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, 1994
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 (Section 229.405 of this chapter) 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 Common Stock, New York Stock Exchange
System, Inc. $1.25 par value Chicago Stock Exchange
Pacific Stock Exchange
Amsterdam Stock Exchange
Monongahela Power Cumulative Preferred
Company Stock,
$100 par value:
4.40% American Stock Exchange
4.50%, Series C American Stock Exchange
The Potomac Edison Cumulative Preferred
Company Stock,
$100 par value:
3.60% Philadelphia Stock Exchange, Inc.
$5.88, Series C Philadelphia Stock Exchange, Inc.
West Penn Power Cumulative Preferred
Company Stock,
$100 par value:
4-1/2% New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Allegheny Generating Common Stock
Company $1.00 par value None
Aggregate market value Number of shares
of voting stock (common stock) of common stock
held by nonaffiliates of of the registrants
the registrants at outstanding at
February 2, 1995 February 2, 1995
Allegheny Power System, Inc. $2,818,296,038 119,292,954
($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
Sales 4
Electric Facilities 8
System Map 11
Research and Development 13
Construction and Financing 14
Fuel Supply 18
Rate Matters 19
Environmental Matters 22
Air Standards
Water Standards
Hazardous and Solid Wastes
Emerging Environmental Issues
Regulation
ITEM 2. Properties
ITEM 3. Legal Proceedings
ITEM 4. Submission of Matters to a Vote of Security
Holders
Executive Officers of the Registrants
PART II:
ITEM 5. Market for the Registrants' Common Equity
and Related Stockholder Matters
ITEM 6. Selected Financial Data
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
ITEM 8. Financial Statements and Supplementary Data
<PAGE>
CONTENTS (Cont'd)
Page
ITEM 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
PART III:
ITEM 10. Directors and Executive Officers of the
Registrants
ITEM 11. Executive Compensation
ITEM 12. Security Ownership of Certain Beneficial Owners
and Management
ITEM 13. Certain Relationships and Related Transactions
PART IV:
ITEM 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K
<PAGE>
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 various
subsidiaries (collectively, the APS System). 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, 1994, the APS System had 6,061
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
343,900 customers in a service area of about 11,900 square miles
with a population of about 710,000. The seven largest communities
served have populations ranging from 10,900 to 33,900. On
December 31, 1994, Monongahela had 1,982 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 361,400 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, 1994, Potomac Edison had 1,137
employees. Its service area is generally rural. 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
<PAGE>
cooperatives, one of which purchases power from Potomac Edison.
There are also several large federal government installations
served by Potomac Edison.
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
653,000 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, 1994, West Penn had 2,053 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).
AYP Capital, Inc. (AYP Capital), incorporated in Delaware in
1994, is an unregulated, 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. APS has been
authorized by the Securities and Exchange Commission to purchase
common stock of and make capital contributions to AYP Capital in
the amount of $3 million. AYP Capital has no employees. Its
officers are employed by APSC. APSC is providing certain services
to AYP Capital pursuant to a service agreement.
The Subsidiaries in the past have experienced and in the
future may 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 Amendments of 1990 (CAAA), which among other things, require a
substantial annual reduction in emissions of sulfur dioxides (SO2)
and nitrogen oxides (NOx).
Additional concerns include proposals to restructure and, to
some extent, deregulate portions of the industry and 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
<PAGE>
conservation, market competition, weather, and interruptions in
fuel supply because of weather. (See ITEM 1. CONSTRUCTION AND
FINANCING, RATE MATTERS, and ENVIRONMENTAL MATTERS for information
concerning the effect on the Subsidiaries of the CAAA.)
COMPETITION
Following the steps of other previously regulated industries
such as airlines, telecommunications and gas, there is a movement
to deregulate or at least allow competition, limited or otherwise,
in the electric utility industry. The passage of the National
Energy Policy Act of 1992 (EPACT) has permitted an increase in
competition by allowing the formation of Exempt Wholesale
Generators (EWGs), with the approval of the Federal Energy
Regulatory Commission (FERC), and by providing for mandatory access
to the interconnected electric grid for wholesale transactions. It
further provides for expansion of the grid where constraints are
determined to exist, providing necessary authority to construct
such facilities can be obtained and the requestor's rate for such
transmission service reflects expansion costs. EPACT permits
utility generation facilities to qualify as EWGs and allows sales
to nonaffiliated and to affiliated utilities provided state
commissions approve such transactions. (See ITEM 1. SALES and
REGULATION for a further discussion of the impact of EPACT.)
Maryland, Ohio, and Pennsylvania have initiated
investigations concerning competition in the retail electric
utility industry and promoting increased competitive options. (See
ITEM 1. REGULATION for a further discussion of the states'
initiatives.)
To meet the challenges of the new competitive environment in
the industry, AYP Capital was formed in 1994. It is intended that
AYP Capital operate as an innovative and flexible organization,
pursuing and developing new opportunities in unregulated markets
that will strengthen the long-term competitiveness and
profitability of APS. The business opportunities which are pursued
by AYP Capital will be directly related to the core utility
business of APS. Management may consider establishing or acquiring
its own EWGs or other nonregulated generation facilities, if
feasible, and management continues to evaluate other nonregulated
opportunities to meet the competitive challenge.
To further meet the challenges of the new competitive
environment in the industry, management has begun to simplify the
structure of the APS System to increase efficient operation. In
addition, APS, along with the other registered electric public
utility holding companies under the Public Utility Holding Company
Act of 1935 (PUHCA), is advocating repeal of PUHCA which is an
impediment to allowing the APS System to compete on a level playing
field in the new era of competition. In the alternative,
restructuring of the APS System to reduce or eliminate the effect
of PUHCA is being considered.
In addition, management continues to explore methods of
marketing and pricing its core product - electric energy and the
transmission thereof - in new and competitive ways, such as bulk
<PAGE>
sales to power marketers, incentive pricing to traditional utility
customers, and repackaging of services in nontraditional ways. It
is also attempting to reduce costs, particularly capital
expenditures, in order to position the APS System in a more
competitive mode. The feasibility of maintaining these reduced
levels in the future will depend upon, among other things, (1) the
ability to maintain adequate levels of reliable service, (2) the
avoidance of unexpected major equipment failures and (3) no changes
in the timing or requirements for regulatory compliance measures.
SALES
In 1994, consolidated kilowatt-hour (kWh) sales to the
Operating Subsidiaries' retail customers increased 2.8% from those
of 1993 as a result of increases of .9%, 2.2% and 4.4% in
residential, commercial and industrial sales, respectively. The
increased kWh sales in 1994 reflect both growth in number of
customers and higher use. Consolidated revenues from residential,
commercial, and industrial sales increased 5.5%, 6.8%, and 8.1%,
respectively, primarily because of rate increases (See ITEM 1. RATE
MATTERS), increases in fuel and energy cost adjustment clause
revenues, and increased kWh sales. Consolidated kWh sales to and
revenues from nonaffiliated utilities decreased 20.0% and 4.4%,
respectively, due to increased native load, decreased demand, and
price competition.
The System's all-time peak load of 7,280 MW, which was higher
than the forecast, occurred on February 6, 1995. The peak load in
1994 and 1993 was 7,153 MW and 6,678 MW, respectively. The
increased 1994 peak would have been higher except for voluntary
conservation efforts by the Operating Subsidiaries' customers. The
average System load (yearly net power supply divided by number of
hours in the year) was 4,776 MW and 4,674 MW in 1994 and 1993,
respectively. More information concerning sales may be found in
the statistical sections and ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Consolidated electric operating revenues for 1994 were
derived as follows: Pennsylvania, 44.5%; West Virginia, 28.0%;
Maryland, 20.5%; Virginia, 5.4%; Ohio, 1.6% (residential, 35.2%;
commercial, 18.8%; industrial, 29.7%; nonaffiliated utilities,
13.5%; and other, 2.8%). The following percentages of such
revenues were derived from these industries: iron and steel, 6.0%;
chemicals, 3.4%; fabricated products,3.4%; aluminum and other
nonferrous metals, 3.3%; coal mines, 3.2%; cement, 1.9%; and all
other industries, 8.5%. Revenues from each of 17 industrial
customers exceeded $5 million, including one coal customer of both
Monongahela and West Penn with total revenues exceeding $22
million, three steel customers with revenues exceeding $27 million
each, and one aluminum customer with revenues exceeding $68
million.
During 1994, Monongahela's kWh sales to retail customers
increased 3.2% as a net result of increases of 1.2% and 6.1% in
commercial and industrial sales, respectively, and a decrease of
<PAGE>
.6% in residential sales. Revenues from residential, commercial
and industrial customers increased 3.1%, 4.9% and 7.7%,
respectively, and revenues from kWh sales to affiliated and
nonaffiliated utilities increased 6.8%. Monongahela's all-time
peak load of 1,694 MW occurred on July 20, 1994.
Monongahela's electric operating revenues were derived as
follows: West Virginia, 94.3% and Ohio, 5.7% (residential, 28.1%;
commercial, 17.1%; industrial, 29.7%; nonaffiliated utilities,
11.7%; and other, 13.4%). Revenues from each of five industrial
customers exceeded $10 million, including one coal customer with
revenues exceeding $19 million and one steel customer with revenues
exceeding $27 million.
During 1994, Potomac Edison's kWh sales to retail customers
increased 2.3% as a result of increases of 1.7%, 2.1%, and 2.8% in
residential, commercial, and industrial sales, respectively.
Revenues from such customers increased 7.9%, 9.0%, and 10.9%,
respectively, and revenues from kWh sales to affiliated and
nonaffiliated utilities decreased 1.0%. 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, 66.6%; Virginia 16.8% and West Virginia, 16.6%;
(residential, 39.0%; commercial, 17.9%; industrial, 25.7%;
nonaffiliated utilities, 14.1%; and other, 3.3%). Revenues from
one industrial customer, the Eastalco aluminum reduction plant near
Frederick, Maryland, amounted to $68 million (9.0% 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 $19.7 million in 1994. Said 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 1994, West Penn's kWh sales to retail customers
increased 2.9% as a result of increases of 1.1%, 2.9% and 4.4% in
residential, commercial, and industrial sales, respectively.
Revenues from residential, commercial, and industrial customers
increased 5.0%, 6.4%, and 6.7%, respectively, and revenues from kWh
sales to affiliated and nonaffiliated utilities decreased 5.7%.
West Penn's all-time peak load of 3,179 MW occurred on February 6,
1995.
West Penn's electric operating revenues were derived as
follows: Pennsylvania, 100% (residential, 33.4%; commercial, 18.4%;
industrial, 29.3%; nonaffiliated utilities, 12.8%; and other,
6.1%). Revenues from each of four industrial customers exceeded
$10 million, including two steel customers with revenues
exceeding $32 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 extremely 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,
<PAGE>
the Operating Subsidiaries face increased competition from
utilities with excess generation that are willing to sell at prices
intended only to cover variable costs. At the same time, the
Operating Subsidiaries are experiencing cost increases due to
compliance with the CAAA and purchases from Public Utility
Regulatory Policies Act of 1978 (PURPA) projects. (See page 7 for
a discussion of PURPA projects, and ITEM 3. LEGAL PROCEEDINGS for a
description of litigation and regulatory proceedings concerning
PURPA capacity.)
