 100.00 1994 50,000 50,000
Total (annual dividend requirements $5,037,000) 74,000 114,000 6.9 10.6
Long-Term Debt and QUIDS (Note I):
First mortgage Date of Date Date
bonds: Issue Redeemable Due
5-1/2% ... 1966 1996 1996 18,000 18,000
6-1/2% ... 1967 1996 1997 15,000 15,000
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
8-7/8% ... 1989 70,000
8-5/8% ... 1991 2001 2021 50,000 50,000
8-1/2% ... 1992 1997 2022 65,000 65,000
8-3/8% ... 1992 2002 2022 40,000 40,000
7-5/8% ... 1995 2005 2025 70,000
December 31, 1995
Interest Rate - %
Quarterly Income Debt Securities
due 2025...................... 8.00 40,000
Secured notes due 1998-2024..... 5.95-6.875 74,050 74,050
Unsecured notes due 1996-2012... 6.30-6.40 7,560 7,560
Installment purchase
obligations due 1998.......... 6.875 19,100 19,100
Unamortized debt discount and premium, net.......... (5,215) (3,579)
Total (annual interest requirements $37,475,131) 508,495 470,131
Less current maturities............................. (18,500)
Total........................................... 489,995 470,131 45.8 43.5
Total Capitalization.................................. $1,069,747 $1,079,824 100.0% 100.0%
See accompanying notes to financial statements.
</TABLE>
<PAGE>
123
Monongahela
NOTES TO FINANCIAL STATEMENTS
(These notes re an integral part of the financial statements)
Note A - Summary of Significant
Accounting Policies:
The Company is a wholly-owned subsidiary of Allegheny Power System, Inc. and
is a part of the Allegheny Power integrated electric utility system (the
System).
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. This procedure has been utilized
for a number of years in West Virginia, as required by the Public
Service Commission of West Virginia, and was adopted for all revenues
beginning in 1994.
DEFERRED POWER COSTS, NET:
The costs of fuel, purchased power, and certain other costs, and revenues
from sales to other companies, 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 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. Cost includes 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, and pensions,taxes, and other fringe benefits related
to employees engaged in construction.
The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
<PAGE>
124
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
1995, 1994, and 1993 were 7.29%, 8.16%, and 8.69%, respectively. AFUDC
is not included in the cost of such 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 3.4%, 3.6%, and 3.8% of average depreciable property
in 1995, 1994, and 1993, respectively. The cost of maintenance and of
certain replacements of property, plant, and equipment is charged
principally to operating expenses.
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 utilizing 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 in the System 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 also provides partially contributory medical and life insurance
plans for eligible retirees and dependents. Medical benefits, which
comprise 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 an amount equal to the annual cost,
<PAGE>
125
but not more than can be deducted for federal income tax purposes.
Funding of these benefits is made primarily into Voluntary Employee
Beneficiary Association (VEBA) trust funds in amounts up to that which can be
deducted for federal income tax purposes. Medical benefits are self-
insured; the life insurance plan is paid through insurance premiums.
ACCOUNTING CHANGES:
Effective January 1, 1994, the Company changed its revenue recognition
method to include the accrual of estimated unbilled revenues for
electric services. This change results in a better matching of revenues and
expenses, and is consistent with predominant utility industry practice and
the practice used in West Virginia for a number of years. The cumulative
effect of this accounting change for the years prior to the adoption of
this practice, including West Virginia, is shown separately in the statement
of income for 1994, and resulted in a benefit of $7.9 million (after
related income taxes of $5.4 million). The effect of the change on 1994
income before the cumulative effect of accounting change, as well as 1993 net
income, is not material.
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of," effective in 1996. The Company does not believe at this time that the
adoption of this standard will have a materially adverse
effect on its financial position.
Note B - Restructuring Charges and Asset Write-Offs:
The System is undergoing a reorganization and reengineering process
(restructuring) to simplify its management structure and to increase
efficiency. As a consequence of this process, approximately 200 employees,
primarily in the System's Bulk Power Supply department, have been placed in a
staffing force. In January 1996, these employees were offered an option
to resign immediately under a Voluntary Separation Program (VSP) or to remain
employed subject to involuntary separation (layoff) after one year, if during
that year they have not found other employment within the System.
In 1995, the Company recorded restructuring charges of $4.1 million
($2.5 million after tax) in other operation expense, for its share of the
estimated liabilities related primarily to staffing force employees'
involuntary separation costs. Further separation costs for these
employees will be recorded in 1996 depending upon those employees who elect
early separation under the VSP, which provides enhanced separation
benefits. Additional restructuring costs may be required as the
restructuring process is completed for other departments.
In connection with changes in inventory management objectives, the Company
in 1995 also recorded $1.4 million ($.8 million after tax) primarily in
maintenance expense for the write-off of obsolete and slow-moving materials.
<PAGE>
126
Note C - Income Taxes:
<TABLE>
<CAPTION>
Details of federal and state income tax provisions are:
1995 1994 1993
(Thousands of Dollars)
Income taxes--current:
<S> <C> <C> <C>
Federal............................. $30,236 $27,793 $25,618
State............................... 8,707 4,841 1,692
Total............................. 38,943 32,634 27,310
Income taxes--deferred, net of
amortization........................ 5,664 5,499 8,517
Amortization of deferred
investment credit................... (2,145) (2,149) (2,165)
Total income taxes................ 42,462 35,984 33,662
Income taxes--credited (charged)
to other income and deductions...... (628) 63 (50)
Income taxes--charged to accounting
change (including state income
taxes).............................. (5,335)
Income taxes--charged to operating
income.............................. $41,834 $30,712 $33,612
</TABLE>
The total provision for income taxes is different than the amount produced
by applying the federal income statutory tax rate to financial
accounting income, as set forth below:
<TABLE>
<CAPTION>
1995 1994 1993
(Thousands of Dollars)
Financial accounting income before
cumulative effect of accounting
<S> <C> <C> <C>
change and income taxes............. $108,547 $90,648 $95,310
Amount so produced.................... $ 38,000 $31,700 $33,400
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation.......... 4,300 5,400 5,700
Plant removal costs............. (1,500) (2,100) (3,000)
State income tax, net of federal
income tax benefit................ 4,800 3,500 3,800
Amortization of deferred
investment credit................. (2,145) (2,149) (2,165)
Equity in earnings of
subsidiaries...................... (2,500) (2,800) (2,500)
Adjustments of provisions
for prior years................... 2,431 (1,900) 400
Other, net.......................... (1,552) (939) (2,023)
Total........................... $ 41,834 $30,712 $33,612
</TABLE>
Federal income tax returns through 1991 have been examined and substantially
settled.
<PAGE>
127
<TABLE>
<CAPTION>
At December 31, the deferred tax assets and liabilities were comprised of
the following:
1995 1994
(Thousands of Dollars)
Deferred tax assets:
<S> <C> <C>
Unamortized investment tax credit............ $ 15,133 $ 16,604
Tax interest capitalized..................... 4,759 4,907
Deferred power costs......................... 7,483
Contributions in aid of construction......... 2,488 2,223
Advances for construction.................... 1,939 1,771
Other........................................ 12,046 10,747
43,848 36,252
Deferred tax liabilities:
Book vs. tax plant basis differences, net.... 209,527 228,997
Other........................................ 32,964 22,425
242,491 251,422
Total net deferred tax liabilities............. 198,643 215,170
Add portion above included in
current assets............................... 7,973 1,094
Total long-term net deferred
tax liabilities.............................. $206,616 $216,264
</TABLE>
It is expected that regulatory commissions will allow recovery of the
deferred tax liabilities in future years as they are paid, and accordingly,
the Company has recorded regulatory assets of $152 million and $174 million
as of December 31, 1995 and 1994, respectively. Regulatory liabilities of
$20 million as of December 31, 1995 and 1994, respectively, have been
recorded in order to reflect the Company's obligation to pass such tax
benefits on to its customers as the benefits are realized in cash in future
years.
Note D - Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of the Company
contain dividend restrictions under the most restrictive of which
$76,384,000 of retained earnings at December 31, 1995, is not available for cash
dividends on common stock, except that a portion thereof may be paid as cash
dividends where concurrently an equivalent amount of cash is received by the
Company as a capital contribution or as the proceeds of the issue
and sale of shares of its common stock.
Note E - Allegheny Generating Company:
The Company owns 27% of the common stock of Allegheny Generating Company
(AGC), and affiliates of the Company own the remainder. AGC 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 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.
<PAGE>
128
The only component which changes is the return on equity (ROE). In December
1991, AGC filed for a continuation of the existing ROE of 11.53% and other
interested parties filed to reduce the ROE to 10%. A recommendation
was issued by an Administrative Law Judge on December 22, 1994, to dismiss the
joint complaint. A settlement agreement for both cases was filed
with the FERC on January 12, 1995, which would reduce AGC's ROE from 11.53%
to 11.13% for the period from March 1, 1992, through December 31, 1994, and
increase AGC's ROE to 11.2% for the period from January 1, 1995, through
December 31, 1995. This settlement was approved by the FERC on March 23,
1995. Refunds were made by AGC of any revenues collected between March 1,
1992 and March 23, 1995 in excess of these levels. A second settlement
has been negotiated to address AGC's ROE after 1995. On December 21, 1995,
AGC submitted the new settlement to the FERC. Interested parties representing
less than 2% of AGC's eventual revenues have filed exceptions to the
settlement. Under the terms of the settlement, AGC's ROE for 1996 would
be 11%, and set by formula in 1997 and 1998 based primarily on changes in
interest rates.
Following is a summary of financial information for AGC:
December 31
1995 1994
(Thousands of Dollars)
Balance sheet information:
Property, plant, and equipment............... $677,857 $680,749
Current assets............................... 7,586 5,991
Deferred charges............................. 24,844 27,496
Total assets............................... $710,287 $714,236
Total capitalization......................... $463,862 $489,894
Current liabilities.......................... 11,892 6,484
Deferred credits............................. 234,533 217,858
Total capitalization and liabilities....... $710,287 $714,236
<TABLE>
<CAPTION>
Year Ended December 31
1995 1994 1993
(Thousands of Dollars)
Income statement information:
<S> <C> <C> <C>
Electric operating revenues......... $86,970 $91,022 $90,606
Operation and maintenance
expense........................... 5,740 6,695 6,609
Depreciation........................ 17,018 16,852 16,899
Taxes other than income taxes....... 5,091 5,223 5,347
Federal income taxes................ 13,552 14,737 13,262
Interest charges.................... 18,361 17,809 21,635
Other income, net................... (16) (11) (328)
Net income........................ $27,224 $29,717 $27,182
</TABLE>
The Company's share of the equity in earnings above was $7.4 million, $8.0
million, and $7.3 million for 1995, 1994, and 1993, respectively, and is
included in other income, net, on the Statement of Income.
<PAGE>
129
Note F - Pension Benefits:
The Company's share of net pension costs under the System's pension plan, a
portion of which (about 25% to 30%) was charged to plant construction,
included the following components:
1995 1994 1993
(Thousands of Dollars)
Service cost - benefits earned........ $ 3,340 $ 3,677 $ 3,198
Interest cost on projected
benefit obligation.................. 9,375 9,045 8,577
Actual (return) loss on
plan assets......................... (27,269) 87 (22,606)
Net amortization and deferral......... 15,183 (11,563) 12,048
Pension cost.......................... 629 1,246 1,217
Regulatory reversal (deferral)........ 3,718 (1,179)
Net pension cost...................... $ 629 $ 4,964 $ 38
The benefits earned to date and funded status of the Company's share of the
System plan at December 31 using a measurement date of September 30
were as follows:
1995 1994
(Thousands of Dollars)
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of
$100,006,000 and $92,823,000)................ $107,672 $ 99,605
Funded status:
Actuarial present value of projected
benefit obligation......................... $133,485 $123,935
Plan assets at market value, primarily
common stocks and fixed income securities.. 156,554 134,166
Plan assets in excess of projected
benefit obligation......................... (23,069) (10,231)
Add:
Unrecognized cumulative net gain from
past experience different from
that assumed............................. 24,151 13,969
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987.......................... 3,242 3,988
Less unrecognized prior service
cost due to plan amendments................ 2,195 2,471
Pension cost liability at September 30....... 2,129 5,255
Fourth quarter contributions................. 1,829
Pension liability at December 31............. $ 2,129 $ 3,426
The foregoing includes the Company's portion of amounts applicable to
employees at power stations which are owned jointly with affiliates.
In determining the actuarial present value of the projected benefit
obligation at September 30, 1995, 1994, and 1993, the discount rates used
were 7.5%, 7.75%, and 7.25%, and the rates of increase in future
<PAGE>
130
compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The expected
long-term rate of return on assets was 9% in each of the years 1995, 1994,
and 1993.
Note G - Postretirement Benefits Other
Than Pensions:
The cost of postretirement benefits other than pensions (principally health
care and life insurance) for employees and covered dependents in 1995
and 1994, a portion of which (about 25% to 30%) was charged to plant
construction, included the following components:
1995 1994
(Thousands of Dollars)
Service cost - benefits earned.................. $ 741 $ 764
Interest cost on accumulated
postretirement benefit obligation............. 3,939 3,655
Actual (return) loss on plan assets............. (1,702) 38
Amortization of unrecognized
transition obligation......................... 1,783 1,783
Other net amortization and deferral............. 1,376 50
Postretirement cost............................. 6,137 6,290
Regulatory reversal (deferral).................. 345 (3,450)
Net postretirement cost......................... $ 6,482 $ 2,840
The benefits earned to date and funded status of the Company's share of the
System plan at December 31 using a measurement date of September 30
were as follows:
1995 1994
(Thousands of Dollars)
Accumulated postretirement benefit obligation
(APBO):
Retirees.................................... $32,249 $33,528
Fully eligible employees.................... 5,221 4,947
Other employees............................. 14,177 14,458
Total obligation.......................... 51,647 52,933
Plan assets at market value, in common stocks,
fixed income securities, and short-term
investments................................... 10,515 5,338
Accumulated postretirement benefit
obligation in excess of plan assets........... 41,132 47,595
Less:
Unrecognized cumulative net loss from past
experience different from that assumed...... 7,559 12,752
Unrecognized transition obligation,
being amortized over 20 years
beginning January 1, 1993................... 30,378 32,368
Postretirement benefit liability
at September 30............................... 3,195 2,475
Fourth quarter contributions
and benefit payments.......................... 2,046 1,437
Postretirement benefit liability
at December 31................................ $ 1,149 $ 1,038
<PAGE>
131
In determining the APBO at September 30, 1995, 1994, and 1993, the discount
rates used were 7.5%, 7.75%, and 7.25% and the rates of increase in future
compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995
expected long-term rate of return on assets was 8.25% net of tax.
For measurement purposes, a health care trend rate of 8% for 1996, declining
1% each year thereafter to 6.5% in the year 1998 and beyond, and plan
provisions which limit future medical and life insurance benefits, were
assumed. Increasing the assumed health care trend rate by 1% in each year
would increase the APBO at December 31, 1995, by $3.4 million and the
aggregate of the service and interest cost components of net periodic
postretirement benefit cost for 1995 by $.3 million.
Note H - Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial instruments at
December 31 were as follows:
1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Liabilities:
Short-term debt..... $ 29,868 $ 29,868 $ 36,570 $ 36,570
Long-term debt and
QUIDS............. 513,710 540,387 473,710 458,714
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 does not have any financial instruments
held or issued for trading purposes.
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.
Note I - Capitalization:
COMMON STOCK AND OTHER PAID-IN CAPITAL:
Other paid-in capital decreased $76,000 in 1995 as a result of preferred
stock transactions and $477,000 in 1994 as a result of underwriting fees
and commissions associated with the Company's sale of $50 million of
preferred stock.
PREFERRED STOCK:
In 1995, the Company refunded $40 million of preferred stock with dividend
rates between 7.36% and 8.80%, with the proceeds from the issuance of
Quarterly Income Debt Securities (QUIDS) described below. In May 1994, the
Company issued 500,000 shares of Series L, $7.73 cumulative preferred stock
with par value of $100 per share. This Series is not redeemable prior
to August 1, 2004. All of the preferred stock is entitled on voluntary
liquidation to its then current call price and on involuntary liquidation to
$100 a share.
<PAGE>
132
LONG-TERM DEBT AND QUIDS:
Maturities for long-term debt for the next five years are: 1996,
$18,500,000; 1997, $15,500,000; 1998, $20,100,000; 1999, $1,000,000;
and 2000, $66,000,000. 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.
In 1995, the Company sold $70 million of 7-5/8% 30-year first mortgage
bonds to refund a $70 million 8-7/8% issue due in 2019. The Company also
issued $25 million of 6.15% 20-year tax-exempt notes to refund a $25
million 7-3/4% issue.
In 1995, the Company issued $40 million of 8% 30-year QUIDS to refund
preferred stock. QUIDS may not be redeemed until the year 2000. Under certain
circumstances the interest payments may be deferred for a period
of up to 20 consecutive quarters.
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 $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 internal money pool
accommodates intercompany short-term borrowing needs, to the extent that
certain of the companies have funds available. In January 1994, the
Company and its affiliates jointly established an aggregate $300 million
multi-year credit program which provides that the Company may borrow up to
$81 million on a standby revolving credit basis. Short-term debt
outstanding for 1995 and 1994 consisted of:
1995 1994
(Thousands of Dollars)
Balance at end of year:
Commercial Paper.................. $22,368-6.09% $24,970-6.21%
Notes Payable to Banks............ 7,500-6.00% 11,600-6.43%
Money Pool........................ 2,900-5.49%
Average amount outstanding
during the year:
Commercial Paper.................. 8,699-5.96% 8,751-3.58%
Notes Payable to Banks............ 7,153-5.99% 15,283-3.89%
Money Pool........................ 3,116-5.85% 11,363-4.51%
Note K - Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its construction program,
for which expenditures are estimated to be $66 million for 1996 and
$75 million for 1997. Through 1999, annual construction expenditures are
not expected to significantly exceed 1996 estimated levels. Construction
expenditure levels in 2000 and beyond will depend upon future generation
requirements, as well as the strategy eventually selected for complying with
Phase II of the Clean Air Act Amendments of 1990.
<PAGE>
133
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 affect adversely the lead time, size, and siting of
future generating stations, increase the complexity and cost of pollution
control equipment, and otherwise add to the cost of future operations.
In the normal course of business, the Company becomes
involved in various legal proceedings. The Company does not believe that
the ultimate outcome of these proceedings will have a material
effect on its financial position.
The Company previously reported that the Environmental Protection Agency
had identified it and its affiliates and approximately 875 others as
potentially responsible parties in a Superfund site subject to cleanup. The
Company has also been named as a defendant 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 their financial position.
The Company is guarantor as to 27% of a $50 million revolving credit
agreement of AGC, which in 1995 was used by AGC solely as support for its
indebtedness for commercial paper outstanding.
<PAGE>
134
<TABLE>
<CAPTION>
Potomac Edison
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential..................................................... $316,714 $296,090 $274,358
Commercial...................................................... 145,096 135,937 124,667
Industrial...................................................... 200,890 195,089 175,902
Nonaffiliated utilities......................................... 125,890 107,027 108,132
Other, including affiliates..................................... 30,429 25,222 29,526
Total Operating Revenues...................................... 819,019 759,365 712,585
Operating Expenses:
Operation:
Fuel.......................................................... 134,459 145,045 143,587
Purchased power and exchanges, net............................ 245,630 217,137 205,073
Deferred power costs, net (Note A)............................ 13,056 1,321 (9,953)
Other (Note B)................................................ 94,688 85,024 74,438
Maintenance (Note B)............................................ 62,147 58,624 64,376
Depreciation.................................................... 68,826 59,989 56,449
Taxes other than income taxes................................... 47,629 46,740 46,813
Federal and state income taxes (Note C)......................... 36,936 33,163 30,086
Total Operating Expenses...................................... 703,371 647,043 610,869
Operating Income.............................................. 115,648 112,322 101,716
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A).................................. 1,054 3,671 4,329
Other income, net............................................... 12,044 10,243 8,419
Total Other Income and Deductions............................. 13,098 13,914 12,748
Income Before Interest Charges................................ 128,746 126,236 114,464
Interest Charges:
Interest on long-term debt...................................... 49,113 44,706 42,695
Other interest.................................................. 2,066 1,750 1,107
Allowance for borrowed funds used during
construction (Note A)......................................... (698) (2,203) (2,805)
Total Interest Charges........................................ 50,481 44,253 40,997
Income Before Cumulative Effect of
Accounting Change............................................... 78,265 81,983 73,467
Cumulative Effect of Accounting Change,
net (Note A).................................................... 16,471
Net Income........................................................ $ 78,265 $ 98,454 $ 73,467
Potomac Edison
STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $207,722 $176,053 $167,412
Add:
Net income...................................................... 78,265 98,454 73,467
285,987 274,507 240,879
Deduct:
Dividends on capital stock:
Preferred stock............................................... 2,455 4,331 4,434
Common stock.................................................. 64,693 62,454 60,386
Charges on redemption of preferred stock........................ 1,987 6
Total Deductions............................................ 69,135 66,785 64,826
Balance at December 31 (Note D)................................... $216,852 $207,722 $176,053
See accompanying notes to financial statements.
</TABLE>
<PAGE>
135
<TABLE>
<CAPTION>
Potomac Edison
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income...................................................... $ 78,265 $ 98,454 $ 73,467
Depreciation.................................................... 68,826 59,989 56,449
Deferred investment credit and income taxes, net................ 14,279 12,688 (3,119)
Deferred power costs, net....................................... 13,056 1,321 (9,953)
Unconsolidated subsidiaries' dividends in excess of earnings.... 2,489 1,704 2,042
Allowance for other than borrowed funds used
during construction........................................... (1,054) (3,671) (4,329)
Cumulative effect of accounting change before
income taxes (Note A)......................................... (26,163)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative effect
of accounting change (Note A)............................... (25,050) 6,004 (7,640)
Materials and supplies........................................ 4,554 (5,367) 13,971
Accounts payable.............................................. 885 (9,981) 2,762
Taxes accrued................................................. 457 (1,083) 240
Interest accrued.............................................. 443 563 1,664
Other, net...................................................... (4,971) (198) 14,006
152,179 134,260 139,560
Cash Flows from Investing:
Construction expenditures....................................... (92,240) (142,826) (179,433)
Allowance for other than borrowed
funds used during construction................................ 1,054 3,671 4,329
(91,186) (139,155) (175,104)
Cash Flows from Financing:
Sale of common stock............................................ 50,000
Retirement of preferred stock................................... (48,396) (1,190) (1,611)
Issuance of long-term debt and QUIDS............................ 207,019 86,877 142,171
Retirement of long-term debt.................................... (175,248) (16,000) (123,888)
Short-term debt, net............................................ 21,637
Notes receivable from affiliates................................ 1,900 2,700 33,400
Dividends on capital stock:
Preferred stock............................................... (2,455) (4,331) (4,434)
Common stock.................................................. (64,693) (62,454) (60,386)
(60,236) 5,602 35,252
Net Change in Cash and
Temporary Cash Investments (Note H)............................. 757 707 (292)
Cash and Temporary Cash Investments at January 1.................. 2,196 1,489 1,781
Cash and Temporary Cash Investments at December 31................ $ 2,953 $ 2,196 $ 1,489
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 49,399 $ 42,680 $ 37,427
Income taxes.................................................. 25,679 30,771 30,378
See accompanying notes to financial statements.
</TABLE>
<PAGE>
136
<TABLE>
<CAPTION>
Potomac Edison
BALANCE SHEET
DECEMBER 31
ASSETS 1995 1994
(Thousands of Dollars)
Property, Plant, and Equipment:
At original cost, including $49,987,000 and
<S> <C> <C>
$76,365,000 under construction...................................... $2,050,835 $1,978,396
Accumulated depreciation.............................................. (729,653) (673,853)
1,321,182 1,304,543
Investments:
Allegheny Generating Company--common stock
at equity (Note E).................................................. 59,963 62,364
Other................................................................. 868 938
60,831 63,302
Current Assets:
Cash.................................................................. 2,953 2,196
Accounts receivable:
Electric service, net of $1,344,000 and $1,177,000
uncollectible allowance (Note A).................................. 93,250 68,714
Affiliated and other................................................ 2,917 2,403
Notes receivable from affiliates (Note J)............................. 1,900
Materials and supplies--at average cost:
Operating and construction.......................................... 26,414 27,800
Fuel................................................................ 19,148 22,316
Prepaid taxes......................................................... 13,748 13,168
Other................................................................. 3,158 5,000
161,588 143,497
Deferred Charges:
Regulatory assets (Note C)............................................ 80,693 88,758
Unamortized loss on reacquired debt................................... 18,926 8,344
Other................................................................. 11,224 21,091
110,843 118,193
Total................................................................... $1,654,444 $1,629,535
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes D and I)............................................ $ 667,242 $ 658,146
Preferred stock (Note I).............................................. 16,378 61,578
Long-term debt and QUIDS (Note I)..................................... 628,854 604,749
1,312,474 1,324,473
Current Liabilities:
Short-term debt (Note J).............................................. 21,637
Long-term debt and preferred stock
due within one year (Note I)........................................ 18,700 1,200
Accounts payable...................................................... 28,931 37,126
Accounts payable to affiliates........................................ 19,565 10,485
Taxes accrued:
Federal and state income............................................ 3,293 3,565
Other............................................................... 12,603 11,874
Interest accrued...................................................... 9,638 9,195
Customer deposits..................................................... 6,540 6,228
Other................................................................. 8,545 11,171
129,452 90,844
Deferred Credits and Other Liabilities:
Unamortized investment credit......................................... 25,816 28,041
Deferred income taxes................................................. 155,432 149,299
Regulatory liabilities (Note C)....................................... 15,255 16,957
Other................................................................. 16,015 19,921
212,518 214,218
Commitments and Contingencies (Note K)
Total................................................................... $1,654,444 $1,629,535
See accompanying notes to financial statements.
</TABLE>
<PAGE>
137
<TABLE>
<CAPTION>
The Potomac Edison Company
STATEMENT OF CAPITALIZATION
DECEMBER 31
1995 1994 1995 1994
(Thousands of Dollars) (Capitalization Ratios)
Common Stock:
Common stock--no par value, authorized 23,000,000
shares, outstanding 22,385,000 shares (issued 2,500,000
<S> <C> <C> <C> <C>
shares in 1993) (Note I)...................................... $ 447,700 $ 447,700
Other paid-in capital (Note I).................................. 2,690 2,724
Retained earnings (Note D)...................................... 216,852 207,722
Total....................................................... 667,242 658,146 50.8% 49.7%
Preferred Stock:
Cumulative preferred stock--par value $100 per share,
authorized 5,378,611 shares, outstanding as follows
(Note I):
Not subject to mandatory redemption:
December 31, 1995
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
$7.00 D... 1968 5,000
$8.32 F... 1971 5,000
$8.00 G... 1972 10,000
Total (annual dividend requirements $817,622)............... 16,378 36,378 1.3 2.7
Subject to mandatory redemption:
$7.16 J... 1986 26,400
Total....................................................... 26,400
Less current sinking fund requirement......................... (1,200)
25,200 1.9
Long-Term Debt and QUIDS (Note I):
First mortgage Date of Date Date
bonds: Issue Redeemable Due
5-7/8% ...... 1966 1996 1996 18,000 18,000
5-7/8% ...... 1993 2000 2000 75,000 75,000
8 % ...... 1991 2001 2006 50,000 50,000
9-1/4% ...... 1989 65,000
9-5/8% ...... 1990 80,000
8-7/8% ...... 1991 2001 2021 50,000 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
7-3/4% ...... 1995 2005 2025 65,000
December 31, 1995
Interest Rate - %
Quarterly Income Debt Securities
due 2025........................ 8.00 45,457
Secured notes due 1998-2024....... 5.95-6.875 91,700 91,700
Unsecured note due 1996-2002...... 6.30 5,500 5,500
Unamortized debt discount and premium, net...................... (8,103) (5,451)
Total (annual interest requirements $48,707,458)............ 647,554 604,749
Less current maturities......................................... (18,700)
Total......................................................... 628,854 604,749 47.9 45.7
Total Capitalization.............................................. $1,312,474 $1,324,473 100.0% 100.0%
See accompanying notes to financial statements.