In 1994, the Operating Subsidiaries provided approximately
10.5 billion kWh of energy to nonaffiliated utility companies, of
which 1.1 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 nonaffiliated utilities. The
transaction began in mid-1987 and will continue through 2005,
unless terminated earlier.
Sales to nonaffiliated utility companies vary with the needs
of those companies for imported power; the availability of System
generating facilities and excess power, fuel, and regional
transmission facilities; and the availability and price of
competitive sources of power. Sales of system generated power
decreased in 1994 relative to 1993 primarily because of continued
decreased demand, increased Operating Subsidiaries' native load,
and increased willingness of other suppliers to make sales at lower
prices. Further decreases in sales of system generated power to
nonaffiliated utilities are expected in 1995 and beyond.
Substantially all of the revenues from kWh sales to nonaffiliated
utilities are 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 which is projected to continue through February
2008, 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 mutually
determined no less than 34 months prior to each year for which an
exchange is to take place. 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 Light
Company (Duquesne) which will continue through February 1996 and
may be extended through 1999 and beyond, 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.
<PAGE>
West Penn supplies power to the Borough of Tarentum
(Tarentum) using in part leased distribution facilities from
Tarentum under a 30 year lease agreement terminating in 1996. In
June 1993, Tarentum, which in that year had 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. The termination of
the lease agreement and resulting transfer and sale of electric
facilities will result in Tarentum becoming a municipal customer
which will purchase electricity on a wholesale basis from West Penn
or another supplier. The sale of electric facilities will require
Pennsylvania Public Utility Commission (Pennsylvania PUC) approval.
The Operating Subsidiaries provide wholesale transmission
services under their FERC-approved Standard Transmission Service
tariff. The tariff provides that such service is subordinate in
priority to native load and reliability requirements of
interconnected systems to avoid adverse effects on regional and
Operating Subsidiaries' reliability. (See ITEM 1. ELECTRIC
FACILITIES for a discussion of stress on the System's transmission
system.) Transmission services requiring special arrangements or
long-term commitments have been and continue to be negotiated
through mutually acceptable bilateral agreements. Substantially
all of the revenues from transmission service sales are passed on
to retail customers and as a result have little effect on net
income. In addition, the Operating Subsidiaries have pending
before the FERC a Standard Generation Service Rate Schedule tariff
under which the Operating Subsidiaries will make available bundled,
non-firm generation services with associated System transmission
services to any customer who executes an agreement under such
tariff. Sales subject to refund under the proposed tariff have
been initiated.
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. The FERC recently completed a generic investigation into
the pricing of such requested transmission services. The FERC has
chosen to maintain existing methods while offering limited
opportunities to implement new methodologies which transmitting
companies may wish to use if they find those methods to be
beneficial. The potential for FERC's new pricing guidelines to be
beneficial or detrimental to the Operating Subsidiaries cannot be
predicted at this time. In addition, the FERC is continuing to
develop new policies and procedures to further implement EPACT,
including seeking comments to a Notice of Proposed Rulemaking on
stranded costs and an Inquiry concerning alternative power pooling
arrangements and in a recent case, 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 the System's transmission facilities).
Under EPACT, consumers of wholesale power including small
electric systems owned by municipalities and rural electric
cooperative associations may purchase power from any available
source and may seek an order from the FERC for transmission service
from any utility. Small electric wholesale customers in the
<PAGE>
Operating Subsidiaries' service areas which do not have long term
contracts may choose to avail themselves of this option. The
Operating Subsidiaries will attempt to retain these customers.
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 provided under PURPA and
ordered by appropriate state commissions. The System's total
generation capacity includes a maximum 299 MW of on-line PURPA
capacity. Payments for PURPA capacity and energy in 1994 totaled
approximately $134 million at an average cost to the System of
5.8 cents/kWh as compared to System cost of about 3 cents/kWh. The
Operating Subsidiaries anticipate an additional 260 MW of PURPA
capacity to come on-line in future years, up from 180 MW. This
increase is due to a litigated PURPA project which had lapsed being
reincluded in the planning process although litigation is ongoing.
In addition, lapsed purchase agreements totaling 123 MW and other
PURPA complaints totaling 520 MW are the subject of ongoing
litigation and are not included in the System's current planning
strategy. (See ITEM 3. LEGAL PROCEEDINGS for a description of
litigation and regulatory proceedings in Pennsylvania and West
Virginia.)
ELECTRIC FACILITIES
The following table shows the System's December 31, 1994
generating capacity, based on the maximum monthly normal seasonal
operating capacity of each unit. The System-owned 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 the System-owned coal-fired
stations shown on the following page, based on generating capacity
at December 31, 1994, was about 24.6 years. In 1994, their average
heat rate was 9,927 Btu's/kWh, and their availability factor was
82.1%, down from 87% in 1993 due, in part, to planned outages for
installation of pollution control equipment for compliance with the
CAAA.
<PAGE>
<TABLE>
<CAPTION>
System-Owned Stations
Maximum Generating Capacity
(Megawatts) (a)
Dates When
Station Monon- Potomac West Service
Station Units Total gahela Edison Penn Commenced (b)
Coal-fired:
<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:(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 System-Owned
Capacity 54 8,070 2,326 2,072 3,672
Nonutility Generation
Maximum Generating Capacity
(Megawatts)(e)
Contract
Project Monon- Potomac West Commencement
Project Total gahela Edison Penn Date
Coal-fired
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 0 138
Total Maximum System
Generating Capacity (a) 8,369 2,487 2,072 3,810
(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 percentage ownership of AGC.
(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 contractual arrangements
pursuant to PURPA.
</TABLE>
<PAGE>
SYSTEM MAP
The Allegheny Power System Map (System Map), which has been omitted,
provides a broad illustration of the names and approximate locations of the
System'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 System 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 System 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 System Map also depicts transmission facilities which are (i) owned
solely by the Operating Subsidiaries; (ii) owned by the Operating Subsidiaries
in conjunction with other utilities; or (iii) owned solely by other utilities.
The transmission facilities portrayed range in capacity from 138kV to 765kV.
Additionally, interconnections with other utilities are displayed.
<PAGE>
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, 1994:
<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 19,794 283 225
Potomac Edison 17,296 202 203
West Penn 21,723 273 534
AGC(c) 85 85 1
Total System 58,898 843 963
(a) The System has a total of 5,506 miles of underground distribution
lines.
(b) The substations have an aggregate transformer capacity of 38,344,534
kilovoltamperes.
(c) Total Bath County transmission lines, of which AGC owns an undivided
40% interest and Virginia Power owns the remainder.
</TABLE>
The System 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 been negatively affected by
frequent periods of heavy loading, predominantly in a west-to-east
direction. In 1994, the west-to-east flows decreased from prior
years due to lower interregional power transfers. However,
increases in customer load, power transfers by the Operating
Subsidiaries and nonaffiliated entities, and parallel flows may
contribute to a possible resumption of the heavy west-to-east power
flows. If power transfers return to the levels experienced during
the late 1980s and early 1990s, the interregional EHV transmission
facilities may operate at times at their reliability limit and
therefore, despite recently installed reactive power sources,
restrictions on transfers may again 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 the System's transmission facilities may add
periodically to heavy power flows on the System's facilities.
The Operating Subsidiaries have, to date, provided managed
contractual access to the System's transmission facilities via the
provisions of their Standard Transmission Service tariff, or the
terms and conditions of bilateral contracts.
<PAGE>
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $7.7 million, $4.6 million,
and $2.7 million in 1994, 1993 and 1992, respectively, for research
programs. Of these amounts, $5.9 million, $3.2 million and $0.6
million were for Electric Power Research Institute (EPRI) dues in
1994, 1993 and 1992, respectively. EPRI is an industry-sponsored
research and development institution. The Operating Subsidiaries
plan to spend approximately $9.7 million for research in 1995, with
EPRI dues representing $6.2 million of that total.
Independent research conducted by 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.
Two U.S. Department of Energy Clean Coal Technology NOx control
projects, which the Operating Subsidiaries cofounded, have recently
been completed. Based upon the results of one of the projects,
retrofitting of low NOx cell burners on Hatfield Power Station
units has been undertaken at much lower costs than would otherwise
have been possible.
Research is also being directed to help address major issues
facing the Operating Subsidiaries including electric and magnetic
field (EMF) assessment, waste disposal, greenhouse gas, client-
server information system prospects, renewable resources, fuel
cells, new combustion turbines and other cogeneration technologies.
In addition, there is continuing evaluation of technical proposals
from outside sources and monitoring of developments in literature,
law, litigation and standards.
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.
With reference to alleged global climate change, a Memorandum
of Understanding was signed on behalf of all Edison Electric
Institute (EEI) companies by EEI and the Department of Energy (DOE)
which contains Initiatives directed toward voluntary programs to
reduce greenhouse gas emissions. In early February 1995, an
individual agreement will be entered into on behalf of the
Operating Subsidiaries and the DOE.
The Operating Subsidiaries, in cooperation with the
Pennsylvania Department of Environmental Resources and the West
Virginia Division of Environmental Protection, are researching the
feasibility and cost-effectiveness of injecting fly ash from the
Operating Subsidiaries' power stations into abandoned underground
<PAGE>
mine sites in Pennsylvania and West Virginia to reduce acid mine
drainage and mine surface subsidence. The project cost is
anticipated to be shared with EPRI as part of a Tailored
Collaboration Agreement with the Institute.
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.
CONSTRUCTION AND FINANCING
Construction expenditures by the Subsidiaries in 1994
amounted to $508 million and for 1995 and 1996 are expected to
aggregate $341 million and $284 million, respectively. In 1994,
these expenditures included $153 million for compliance with the
CAAA. The 1995 and 1996 estimated expenditures include $61 million
and $7 million, respectively, to cover the costs of compliance with
the CAAA. Allowance for funds used during construction (AFUDC)
(shown below) has been reduced for carrying charges on CAAA
expenditures that are being collected through currently approved
surcharges or in base rates.
<PAGE>
<TABLE>
<CAPTION>
Construction Expenditures
1994 1995 1996
Millions of Dollars
(Actual) (Estimated)
Monongahela
<S> <C> <C> <C>
Generation $ 55.1 $ 28.3 $ 34.4
Transmission and Distribution 47.7 44.8 34.9
Other 1.2 1.3 1.2
Total* $ 104.0 $ 74.4 $ 70.5
Potomac Edison
Generation $ 55.6 $ 31.3 $ 29.7
Transmission and Distribution 81.3 58.4 64.9
Other 5.9 2.6 3.6
Total* $ 142.8 $ 92.3 $ 98.2
West Penn
Generation $ 169.6 $ 108.6 $ 58.1
Transmission and Distribution 74.4 57.7 50.0
Other 16.4 6.1 7.2
Total* $ 260.4 $ 172.4 $ 115.3
AGC
Generation $ 1.0 $ 2.1 $ .5
Transmission and Distribution
Other .1 - -
Total $ 1.1 $ 2.1 $ .5
Total Construction Expenditures $ 508.3 $ 341.2 $ 284.5
* Includes allowance for funds used during construction for 1994, 1995 and
1996 of: Monongahela $2.9, $1.4 and $1.1; Potomac Edison $5.9, $2.1 and
$1.8; and West Penn $10.8, $4.3 and $1.9.