</TABLE>
<PAGE>
138
Potomac Edison
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
Note A - Summary of Significant
Accounting Policies:
The Company is a wholly-owned subsidiary of Allegheny Power System, Inc. and
is a part of the Allegheny Power integrated electric utility system (the
System).
The Company is subject to regulation by the Securities and Exchange Commis-
sion (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:
Beginning in 1994, revenues, including amounts resulting from the applica-
tion 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. In 1993, revenues
were recorded for billings rendered to customers. Revenues of $67.4 million
from one industrial customer, Eastalco Aluminum Company, were 8% of total
electric operating revenues in 1995.
DEFERRED POWER COSTS, NET:
The costs of fuel, purchased power, and certain other costs, and revenues
from sales to other companies, 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 affiliates
in the System, are stated at original cost, less contributions in aid of
construction. Cost includes 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 administra-
tion, maintenance, and depreciation of transportation and construction
equipment, and pensions, taxes, and other fringe benefits related to employees
engaged in construction.
The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
<PAGE>
139
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 1995, 1994, and 1993 were
9.71%, 9.73%, and 9.97%, respectively. AFUDC is not included
in the cost of such 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 3.6%, 3.4%, and 3.6% of average depreciable property in 1995,
1994, and 1993, respectively. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.
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 substan-
tially 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 utilizing the most current tax rates.
Provisions for federal income tax were reduced in previous years by invest-
ment 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 in the System 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.
<PAGE>
140
The Company also provides partially contributory medical and life insurance
plans for eligible retirees and dependents. Medical benefits, which comprise
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 an amount equal to the annual cost, but not more than can be
deducted for federal income tax purposes. Funding of these benefits is made
primarily into Voluntary Employee Beneficiary Association (VEBA) trust funds
in amounts up to that which can be deducted for federal income tax purposes.
Medical benefits are self-insured; the life insurance plan is paid through
insurance premiums.
ACCOUNTING CHANGES:
Effective January 1, 1994, the Company changed its revenue recognition
method to include the accrual of estimated unbilled revenues for electric
services. This change results in a better matching of revenues and expenses,
and is consistent with predominant utility industry practice. The cumulative
effect of this accounting change for years prior to 1994, which is shown
separately in the statement of income for 1994, resulted in a benefit of $16.5
million (after related income taxes of $9.7 million). The effect of the
change on 1994 income before the cumulative effect of accounting change, as
well as 1993 net income, is not material.
In March 1995, the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards (SFAS) No. 121, "Accounting for the Impairment
of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," effective
in 1996. The Company does not believe at this time that the adoption of this
standard will have a materially adverse effect on its financial position.
Note B - Restructuring Charges and Asset Write-Offs:
The System is undergoing a reorganization and reengineering process (re-
structuring) to simplify its management structure and to increase efficiency.
As a consequence of this process, approximately 200 employees, primarily in
the System's Bulk Power Supply department, have been placed in a staffing
force. In January 1996, these employees were offered an option to resign
immediately under a Voluntary Separation Program (VSP) or to remain employed
subject to involuntary separation (layoff) after one year, if during that year
they have not found other employment within the System.
In 1995, the Company recorded restructuring charges of $4.6 million
($2.9 million after tax) in other operation
expense, for its share of the estimated liabilities related primarily to
staffing force employees' involuntary separation costs. Further separation
costs for these employees will be recorded in 1996 depending upon those
employees who elect early separation under the VSP, which provides enhanced
separation benefits. Additional restructuring costs may be required as the
restructuring process is completed for other departments.
In connection with changes in inventory management objectives, the Company
in 1995 also recorded $2.2 million ($1.4 million after tax) primarily in
maintenance expense for the write-off of obsolete and slow-moving materials.
<PAGE>
141
Note C - Income Taxes:
Details of federal and state income tax provisions are:
1995 1994 1993
(Thousands of Dollars)
Income taxes--current:
Federal............................. $25,949 $34,193 $29,758
State............................... (640) (2,849) 3,991
Total............................. 25,309 31,344 33,749
Income taxes--deferred, net of
amortization........................ 16,504 14,955 (770)
Amortization of deferred
investment credit................... (2,225) (2,267) (2,349)
Total income taxes................ 39,588 44,032 30,630
Income taxes--charged to other
income and deductions............... (2,652) (1,176) (544)
Income taxes--charged to
accounting change (including
state income taxes)................. (9,693)
Income taxes--charged to
operating income.................... $36,936 $33,163 $30,086
The total provision for income taxes is different than the amount produced
by applying the federal income statutory tax rate to financial accounting
income, as set forth below:
1995 1994 1993
(Thousands of Dollars)
Financial accounting income before
cumulative effect of accounting
change and income taxes............ $115,201 $115,146 $103,553
Amount so produced................... $ 40,300 $ 40,300 $ 36,200
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation......... 4,200 100 2,300
Plant removal costs............ (1,200) (1,700) (2,100)
State income tax, net of federal
income tax benefit............... 2,200 1,300 1,600
Amortization of deferred
investment credit................ (2,225) (2,267) (2,349)
Equity in earnings of
subsidiaries..................... (2,600) (2,900) (2,600)
Other, net......................... (3,739) (1,670) (2,965)
Total.......................... $ 36,936 $ 33,163 $ 30,086
Federal income tax returns through 1991 have been examined and substantially
settled.
<PAGE>
142
At December 31, the deferred tax assets and liabilities were comprised of
the following:
1995 1994
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit............ $ 15,084 $ 16,497
Unbilled revenue............................. 3,492 3,504
Tax interest capitalized..................... 11,221 12,701
Contributions in aid of construction......... 12,614 11,653
State tax loss carryback/carryforward........ 24 2,721
Advances for construction.................... 1,573 1,338
Other........................................ 5,619 5,800
49,627 54,214
Deferred tax liabilities:
Book vs. tax plant basis differences, net.... 189,618 192,862
Other........................................ 15,803 13,367
205,421 206,229
Total net deferred tax liabilities............. 155,794 152,015
Less portion above included in
current liabilities.......................... 362 2,716
Total long-term net deferred
tax liabilities.............................. $155,432 $149,299
It is expected that regulatory commissions will allow recovery of the
deferred tax liabilities in future years as they are paid, and accordingly,
the Company has recorded regulatory assets of $61 million and $76 million as
of December 31, 1995 and 1994, respectively. Regulatory liabilities of $15
million and $17 million as of December 31, 1995 and 1994, respectively, have
been recorded in order to reflect the Company's obligation to pass such tax
benefits on to its customers as the benefits are realized in cash in future
years.
Note D - Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of the Company
contain dividend restrictions under the most restrictive of which $94,355,000
of retained earnings at December 31, 1995, is not available for cash dividends
on common stock, except that a portion thereof may be paid as cash dividends
where concurrently an equivalent amount of cash is received by the Company as
a capital contribution or as the proceeds of the issue and sale of shares of
its common stock.
Note E - Allegheny Generating Company:
The Company owns 28% of the common stock of Allegheny Generating Company
(AGC), and affiliates of the Company own the remainder. 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 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
<PAGE>
143
a formula filed with and previously accepted by the FERC. The only component
which changes is the return on equity (ROE). In December 1991, AGC filed for
a continuation of the existing ROE of 11.53% and other interested parties
filed to reduce the ROE to 10%. A recommendation was issued by an Administra-
tive Law Judge on December 22, 1994, to dismiss the joint complaint. A
settlement agreement for both cases was filed with the FERC on January 12,
1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from
March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.2% for
the period from January 1, 1995, through December 31, 1995. This settlement
was approved by the FERC on March 23, 1995. Refunds were made by AGC of any
revenues collected between March 1, 1992 and March 23, 1995 in excess of these
levels. A second settlement has been negotiated to address AGC's ROE after
1995. On December 21, 1995, AGC submitted the new settlement to the FERC.
Interested parties representing less than 2% of AGC's eventual revenues have
filed exceptions to the settlement. Under the terms of the settlement, AGC's
ROE for 1996 would be 11%, and set by formula in 1997 and 1998 based primarily
on changes in interest rates.
Following is a summary of financial information for AGC:
December 31
1995 1994
(Thousands of Dollars)
Balance sheet information:
Property, plant, and equipment............... $677,857 $680,749
Current assets............................... 7,586 5,991
Deferred charges............................. 24,844 27,496
Total assets............................... $710,287 $714,236
Total capitalization......................... $463,862 $489,894
Current liabilities.......................... 11,892 6,484
Deferred credits............................. 234,533 217,858
Total capitalization and liabilities....... $710,287 $714,236
Year Ended December 31
1995 1994 1993
(Thousands of Dollars)
Income statement information:
Electric operating revenues......... $86,970 $91,022 $90,606
Operation and maintenance
expense........................... 5,740 6,695 6,609
Depreciation........................ 17,018 16,852 16,899
Taxes other than
income taxes...................... 5,091 5,223 5,347
Federal income taxes................ 13,552 14,737 13,262
Interest charges.................... 18,361 17,809 21,635
Other income, net................... (16) (11) (328)
Net income.......................... $27,224 $29,717 $27,182
The Company's share of the equity in earnings above was $7.6 million, $8.3
million, and $7.6 million for 1995, 1994, and 1993, respectively, and is
included in other income, net, on the Statement of Income.
<PAGE>
144
Note F - Pension Benefits:
The Company's share of net pension costs under the System's pension plan, a
portion of which (about 30% to 35%) was charged to plant construction,
included the following components:
1995 1994 1993
(Thousands of Dollars)
Service cost--benefits earned......... $ 3,286 $ 3,555 $ 3,225
Interest cost on projected
benefit obligation.................. 10,161 9,867 9,612
Actual (return) loss on
plan assets......................... (25,718) 304 (22,481)
Net amortization and deferral......... 12,631 (12,808) 10,669
Pension cost.......................... 360 918 1,025
Regulatory reversal................... 1,194 537
Net pension cost...................... $ 360 $ 2,112 $ 1,562
The benefits earned to date and funded status of the Company's share of the
System plan at December 31 using a measurement date of September 30 were as
follows:
1995 1994
(Thousands of Dollars)
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of
$111,538,000 and $103,546,000)............... $119,383 $110,577
Funded status:
Actuarial present value of projected
benefit obligation......................... $144,800 $135,060
Plan assets at market value, primarily
common stocks and fixed income securities.. 169,830 146,211
Plan assets in excess of projected
benefit obligation......................... (25,030) (11,151)
Add:
Unrecognized cumulative net gain from
past experience different from
that assumed............................. 23,839 13,165
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987.......................... 3,435 4,183
Less unrecognized prior service
cost due to plan amendments................ 2,450 2,732
Pension cost liability at September 30....... (206) 3,465
Fourth quarter contributions................. 1,989
Pension (prepayment) liability
at December 31............................. $ (206) $ 1,476
The foregoing includes the Company's portion of amounts applicable to
employees at power stations which are owned jointly with affiliates.
<PAGE>
145
In determining the actuarial present value of the projected benefit obliga-
tion at September 30, 1995, 1994, and 1993, the discount rates used were 7.5%,
7.75%, and 7.25%, and the rates of increase in future compensation levels were
4.5%, 4.75%, and 4.75%, respectively. The expected long-term rate of return
on assets was 9% in each of the years 1995, 1994, and 1993.
Note G - Postretirement Benefits Other
Than Pensions:
The cost of postretirement benefits other than pensions (principally health
care and life insurance) for employees and covered dependents in 1995 and
1994, a portion of which (about 25% to 30%) was charged to plant construction,
included the following components:
1995 1994
(Thousands of Dollars)
Service cost - benefits earned.................. $ 683 $ 696
Interest cost on accumulated
postretirement benefit obligation............. 4,476 4,047
Actual loss (return) on plan assets............. (1,938) 47
Amortization of unrecognized
transition obligation......................... 2,011 1,976
Other net amortization and deferral............. 1,570 53
Postretirement cost............................. 6,802 6,819
Regulatory reversal (deferral).................. 11 (457)
Net postretirement cost......................... $6,813 $6,362
<PAGE>
148
The benefits earned to date and funded status of the Company's share of the
System plan at December 31 using a measurement date of September 30 were as
follows:
1995 1994
(Thousands of Dollars)
Accumulated postretirement benefit obligation
(APBO):
Retirees.................................... $35,852 $36,927
Fully eligible employees.................... 8,699 8,152
Other employees............................. 13,805 14,035
Total obligation.......................... 58,356 59,114
Plan assets at market value, in common stocks,
fixed income securities, and short-term
investments................................... 11,882 5,962
Accumulated postretirement benefit
obligation in excess of plan assets........... 46,474 53,152
Less:
Unrecognized cumulative net loss from past
experience different from that assumed...... 8,578 14,223
Unrecognized transition obligation,
being amortized over 20 years
beginning January 1, 1993................... 34,125 35,928
Postretirement benefit liability
at September 30............................... 3,771 3,001
Fourth quarter contributions
and benefit payments.......................... 2,221 1,634
Postretirement benefit liability
at December 31................................ $ 1,550 $ 1,367
In determining the APBO at September 30, 1995, 1994, and 1993, the discount
rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in future
compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The 1995
expected long-term rate of return on assets was 8.25% net of tax.
For measurement purposes, a health care trend rate of 8% for 1996, declining
1% each year thereafter to 6.5% in the year 1998 and beyond,
and plan provisions which limit future medical and life insurance benefits,
were assumed. Increasing the assumed health care trend rate by 1% in each
year would increase the APBO at December 31, 1995, by $3.8 million and the
aggregate of the service and interest cost components of net periodic
postretirement benefit cost for 1995 by $.4 million.