</TABLE>
These construction expenditures include major capital projects at
existing generating stations, including the construction of flue-gas
desulfurization equipment (scrubbers) at the Harrison Power Station,
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)
the absence of any major construction problems; b) financing and
material and equipment costs lower than expected; and c) favorable
rulings of state commissions allowing the inclusion of carrying costs
of construction in rates in lieu of AFUDC.
On a collective basis for the Operating Subsidiaries, total
expenditures for 1994, 1995, and 1996 include $190 million, $101
<PAGE>
million, and $52 million, respectively, for construction of
environmental control technology. Outages for construction, CAAA
compliance work and other environmental work is and will continue to be
coordinated with planned outages.
The Operating Subsidiaries continue 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 and
increasing the efficiency and availability of System generating
facilities, reducing company 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.) Several jurisdictions have adopted mechanisms
which provide for recovery of the costs of such activities, some return
on the related investment, the associated revenue reductions and a
performance incentive, either on a current basis or through deferral to
a base rate case.
Current forecasts, which reflect demand-side management efforts
and other considerations and assume normal weather conditions, project
both average annual winter and summer peak load growth rates of 1.59%
in the period 1995-2005. After considering the reactivation of West
Penn capacity in cold reserve (see page 10), 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 System-owned 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,
<PAGE>
medium-term note 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.
Effective January 1994, the Operating Subsidiaries also have available
a $300 million multi-year credit facility. 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 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.
In 1994, the Subsidiaries issued $225.3 million of securities
having interest rates between 6.75% and 8.125%. In May 1994,
Monongahela issued 500,000 shares of cumulative preferred stock (par
value $100 per share) with a dividend rate of $7.73. In June 1994,
Potomac Edison issued $75 million of 8% first mortgage bonds due 2024.
In August 1994, West Penn issued $65 million of 8.125% first mortgage
bonds due 2024, and Monongahela, Potomac Edison, and West Penn issued
$8.825 million, $11.560 million, and $14.910 million, respectively, in
solid waste disposal notes to Harrison County, West Virginia. Harrison
County in turn issued $35.295 million of 6-3/4% tax-exempt 30-year
solid waste disposal revenue bonds. The Operating Subsidiaries are
using the proceeds from the issuance of their solid waste disposal
notes to finance certain solid waste disposal facilities which comprise
a portion of the scrubbers located at the Harrison Power Station.
In 1994, APS sold 1,629,372 shares of its common stock for $35
million through its Dividend Reinvestment and Stock Purchase Plan and
its Employee Stock Ownership and Savings Plan.
In October 1994, West Penn issued and sold to APS 2,000,000
additional shares of common stock at a price of $20 per share.
During 1994, 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 2.52%, 3.09%, 3.59% and 4.28%. The rate set at
auction on January 13, 1995, was 4.75%.
At December 31, 1994, APS had $90.25 million outstanding in
short-term debt, Monongahela had $39.5 million outstanding in short-
term debt and notes payable to affiliates, and AGC had $41.74 million
outstanding in commercial paper, while Potomac Edison and West Penn had
notes receivable from an affiliate of $1.9 million and $1.0 million,
respectively.
<PAGE>
The Subsidiaries' ratios of earnings to fixed charges for the
year ended December 31, 1994, were as follows: Monongahela, 3.33;
Potomac Edison, 3.46; West Penn, 3.40; and AGC, 3.50.
APS and the Subsidiaries' consolidated capitalization ratios as
of December 31, 1994, were: common equity, 45.1%; preferred stock,
7.2%; and long-term debt, 47.7%. APS and the Subsidiaries' long-term
objective is to maintain the common equity portion above 45%, reduce
the long-term debt portion toward 45%, and maintain the preferred stock
ratio for the balance of the capital structure.
In January 1994, the Operating Subsidiaries jointly entered into
an aggregate $300 million multi-year credit agreement with eighteen
lenders. Each Operating Subsidiary's borrowings under the agreement
are limited to its pro rata share of the stock of AGC, which stock was
pledged to secure the credit agreement. The Operating Subsidiaries'
percentage ownership of AGC and resulting borrowing limitations are:
Monongahela 27%, $81,000,000; Potomac Edison 28%, $84,000,000; and West
Penn 45%, $135,000,000. The agreement may be used as a supplement to
or in lieu of public financings and short-term debt programs.
During 1995, the Operating Subsidiaries anticipate meeting their
capital requirements through a combination of internally generated
funds, cash on hand, and short-term borrowing as necessary. The
Operating Subsidiaries may engage in tax-exempt solid waste disposal
financings during 1995 to the extent funds are available to Harrison
County from the West Virginia cap allocation. APS plans to sell common
stock through its Dividend Reinvestment and Stock Purchase Plan and
Employee Stock Ownership and Savings Plan.
The Operating Subsidiaries, if economic and market conditions
make it desirable, may refund during 1995 up to $565 million of first
mortgage bonds, up to $140 million of preferred stock, and up to $78
million of pollution control revenue notes through optional
redemptions.
FUEL SUPPLY
System-operated stations burned approximately 15.8 million tons
of coal in 1994. Of that amount, 69% was either cleaned (7.2 million
tons) or used in stations equipped with scrubbers (3.6 million tons).
Use of desulfurization equipment and cleaning and blending of coal make
burning local higher-sulfur coal practical, and in 1994 about 97% of
the coal received at System 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 12 million tons of coal in 1995.
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 System-operated stations
<PAGE>
are expected to be met with coal acquired under existing contracts or
from known suppliers. The Operating Subsidiaries signed two 10-year
lime supply agreements during 1994 which will provide for the long-term
lime requirements of the System's scrubbers.
The Operating Subsidiaries renegotiated several long-term coal
contracts with Consolidation Coal Company effective January 1, 1995,
resulting in reduced prices, the benefit of which will, for the most
part, accrue to the Operating Subsidiaries' customers.
For each of the years 1990 through 1993, the average cost per ton
of coal burned was $35.97, $36.74, $36.31 and $36.19, respectively.
For the year 1994, the cost per ton decreased to $35.88.
In addition to using ash in various power plant applications such
as sludge 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 ITEM 1. RESEARCH AND DEVELOPMENT.) In 1994, the
Operating Subsidiaries received approximately $236,000 for the sale of
85,998 tons of fly ash and 64,511 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 in almost all jurisdictions were issued for
the Operating Subsidiaries in 1994.
West Penn
On March 31, 1994, West Penn filed an application with the
Pennsylvania PUC for a base rate increase designed to produce $80.1
million in additional annual revenues from its retail customers. This
request 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. West
Penn filed a petition on January 12, 1994 with the Pennsylvania PUC
requesting authorization to accrue post in-service carrying charges on
the Harrison scrubbers and to defer related depreciation and operating
and maintenance expenses until they were recognized in rates. This
request was approved by the Pennsylvania PUC on May 4, 1994. By
Pennsylvania PUC order adopted December 15, 1994, an annual increase of
$55.5 million for West Penn's retail customers was authorized to become
effective December 31, 1994. Included in this amount was an authorized
return on equity (ROE) of 11.5%.
<PAGE>
Monongahela
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 includes 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. The West Virginia PSC, on November 9, 1994 affirmed the
recommended decision of the Administrative Law Judge (ALJ) providing
for a rate increase to be effective November 16, 1994 of $23.5 million
of new money. This amount was in addition to $6.9 million of CAAA
recovery granted effective July 1, 1994 to be transferred from fuel
clause recovery to base rates. The $6.9 million was included in
Monongahela's $61.3 million request. The decision reflects an ROE of
10.85%. The West Virginia PSC's order stated that it was affirming the
ALJ's recommendation because of time constraints and invited all
parties to file petitions for reconsideration. All parties have filed
petitions and a decision from the West Virginia PSC is pending. In the
meantime, Monongahela is collecting the new rates, which are not
subject to refund. Monongahela cannot predict the outcome of the
request for reconsideration.
Because of procedural requirements of Ohio law, a rate case in
Ohio in 1994 to request recovery of the cost of the Harrison scrubbers
was not deemed practical. 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 includes 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. The
Ohio PUC approved Monongahela's petition of January 11, 1994 requesting
authorization to accrue post in-service carrying charges on the
Harrison scrubbers until its investment in such scrubbers is recognized
in rates. That order also allows Monongahela to defer depreciation and
operating and maintenance expenses, including property taxes (but not
including fuel costs), with respect to the scrubbers. This accrual is
included in the rate case filing. It is expected that the new rates
will become effective in late 1995.
Potomac Edison
The Maryland Public Service Commission (Maryland PSC) issued a
final order on September 20, 1994 approving a settlement agreement in
Potomac Edison's base rate case authorizing an annual increase of $19.6
million effective November 11, 1994. The rate case filed by Potomac
Edison on April 15, 1994 originally requested a $30.9 million increase.
The authorized $19.6 million increase is in addition to $2.7 million of
demand-side management costs which were included in Potomac Edison's
original request but which were granted as a separate surcharge. The
rate case increase includes recovery of the remaining carrying charges
<PAGE>
on investment, depreciation, and all operating costs required to comply
with Phase I of the CAAA, and other increasing levels of expense.
On April 30, 1993 and June 22, 1994, Potomac Edison filed two
rate cases with the Virginia State Corporation Commission (Virginia
SCC) seeking a total increase of $12.5 million. The Virginia SCC
granted an increase of $4.5 million effective September 28, 1993, based
on the case filed April 30, 1993. In the case filed June 22, 1994, a
settlement agreement was filed with the Hearing Examiner reflecting an
additional increase of $3 million effective November 20, 1994. The
settlement agreement has been accepted by the now pending before the
Virginia SCC.
On November 9, 1994, the West Virginia PSC affirmed the
recommended decision of the ALJ providing for a rate increase effective
November 11, 1994. The increase of $1.5 million is in addition to $1.9
million of CAAA recovery granted effective July 1, 1994 which was
included in Potomac Edison's original request for $12.2 million filed
January 14, 1994. The request included recovery of the appropriate
costs to comply with Phase I of the CAAA as well as other increasing
levels of expense. The decision reflects an ROE of 10.85%. The West
Virginia PSC's order stated that it was affirming the ALJ's
recommendation because of time constraints and invited all parties to
file petitions for reconsideration. All parties have filed petitions
and a decision from the West Virginia PSC is pending. In the meantime,
Potomac Edison is collecting the new rates, which are not subject to
refund. Potomac Edison cannot predict the outcome of the request for
reconsideration.
AGC
Through February 29, 1992, AGC's ROE was adjusted annually
pursuant to a settlement agreement approved by the FERC. In December
1991, AGC filed for a continuation of the existing ROE of 11.53% and
other parties filed to reduce the ROE to 10%. Hearings were completed
in June 1992, and a recommendation was issued by an ALJ on December 21,
1993, for an ROE of 10.83%, which the other parties 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
Consumer Advocate Division of the West Virginia PSC, Maryland People's
Counsel, and Pennsylvania Office of Consumer Advocate filed a joint
complaint 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. 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 Joint Consumer Advocates' complaint. A settlement
agreement for both cases is currently pending, which would reduce AGC's
ROE to 11.13% for the period from March 1, 1992 through December 31,
1994, and increase AGC's ROE to 11.20% for the period from January 1,
1995 through December 31, 1995. During 1995, the parties have agreed
<PAGE>
to negotiate in good faith to approve a mechanism for setting ROE in
the future. This settlement is subject to FERC approval. If approved,
this settlement will require a refund to customers for the period
through December 31, 1994, of about $4.42 million for which adequate
reserves have been provided.