<PAGE>
149
Note H - Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial instruments at
December 31 were as follows:
1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Liabilities:
Mandatorily
redeemable
preferred stock.... $ - $ - $ 26,400 $ 25,542
Short-term debt...... 21,637 21,637
Long-term debt and
QUIDS.............. 655,657 689,003 610,200 594,519
The fair value of mandatorily redeemable preferred stock was estimated based
on quoted market prices. 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 does not have any financial
instruments held or issued for trading purposes.
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.
Note I - Capitalization:
COMMON STOCK AND OTHER PAID-IN CAPITAL:
In October 1993, the Company issued and sold 2,500,000 shares of common
stock to its parent at $20 per share. Other paid-in capital decreased $34,000
in 1995 and increased $10,000 in 1994 as a result of preferred stock transac-
tions.
PREFERRED STOCK:
In 1995, the Company refunded $45.5 million of preferred stock with dividend
rates between 7% and 8.32%, with the proceeds from the issuance of Quarterly
Income Debt Securities (QUIDS) described below. 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 for the next five years are: 1996, $18,700,
000; 1997, $800,000; 1998, $1,800,000; 1999, $1,800,000; and 2000, $76,800,000.
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.
<PAGE>
150
In 1995, the Company sold $65 million of 7-3/4% 30-year first mortgage bonds
to refund a $65 million 9-1/4% issue due in 2019 and $80 million of 7-5/8% 30-
year first mortgage bonds to refund an $80 million 9-5/8% issue due in 2020.
The Company also issued $21 million of 6.15% 20-year tax-exempt notes to
refund a $21 million 7.3% issue.
In 1995, the Company issued $45.5 million of 8% 30-year QUIDS to refund
preferred stock. QUIDS may not be redeemed until the year 2000. Under
certain circumstances the interest payments may be deferred for a period of up
to 20 consecutive quarters.
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 $115 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 internal money pool accommodates intercompany short-term borrowing needs,
to the extent that certain of the companies have funds available. In January
1994, the Company and its affiliates jointly established an aggregate $300
million multi-year credit program which provides that the Company may borrow
up to $84 million on a standby revolving credit basis. Short-term debt
outstanding for 1995 and 1994 consisted of:
1995 1994
(Thousands of Dollars)
Balance at end of year:
Commercial Paper.................... $21,637-6.10%
Average amount outstanding
during the year:
Commercial Paper.................. $ 499-5.94% $1,021-3.96%
Notes Payable to Banks............ 995-6.04% 2,499-3.96%
Money Pool........................ 179-5.96% 87-4.10%
Note K - Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its construction program, for
which expenditures are estimated to be $87 million for 1996 and
$103 million for 1997. Through 1999, annual construction expenditures are not
expected to significantly exceed 1996 estimated levels. Construction
expenditure levels in 2000 and beyond will depend upon future generation
requirements, as well as the strategy eventually selected for complying with
Phase II of the Clean Air Act Amendments of 1990.
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 affect adversely the lead time, size, and siting of future
generating stations, increase the complexity and cost of pollution control
equipment, and otherwise add to the cost of future operations. In the normal
course of business, the Company becomes involved in various legal proceedings.
<PAGE>
151
The Company does not believe that the ultimate outcome of these proceedings
will have a material effect on its financial position.
The Company previously reported that the Environmental Protection Agency had
identified it and its affiliates and approximately 875 others as potentially
responsible parties in a Superfund site subject to cleanup. The Company has
also been named as a defendant 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.
The Company is guarantor as to 28% of a $50 million revolving credit
agreement of AGC, which in 1995 was used by AGC solely as support for its
indebtedness for commercial paper outstanding.
<PAGE>
152
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED STATEMENT
OF INCOME
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential..................................................... $ 401,186 $ 376,776 $ 358,900
Commercial...................................................... 224,144 207,165 194,773
Industrial...................................................... 356,937 330,739 309,847
Nonaffiliated utilities......................................... 168,215 144,829 152,541
Other, including affiliates..................................... 75,859 68,733 68,916
Total Operating Revenues...................................... 1,226,341 1,128,242 1,084,977
Operating Expenses:
Operation:
Fuel.......................................................... 237,376 252,108 256,664
Purchased power and exchanges, net............................ 274,705 247,194 235,772
Deferred power costs, net (Note A)............................ 15,091 2,880 979
Other (Note B)................................................ 148,781 145,781 131,854
Maintenance (Note B)............................................ 118,162 111,841 96,706
Depreciation.................................................... 112,334 88,935 80,872
Taxes other than income taxes................................... 89,694 87,224 89,249
Federal and state income taxes (Note C)......................... 61,745 50,385 51,529
Total Operating Expenses...................................... 1,057,888 986,348 943,625
Operating Income.............................................. 168,453 141,894 141,352
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A).................................. 2,974 6,729 5,077
Other income, net (Note B)...................................... 12,287 8,618 12,728
Total Other Income and Deductions............................. 15,261 15,347 17,805
Income Before Interest Charges................................ 183,714 157,241 159,157
Interest Charges:
Interest on long-term debt...................................... 64,571 58,102 58,857
Other interest.................................................. 3,331 2,172 1,728
Allowance for borrowed funds used during
construction (Note A)......................................... (2,067) (4,048) (3,489)
Total Interest Charges........................................ 65,835 56,226 57,096
Consolidated Income Before Cumulative
Effect of Accounting Change..................................... 117,879 101,015 102,061
Cumulative Effect of Accounting Change,
net (Note A).................................................... 19,031
Consolidated Net Income........................................... $ 117,879 $ 120,046 $ 102,061
West Penn
CONSOLIDATED STATEMENT
OF RETAINED EARNINGS
Balance at January 1.............................................. $ 433,801 $ 412,288 $ 400,515
Add:
Consolidated net income......................................... 117,879 120,046 102,061
551,680 532,334 502,576
Deduct:
Dividends on capital stock of the Company:
Preferred stock............................................... 6,204 8,504 8,206
Common stock.................................................. 91,600 90,029 82,082
Charge on redemption of preferred stock....................... 2,157
Total Deductions............................................ 99,961 98,533 90,288
Balance at December 31 (Note D)................................... $ 451,719 $ 433,801 $ 412,288
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
153
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Consolidated net income......................................... $117,879 $120,046 $102,061
Depreciation.................................................... 112,334 88,935 80,872
Deferred investment credit and income taxes, net................ 2,364 699 (10,115)
Deferred power costs, net....................................... 15,091 2,880 979
Unconsolidated subsidiaries' dividends in excess of earnings.... 4,034 2,773 3,311
Allowance for other than borrowed funds used
during construction........................................... (2,974) (6,729) (5,077)
Cumulative effect of accounting change before
income taxes (Note A)......................................... (32,891)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative effect
of accounting change (Note A)............................... (30,280) 18,951 (5,947)
Materials and supplies........................................ 9,022 (9,205) 26,889
Accounts payable.............................................. (15,041) (675) 3,196
Taxes accrued................................................. (5,577) (4,502) 9,198
Interest accrued.............................................. (585) 2,620 (5,146)
Other, net...................................................... 1,396 25,019 8,878
207,663 207,921 209,099
Cash Flows from Investing:
Construction expenditures....................................... (149,122) (260,366) (251,017)
Allowance for other than borrowed
funds used during construction................................ 2,974 6,729 5,077
(146,148) (253,637) (245,940)
Cash Flows from Financing:
Sale of common stock............................................ 40,000 100,000
Retirement of preferred stock................................... (72,369)
Issuance of long-term debt and QUIDS............................ 143,700 80,129 268,766
Retirement of long-term debt.................................... (105,888) (251,414)
Short-term debt, net............................................ 70,218
Notes receivable from affiliates................................ 1,000 23,900 (4,000)
Dividends on capital stock:
Preferred stock............................................... (6,204) (8,504) (8,206)
Common stock.................................................. (91,600) (90,029) (82,082)
(61,143) 45,496 23,064
Net Change in Cash and
Temporary Cash Investments (Note H)............................. 372 (220) (13,777)
Cash and Temporary Cash Investments at January 1.................. 345 565 14,342
Cash and Temporary Cash Investments at December 31................ $ 717 $ 345 $ 565
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 64,374 $ 51,745 $ 61,329
Income taxes.................................................. 64,330 54,958 55,111
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED BALANCE SHEET
DECEMBER 31
ASSETS 1995 1994
(Thousands of Dollars)
Property, Plant, and Equipment:
At original cost, including $67,626,000 and
<C> <C> <C>
$103,514,000 under construction..................................... $3,097,522 $3,013,777
Accumulated depreciation.............................................. (1,063,399) (1,009,565)
2,034,123 2,004,212
Investments and Other Assets:
Allegheny Generating Company--common stock
at equity (Note E).................................................. 96,369 100,228
Other................................................................. 1,239 1,474
97,608 101,702
Current Assets:
Cash and temporary cash investments (Note H).......................... 717 345
Accounts receivable:
Electric service, net of $9,436,000 and $8,267,000
uncollectible allowance (Note A).................................. 140,979 119,020
Affiliated and other................................................ 20,183 11,862
Notes receivable from affiliates (Note J)............................. 1,000
Materials and supplies--at average cost:
Operating and construction.......................................... 36,660 39,922
Fuel................................................................ 32,445 38,205
Deferred income taxes................................................. 21,024 12,538
Prepaid and other..................................................... 17,744 12,525
269,752 235,417
Deferred Charges:
Regulatory assets (Note C)............................................ 342,150 364,473
Unamortized loss on reacquired debt................................... 12,256 10,494
Other................................................................. 15,275 15,560
369,681 390,527
Total................................................................... $2,771,164 $2,731,858
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes D and I)............................................ $ 973,188 $ 955,482
Preferred stock (Note I).............................................. 79,708 149,708
Long-term debt and QUIDS (Note I)..................................... 904,669 836,426
1,957,565 1,941,616
Current Liabilities:
Short-term debt (Note J).............................................. 70,218
Long-term debt due within one year (Note I)........................... 27,000
Accounts payable...................................................... 86,935 107,792
Accounts payable to affiliates........................................ 12,293 6,477
Taxes accrued:
Federal and state income............................................ 4,128 9,217
Other............................................................... 20,149 20,637
Interest accrued...................................................... 15,890 16,475
Deferred power costs (Note A)......................................... 12,399
Other................................................................. 20,377 24,028
242,389 211,626
Deferred Credits and Other Liabilities:
Unamortized investment credit......................................... 50,366 52,946
Deferred income taxes................................................. 469,559 471,515
Regulatory liabilities (Note C)....................................... 35,077 39,881
Other................................................................. 16,208 14,274
571,210 578,616
Commitments and Contingencies (Note K)
Total................................................................... $2,771,164 $2,731,858
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
154
<TABLE>
<CAPTION>
West Penn Power Company and Subsidiaries
CONSOLIDATED STATEMENT OF CAPITALIZATION
DECEMBER 31
1995 1994 1995 1994
(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 (issued
<C> <C> <C> <C> <C>
2,000,000 shares in 1994) (Note I)................ $ 465,994 $ 465,994
Other paid-in capital (Note I)...................... 55,475 55,687
Retained earnings (Note D).......................... 451,719 433,801
Total.......................................................... 973,188 955,482 49.7% 49.2%
Preferred Stock of the Company:
Cumulative preferred stock--par value $100 per share,
authorized 3,097,077 shares, outstanding as follows
(Note I):
December 31, 1995
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
$7.00 D... 1967 10,000
$7.12 E... 1968 10,000
$8.08 G... 1971 10,000
$7.60 H... 1972 10,000
$7.64 I... 1973 10,000
$8.20 J... 1976 20,000
Auction
4.25%-
4.75%. 400 000 100.00 1992 40,000 40,000
Total (annual dividend requirements $3,468,647) 79,708 149,708 4.1 7.7
Long-Term Debt and QUIDS (Note I):
First mortgage
bonds: Date of Date Date
Issue Redeemable Due
4-7/8% U..... 1965 27,000
5-1/2% JJ.... 1993 1998 1998 102,000 102,000
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
9 % EE.... 1989 30,000
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
December 31, 1995
Interest Rate - %
Quarterly Income Debt Securities
due 2025........................ 8.00 70,000
Secured notes due 1998-2024....... 4.95-6.75 202,550 202,550
Unsecured notes due 2000-2007..... 6.10 14,435 14,435
Unamortized debt discount and premium, net.......... (9,316) (7,559)
Total (annual interest requirements $64,988,743) 904,669 863,426
Less current maturities............................. (27,000)
904,669 836,426 46.2 43.1
Total Capitalization.................................. $1,957,565 $1,941,616 100.0% 100.0%
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
155
West Penn
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial statements.)
Note A - Summary of Significant
Accounting Policies:
The Company is a wholly-owned subsidiary of Allegheny Power System, Inc.
and is a part of the Allegheny Power integrated electric utility system (the
System).
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).
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:
Beginning in 1994, 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. In 1993, revenues
were recorded for billings rendered to customers.
DEFERRED POWER COSTS, NET:
The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other companies, 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
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. Cost includes 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 administra-
tion, maintenance, and depreciation of transportation and construction
equipment, and pensions, taxes, and other fringe benefits related to employees
engaged in construction.
<PAGE>
156
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 of property, plant, and equipment with offsetting credits to other
income and interest charges. Rates used for computing AFUDC in 1995, 1994,
and 1993 were 8.90%, 8.88%, and 9.40%, respectively. AFUDC is not included
in the cost of such 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 3.9%, 3.5%, and 3.4% of average depreciable property in 1995,
1994, and 1993, respectively. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.
INCOME TAXES:
The companies join with the parent and affiliates in filing a consoli-
dated 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 substan-
tially 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 utilizing 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 in the System 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 also provides partially contributory medical and life
insurance plans for eligible retirees and dependents. Medical benefits, which
<PAGE>
157
comprise 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 an amount equal to the annual cost, but not more
than can be deducted for federal income tax purposes. Funding of these
benefits is made primarily into Voluntary Employee Beneficiary Association
(VEBA) trust funds in amounts up to that which can be deducted for federal
income tax purposes. Medical benefits are self-insured; the life insurance
plan is paid through insurance premiums.