Through a filing completed on October 31, 1994, AGC sought to add
a prior tax payment of approximately $12 million to rate base which
will produce about $1.4 million in additional annual revenues. On
December 30, 1994, the FERC accepted AGC's filing, ordered that the
increase in rates go into effect on June 1, 1995, subject to refund,
and set AGC's ROE for hearing in 1995. A settlement agreement is
currently pending. This settlement is subject to FERC approval.
FERC
In 1994, West Penn and Monongahela implemented settlement
agreements covering wholesale rates in effect for their municipal, co-
op, and borderline agreement customers subject to the jurisdiction of
the FERC. Each 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 amounts of the increases were $2.1 million for West Penn
and $300,000 for Monongahela, both effective December 1, 1994.
On October 14, 1994, as supplemented on November 25, 1994,
Potomac Edison filed a petition for a $3.8 million increase with the
FERC. The request includes 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. By
order dated January 18, 1995, the FERC accepted Potomac Edison's filing
and set the matter for hearing. FERC also granted a request for
summary disposition of one item which reduced Potomac Edison's request
to $3.65 million. These new rates will go into effect on June 25,
1995, subject to refund. Potomac Edison cannot predict the outcome of
this proceeding.
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 $217 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.
<PAGE>
Air Standards
The Operating Subsidiaries meet applicable standards as to
particulates and opacity at major stations with 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. The West Virginia Division of
Environmental Protection (WVDEP), Office of Air Quality (OAQ), issued
Notices of Violation (NOVs) for opacity exceedances for the fourth
quarter of 1993 and first quarter of 1994 at the Albright, Fort Martin,
and Harrison Power Stations. An NOV was issued by OAQ for visual
opacity exceedances on March 23, 1994 at Pleasants Power Station. The
Operating Subsidiaries have submitted written responses to OAQ
regarding the opacity exceedances and are awaiting a response.
Because of the stringent 10% opacity limit in West Virginia which
led to the above-mentioned NOVs, Monongahela and other West Virginia
electric utilities petitioned the OAQ in 1994 to revise the opacity
limit from 10% to 20% in order to be consistent with surrounding states
and the federal New Source Performance Standards (NSPS). The OAQ on
October 21, 1994 published a proposed revision to Title 45, Regulation
2 to increase the opacity limit to 20%. The final rule should be
submitted to the state legislature in West Virginia for approval in
1995.
The Operating Subsidiaries meet current emission standards as to
SO2 by the use of scrubbers, the burning of low-sulfur coal, the
purchase of cleaned coal to lower the sulfur content and the blending
of low-sulfur with higher sulfur coal.
The CAAA, among other things, require an annual reduction in
total utility emissions within the United States of 10 million tons of
SO2 and two million tons of NOx from 1980 emission levels, to be
completed in two phases, Phase I and Phase II. Five coal-fired System
plants are affected in Phase I and the remaining plants or units
reactivated in the future will be affected in Phase II. Installation
of scrubbers at the Harrison Power Station was the strategy undertaken
by the Operating Subsidiaries to meet the required SO2 emission
reductions for Phase I (1995-1999). Continuing studies will determine
the compliance strategy for Phase II (2000 and beyond). It is expected
that burner modifications at possibly all System 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. Studies to evaluate cost effective
options to comply with Phase II, including those which may be available
from the use of Operating Subsidiaries' banked emission allowances and
from the emission allowance trading market, are continuing.
In a case brought by the electric utility industry which disputed
the EPA's inclusion of overfire air equipment as well as low NOx burners
<PAGE>
in its definition of "low NOx burner technology," the District of
Columbia Circuit Court of Appeals on November 29, 1994 vacated and
remanded to the EPA the Title IV NOx rule. As a result, the January 1,
1995 Phase I NOx compliance deadline under Title IV is no longer
applicable. It is uncertain when a revised rule will be issued,
whether the emission limits will be revised, and what the compliance
deadline will be.
Pursuant to an option in the CAAA and in order to avoid the
potential for more stringent NOx limits in Phase II, the Operating
Subsidiaries chose to treat Phase II Group 1 boilers (tangential and
wall-fired) as Phase I affected units as of January 1, 1995. This was
accomplished by activation of substitution unit plans for the seven
Phase II Group 1 boilers. As a result of being Phase I affected, these
units will also be required to comply with the Phase I SO2 limits.
Phase I NOx and SO2 compliance for these units should not require
additional capital or operating expenditures.
Title I of the CAAA established an ozone transport region
consisting of the District of Columbia and 11 northeast states
including Maryland and Pennsylvania. Sources within the region will be
required to reduce NOx emissions, a precursor of ozone, to a level
conducive to attainment of the ozone national ambient air quality
standard (NAAQS). The installation of reasonably available control
technology (RACT) (overfire air equipment and/or low NOx burners) at all
Pennsylvania and Maryland stations is expected to be completed by May
31, 1995. This is essentially compatible with Title IV NOx reduction
requirements, prior to their remand.
The Ozone Transport Commission (OTC) has determined that the
Operating Subsidiaries may be required to make additional NOx reductions
beyond RACT in order for the ozone transport region to meet the ozone
NAAQS. Under terms of a Memorandum of Understanding (MOU), the
Operating Subsidiaries' power stations located in Maryland and
Pennsylvania will be required to reduce NOx emissions by 55% from the
1990 baseline emissions, with a compliance date of May 1999. Further
reductions of 75% from the 1990 baseline may be required by May 2003,
unless the results of modeling studies due to be completed by 1998,
indicate otherwise. Both Maryland and Pennsylvania must promulgate
regulations to implement the terms of the MOU.
In an effort to introduce market forces into pollution control,
the CAAA created SO2 emission allowances. An allowance is defined as an
authorization to emit one ton of SO2 into the atmosphere. Subject to
regulatory limitations, allowances (including bonus and extension
allowances) may be sold or "banked" for future use or sale. Through an
industry allowance pooling agreement, the Operating Subsidiaries will
receive a total of approximately 554,000 bonus and extension allowances
during Phase I. These allowances are in addition to the Table A
allowances of approximately 356,000 per year during the Phase I years.
Ownership of these allowances permits the Operating Subsidiaries to
operate in compliance with Phase I, as well as postpone a decision on
their compliance strategy for Phase II. As part of their compliance
strategy, the Operating Subsidiaries continue to study the allowance
<PAGE>
market to determine whether sales or purchases of allowances are
appropriate.
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 the NAAQS for SO2. Pursuant to a
consent order, Monongahela agreed to collect on-site meteorological
data and conduct additional dispersion modeling in order to demonstrate
compliance. The modeling study and a compliance strategy recommending
construction of a new "good engineering practices" (GEP) stack were
submitted to the 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 SO2 would follow. As a result of the 1985 revision of its stack
height rules, EPA refused to reclassify the area to attainment status.
Subsequently, West Penn filed an appeal with the U.S. Court of Appeals
for the Third Circuit for review of that decision as well as a petition
for reconsideration with EPA. In 1988, the Court dismissed West Penn's
appeal stating it could not decide a 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 System-owned stations and disposal sites are
in place. However, NPDES permit renewals for several West Virginia
disposal sites contain what the Operating Subsidiaries believe are
overly stringent discharge limitations. The WVDEP has temporarily
stayed the stringent permit limitations while the Operating
Subsidiaries continue 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 EPA and state agencies have 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 current round of permit renewals began in
1993, monitoring requirements have been imposed, with pollution
reduction plans and additional control of some discharges anticipated.
The Clean Water Act deadline of October 1, 1994 for compliance
with Phase II of the stormwater program passed without EPA promulgating
<PAGE>
regulations specifying which additional stormwater sources require
NPDES permits. Affected System-owned facilities could include office
buildings, parking lots, substations and rights-of-way. In the
interim, the EPA has issued a policy memorandum specifying that its
stormwater compliance enforcement strategy does not apply to Phase II
sources. The Subsidiaries cannot predict the effect of EPA's
regulations when promulgated.
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 the
Operating Subsidiaries 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 the Operating
Subsidiaries jointly filed with American Electric Power 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 by the
Operating Subsidiaries under a contract with EPRI. While the
justification for the variance requests is being developed, the
Operating Subsidiaries are 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 Resources (PADER)
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. PADER 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 the Operating Subsidiaries
cannot be predicted.
In 1994, the Operating Subsidiaries received two NOVs from PADER
and one NOV from WVDEP, all of which have been resolved. A chronic
NPDES compliance problem at the closed Springdale Ash Area was resolved
recently with the negotiation of a compliance agreement with PADER.
The agreement specified the payment of a penalty for past permit
exceedances, required payment of additional penalties for any future
exceedances and provided for the installation of innovative constructed
wetland treatment technology. The first stage has been installed and
is operating in compliance with current NPDES permit effluent
limitations.
<PAGE>
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, Pennsylvania, Ohio, 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.
The Operating Subsidiaries are 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.
It is anticipated that additional disposal capacity will be
required for Armstrong Power Station. A small extension to the
existing permitted disposal site and the permitting of a new site, are
being actively pursued with PADER. A permit for an extension of the
existing disposal site is anticipated to be granted by the end of 1995
for construction and use in 1996. Siting of a new disposal area will
be a much longer process. If the Operating Subsidiaries fail to obtain
either disposal permit, it could have an adverse impact on the
operation of the Armstrong Power Station.
Significant costs were incurred during 1994 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 the Operating Subsidiaries' facilities. The Operating Subsidiaries
continue 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.
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.
On March 4, 1994, the Operating Subsidiaries received notice that
the EPA had identified them as potentially responsible parties under
the Comprehensive Environmental Response, Compensation and Liability
Act of 1980, as amended, with respect to the Jack's Creek/Sitkin
Smelting Superfund Site. (See ITEM 3. LITIGATION for a further
discussion of this case.)
<PAGE>
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 late 1995. 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 the Operating Subsidiaries is
unknown at this time.
Reauthorization of the Clean Water Act, the Comprehensive
Environmental Response, Compensation and Liability Act of 1980 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 will begin 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 sludge disposal
areas containing pyrites to that 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 the Operating Subsidiaries
and which is undergoing intense study, is the health effect, if any, of
electric and magnetic fields. The financial impact of this issue on
the Operating Subsidiaries, if any, cannot be assessed at this time.
In connection with President Clinton's Climate Change Action Plan
concerning greenhouse gases, the Operating Subsidiaries expressed by
letter to the Department of Energy (DOE) in August 1993, their
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 the Operating Subsidiaries' integrated resource
planning process and must not have an adverse effect on competitive
position in terms of costs and rates or be unacceptable to their
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 establishes the principles DOE and
utilities will operate under to reduce or avoid emission of greenhouse
gases. A company-specific agreement is to be entered into on behalf of
the Operating Subsidiaries and DOE in early February 1995.