ACCOUNTING CHANGES:
Effective January 1, 1994, the Company changed its revenue recognition
method to include the accrual of estimated unbilled revenues for electric
services. This change results in a better matching of revenues and expenses,
and is consistent with predominant utility industry practice. The cumulative
effect of this accounting change for years prior to 1994, which is shown
separately in the consolidated statement of income for 1994, resulted in a
benefit of $19.0 million (after related income taxes of $13.9 million). The
effect of the change on 1994 consolidated income before the cumulative effect
of accounting change, as well as 1993 consolidated net income, is not
material.
In March 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
effective in 1996. The Company does not believe at this time that the
adoption of this standard will have a materially adverse effect on its
financial position.
Note B - Restructuring Charges and Asset Write-Offs:
The System is undergoing a reorganization and reengineering process
(restructuring) to simplify its management structure and to increase efficien-
cy. As a consequence of this process, approximately 200 employees, primarily
in the System's Bulk Power Supply department, have been placed in a staffing
force. In January 1996, these employees were offered an option to resign
immediately under a Voluntary Separation Program (VSP) or to remain employed
subject to involuntary separation (layoff) after one year, if during that year
they have not found other employment within the System.
In 1995 the Company recorded restructuring charges of $7.3 million
($4.3 million after tax) in other operation expense, for its share of the
estimated liabilities related primarily to staffing force employees' involun-
tary separation costs. Further separation costs for these employees will be
recorded in 1996 depending upon those employees who elect early separation
under the VSP, which provides enhanced separation benefits. Additional
restructuring costs may be required as the restructuring process is completed
for other departments.
In connection with changes in inventory management objectives, the
Company in 1995 also recorded $3.8 million ($2.3 million after tax) primarily
in maintenance expense for the write-off of obsolete and slow-moving materi-
als.
In 1994, the Company wrote off $8.9 million ($5.2 million after tax) in
other income (expense), net, of previously accumulated costs related to a
potential future power plant site and a proposed transmission line. In
<PAGE>
158
the industry's more competitive environment, it was no longer reasonable to
assume future recovery of these costs in rates.
Note C - Income Taxes:
Details of federal and state income tax provisions are:
1995 1994 1993
(Thousands of Dollars)
Income taxes--current:
Federal............................. $49,928 $46,964 $47,089
State............................... 9,344 13,282 14,983
Total............................. 59,272 60,246 62,072
Income taxes--deferred,
net of amortization................. 4,944 3,277 (7,522)
Amortization of deferred
investment credit................... (2,580) (2,578) (2,592)
Total income taxes................ 61,636 60,945 51,958
Income taxes--credited (charged)
to other income and deductions...... 109 3,300 (429)
Income taxes--charged to
accounting change (including
state income taxes)................. (13,860)
Income taxes--charged to
operating income.................... $61,745 $50,385 $51,529
The total provision for income taxes is different than the amount
produced by applying the federal income statutory tax rate to financial
accounting income, as set forth below:
1995 1994 1993
(Thousands of Dollars)
Financial accounting income before
cumulative effect of accounting
change and income taxes............ $179,624 $151,400 $153,590
Amount so produced................... $ 62,900 $ 53,000 $ 53,800
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation......... 4,300 2,000 100
Plant removal costs............ (900) (1,700) (900)
State income tax, net of federal
income tax benefit............... 9,300 6,400 9,600
Amortization of deferred
investment credit................ (2,580) (2,578) (2,592)
Equity in earnings of
subsidiaries..................... (4,300) (4,600) (4,300)
Other, net......................... (6,975) (2,137) (4,179)
Total.......................... $ 61,745 $ 50,385 $ 51,529
Federal income tax returns through 1991 have been examined and substan-
tially settled.
<PAGE>
159
At December 31, the deferred tax assets and liabilities were comprised
of the following:
1995 1994
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit............ $ 35,043 $ 38,560
Unbilled revenue............................. 8,594 9,539
Tax interest capitalized..................... 19,049 16,165
State tax loss carryback/carryforward........ 508 5,535
Postretirement benefits other than pensions.. 7,324 3,952
Contributions in aid of construction......... 6,009 4,866
Other........................................ 21,499 14,953
98,026 93,570
Deferred tax liabilities:
Book vs. tax plant basis differences, net.... 526,257 536,343
Other........................................ 20,304 16,204
546,561 552,547
Total net deferred tax liabilities............. 448,535 458,977
Add portion above included
in current assets............................ 21,024 12,538
Total long-term net deferred
tax liabilities.............................. $469,559 $471,515
It is expected that regulatory commissions will allow recovery of the
deferred tax liabilities in future years as they are paid, and accordingly,
the Company has recorded regulatory assets of $332 million and $351 million as
of December 31, 1995 and 1994, respectively. Regulatory liabilities of $36
million and $39 million as of December 31, 1995 and 1994, respectively, have
been recorded in order to reflect the Company's obligation to pass such tax
benefits on to its customers as the benefits are realized in cash in future
years.
Note D - Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of the
Company contain dividend restrictions under the most restrictive of which
$70,576,000 of consolidated retained earnings at December 31, 1995, is not
available for cash dividends on common stock, except that a portion thereof
may be paid as cash dividends where concurrently an equivalent amount of cash
is received by the Company as a capital contribution or as the proceeds of the
issue and sale of shares of its common stock.
Note E - Allegheny Generating Company:
The Company owns 45% of the common stock of Allegheny Generating Company
(AGC), and affiliates of the Company own the remainder. 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 Power Company, a nonaffiliated utility.
<PAGE>
160
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). In December 1991, AGC filed for
a continuation of the existing ROE of 11.53% and other interested parties
filed to reduce the ROE to 10%. A recommendation was issued by an Adminis-
trative Law Judge on December 22, 1994, to dismiss the joint complaint. A
settlement agreement for both cases was filed with the FERC on January 12,
1995, which would reduce AGC's ROE from 11.53% to 11.13% for the period from
March 1, 1992, through December 31, 1994, and increase AGC's ROE to 11.2% for
the period from January 1, 1995, through December 31, 1995. This settlement
was approved by the FERC on March 23, 1995. Refunds were made by AGC of any
revenues collected between March 1, 1992 and March 23, 1995 in excess of these
levels. A second settlement has been negotiated to address AGC's ROE after
1995. On December 21, 1995, AGC submitted the new settlement to the FERC.
Interested parties representing less than 2% of AGC's eventual revenues have
filed exceptions to the settlement. Under the terms of the settlement, AGC's
ROE for 1996 would be 11%, and set by formula in 1997 and 1998 based primarily
on changes in interest rates.
Following is a summary of financial information for AGC:
December 31
1995 1994
(Thousands of Dollars)
Balance sheet information:
Property, plant, and equipment............... $677,857 $680,749
Current assets............................... 7,586 5,991
Deferred charges............................. 24,844 27,496
Total assets............................... $710,287 $714,236
Total capitalization......................... $463,862 $489,894
Current liabilities.......................... 11,892 6,484
Deferred credits............................. 234,533 217,858
Total capitalization and liabilities....... $710,287 $714,236
<PAGE>
161
Year Ended December 31
1995 1994 1993
(Thousands of Dollars)
Income statement information:
Electric operating revenues......... $86,970 $91,022 $90,606
Operation and maintenance
expense........................... 5,740 6,695 6,609
Depreciation........................ 17,018 16,852 16,899
Taxes other than
income taxes...................... 5,091 5,223 5,347
Federal income taxes................ 13,552 14,737 13,262
Interest charges.................... 18,361 17,809 21,635
Other income, net................... (16) (11) (328)
Net income.......................... $27,224 $29,717 $27,182
The Company's share of the equity in earnings above was $12.3 million,
$13.4 million, and $12.2 million for 1995, 1994, and 1993, respectively, and
is included in other income, net, on the Consolidated Statement of Income.
Note F - Pension Benefits:
The Company's share of net pension costs under the System's pension
plan, a portion of which (about 25% to 30%) was charged to plant construction,
included the following components:
1995 1994 1993
(Thousands of Dollars)
Service cost - benefits earned........ $ 4,655 $ 5,124 $ 4,606
Interest cost on projected
benefit obligation.................. 14,412 14,051 13,773
Actual (return) loss on
plan assets......................... (32,610) 358 (31,224)
Net amortization and deferral......... 14,000 (18,210) 14,262
Pension cost.......................... 457 1,323 1,417
Regulatory reversal (deferral)........ 760 - (1,309)
Net pension cost...................... $ 1,217 $ 1,323 $ 108
Regulatory deferrals amounting to $3,039,000 will be amortized to
operating expenses over the four-year period 1995 through 1998 in accordance
with authorized rate recovery. An additional $833,000 regulatory deferral was
charged to plant construction in 1994.
The benefits earned to date and funded status of the Company's share of
the System plan at December 31 using a measurement date of September 30 were
as follows:
<PAGE>
162
1995 1994
(Thousands of Dollars)
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of
$155,921,000 and $150,168,000)............... $165,162 $158,578
Funded status:
Actuarial present value of projected
benefit obligation......................... $199,683 $191,787
Plan assets at market value, primarily
common stocks and fixed income securities.. 234,200 207,623
Plan assets in excess of projected
benefit obligation......................... (34,517) (15,836)
Add:
Unrecognized cumulative net gain from
past experience different from
that assumed............................. 29,164 15,103
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987.......................... 7,178 8,427
Less unrecognized prior service
cost due to plan amendments................ 4,467 4,999
Pension cost liability at September 30....... (2,642) 2,695
Fourth quarter contributions................. 2,843
Pension prepayment at December 31............ $ (2,642) $ (148)
The foregoing includes the Company's portion of amounts applicable to
employees at power stations which are owned jointly with affiliates.
In determining the actuarial present value of the projected benefit
obligation at September 30, 1995, 1994, and 1993, the discount rates used were
7.5%, 7.75%, and 7.25%, and the rates of increase in future compensation
levels were 4.5%, 4.75%, and 4.75%, respectively. The expected long-term rate
of return on assets was 9% in each of the years 1995, 1994, and 1993.
Note G - Postretirement Benefits Other
Than Pensions:
The cost of postretirement benefits other than pensions (principally
health care and life insurance) for employees and covered dependents in 1995
and 1994, a portion of which (about 25% to 30%) was charged to plant construc-
tion, included the following components:
<PAGE>
163
1995 1994
(Thousands of Dollars)
Service cost - benefits earned.................. $ 1,055 $ 1,154
Interest cost on accumulated
postretirement benefit obligation............. 4,595 4,461
Actual (return) loss on plan assets............. (1,990) 31
Amortization of unrecognized
transition obligation......................... 2,830 2,817
Other net amortization and deferral............. 1,610 83
Postretirement cost............................. 8,100 8,546
Regulatory reversal............................. 137 -
Net postretirement cost......................... $ 8,237 $ 8,546
The benefits earned to date and funded status of the Company's share of
the System plan at December 31 using a measurement date of September 30 were
as follows:
1995 1994
(Thousands of Dollars)
Accumulated postretirement benefit obligation
(APBO):
Retirees.................................... $36,041 $35,895
Fully eligible employees.................... 7,802 8,290
Other employees............................. 17,608 17,013
Total obligation.......................... 61,451 61,198
Plan assets at market value in common stocks,
fixed income securities, and short-term
investments................................... 12,512 6,173
Accumulated postretirement benefit
obligation in excess of plan assets........... 48,939 55,025
Less:
Unrecognized cumulative net gain from
past experience different from
that assumed................................ (3,292) (543)
Unrecognized transition obligation,
being amortized over 20 years
beginning January 1, 1993................... 48,099 50,929
Postretirement benefit liability
at September 30............................... 4,132 4,639
Fourth quarter contributions
and benefit payments.......................... 3,649 2,113
Postretirement benefit liability
at December 31................................ $ 483 $ 2,526
<PAGE>
164
In determining the APBO at September 30, 1995, 1994, and 1993, the
discount rates used were 7.5%, 7.75%, and 7.25%, and the rates of increase in
future compensation levels were 4.5%, 4.75%, and 4.75%, respectively. The
1995 expected long-term rate of return on assets was 8.25% net of tax. For
measurement purposes, a health care trend rate of 8% for 1996, declining 1%
each year thereafter to 6.5% in the year 1998 and beyond, and plan provisions
which limit future medical and life insurance benefits, were assumed.
Increasing the assumed health care trend rate by 1% in each year would
increase the APBO at December 31, 1995, by $4.0 million and the aggregate of
the service and interest cost components of net periodic postretirement
benefit cost for 1995 by $.4 million.
Note H - Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial instruments
at December 31 were as follows:
1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Assets:
Temporary cash
investments........ $ 425 $ 425 $ 73 $ 73
Liabilities:
Short-term debt...... 70,218 70,218 - -
Long-term debt
and QUIDS............ 913,985 955,336 870,985 826,003
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 does
not have any financial instruments held or issued for trading purposes.
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.
Note I - Capitalization:
COMMON STOCK AND OTHER PAID-IN CAPITAL:
The Company issued and sold common stock to its parent, at $20 per
share, 2,000,000 shares in October 1994 and 5,000,000 shares in 1993. Other
paid-in capital decreased $212,000 in 1995 as a result of preferred stock
transactions and decreased $145,000 in 1993 due to underwriting fees and
commissions and miscellaneous expenses associated with the Company's sale of
$40 million of preferred stock in 1992.
<PAGE>
165
PREFERRED STOCK:
In 1995, the Company refunded $70 million of preferred stock with
dividend rates between 7% and 8.2%, with the proceeds from the issuance of
Quarterly Income Debt Securities (QUIDS) described below. All of the
preferred stock is entitled on voluntary liquidation to its then current call
price and on involuntary liquidation to $100 per 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 for the next five years are: 1996 and
1997, none; 1998, $103,500,000; 1999, $1,500,000; and 2000, $2,500,000.
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.
In 1995, the Company sold $30 million of 7-3/4% 30-year first mortgage
bonds to refund a $30 million 9% issue due in 2019. The Company also issued
$31.5 million of 6.15% 20-year tax-exempt notes to refund a $20 million 7%
issue and an $11.5 million 6.95% issue and issued $15.4 million of 6.05% 19-
year tax-exempt notes to refund a $15.4 million 9-3/8% issue.