<PAGE>
REGULATION
APS and the Subsidiaries are subject to the broad jurisdiction of
the Securities and Exchange Commission (SEC) under the Public Utility
Holding Company Act of 1935 (PUHCA). APS 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 and the FERC. In addition, they are subject to numerous
other city, county, state, and federal laws, regulations, and rules.
In November 1994, the SEC published a release requesting comments
from regulated public utility holding company systems and other
interested parties on modernizing PUHCA by internal changes in rules
and regulations. Comments are due in early February 1995. APS, along
with all of the other registered electric public utility holding
companies, is advocating repeal of PUHCA. However, APS cannot predict
what changes, if any, will be made to PUHCA.
The National Energy Policy Act of 1992 (EPACT), among other
things, amends PUHCA to permit utilities subject to PUHCA to compete in
the wholesale generation business with other wholesale generators not
subject to PUHCA; to ease restrictions on financing for that purpose;
and to permit investment in foreign utilities. EPACT also amends the
Federal Power Act to permit the FERC to order, under specified
circumstances, access to transmission systems (including those of the
System) so long as it would not unreasonably impair reliability nor
adversely affect its existing wholesale, retail and transmission
customers. It also amends PURPA to encourage states to study and
regulate various matters, including the capital structures of EWGs,
integrated resource planning, and the amount of purchased power that
electric utilities should have in their generation mix. In addition it
sets forth waste disposal standards, new nuclear licensing procedures,
and contains provisions promoting alternate transportation fuels,
research on environmental issues, and increased energy from renewables
(See discussion of EPACT in ITEM 1. BUSINESS, SALES and ELECTRIC
FACILITIES).
Section 111 of EPACT requires the 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. Maryland,
Pennsylvania, Virginia, and West Virginia initiated investigations to
determine whether to adopt the federal standards, while Ohio summarily
issued a final order without an investigation. The Operating
Subsidiaries submitted comments in the Maryland, Pennsylvania, and West
Virginia proceedings and will file comments in 1995 in Virginia. To
date, Maryland, Ohio, and West Virginia have issued final orders. All
three states declined to adopt the federal standards, concluding that
existing state regulations adequately address the issues. The outcome
in the remaining jurisdictions cannot be predicted.
The Operating Subsidiaries founded and continue to participate
in, along with other utilities, an organization whose primary purpose
<PAGE>
is to develop a mutually acceptable method of resolving the inequities
imposed on transmission network owners by parallel power flows.
In July 1993, the Pennsylvania PUC directed the Bureau of
Conservation, Economics and Energy Planning to develop competitive
bidding regulations to replace, at least in part, the existing state
PURPA regulations. The Pennsylvania PUC has instituted a proposed
rulemaking regarding competitive bidding regulations. In collaboration
with other Pennsylvania Electric Association companies, West Penn filed
comments to the proposed competitive bidding rulemaking in October
1994. The Pennsylvania PUC has not issued a final order in connection
with the proposed competitive bidding rulemaking. West Penn cannot
predict the outcome of this proceeding. 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. Various aspects of the Pennsylvania PUC's
decision have been appealed to the Pennsylvania Commonwealth Court by
South River, West Penn, and Shannopin. This proceeding has been stayed
pending the outcome of an appeal in an unrelated case. (See ITEM 3.
LEGAL PROCEEDINGS for a description of the South River complaint, the
Shannopin Project, and events that have taken place in Pennsylvania
Commonwealth Court.)
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
opinion.
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 by March 3, 1993 and
reply comments by March 24, 1993. A number of interested parties,
including Monongahela, submitted comments. The Ohio PUC has taken no
further action following the filing of comments.
Maryland and Virginia have not mandated compulsory competitive
bidding as of this date.
On September 20, 1994, the Maryland PSC issued an order which
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 distributed a discussion paper
describing the issues which they believe warrant analysis and comment
by the utilities and interested persons. Potomac Edison submitted
initial comments in response to the staff paper in January 1995.
Legislative hearings are currently scheduled for March 1995.
<PAGE>
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 that do not
unduly harm the interests of utility company shareholders or
ratepayers". These discussions are being undertaken pursuant to an
Ohio Energy Strategy issued in April 1994. The first two roundtable
discussions, attended by representatives of electric utilities,
including Monongahela, businesses, residential consumers, environmental
groups, and other interested persons or organizations were held on
October 17 and December 8, 1994. The Ohio PUC will continue to hold
roundtable meetings at approximately six-week intervals.
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 were filed on November 10, 1994 and reply
comments were filed on January 10, 1995. The Pennsylvania PUC has set
a deadline of May 10, 1995 to conclude the investigation.
In August 1994, the Pennsylvania PUC instituted a proposed
rulemaking relating to Pennsylvania PUC review of siting and
construction of electric transmission lines. In an order 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 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 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 of the
Pennsylvania PUC 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. On January 23, 1995, the Pennsylvania PUC requested
reargument of the case before the Commonwealth Court, and that request
is pending.
During 1994, Potomac Edison continued its participation in the
Collaborative Process for demand-side management in Maryland with the
Maryland PSC Staff, Office of People's Counsel, the Department of
Natural Resources, Maryland Energy Administration, and Potomac Edison's
largest industrial customer. Potomac Edison had received the Maryland
PSC's approval to implement the Commercial and Industrial Lighting
Rebate Program and the Power Saver/Comfort Home Program for new
residential construction as of July 1, 1993. Through December 31, 1994
Potomac Edison had approved applications for $16.1 million in rebates
related to the commercial lighting program and $1.2 million in rebates
related to the residential new construction program. The peak demand
<PAGE>
reductions from these two programs through the end of 1994 should
reduce future generation requirements by about 26.0 and 1.9 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.
West Penn implemented a Low Income Payment and Usage Reduction
Program in 1994. This pilot program will run for two years and 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 non-profit, 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 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 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 SYSTEM MAP.)
ITEM 3. LEGAL PROCEEDINGS
On September 16, 1994, Duquesne initiated a proceeding before the
FERC by filing a request for an order requiring the System to provide
300 MW of transmission service at parity with native load customers
from interconnection points within the System to the System's points of
interconnection with the Pennsylvania-New Jersey-Maryland
Interconnection (PJM). Duquesne is seeking to transmit primarily its
<PAGE>
own baseload generation for sales within and beyond the PJM system.
The Operating Subsidiaries responded on October 24, 1994 requesting
that the FERC order the parties back to negotiations to resolve,
through a bilateral contract, outstanding issues concerning the
transmission services. The FERC has yet to issue an order in this
proceeding.
In 1979, National Steel Corporation (National Steel) filed suit
against 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 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. The Subsidiaries believe the motion is without
merit; however, they cannot predict the outcome of this case.
In 1987, West Penn entered into separate agreements with
developers of three PURPA projects: Milesburg (43 MW), Burgettstown
(80 MW), and Shannopin (80 MW). The agreements provided for the
purchase of each project's power over 30 years or more at rates
generally approximating West Penn's avoided cost at the time the
agreements were negotiated. Each agreement 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
agreement. Since that time, all three agreements 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 and Allegheny Ludlum, 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 acted upon a pending
petition of Shannopin and on December 1, 1994 refused to answer
termination issues regarding Shannopin and ordered that the project be
paid capacity costs. West Penn and its two largest industrial customers
have appealed this order to the Pennsylvania Commonwealth Court. West
Penn cannot predict the outcome of this proceeding.
There has been no further action on the Milesburg case since the
denial of Cert. West Penn cannot predict the outcome of this matter.
As a result of the denial of Cert by the U.S. Supreme Court, the
Pennsylvania PUC orders that recalculated rates and adjusted milestone
dates for Burgettstown became final and non-appealable 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 cancel its orders regarding these
projects because they are no longer in the public interest. On
December 16, 1994, the Pennsylvania PUC dismissed the complaint. West
Penn has appealed the order to the Pennsylvania Commonwealth Court.
West Penn cannot predict the outcome of this proceeding.
<PAGE>
In November 1994, Burgettstown filed a complaint against West
Penn in the Court of Common Pleas of Washington County, Pennsylvania.
The complaint requests equitable relief in the form of specific
performance, declaratory and injunctive relief, and also seeks monetary
damages for breach of contract and for tortious interference with
Burgettstown's contractual relations with others. The Court has set
April 3, 1995 as the trial date for the specific performance remedy
only. West Penn cannot predict the outcome of this proceeding.
On March 19, 1995, West Penn filed a petition for issuance of a
declaratory order with FERC (Petition). This Petition seeks a
declaration that the orders of the Pennsylvania PUC requiring West Penn
to purchase capacity from Burgettstown violate PURPA and FERC's PURPA
regulations and thus West Penn has no obligation to purchase capacity
from Burgettstown. West Penn cannot predict the outcome of this
proceeding.
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 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. In August 1994, the
Pennsylvania PUC granted West Penn's request to stay proceedings
pending resolution of issues in a related matter concerning competitive
bidding currently on appeal to the Pennsylvania Commonwealth Court.
(See ITEM 1. REGULATION for a discussion of West Penn's competitive
bidding petition.) West Penn cannot predict the outcome of this
proceeding.
Two previously reported complaints had been filed with the West
Virginia PSC by developers of cogeneration projects pursuant to PURPA
in Marshall and Barbour Counties, West Virginia, seeking to require
Monongahela and Potomac Edison to purchase capacity from the projects.
These two cases were consolidated. The West Virginia PSC on March 5,
1993 found that: Monongahela had no need for additional capacity;
Potomac Edison will need new combustion turbine generating capacity
beginning in 1996; and Potomac Edison's avoided cost estimate, which is
substantially below the costs sought by the developers of the projects,
is reasonable. The developers subsequently asked the West Virginia PSC
to consider issues which were not resolved in the March 5, 1993 order.
On June 25, 1993 the West Virginia PSC found that Potomac Edison had a
PURPA obligation to purchase power from qualifying facilities properly
interconnected to the System in Monongahela's service territory and
ordered negotiations by Monongahela and Potomac Edison with the two
PURPA developers. On August 9, 1993, the West Virginia PSC
deconsolidated the two cases. Following the West Virginia Supreme
Court's denial of a petition for review of the June 25, 1993 order,
both developers requested the start of negotiations. In February 1994,
Potomac Edison and Monongahela met with the developer of the Barbour
County Project to begin negotiation of issues not resolved in the March
1993 order. There have been no further developments in the Barbour
County project since that time. In September 1994, Potomac Edison
received a new proposal concerning the Marshall County site from its
developer, pursuant to which the developer proposes to sell capacity to
Potomac Edison. Potomac Edison replied to the proposal in October
1994. On January 10, 1995, the developer filed a motion with the West
Virginia PSC to compel Potomac Edison to enter into an Electric Energy
Purchase Agreement. Monongahela and Potomac Edison cannot predict the
outcome of these proceedings.
As previously reported, effective March 1, 1989, West Virginia
enacted a new method for calculating the Business and Occupation Tax
<PAGE>
(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 have been filed. West Penn cannot predict
the outcome of this litigation.
As of December 1994, Monongahela has been named as a defendant
along with multiple other defendants in 1,625 pending asbestos cases
involving one or more plaintiffs and Monongahela, Potomac Edison and
West Penn have been named as defendants along with multiple other
defendants in an additional 716 cases by one or more plaintiffs.