In 1995, the Company issued $70 million of 8% 30-year QUIDS to refund
preferred stock. QUIDS may not be redeemed until the year 2000. Under
certain circumstances the interest payments may be deferred for a period of up
to 20 consecutive quarters.
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
$170 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 internal money pool accommodates intercompany short-term borrowing needs,
to the extent that certain of the companies have funds available. In January
1994, the Company and its affiliates jointly established an aggregate $300
million multi-year credit program which provides that the Company may borrow
up to $135 million on a standby revolving credit basis. Short-term debt
outstanding for 1995 and 1994 consisted of:
1995 1994
(Thousands of Dollars)
Balance at end of year:
Commercial Paper.................. $36,318-6.09%
Notes Payable to Banks............ 33,900-5.90%
Average amount outstanding during
the year:
Commercial Paper.................. $ 5,692-6.00% $2,216-4.38%
Notes Payable to Banks............ 5,342-5.96% 2,379-4.37%
Money Pool........................ 592-5.79% 521-4.24%
<PAGE>
166
Note K - Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its construction program,
for which expenditures are estimated to be $125 million for 1996 and
$126 million for 1997. Through 1999, annual construction expenditures are not
expected to significantly exceed 1996 estimated levels. Construction
expenditure levels in 2000 and beyond will depend upon future generation
requirements, as well as the strategy eventually selected for complying with
Phase II of the Clean Air Act Amendments of 1990.
ENVIRONMENTAL MATTERS AND LITIGATION:
System companies are subject to various laws, regulations, and uncer-
tainties 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 affect adversely the lead time, size, and
siting of future generating stations, increase the complexity and cost of
pollution control equipment, and otherwise add to the cost of future opera-
tions. In the normal course of business, the Company becomes involved in
various legal proceedings. The Company does not believe that the ultimate
outcome of these proceedings will have a material effect on its financial
position.
The Company previously reported that the Environmental Protection Agency
had identified it and its affiliates and approximately 875 others as poten-
tially responsible parties in a Superfund site subject to cleanup. The
Company has also been named as a defendant along with multiple other defen-
dants 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.
The Company is guarantor as to 45% of a $50 million revolving credit
agreement of AGC, which in 1995 was used by AGC solely as support for its
indebtedness for commercial paper outstanding.
<PAGE>
167
<TABLE>
<CAPTION>
AGC
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
<S> <C> <C> <C>
Electric Operating Revenues....................................... $86,970 $91,022 $90,606
Operating Expenses:
Operation and maintenance expense............................... 5,740 6,695 6,609
Depreciation.................................................... 17,018 16,852 16,899
Taxes other than income taxes................................... 5,091 5,223 5,347
Federal income taxes (Note B)................................... 13,552 14,737 13,262
Total Operating Expenses...................................... 41,401 43,507 42,117
Operating Income.............................................. 45,569 47,515 48,489
Other Income and Deductions....................................... 16 11 328
Income Before Interest Charges.................................. 45,585 47,526 48,817
Interest Charges:
Interest on long-term debt...................................... 16,859 16,863 21,185
Other interest.................................................. 1,502 946 450
Total Interest Charges........................................ 18,361 17,809 21,635
Net Income........................................................ $27,224 $29,717 $27,182
STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $12,729 $18,512 $25,530
Add:
Net income...................................................... 27,224 29,717 27,182
39,953 48,229 52,712
Deduct:
Dividends on common stock....................................... 35,800 35,500 34,200
Balance at December 31............................................ $ 4,153 $12,729 $18,512
See accompanying notes to financial statements.
</TABLE>
<PAGE>
168
<TABLE>
<CAPTION>
AGC
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1995 1994 1993
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income...................................................... $ 27,224 $ 29,717 $ 27,182
Depreciation.................................................... 17,018 16,852 16,899
Deferred investment credit and income taxes, net................ 6,508 9,567 5,321
Changes in certain current assets and liabilities:
Accounts receivable........................................... (3,758) 7,099 (6,118)
Materials and supplies........................................ 144 (2) (163)
Accounts payable.............................................. (32) 37 6
Taxes accrued................................................. 80 (216) (153)
Interest accrued.............................................. 251 (200) 632
Other, net...................................................... 2,703 (7,133) 4,851
50,138 55,721 48,457
Cash Flows from Investing:
Construction expenditures....................................... (2,177) (1,065) (2,739)
Cash Flows from Financing:
Issuance of long-term debt...................................... 198,075
Retirement of long-term debt.................................... (12,175) (19,126) (209,598)
Cash dividends on common stock.................................. (35,800) (35,500) (34,200)
(47,975) (54,626) (45,723)
Net Change in Cash................................................ (14) 30 (5)
Cash at January 1................................................. 45 15 20
Cash at December 31............................................... $ 31 $ 45 $ 15
Supplemental Cash Flow Information
Cash paid during the year for:
Interest...................................................... $ 17,165 $ 17,078 $ 21,109
Income taxes.................................................. 5,274 7,137 8,220
See accompanying notes to financial statements.
</TABLE>
<PAGE>
169
<TABLE>
<CAPTION>
AGC
BALANCE SHEET
DECEMBER 31
ASSETS 1995 1994
(Thousands of Dollars)
Property, Plant, and Equipment:
At original cost, including $412,000 and
<S> <C> <C>
$21,000 under construction...................................... $ 836,894 $ 824,714
Accumulated depreciation.......................................... (159,037) (143,965)
677,857 680,749
Current Assets:
Cash.............................................................. 31 45
Accounts receivable from parents.................................. 5,274 1,516
Materials and supplies--at average cost........................... 2,049 2,193
Other............................................................. 232 2,237
7,586 5,991
Deferred Charges:
Regulatory assets (Note B)........................................ 14,617 4,449
Unamortized loss on reacquired debt............................... 9,900 10,653
Other............................................................. 327 12,394
24,844 27,496
Total............................................................... $ 710,287 $ 714,236
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............................................. 209,999 209,999
Retained earnings................................................. 4,153 12,729
214,153 222,729
Long-term debt (Note D)........................................... 249,709 267,165
463,862 489,894
Current Liabilities:
Long-term debt due within one year (Note D)....................... 6,375 1,000
Accounts payable.................................................. 16 48
Interest accrued.................................................. 5,151 4,900
Taxes accrued..................................................... 113 33
Other............................................................. 237 503
11,892 6,484
Deferred Credits:
Unamortized investment credit..................................... 50,987 52,297
Deferred income taxes............................................. 156,091 137,297
Regulatory liabilities (Note B)................................... 27,455 28,264
234,533 217,858
Total............................................................... $ 710,287 $ 714,236
See accompanying notes to financial statements.
</TABLE>
<PAGE>
170
AGC
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
Note A - Summary of Significant
Accounting Policies:
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 Power System, Inc. and are a part of the Allegheny
Power integrated electric utility system. The Company is subject to regula-
tion 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.
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 1995,
1994, and 1993. The cost of maintenance and of certain replacements of
property, plant, and equipment is charged to operating expenses.
INCOME TAXES:
The Company joins with its parents and affiliates in filing a consoli-
dated 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 utilizing the most current tax rates.
<PAGE>
171
Prior to 1987, provisions for federal income tax were reduced 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.
ACCOUNTING CHANGE:
In March 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards (SFAS) No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,"
effective in 1996. The Company does not believe at this time that the
adoption of this standard will have a materially adverse effect on its
financial position.
Note B - Income Taxes:
Details of federal income tax provisions are:
1995 1994 1993
(Thousands of Dollars)
Current income taxes payable.......... $ 7,053 $ 5,176 $ 8,112
Deferred income taxes-
accelerated depreciation............ 7,818 10,883 6,637
Amortization of deferred
investment credit................... (1,310) (1,316) (1,316)
Total income taxes................ 13,561 14,743 13,433
Income taxes--charged to
other income........................ (9) (6) (171)
Income taxes--charged to
operating income.................... $13,552 $14,737 $13,262
In 1995, the total provision for income taxes ($13,552,000) was less
than the amount produced by applying the federal income tax statutory rate to
financial accounting income before income taxes ($14,272,000), due primarily
to amortization of deferred investment credit ($1,310,000).
Federal income tax returns through 1991 have been examined and substan-
tially settled.
At December 31, the deferred tax assets and liabilities were comprised
of the following:
1995 1994
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit............ $ 27,455 $ 28,160
Other........................................ 104
27,455 28,264
Deferred tax liabilities:
Book vs. tax plant basis differences, net.... 183,546 165,561
Total net deferred tax liabilities............. $156,091 $137,297
<PAGE>
172
It is expected the FERC will allow recovery of the deferred tax
liabilities in future years as they are paid, and accordingly, the Company has
recorded regulatory assets of $14.6 million and $4.4 million as of
December 31, 1995 and 1994, respectively. Regulatory liabilities of
$27.5 million and $28.3 million as of December 31, 1995 and 1994, respective-
ly, have been recorded in order to reflect the Company's obligation to pass
such tax benefits on to its customers as the benefits are realized in cash in
future years.
Note C - Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial instruments
at December 31 were as follows:
1995 1994
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Liabilities:
Long-term debt:
Debentures......... $150,000 $146,279 $150,000 $120,195
Medium term notes.. 76,975 78,075 77,975 73,704
Commercial paper... 30,561 30,561 41,736 41,736
The carrying amount of debentures and medium-term notes was based on
actual market prices or market prices of similar issues. The carrying amount
of commercial paper approximates the fair value because of the short maturity
of those instruments. The Company does not have any financial instruments
held or issued for trading purposes.
Note D - Long-Term Debt:
The Company had long-term debt outstanding as follows:
Interest December 31
Rate - % 1995 1994
(Thousands of Dollars)
Debentures due:
September 1, 2003............... 5.625 $ 50,000 $ 50,000
September 1, 2023............... 6.875 100,000 100,000
Commercial paper.................. 5.82 (1) 30,561 41,736
Medium term notes due 1995-1998... 6.36 (1) 76,975 77,975
Unamortized debt discount......... (1,452) (1,546)
Total......................... 256,084 268,165
Less current maturities........... 6,375 1,000
Total......................... $249,709 $267,165
(1) Weighted average interest rate at December 31, 1995.
<PAGE>
173
The Company has a revolving credit agreement with a group of seven banks
which provides for loans of up to $50 million at any one time outstanding
through 1999. Each bank has the option to discontinue its loans after 1999
upon three years' prior written notice. Without such notice, the loans are
automatically extended for one year. Amounts borrowed are guaranteed by the
Parents in proportion to their equity interest. Interest rates are determined
at the time of each borrowing. The revolving credit agreement serves as
support for the Company's commercial paper. In addition to bank lines of
credit, an internal money pool accommodates intercompany short-term borrowing
needs, to the extent that certain of the Company's affiliates have funds
available.
Maturities for long-term debt for the next five years are: 1996,
$6,375,000; 1997, $10,600,000; 1998, $60,000,000; 1999, $30,561,000; and 2000,
none.
<PAGE>
<TABLE>
<CAPTION>
S-1 SCHEDULE II
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1995, 1994, and 1993
Col. A Col. B Col. C Col. D Col. 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:
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1995 $11 352 674 $ 9 206 000 $ 3 130 418 $10 642 192 $13 046 900
Year ended December 31, 1994 $ 3 418 261 $14 714 000 $ 3 060 544 $ 9 840 131 $11 352 674
Year ended December 31, 1993 $ 3 364 104 $ 5 732 000 $ 2 546 341 $ 8 224 184 $ 3 418 261
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
S-2 SCHEDULE II
MONONGAHELA POWER COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1995, 1994, and 1993
Col. A Col. B Col. C Col. D Col. 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:
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1995 $ 1 910 605 $ 2 266 000 $ 700 288 $ 2 610 085 $ 2 266 808
Year ended December 31, 1994 $ 1 084 037 $ 2 240 000 $ 667 910 $ 2 081 342 $ 1 910 605
Year ended December 31, 1993 $ 1 056 010 $ 1 210 000 $ 604 387 $ 1 786 360 $ 1 084 037
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
S-3 SCHEDULE II
THE POTOMAC EDISON COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1995, 1994, and 1993
Col. A Col. B Col. C Col. D Col. 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:
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1995 $ 1 175 437 $ 1 630 000 $ 983 776 $ 2 445 136 $ 1 344 077
Year ended December 31, 1994 $ 1 207 979 $ 1 624 000 $ 1 007 652 $ 2 664 194 $ 1 175 437
Year ended December 31, 1993 $ 1 178 009 $ 1 412 000 $ 790 089 $ 2 172 119 $ 1 207 979
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
S-4 SCHEDULE II
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1995, 1994, and 1993
Col. A Col. B Col. C Col. D Col. 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:
<S> <C> <C> <C> <C> <C>
Year ended December 31, 1995 $ 8 266 632 $ 5 310 000 $ 1 446 354 $ 5 586 971 $ 9 436 015
Year ended December 31, 1994 $ 1 126 244 $10 850 000 $ 1 384 982 $ 5 094 594 $ 8 266 632
Year ended December 31, 1993 $ 1 130 085 $ 3 110 000 $ 1 151 865 $ 4 265 706 $ 1 126 244
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Supplementary Data
Quarterly Financial Data (Unaudited)
(Thousands of Dollars)
Earnings Per
Electric Income Before Share Before
Operating Operating Cumulative Effect of Net Cumulative Effect of Earnings
Quarter ended Revenues Income Accounting Change Income Accounting Change Per Share
APS
<S> <C> <C> <C> <C> <C> <C>
March 1995 $699 988 $122 239 $ 76 129 $ 76 129 $ .64 $ .64
June 1995 603 091 89 613 42 693 42 693 .36 .36
September 1995 672 077 102 735 58 236 58 236 .49 .49
December 1995 672 652 107 526 62 634 62 634 .52 .52
March 1994 697 299 115 118 75 865 119 311 .65 1.02
June 1994 561 217 79 717 39 367 39 367 .33 .33
September 1994 591 123 90 855 49 807 49 807 .42 .42
December 1994 602 045 102 451 54 712 54 712 .46 .46
Monongahela
March 1995 187 702 26 676 19 470 19 470
June 1995 167 727 20 048 12 886 12 886
September 1995 186 616 24 161 16 979 16 979
December 1995 180 437 25 072 17 378 17 378
March 1994 187 909 24 294 17 580 25 525
June 1994 157 940 16 855 10 222 10 222
September 1994 165 932 20 613 13 523 13 523
December 1994 168 349 25 473 18 611 18 611
Potomac Edison
March 1995 218 348 34 983 26 439 26 439
June 1995 181 406 21 457 12 089 12 089
September 1995 205 049 26 770 16 727 16 727
December 1995 214 216 32 438 23 010 23 010
March 1994 223 648 37 350 30 607 47 078
June 1994 171 047 20 934 13 060 13 060
September 1994 179 114 23 109 15 028 15 028
December 1994 185 556 30 929 23 288 23 288
West Penn
March 1995 325 791 49 891 37 412 37 412
June 1995 282 088 36 781 24 613 24 613
September 1995 309 285 40 892 28 634 28 634
December 1995 309 177 40 889 27 220 27 220
March 1994 321 051 42 139 32 665 51 696
June 1994 263 946 30 877 22 006 22 006
September 1994 274 161 35 578 26 745 26 745
December 1994 269 084 33 300 19 599 19 599
AGC
March 1995 22 096 11 554 6 569 6 569
June 1995 22 061 11 516 7 093 7 093
September 1995 21 573 11 344 6 964 6 964
December 1995 21 240 11 155 6 598 6 598
March 1994 22 431 11 509 7 085 7 085
June 1994 21 869 11 253 6 771 6 771
September 1994 22 337 11 551 7 087 7 087
December 1994 24 385 13 202 8 774 8 774
</TABLE>
<PAGE>
174
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
For APS and the Subsidiaries, none.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
APS, 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, and the business experience during the past five years of the
directors of the System companies are set forth below:
<TABLE>
<CAPTION>
Business Experience during Director since date shown of
Name the Past Five Years Age APS MP PE WP AGC
<S> <C> <C> <C> <C> <C> <C>
Eleanor Baum See below (a) 55 1988 1988 1988 1988
William L. Bennett See below (b) 46 1991 1991 1991 1991
Klaus Bergman System employee (1) 64 1985 1985 1985 1979 1982
Stanley I. Garnett,II* System employee (1) 52 1990 1990 1990 1990
Wendell F. Holland See below (c) 43 1994 1994 1994 1994
Kenneth M. Jones System employee (1) 58 1991
Phillip E. Lint See below (d) 66 1989 1989 1989 1989
Edward H. Malone See below (e) 71 1985 1985 1985 1985
Frank A. Metz, Jr. See below (f) 61 1984 1984 1984 1984
Alan J. Noia System employee (1) 48 1994 1994 1987 1994 1994
Jay S. Pifer System employee (1) 58 1995 1995 1992
Steven H. Rice See below (g) 52 1986 1986 1986 1986
Gunnar E. Sarsten See below (h) 58 1992 1992 1992 1992
Peter L. Shea See below (i) 63 1993 1993 1993 1993
Peter J. Skrgic System employee (1) 54 1990 1990 1990 1989
</TABLE>
(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.
Commissioner of the Engineering Manpower Commission, a fellow of the
Institute of Electrical and Electronic Engineers, member of Board of
Governors, New York Academy of Sciences and President, American
Society of Engineering Education.
(b) William L. Bennett. Chairman, HealthPlan Services Corporation, a
leading managed health care services company. Formerly, Chairman and
Chief Executive Officer of Noel Group, Inc. Director of
Belding Heminway Company, Inc., Global Natural Resources Inc.,
Noel Group, Inc. and Sylvan, Inc.
(c) Wendell F. Holland. Of Counsel, Law Firm of Reed, Smith, Shaw &
McClay. Formerly, 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) Edward H. Malone. Retired. Formerly, Vice President of General
Electric Company and Chairman, eneral Electric Investment
Corporation. Director of Fidelity Group of Mutual Funds, General Re
Corporation, and Mattel, Inc.
(f) Frank A. Metz, Jr. Retired. Formerly, Senior Vice President,
Finance and Planning, and Director, International Business Machines
Corporation. Director of Monsanto Company and Norrell Corporation.
(g) Steven H. Rice. Bank consultant and attorney-at-law. Director and
Vice Chairman of the Board of Stamford Federal Savings Bank.
Formerly, President and Director of The Seamen's Bank for Savings
and Director of Royal Group, Inc.
(h) 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, Inc.), and Deputy Chairman of the Third
District Federal Reserve Bank in Philadelphia.
(i) Peter L. Shea. Managing director of Hydrocarbon Energy, Inc., a
privately owned oil and gas development drilling and production
company and an Individual General Partner of Panther Partners,
L.P., a closed-end, non-diversified management company. Member and
Manager of Temblor Petroleum Company L.L.C., a privately owned oil
and gas exploration and production company operating
exclusively in California.
* Stanley I. Garnett, II resigned effective December 1, 1995.
<PAGE>
175
<TABLE>
<CAPTION>
ITEM ll. EXECUTIVE COMPENSATION
During 1995, and for 1994 and 1993, the annual compensation paid by the System companies, APS, APSC,
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 $100,000 was as follows:
Summary Compensation Tables (a)
APS(b), Monongahela, Potomac Edison, West Penn and AGC(c)
Annual Compensation
Other All
Name Annual Other
and Compen- Compen-
Principal sation sation
Position(d) Year Salary($) Bonus($)(e) ($)(f) ($)(g)(h)
<S> <C> <C> <C> <C> <C>
Klaus Bergman, 1995 515,000 187,500 63,677
Chief Executive 1994 485,004 120,000 91,458
Officer 1993 460,008 90,000 46,889
Alan J. Noia, 1995 305,000 120,000 48,983
President and 1994 236,336 57,000 47,867
Chief Operating Officer 1993 212,500 37,000 20,107
Peter J. Skrgic, 1995 238,000 73,800 37,830
Senior Vice President 1994 213,336 50,000 57,253
1993 185,004 38,000 (i) 18,678
Jay S. Pifer, 1995 220,000 72,600 34,098
President of each 1994 189,996 39,000 50,630
Operating Subsidiary 1993 175,500 25,000 18,093
Nancy H. Gormley, 1995 187,500 42,000 51,776(k)
Vice President (j) 1994 175,008 37,000 22,478
1993 162,504 28,000 15,446
(a) In 1995, Allegheny Power put into effect a unified management structure in which executive management
positions were consolidated. 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 APS, APSC and
the Subsidiaries. All salaries and bonuses of these executives are paid by APSC.
(b) APS has no paid employees.
(c) AGC has no paid employees.
(d) See Executive Officers of the Registrants for all positions held.
(e) Incentive awards are based upon performance in the year in which the figure appears but are paid in the
first quarter of the following year. The incentive award plan will be continued for 1996.
(f) Amounts constituting less than 10% of the total annual salary and bonus are not disclosed. All officers
did receive miscellaneous other items amounting to less than 10% of total annual salary and bonus.
(g) 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 5 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. Effective January 1, 1993,
APS started to provide funds to pay for the future benefits due under the supplemental retirement plan
(Secured Benefit Plan) as described in note (a) on p.176. To do this, APS purchased, during 1993, life
insurance on the lives of the covered executives. The premium costs of both the 1992 and 1993 policies
plus a factor for the use of the money are returned to APS 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. The figures in this column
include the present value of the executives' cash value at retirement attributable to the current year's
premium payment (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 401(k) plan. For 1995, 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) 401(k) contributions as follows: Mr. Bergman
$59,177 and $4,500; Mr. Noia $44,483 and $4,500; Mr. Skrgic $33,855 and $3,975; Mr. Pifer $29,598 and
$4,500; and Ms. Gormley $24,199 and $4,500, respectively.
(h) In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance
Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual
meeting in May 1994. The first Plan cycle began on January 1, 1994 and will end on December 31, 1996. A
second cycle began January 1, 1995 and will end on December 31, 1997. A third cycle began January 1, 1996
and will end on December 31, 1998. After completion of all cycles, performance share awards or cash may
be granted if performance criteria have been met. Since the Plan cycles are not completed, no awards have
been granted and the amount which any named executive officer will receive has not yet been determined.
(i) Although less than 10% of total annual salary and bonus, Mr. Skrgic received a $15,000 housing allowance
in 1993.
(j) Retired effective January 1, 1996.
(k) Included in this amount is $23,077 representing accrued vacation for which she was paid.
</TABLE>
<PAGE>
176
<TABLE>
<CAPTION>
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE (a)
APS(b), Monongahela, Potomac Edison, West Penn and AGC(c)
Estimated
Name and Capacitites Annual Benefits
In Which Served on Retirement (d)
<S> <C>
Klaus Bergman, $242,212
Chairman of the Board and
Chief Executive Officer (e)(f)(g)
Alan J. Noia, President 183,002
and Chief Operating Officer (e)(g)
Peter J. Skrgic, 142,805
Senior Vice President (e)(g)
Jay S. Pifer, 129,063
President of each of
the Operating Subsidiaries (e)(g)
Nancy H. Gormley, 72,335
Vice President (e)(h)
(a) In 1995, Allegheny Power put into effect a unified management structure in which executive management
positions were consolidated. The individuals appearing in this chart perform policy-making functions for
each of the Registrants.
(b) APS has no paid employees.
(c) AGC has no paid employees.
(d) Assumes present insured benefit plan and salary continue and retirement at age 65 with single life
annuity. Under plan provisions, the annual rate of benefits payable at the normal retirement age of 65
are computed by adding (i) 1% of final average pay up to covered compensation times years of service up to
35 years, plus (ii) 1.5% of final average pay in excess of covered compensation times years of service up
to 35 years, plus (iii) 1.3% of final average pay times years of service in excess of 35 years. Covered
compensation is the average of the maximum taxable Social Security wage bases during the 35 years
preceding the member's retirement. The final average pay benefit is based on the member's average total
earnings during the highest-paid 60 consecutive calendar months or, if smaller, the member's highest rate
of pay as of any July 1st. Effective July 1, 1994 the maximum amount of any employee's compensation that
may be used in these computations was decreased to $150,000. Benefits for employees retiring between 55
and 62 differ from the foregoing.
Pursuant to a supplemental plan (Secured Benefit Plan), senior executives of Allegheny Power System
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 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. In order to provide funds to pay such
benefits, effective January 1, 1993 the Company purchased insurance on the lives of the plan participants.
The Secured Benefit Plan has been designed that 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 amount of the premiums for this insurance required to be deemed
"compensation" by the SEC is described and included in the "All Other Compensation" column on page .
All executive officers are participants in the Secured Benefit Plan. This does not include benefits from
an 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. Under the ESOSP for 1995, all eligible employees may elect to have from 2% to 7% 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 available funds.
Each System company matches 50% of the pre-tax contributions up to 6% of compensation with common stock of
Allegheny Power System, Inc. Effective January 1, 1994 the maximum amount of any employee's compensation
that may be used in these computations was decreased to $150,000. 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.
(e) See Executive Officers of the Registrants for all positions held.
(f) Mr. Bergman is retiring effective June 1, 1996 as Chief Executive Officer.
(g) The total estimated annual benefits on retirement payable to Messrs. Bergman, Noia, Pifer, and Skrgic
for services in all capacities to APS, APSC and the Subsidiaries is set forth in the table.
(h) Ms. Gormley retired effective January 1, 1996. The actual amount she is receiving for services in all
capacities to APS, APSC and the Subsidiaries is set forth in the table.
</TABLE>
<PAGE>
177
Employment Contracts
In February 1995, APS entered into employment contracts with certain
Allegheny Power 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 APS (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 APS 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 annualized
compensation and APS will maintain existing benefits for the employee and the
employee's dependents for a period of three years. Each Agreement initially
expires on December 31, 1997 but will be automatically extended for one year
periods thereafter unless either APS or the employee gives notice otherwise.
Notwithstanding the delivery of such notice, the Agreements will continue in
effect for twenty-four months after a Change in Control.
Compensation of Directors
In 1995, APS 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 meeting attend-
ed, except Executive Committee meetings, for which fees are $200, and
(c) $250 for each Board meeting of each company attended. 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.
Effective January 1, 1995, in addition to the fees mentioned
above, the Chairperson of each of the Audit, Finance, Management
Review, and New Business Committees will receive a further fee of
$4,000 per year, and the retainer fee paid outside directors will be
increased by 200 shares of APS common stock pursuant to the Restricted
Stock Plan for Outside Directors which was adopted effective January
1, 1995. Also adopted effective January 1, 1995 was a Directors'
Retirement Plan which will provide an annual pension equal to the
retainer fee paid to the outside director at the time of his or her
retirement, provided the director has at least five (5) years of
service and, except under special circumstances described in the Plan,
serves until age 65.
<PAGE>
178
<TABLE>
<CAPTION>
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The table below shows the number of shares of APS common stock that are
beneficially owned, directly or indirectly, by each director and named executive
officer of APS, 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, 1995. To
the best of the knowledge of APS, there is no person who is a beneficial owner of
more than 5% of the voting securities of APS.
Executive Shares of
Officer or APS Percent
Name Director of Common Stock of Class
<S> <C> <C> <C>
Eleanor Baum APS,MP,PE,WP 2,200 Less than .01%
William L. Bennett APS,MP,PE,WP 2,749 "
Klaus Bergman APS,MP,PE,WP,AGC 11,390 "
Stanley I. Garnett, II* APS,MP,PE,WP,AGC 4,911 "
Nancy H. Gormley** APS, MP 6,185 "
Wendell F. Holland APS,MP,PE,WP 350 "
Phillip E. Lint APS,MP,PE,WP 810 "
Edward H. Malone APS,MP,PE,WP 1,668 "
Frank A. Metz, Jr. APS,MP,PE,WP 2,275 "
Alan J. Noia APS,MP,PE,WP,AGC 12,436 "
Jay S. Pifer APS,MP,PE,WP 8,595 "
Steven H. Rice APS,MP,PE,WP 2,512 "
Gunnar E. Sarsten APS,MP,PE,WP 6,200 "
Peter L. Shea APS,MP,PE,WP 1,800 "
Peter J. Skrgic APS,MP,PE,WP,AGC 6,198 "
All directors and executive officers
of APS as a group (19 persons) 85,994 Less than .075%
All directors and executive officers 110,839 "
of MP as a group (24 persons)
All directors and executive officers 98,461 "
of PE as a group (22 persons)
All directors and executive officers
of WP as a group (23 persons) 98,629 "
All directors and executive officers
of AGC as a group (9 persons) 54,235 "
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 APS. All of the common stock of AGC is owned by Monongahela (270 shares), Potomac Edison
(280 shares), and West Penn (450 shares).