Because these cases are filed by "shot-gun" complaints naming many
plaintiffs and many defendants, it is presently impossible to determine
the actual number of claims against the Operating Subsidiaries.
However, based on past experience and data available to date, it is
estimated that less than 500 cases 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. All
plaintiffs claiming exposure at stations operated by the Operating
Subsidiaries were employed by third-party contractors, with the
exception of three known plaintiffs who claim to have been 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 that 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. Therefore, because of
the multiple defendants, the Operating Subsidiaries believe their
potential liability is a very small percentage of the total amount of
the damages sought. A total of 94 cases have been previously settled
by Monongahela for an amount substantially less than the anticipated
cost of defense. While the Operating Subsidiaries believe that all of
these cases are without merit, they cannot predict the outcome of these
cases or whether other cases will be filed.
On June 10, 1994, APS and all of its subsidiaries filed a
declaratory judgment action in the Superior Court of New Jersey against
their historic comprehensive general liability (CGL) insurers. This
suit seeks a declaration that the CGL insurers have a duty to defend
and indemnify the Operating Subsidiaries in the asbestos cases, as well
as in certain environmental actions. To date, one insurer has settled.
All other parties have answered the complaint. On January 27, 1995,
the Court granted the CGL insurers' motion which dismissed the
complaint, without prejudice, on procedural grounds. On the same day,
APS and all of its subsidiaries recommenced the action in the Court of
Common Pleas of Westmoreland County, Pennsylvania. The outcome of this
proceeding cannot be predicted.
<PAGE>
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
prepared by the EPA indicates remedial alternatives which range as high
as $113 million, to be shared by all responsible parties. The EPA has
not yet selected which remedial alternatives it will use, nor has it
issued a Proposed Plan and Record of Decision. The Operating
Subsidiaries believe they have defenses to allegations of liability and
intend to vigorously defend this matter. 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
making 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
Neither APS, Monongahela, Potomac Edison, West Penn nor AGC
submitted any matters to a vote of shareholders during the fourth
quarter of 1994.
<PAGE>
<TABLE>
<CAPTION>
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
Name Age APS APSC MP PE WP AGC
<S> <C> <C> <C> <C> <C> <C> <C>
Charles S. Ault 56 V.P.
(1990- )
Previously,
Dir., Per.
(1986-90)
Thomas A. Barlow 60 V.P.
(1987- )
Eileen M. Beck 53 Sec. Sec. Secretary Asst. Sec. Asst. Sec. Sec. (1982- )
(1988- ) (1988- ) (1995- ) (1988- ) (1988- )
Asst. Treas. Asst. Treas. Asst. Treas.
(1979- ) (1979- ) (1981- )
Previously,
Asst. Sec.
(1988-94)
Klaus Bergman 63 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)
Charles V. Burkley 63 Comptroller
(1984- )
Nancy L. Campbell 55 V.P. V.P. Treas. Asst. Treas. Treas. &
(1994- ) (1993- ) (1995- ) & Asst. Sec. Asst. Sec.
Treas. Treas. (1988- ) (1988- )
(1988- ) (1988- )
Richard J. Gagliardi 44 V.P. V.P. Asst. Sec. Asst. Treas.
(1991- ) (1990- ) (1990- ) (1982- )
Previously,
Asst. V.P. &
Dir. Taxes
(1988-90)
Stanley I. Garnett,II 51 Senior Senior Dir. Dir. Dir. Dir. & V.P.
V.P. - Fin. V.P. - Fin. (1990- ) (1990- ) (1990- ) (1990- )
(9/94- ) (9/94- ) V.P.
& Asst. Sec. & Asst. Sec. (1985- )
(1982- ) (1982- ) Previously,
Previously, Previously, Asst. Treas.
V.P. - Fin. V.P. - Fin. Asst. Sec.
(1990-9/94) (1990-9/94) (1981-90)
Previously,
V.P. - Legal
& Regulatory
(a) All officers and directors are elected annually.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Position (a) and Period of Service
Name Age APS APSC MP PE WP AGC
<S> <C> <C> <C> <C> <C> <C> <C>
Nancy H. Gormley 62 V.P. V.P. - Legal V.P. Asst. Sec.
(1991- ) & Regulatory (1992- ) & Asst. Treas.
(1990- ) (1990- )
Previously,
Asst. V.P.
(1/90-9/90);
Previously,
Gen. Solicitor
Benjamin H. Hayes(b) 60 Pres.
(1987-94) &
Dir.
(1992-94)
Thomas K. Henderson 54 V.P. V.P. V.P.
(1995- ) (1995- ) (1985- )
Kenneth M. Jones 57 V.P. & V.P. & Dir. & V.P.
Comptroller Comptroller (1991- )
(1991- ) (1991- )
Previously,
Comptroller
(1976- )
Thomas J. Kloc 42 Comptroller Comptroller
(1988- ) (1988- )
James D. Latimer 56 Executive V.P.
(6/94- )
Previously,
V.P.
(1988-6/94)
(a) All officers and directors are elected annually.
(b) Retired effective January 1, 1995.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Position (a) and Period of Service
Name Age APS APSC MP PE WP AGC
<S> <C> <C> <C> <C> <C> <C> <C>
Kenneth D. Mowl 55 Sec. & Treas.
(1986- )
Charles S. Mullett(b) 63 Sec. & Treas.
(1983-94)
Robert B. Murdock(b) 62 V.P.
(1972-94)
Richard E. Myers 58 Comptroller
(1980- )
Alan J. Noia 47 Pres., COO Pres., COO Dir. Pres. Dir. Dir. & V.P.
& Dir. & Dir. (9/94- ) (1990-94) (9/94- ) (9/94- )
(9/94- ) (9/94- ) Previously, & Dir. Previously, Previously,
Previously, Previously, Dir. (1990- ) Dir. Dir. (1984-90) &
V.P.-Fin. V.P.-Fin. (1987-90) Previously, (1987-90) V.P. (1982-90)
(1987-90) (1987-90) Dir. & Exec. V.P.
(3/90 - 5/90);
Dir. & V.P.
(1987-1990)
Jay S. Pifer 57 Senior V.P. Pres. & Dir. Pres. & Dir. Pres.
(1995- ) (1995- ) (1995- ) (1990- )
& Dir.
(1992- )
Previously,
V.P.
(1985-90)
Richard A. Roschli 60 V.P.
(6/94- )
Previously,
Asst. V.P.
(5/94-6/94);
Div. Mgr.
(1988-5/94)
Peter J. Skrgic 53 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 51 V.P. V.P.
(1987- ) (1995- )
Dale F. Zimmerman 61 Asst. Sec. & Sec. & Treas.
Asst. Treas. (1990 - )
(1995- ) Previously,
Asst. Sec.
(1964-89);
Asst. Treas.
(1967-89)
(a) All officers and directors are elected annually.
(b) Retired effective January 1, 1995.
</TABLE>
<PAGE>
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, 1994, there were 66,818 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>
1994 1993(a)
Dividend High Low Dividend High Low
<S> <C> <C> <C> <C> <C> <C>
1st Quarter 41 cents $26-1/2 $22-3/8 40-1/2 cents $25-15/16 $23-7/16
2nd Quarter 41 cents $24 $20-1/8 40-1/2 cents $26-3/4 $25
3rd Quarter 41 cents $22-3/4 $19-3/4 41 cents $28-7/16 $26-5/8
4th Quarter 41 cents $22 $19-3/4 41 cents $28 $25-1/2
(a) Stock prices and dividends were adjusted to reflect a two-for-one stock
split effective November 4, 1993.
</TABLE>
The high and low prices through February 2, 1995 were 24 and
21-1/2. The last reported sale on that date was at 23-5/8.
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>
ITEM 6. SELECTED FINANCIAL DATA
Page No.
APS D-1
Monongahela D-3
Potomac Edison D-5
West Penn D-7
AGC D-9
<PAGE>
<TABLE>
<CAPTION>
D-1
APS
CONSOLIDATED STATISTICS
Year ended December 31
1994 1993 1992 1991 1990 1989 1984
Summary of Operations (in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $2 451.7 $2 331.5 $2 306.7 $2 282.2 $2 301.9 $2 260.7 $1 725.6
Operation expense 1 284.9 1 208.4 1 252.0 1 252.2 1 338.6 1 337.1 948.4
Maintenance 241.9 231.2 210.9 204.2 182.0 185.5 131.3
Depreciation 223.9 210.4 197.8 189.7 180.9 172.3 118.8
Taxes other than income 183.1 178.8 174.6 167.5 152.5 139.5 105.3
Taxes on income 129.7 128.1 115.4 119.1 106.4 89.0 134.4
Allowance for funds used during
construction (19.6) (21.5) (17.5) (7.9) (7.2) (7.7) (34.9)
Interest charges and preferred
dividends 184.2 180.3 171.3 165.0 161.1 156.0 152.1
Other income and deductions (a) 3.8 (1.3) (1.6) (3.8) (5.9) (6.1)
Consolidated income before
cumulative effect of accounting
change (a) 219.8 215.8 203.5 194.0 191.4 194.9 176.3
Cumulative effect of accounting
change, net (b) 43.4
Consolidated net income $ 263.2 $ 215.8 $ 203.5 $ 194.0 $ 191.4 $ 194.9 $ 176.3
Common Stock Data (c)
Shares outstanding at Dec. 31
(in thousands) 119 293 117 664 113 899 108 451 106 984 105 579 98 757
Average shares outstanding
(in thousands) 118 272 114 937 111 226 107 548 106 102 104 787 97 627
Earnings per average share:
Consolidated income before
cumulative effect of accounting
change (a) $1.86 $1.88 $1.83 $1.80 $1.80 $1.86 $1.81
Cumulative effect of accounting
change (b) .37
Consolidated net income $2.23 $1.88 $1.83 $1.80 $1.80 $1.86 $1.81
Dividends paid per share $1.64 $1.63 $1.60 1/2 $1.58 1/2 $1.58 $1.55 $1.31 1/4
Dividend pay-out ratio (d) 86.2% 86.9% 88.3% 87.8% 87.6% 83.3% 72.7%
Stockholders at Dec. 31 66 818 63 396 63 918 62 095 63 201 68 156 85 080
Market price range per share:
High 26 1/2 28 7/16 24 3/8 23 1/4 21 1/16 21 1/4 15
Low 19 3/4 23 7/16 20 3/4 17 7/16 17 17 13/16 12 5/16
Book value per share at Dec. 31 $17.26 $16.62 $16.05 $15.54 $15.26 $14.99 $12.37
Return on average common equity (d)11.22% 11.40% 11.45% 11.59% 11.78% 12.41% 14.69%
Capitalization Data at Dec. 31
Capitalization (in millions):