* Mr. Garnett resigned effective December 1, 1995.
** Ms. Gormley retired effective January 1, 1996.
</TABLE>
<PAGE>
178
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with the relocation of the New York office, Allegheny
Power made available to each employee involved in the relocation an interest-
free loan of up to 95% of the appraised equity in the employee's current
residence for the purchase of a new residence. The loans must be repaid to
Allegheny Power upon actual relocation. In addition, interest paid by an
employee on a new mortgage will be reimbursed by Allegheny Power until the
actual date of relocation. On October 10, 1995, Allegheny Power made an
interest-free loan in the amount of $215,000 to Richard J. Gagliardi, a Vice
President of APS. On December 7, 1995, Allegheny Power made an interest-free
loan in the amount of $75,000 to Thomas K. Henderson, a Vice President of
Monongahela, Potomac Edison and West Penn. On January 5, 1996, Allegheny
Power made an interest-free loan in the amount of $61,000 to Peter J. Skrgic,
a Senior Vice President of APS and a Vice President of Potomac Edison and AGC.
Appropriate monthly interest payments as described above also have been and
will be paid.
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 97.
(b) No reports on Form 8-K were filed by System companies during the quarter
ended December 31, 1995.
(c) Exhibits for APS, Monongahela, Potomac Edison, West Penn, and AGC are
listed in the Exhibit Index beginning on page E-1 and are incorporated herein
by reference.
<PAGE>
179
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 POWER SYSTEM, INC.
By: KLAUS BERGMAN
(Klaus Bergman
Chief Executive Officer)
Date: February 1, 1996
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:
Chairman of the Board, 2/1/96
KLAUS BERGMAN Chief Executive Officer,
(Klaus Bergman) and Director
(ii) Principal Financial Officer:
ALAN J. NOIA Chief Operating Officer 2/1/96
(Alan J. Noia) and Director
(iii) Principal Accounting Officer:
KENNETH M. JONES Vice President 2/1/96
(Kenneth M. Jones) and Controller
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Steven H. Rice
*Klaus Bergman *Alan J. Noia
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone
*By: THOMAS K. HENDERSON 2/1/96
(Thomas K. Henderson)
<PAGE>
180
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: JAY S. PIFER
(Jay S. Pifer, President)
Date: February 1, 1996
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:
Chairman of the Board, 2/1/96
KLAUS BERGMAN Chief Executive Officer,
(Klaus Bergman) and Director
(ii) Principal Financial Officer:
NANCY L. CAMPBELL Treasurer 2/1/96
(Nancy L. Campbell)
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 2/1/96
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Eleanor Baum *Alan J. Noia
*William L. Bennett *Jay S. Pifer
*Klaus Bergman *Steven H. Rice
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone *Peter J. Skrgic
*Frank A. Metz, Jr.
*By: THOMAS K. HENDERSON 2/1/96
(Thomas K. Henderson)
<PAGE>
181
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: JAY S. PIFER
(Jay S. Pifer, President)
Date: February 1, 1996
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:
Chairman of the Board, 2/1/96
KLAUS BERGMAN Chief Executive Officer,
(Klaus Bergman) and Director
(ii) Principal Financial Officer:
NANCY L. CAMPBELL Treasurer 2/1/96
(Nancy L. Campbell)
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 2/1/96
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Eleanor Baum *Alan J. Noia
*William L. Bennett *Jay S. Pifer
*Klaus Bergman *Steven H. Rice
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone *Peter J. Skrgic
*Frank A. Metz, Jr.
*By: THOMAS K. HENDERSON 2/1/96
(Thomas K. Henderson)
<PAGE>
182
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: JAY S. PIFER
(Jay S. Pifer, President)
Date: February 1, 1996
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.
Signature Title Date
(i) Principal Executive Officer:
Chairman of the Board, 2/1/96
KLAUS BERGMAN Chief Executive Officer,
(Klaus Bergman) and Director
(ii) Principal Financial Officer:
NANCY L. CAMPBELL Treasurer 2/1/96
(Nancy L. Campbell)
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 2/1/96
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Eleanor Baum *Alan J. Noia
*William L. Bennett *Jay S. Pifer
*Klaus Bergman *Steven H. Rice
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone *Peter J. Skrgic
*Frank A. Metz, Jr.
*By: THOMAS K. HENDERSON 2/1/96
(Thomas K. Henderson)
<PAGE>
183
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: KLAUS BERGMAN
(Klaus Bergman, President
and Chief Executive
Officer)
Date: February 1, 1996
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:
KLAUS BERGMAN President, 2/1/96
(Klaus Bergman) Chief Executive Officer,
and Director
(ii) Principal Financial Officer:
NANCY L. CAMPBELL Treasurer and 2/1/96
(Nancy L. Campbell Assistant Secretary
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 2/1/96
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Klaus Bergman
*Kenneth M. Jones
*Alan J. Noia
*Peter J. Skrgic
*By: THOMAS K. HENDERSON 2/1/96
(Thomas K. Henderson)
<PAGE>
184
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospec-
tus constituting part of Allegheny Power System, Inc.'s Registration Statement
on Form S-3 (Nos. 33-36716 and 33-57027) relating to the Dividend Reinvestment
and Stock Purchase Plan of Allegheny Power System, Inc.; in the Prospectus
constituting part of Allegheny Power System, Inc.'s 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. 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. 33-51305 and 33-59493); and in the Prospectus
constituting part of West Penn Power Company's Registration Statements on
Form S-3 (Nos. 33-51303, 33-56997, 33-52862, 33-56260 and 33-59133); of our
reports dated February 1, 1996 included in ITEM 8 of this Form 10-K. We also
consent to the references to us under the heading "Experts" in such Prospec-
tuses.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
March 12, 1996
<PAGE>
185
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of
Allegheny Power System, 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, 1995 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 under-
signed 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: February 1, 1996
ELEANOR BAUM FRANK A. METZ, JR.
(Eleanor Baum) (Frank A. Metz, Jr.)
WILLIAM L. BENNETT ALAN J. NOIA
(William L. Bennett) (Alan J. Noia)
KLAUS BERGMAN STEVEN H. RICE
(Klaus Bergman) (Steven H. Rice)
WENDELL F. HOLLAND GUNNAR E. SARSTEN
(Wendell F. Holland) (Gunnar E. Sarsten)
PHILLIP E. LINT PETER L. SHEA
(Phillip E. Lint) (Peter L. Shea)
EDWARD H. MALONE
(Edward H. Malone)
<PAGE>
186
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, 1995 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: February 1, 1996
JAY S. PIFER
(Jay S. Pifer)
PETER J. SKRGIC
(Peter J. Skrgic)
<PAGE>
187
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, 1995 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: February 1, 1996
KLAUS BERGMAN
(Klaus Bergman)
KENNETH M. JONES
(Kenneth M. Jones)
ALAN J. NOIA
(Alan J. Noia)
PETER J. SKRGIC
(Peter J. Skrgic)
<PAGE>
<TABLE>
<CAPTION>
E-1
EXHIBIT INDEX
(Rule 601(a))
Allegheny Power System, Inc.
Incorporation
Documents by Reference
<S> <C> <C>
3.1 Charter of the Company, Form 10-Q of the Company
as amended (1-267), September 1993,
exh. (a)(3)
3.2 By-laws of the Company, Form 10-Q of the Company
as amended November 2, 1995 (1-267), September 1995,
exh. (a)(3)(ii)
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, 1994,
exh. 10.2
10.3 Allegheny Power System Incentive Form 10-K of the Company
Compensation Plan (1-267), December 31, 1994,
exh. 10.3
10.4 Allegheny Power System Form 10-K of the Company
Supplemental Executive (1-267), December 31, 1994,
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 Form 10-K of the Company
for Outside Directors (1-267), December 31, 1994,
exh. 10.7
10.8 Retirement Plan Form 10-K of the Company
for Outside Directors (1-267), December 31, 1994,
exh. 10.8
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
E-1 (Cont'd)
EXHIBIT INDEX
(Rule 601(a))
Allegheny Power System, Inc.
Incorporation
Documents by Reference
<S> <C> <C>
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 Form 8-K of the Company (1-267),
Employment Contract dated February 15, 1995,
exh. 10.1
11 Statement re computation of per share earnings:
Clearly determinable from the financial statements
contained in Item 8.
21 Subsidiaries of APS:
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 184 herein.
24 Powers of Attorney See pages 185-187 herein.
27 Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
E-2
Monongahela Power Company
Incorporation
Documents by Reference
<S> <C> <C>
3.1 Charter of the Company, Form 10-Q of the Company
as amended (15164), 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, June 4, 1992, 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 Employment Contract Form 8-K of the Company
of Jay S. Pifer (1-5164) dated February 15,
1995, exh. 10.1
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 Pennsyl-
vania.
23 Consent of Independent Accountants See page 184 herein.
24 Powers of Attorney See pages 185-187 herein.
27 Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1995
(Dollar Amounts in Thousands)
Monongahela Power Company
Earnings:
<S> <C>
Net Income $ 66,713
Fixed charges (see below) 40,679
Income taxes 42,460
Total earnings $149,852
Fixed Charges:
Interest on long-term debt $ 37,244
Other interest 2,628
Estimated interest
component of rentals 807
Total fixed charges $ 40,679
Ratio of Earnings to
Fixed Charges 3.68
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
E-3
The Potomac Edison Company
Incorporation
Documents by Reference
<S> <C> <C>
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 August 21,
Company defining rights 1991, December 11, 1991
of security holders* December 15, 1992,
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 Employment Contract Form 8-K of the Company
of Jay S. Pifer (1-3376-2) dated February
15, 1995, exh. 10.1
12 Computation of ratio of earnings
to fixed charges
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 184 herein.
Accountants
24 Powers of Attorney See pages 185-187 herein.
27 Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1995
(Dollar Amounts in Thousands)
The Potomac Edison Company
Earnings:
<S> <C>
Net Income $ 78,265
Fixed charges (see below) 51,982
Income taxes 39,591
Total earnings $169,838
Fixed Charges:
Interest on long-term debt $ 49,113
Other interest 2,066
Estimated interest
component of rentals 803
Total fixed charges $ 51,982
Ratio of Earnings to
Fixed Charges 3.27
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
E-4
West Penn Power Company
Incorporation
Documents by Reference
<S> <C> <C>
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,
1993, September 15, 1992, June
9, 1993, 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 Employment Contract Form 8-K of the Company
of Jay S. Pifer (1-255-2) dated February 15,
1995, exh. 10.1
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 184 herein.
Accountants
24 Powers of Attorney See pages 185-187 herein.
27 Financial Data Schedule
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1995
(Dollar Amounts in Thousands)
West Penn Power Company
Earnings:
<S> <C>
Net Income $117,879
Fixed charges (see below) 69,520
Income taxes 61,636
Total earnings $249,035
Fixed Charges:
Interest on long-term debt $ 64,571
Other interest 3,331
Estimated interest
component of rentals 1,618
Total fixed charges $ 69,520
Ratio of Earnings to
Fixed Charges 3.58
</TABLE>
<PAGE>
E-5
Allegheny Generating Company
Documents
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***
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 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.*****
10.3 Equity Agreement, dated June 17, 1981, between and among
Allegheny Generating Company, Monongahela Power Company,
West Penn Power Company and The Potomac Edison Company.*****
10.4 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 See page 184 herein.
Accountants
24 Powers of Attorney See pages 185-187 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).
*** Form 10-Q of the Company (0-14688), September 1995, exh. (a)(3)(ii).
**** 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).
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1995
(Dollar Amounts in Thousands)
Allegheny Generating Company
Earnings:
<S> <C>
Net Income $ 27,224
Fixed charges (see below) 18,361
Income taxes 13,561
Total earnings $ 59,146
Fixed Charges:
Interest on long-term debt $ 16,859
Other interest 1,502
Estimated interest
component of rentals ---
Total fixed charges $ 18,361
Ratio of Earnings to
Fixed Charges 3.22
</TABLE>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1995
(Dollar Amounts in Thousands)
Monongahela Power Company
Earnings:
Net Income $ 66,713
Fixed charges (see below) 40,679
Income taxes 42,460
Total earnings $149,852
Fixed Charges:
Interest on long-term debt $ 37,244
Other interest 2,628
Estimated interest
component of rentals 807
Total fixed charges $ 40,679
Ratio of Earnings to
Fixed Charges 3.68
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<CURRENCY> U.S. DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1995
<PERIOD-START> JAN-01-1995
<PERIOD-END> DEC-31-1995
<EXCHANGE-RATE> 1
<CASH> 117
<SECURITIES> 0
<RECEIVABLES> 85,603
<ALLOWANCES> 2,267
<INVENTORY> 41,602
<CURRENT-ASSETS> 155,662
<PP&E> 1,821,613
<DEPRECIATION> 747,013
<TOTAL-ASSETS> 1,480,591
<CURRENT-LIABILITIES> 150,679
<BONDS> 489,995
0
74,000
<COMMON> 294,550
<OTHER-SE> 211,202
<TOTAL-LIABILITY-AND-EQUITY> 1,480,591
<SALES> 722,482
<TOTAL-REVENUES> 722,482
<CGS> 488,276
<TOTAL-COSTS> 584,691
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 38,925
<INCOME-PRETAX> 108,547
<INCOME-TAX> 41,834
<INCOME-CONTINUING> 66,713
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 66,713
<EPS-PRIMARY> 0.00<F1>
<EPS-DILUTED> 0.00<F1>
<FN>
<F1>All common stock is owned by parent, no EPS required.
</FN>
</TABLE>