Common stock $2 059.3 $1 955.8 $1 827.8 $1 685.6 $1 632.3 $1 582.4 $1 221.5
Preferred stock:
Not subject to mandatory
redemption 300.1 250.1 250.1 235.1 235.1 235.1 240.1
Subject to mandatory redemption 25.2 26.4 28.0 29.3 30.6 30.6 81.0
Long-term debt 2 178.5 2 008.1 1 951.6 1 747.6 1 642.2 1 578.4 1 464.9
Total capitalization $4 563.1 $4 240.4 $4 057.5 $3 697.6 $3 540.2 $3 426.5 $3 007.5
Capitalization ratios:
Common stock 45.1% 46.1% 45.0% 45.6% 46.1% 46.2% 40.6%
Preferred stock:
Not subject to mandatory
redemption 6.6 5.9 6.2 6.3 6.6 6.8 8.0
Subject to mandatory redemption .6 .6 .7 .8 .9 .9 2.7
Long-term debt 47.7 47.4 48.1 47.3 46.4 46.1 48.7
Total Assets at Dec. 31
(in millions) $6 362.2 $5 949.2 $5 039.3 $4 855.0 $4 561.3 $4 433.3 $3 736.8
Property Data at Dec. 31 (in millions)
Gross property $7 586.8 $7 176.9 $6 679.9 $6 255.7 $5 986.2 $5 721.5 $4 424.3
Accumulated depreciation (2 529.4) (2 388.8) (2 240.0) (2 093.7) (1 946.1)(1 807.1) (1 176.0)
Net property $5 057.4 $4 788.1 $4 439.9 $4 162.0 $4 040.1 $3 914.4 $3 248.3
Gross additions during year $ 508.3 $ 574.0 $ 487.6 $ 337.7 $ 321.8 $ 302.5 $ 297.9
Ratio of provisions for depreciation
to depreciable property 3.32% 3.37% 3.31% 3.28% 3.27% 3.26% 3.15%
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-2
CONSOLIDATED STATISTICS (continued)
1994 1993 1992 1991 1990 1989 1984
Revenues (in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 863.7 $ 818.4 $ 734.9 $ 708.3 $ 649.5 $ 626.2 $ 514.1
Commercial 459.3 430.2 391.9 375.4 343.0 327.5 260.1
Industrial 728.0 673.4 637.7 600.2 571.5 553.5 515.5
Nonaffiliated utilities 331.6 346.7 465.5 525.0 679.9 698.5 389.5
Other 69.1 62.8 76.7 73.3 58.0 55.0 46.4
Total revenues $2 451.7 $2 331.5 $2 306.7 $2 282.2 $2 301.9 $2 260.7 $1 725.6
Sales--kWh (in millions)
Residential 12 630 12 514 11 746 11 755 11 264 11 042 9 411
Commercial 7 607 7 440 7 071 7 003 6 670 6 479 5 274
Industrial 17 708 16 967 16 910 16 430 16 511 16 239 15 431
Nonaffiliated utilities 9 915 12 388 17 753 18 211 21 796 24 383 12 413
Other 1 275 1 240 1 186 1 146 1 101 1 110 950
Total sales 49 135 50 549 54 666 54 545 57 342 59 253 43 479
Output--kWh (in millions)
Steam generation 38 959 38 247 40 373 42 307 41 933 43 497 39 298
Hydro and pumped-storage
generation 1 390 1 233 1 204 1 654 1 426 1 774 205
Pumped-storage input (1 564) (1 385) (1 340) (1 907) (1 568) (1 973)
Purchased power and exchanges, net 12 965 15 245 17 279 15 321 17 924 19 169 6 383
Losses and system uses (2 615) (2 791) (2 850) (2 830) (2 373) (3 214) (2 407)
Total sales as above 49 135 50 549 54 666 54 545 57 342 59 253 43 479
Energy Supply
Generating capability--MW at Dec. 31
System-owned 8 070 7 991 7 991 7 992 7 991 7 906 7 109
Nonutility contracts (e) 299 292 212 162 160 160
Maximum hour peak--MW 7 153 6 678 6 530 6 238 6 070 6 489 5 508
Load factor 66.8% 70.0% 69.3% 71.7% 71.3% 67.0% 69.3%
Heat rate--Btu's per kWh 9 927 10 020 9 910 9 956 9 944 9 967 10 136
Fuel costs--cents per million Btu's 141.50 142.12 141.93 143.19 140.97 136.70 154.38
Customers at Dec. 31 (in thousands)
Residential 1 189.7 1 176.6 1 161.5 1 146.6 1 133.4 1 118.1 1 045.4
Commercial 143.0 140.1 137.4 134.7 132.2 128.9 113.6
Industrial 24.2 23.8 23.6 23.1 22.8 2.4 20.4
Other 1.3 1.2 1.2 1.3 1.3 1.2 1.1
Total customers 1 358.2 1 341.7 1 323.7 1 305.7 1 289.7 1 270.6 1 180.5
Average Annual Use--kWh per customer
Residential--APS 10 682 10 715 10 181 10 316 10 011 9 950 9 061
Residential--National 9 445 (f) 9 380 (f) 8 949 (f) 9 280 (c) 9 056 9 063 8 500
All retail service--APS 28 205 27 800 27 259 27 205 26 996 26 866 25 776
Average Rate--cents per kWh
Residential--APS 6.84 6.54 6.26 6.03 5.77 5.67 5.46
Residential--National 8.78 (f) 8.73 (f) 8.63 (f) 8.46 8.17 7.95 7.53
All retail service--APS 5.43 5.23 4.96 4.80 4.56 4.48 4.30
(a) Includes asset write-off of $5.3 million ($.05 per share), net of income taxes in 1994.
(b) To record unbilled revenues, net of income taxes.
(c) Reflects a two-for-one common stock split effective November 4, 1993.
(d) Excludes the cumulative effect of the accounting change and asset write-off in 1994.
(e) Capability available through contractual arrangements with nonutility generators.
(f) Preliminary.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-3
Monongahela
SUMMARY OF OPERATIONS
(Thousands of Dollars)
1994 1993 1992 1991 1990 1989
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential $190 861 $185 141 $169 589 $163 757 $151 658 $146 429
Commercial 116 201 110 762 102 709 97 849 90 095 86 527
Industrial 202 181 187 669 186 442 177 688 169 654 165 940
Nonaffiliated utilities 79 701 86 032 119 628 140 029 177 573 185 122
Other,
including affiliates 91 186 72 240 53 595 45 803 41 348 44 881
Total 680 130 641 844 631 963 625 126 630 328 628 899
Operation expense 394 438 364 027 372 002 364 968 379 663 395 614
Maintenance 69 389 67 770 62 909 64 035 57 768 58 690
Depreciation 57 952 56 056 53 865 51 903 50 433 48 381
Taxes other
than income 40 404 34 076 33 207 35 378 34 310 32 552
Taxes on income 30 712 33 612 27 919 31 173 31 005 19 293
Allowance for funds used
during construction (2 946) (5 780) (3 908) (1 341) (1 559) (2 295)
Interest charges 38 156 37 588 36 013 33 494 33 264 32 544
Other income, net (7 911) (7 203) (8 388) (8 573) (9 505) (11 325)
Income before
cumulative effect of
accounting change 59 936 61 698 58 344 54 089 54 949 55 445
Cumulative effect of
accounting change,
net (a) 7 945
Net income $67 881 $61 698 $58 344 $54 089 $54 949 $55 445
Return on average
common equity (b) 10.66% 11.83% 11.96% 11.43% 11.84% 12.23%
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-4
Monongahela
FINANCIAL AND OPERATING STATISTICS
1994 1993 1992 1991 1990 1989
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (in thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross $1 763 533 $1 684 322 $1 567 252 $1 458 643 $1 389 906 $1 334 814
Accumulated
depreciation (701 271) (664 947) (628 595) (590 311) (550 104) (512 439)
Net $1 062 262 $1 019 375 $ 938 657 $ 868 332 $ 839 802 $ 822 375
GROSS ADDITIONS TO PROPERTY
(in thousands) $ 103 975 $ 140 748 $ 126 422 $ 84 515 $ 74 575 $ 84 972
TOTAL ASSETS at Dec. 31
(in thousands) $1 476 483 $1 407 453 $1 166 410 $1 091 287 $1 054 497 $1 024 709
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $ 495 693 $ 483 030 $ 475 628 $ 428 855 $ 425 016 $ 410 409
Preferred stock
(not subject to mandatory
redemption) 114 000 64 000 64 000 69 000 69 000 69 000
Long-term debt 470 131 460 129 444 506 372 618 367 871 367 826
$1 079 824 $1 007 159 $ 984 134 $ 870 473 $ 861 887 $ 847 235
Ratios:
Common stock 45.9% 48.0% 48.3% 49.3% 49.3% 48.4%
Preferred stock
(not subject to mandatory
redemption) 10.6 6.3 6.5 7.9 8.0 8.2
Long-term debt 43.5 45.7 45.2 42.8 42.7 43.4
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY-
kW at Dec. 31:
Company-owned 2 326 300 2 325 300 2 325 300 2 325 300 2 325 300 2 301 925
Nonutility
contracts* 161 000 159 000 79 000 29 000 27 000 27 000
KILOWATTHOURS IN THOUSANDS:
Sales:
Residential 2 674 664 2 689 830 2 527 247 2 581 628 2 430 539 2 401 287
Commercial 1 846 791 1 825 127 1 742 469 1 744 881 1 656 961 1 606 830
Industrial 4 942 388 4 656 921 4 872 126 4 905 715 4 868 551 4 828 376
Nonaffiliated
utilities 2 383 531 3 082 715 4 578 187 4 877 930 5 634 908 6 490 586
Other,including
affiliates 1 925 450 1 565 561 824 393 584 677 590 920 942 404
Total sales 13 772 824 13 820 154 14 544 422 14 694 831 15 181 879 16 269 483
Output:
Steam generation 10 743 934 10 194 794 10 593 059 11 512 714 11 247 964 12 328 241
Pumped-storage
generation 290 586 263 329 260 155 375 500 306 470 390 151
Pumped-storage
input (373 116) (337 737) (332 989) (475 898) (389 467) (530 642)
Purchased power and
exchanges, net 3 784 421 4 381 916 4 705 418 3 969 954 4 618 564 4 815 449
Losses and
system uses (673 001) (682 148) (681 221) (687 439) (601 652) (733 716)
Total sales
as above 13 772 824 13 820 154 14 544 422 14 694 831 15 181 879 16 269 483
CUSTOMERS at Dec. 31:
Residential 300 465 297 865 294 595 291 578 288 990 286 823
Commercial 35 268 34 626 34 005 33 484 33 107 32 614
Industrial 8 029 8 014 8 005 7 994 7 946 7 870
Other 171 170 172 172 170 166
Total
customers 343 933 340 675 336 777 333 228 330 213 327 473
RESIDENTIAL SERVICE:
Average use-kWh
per customer 8 957 9 093 8 636 8 905 8 457 8 406
Average revenue-dollars
per customer 639.16 625.87 579.51 564.87 527.70 512.62
Average rate-cents
per kWh 7.14 6.88 6.71 6.34 6.24 6.10
* Capability available through contractual arrangements with
nonutility generators.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-5
Potomac Edison
SUMMARY OF OPERATIONS
(Thousands of Dollars)
1994 1993 1992 1991 1990 1989
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential $296 090 $274 358 $243 413 $227 851 $213 165 $208 663
Commercial 135 937 124 667 111 506 104 642 97 902 94 648
Industrial 195 089 175 902 157 304 147 654 148 632 152 296
Nonaffiliated
utilities 107 027 108 132 141 120 161 720 210 710 208 524
Other,
including affiliates 25 222 29 526 34 544 32 210 27 135 26 287
Total 759 365 712 585 687 887 674 077 697 544 690 418
Operation expense 448 527 413 145 414 939 423 489 460 546 449 480
Maintenance 58 624 64 376 53 141 49 766 45 035 46 837
Depreciation 59 989 56 449 53 446 50 578 47 547 44 638
Taxes other than
income 46 740 46 813 45 791 43 937 38 527 36 483
Taxes on income 33 163 30 086 28 422 24 194 25 132 27 680
Allowance for funds used
during construction (5 874) (7 134) (5 368) (3 366) (2 908) (2 381)
Interest charges 46 456 43 802 39 392 36 831 33 049 28 805
Other income, net (10 243) (8 419) (9 352) (9 593) (10 964) (10 802)
Income before cumulative effect
of accounting change 81 983 73 467 67 476 58 241 61 580 69 678
Cumulative effect of accounting
change, net (a) 16 471
Net income $98 454 $73 467 $67 476 $58 241 $61 580 $69 678
Return on average
common equity (b) 11.86% 11.63% 11.85% 11.04% 12.31% 15.07%
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change in 1994.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-6
FINANCIAL AND OPERATING STATISTICS
1994 1993 1992 1991 1990 1989
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (in thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross $1 978 396 $1 857 961 $1 698 711 $1 557 695 $1 454 250 $1 352 491
Accumulated
depreciation (673 853) (632 269) (591 378) (546 867) (504 168) (466 428)
Net $1 304 543 $1 225 692 $1 107 333 $1 010 828 $ 950 082 $ 886 063
GROSS ADDITIONS TO PROPERTY
(in thousands) $ 142 826 $ 179 433 $ 153 485 $ 116 589 $ 116 627 $ 104 009
TOTAL ASSETS at Dec. 31
(in thousands) $1 629 535 $1 519 763 $1 355 385 $1 256 712 $1 140 623 $1 074 464
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $ 658 146 $ 626 467 $ 567 826 $ 480 931 $ 453 761 $ 421 583
Preferred stock:
Not subject to mandatory
redemption 36 378 36 378 36 378 56 378 56 378 56 378
Subject to mandatory
redemption 25 200 26 400 28 005 29 280 30 555 30 630
Long-term debt 604 749 517 910 511 801 453 584 399 518 320 533
$1 324 473 $1 207 155 $1 144 010 $1 020 173 $ 940 212 $ 829 124
Ratios:
Common stock 49.7% 51.9% 49.6% 47.1% 48.3% 50.8%
Preferred stock:
Not subject to
mandatory redemption 2.7 3.0 3.2 5.5 6.0 6.8
Subject to mandatory
redemption 1.9 2.2 2.5 2.9 3.2 3.7
Long-term debt 45.7 42.9 44.7 44.5 42.5 38.7
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY:
kW at Dec. 31 2 072 292 2 076 592 2 076 592 2 077 192 2 076 292 2 059 292
KILOWATTHOURS IN THOUSANDS:
Sales:
Residential 4 214 997 4 144 958 3 822 387 3 753 884 3 561 824 3 466 647
Commercial 2 136 081 2 091 930 1 954 025 1 912 848 1 818 789 1 744 825
Industrial 5 339 737 5 194 909 4 979 219 4 881 835 4 928 433 4 896 273
Nonaffiliated
utilities 3 194 580 3 860 791 5 394 006 5 649 050 6 818 528 7 311 705
Other,
including affiliates 653 614 649 636 616 711 615 604 593 548 599 099
Total sales 15 539 009 15 942 224 16 766 348 16 813 221 17 721 122 18 018 549
Output:
Steam generation 10 464 607 10 103 411 10 713 987 11 192 300 11 094 016 11 538 206
Hydro and pumped-storage
generation 426 550 368 834 351 035 502 302 430 500 522 300
Pumped-storage input (506 213) (433 885) (407 393) (593 879) (489 243) (550 944)
Purchased power and
exchanges, net 5 896 492 6 691 792 6 937 037 6 517 575 7 387 314 7 526 595
Losses and system uses (742 427) (787 928) (828 318) (805 077) (701 465) (1 017 608)
Total sales as above 15 539 009 15 942 224 16 766 348 16 813 221 17 721 122 18 018 549
CUSTOMERS at Dec. 31:
Residential 315 309 309 096 302 559 295 564 289 695 281 469
Commercial 40 927 40 173 39 236 38 522 37 708 36 237
Industrial 4 595 4 509 4 435 4 283 4 132 3 957
Other 524 510 510 501 471 442
Total customers 361 355 354 288 346 740 338 870 332 006 322 105
RESIDENTIAL SERVICE:
Average use-kWh per
customer 13 506 13 562 12 766 12 822 12 463 12 511
Average revenue-dollars
per customer 948.76 897.70 812.96 778.25 745.90 753.04
Average rate-cents per kWh 7.02 6.62 6.37 6.07 5.98 6.02
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-7
West Penn
SUMMARY OF OPERATIONS
(Thousands of Dollars)
1994 1993 1992 1991 1990 1989
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential $ 376 776 $ 358 900 $ 321 871 $ 316 685 $ 284 691 $ 271 067
Commercial 207 165 194 773 177 697 172 924 154 999 146 364
Industrial 330 739 309 847 293 910 274 896 253 184 235 286
Nonaffiliated
utilities 144 829 152 541 204 743 223 225 291 636 304 822
Other, including
affiliates 68 733 68 916 78 620 83 073 74 342 58 108
Total 1 128 242 1 084 977 1 076 841 1 070 803 1 058 852 1 015 647
Operation expense 647 963 625 269 647 989 649 422 684 508 673 158
Maintenance 111 841 96 706 93 067 87 717 77 516 78 167
Depreciation 88 935 80 872 73 469 70 334 66 122 62 428
Taxes other
than income 87 224 89 249 87 300 80 630 72 114 62 846
Taxes on income 50 385 51 529 44 078 47 846 33 867 24 988
Allowance for funds
used during
construction (10 777) (8 566) (8 276) (3 224) (2 729) (2 991)
Interest charges 60 274 60 585 55 592 51 977 49 268 45 953
Asset write-off, net 5 179
Other income, net (13 797) (12 728) (14 534) (15 077) (15 067) (17 153)
Consolidated income before
cumulative effect of
accounting change 101 015 102 061 98 156 101 178 93 253 88 251
Cumulative effect of accounting
change, net (a) 19 031
Consolidated
net income $120 046 $102 061 $98 156 $101 178 $93 253 $88 251
Return on average common
equity (b) 10.49% 11.49% 11.53% 12.66% 12.07% 11.62%
(a) To record unbilled revenues, net of income taxes.
(b) Excludes the cumulative effect of the accounting change and
asset write-off in 1994.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-8
West Penn Power Company and Subsidiaries
FINANCIAL AND OPERATING STATISTICS
1994 1993 1992 1991 1990 1989
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (in thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross $3 013 777 $2 803 811 $2 581 641 $2 409 005 $2 312 425 $2 209 054
Accumulated
depreciation (1 009 565) (962 623) (904 906) (857 999) (809 674) (762 700)
Net $2 004 212 $1 841 188 $1 676 735 $1 551 006 $1 502 751 $1 446 354
GROSS ADDITIONS TO PROPERTY
(in thousands) $ 260 366 $ 251 017 $ 204 409 $ 134 443 $ 128 762 $ 112 801
TOTAL ASSETS at Dec. 31
(in thousands) $2 731 858 $2 544 763 $2 083 127 $2 006 309 $1 842 766 $1 784 493
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $ 955 482 $ 893 969 $ 782 341 $ 774 707 $ 723 567 $ 694 107
Preferred stock (not
subject to mandatory
redemption) 149 708 149 708 149 708 109 708 109 708 109 708
Long-term debt 836 426 782 369 759 005 621 906 563 378 563 410
$1 941 616 $1 826 046 $1 691 054 $1 506 321 $1 396 653 $1 367 225
Ratios:
Common stock 49.2% 49.0% 46.3% 51.4% 51.8% 50.8%
Preferred stock (not
subject to mandatory
redemption) 7.7 8.2 8.8 7.3 7.9 8.0
Long-term debt 43.1 42.8 44.9 41.3 40.3 41.2
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY-kW at Dec. 31:
Company-owned 3 671 408 3 589 408 3 589 408 3 589 408 3 589 408 3 544 783
Nonutility
contracts (a) 138 000 133 000 133 000 133 000 133 000 133 000
KILOWATTHOURS IN THOUSANDS:
Sales:
Residential 5 740 028 5 679 746 5 396 533 5 419 150 5 271 390 5 173 781
Commercial 3 624 117 3 522 566 3 374 355 3 345 255 3 194 141 3 127 641
Industrial 7 426 267 7 114 765 7 058 895 6 643 238 6 713 824 6 514 384
Nonaffiliated
utilities 4 337 106 5 444 798 7 780 654 7 683 817 9 342 543 10 580 015
Other, including
affiliates 1 530 853 1 821 189 2 247 844 2 485 366 2 426 414 1 868 121
Total sales 22 658 371 23 583 064 25 858 281 25 576 826 26 948 312 27 263 942
Output:
Steam
generation 17 750 267 17 949 335 19 066 445 19 602 129 19 590 731 19 630 384
Hydro and pumped-storage
generation 673 195 600 497 592 895 775 798 688 517 862 119
Pumped-storage
input (684 715) (613 290) (599 729) (836 700) (689 186) (891 847)
Purchased power and
exchanges, net 6 119 757 6 967 752 8 139 496 7 373 185 8 428 158 9 125 988
Losses and
system uses (1 200 133) (1 321 230) (1 340 826) (1 337 586) (1 069 908) (1 462 702)
Total sales
as above 22 658 371 23 583 064 25 858 281 25 576 826 26 948 312 27 263 942
CUSTOMERS at Dec. 31:
Residential 573 963 569 601 564 300 559 444 554 716 549 773
Commercial 66 842 65 337 64 212 62 674 61 396 60 062
Industrial 11 563 11 218 11 138 10 826 10 687 10 561
Other 586 576 569 692 680 660
Total customers 652 954 646 732 640 219 633 636 627 479 621 056
RESIDENTIAL SERVICE:
Average use-kWh
per customer 10 041 10 025 9 608 9 733 9 550 9 459
Average revenue-dollars
per customer 659.07 633.48 573.07 568.76 515.75 495.60
Average rate-cents
per kWh 6.56 6.32 5.96 5.84 5.40 5.24
(a) Capability available through contractual arrangements with
nonutility generators.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
D-9
AGC
STATISTICS
1994 1993 1992 1991 1990 1989
SUMMARY OF OPERATIONS
(Thousands of Dollars)
Electric
<S> <C> <C> <C> <C> <C> <C>
operating revenues $91 022 $90 606 $96 147 $100 505 $104 482 $111 011
Operation and
maintenance expense 6 695 6 609 6 094 6 774 5 974 6 229
Depreciation 16 852 16 899 16 827 16 778 16 756 16 816
Taxes other
than income taxes 5 223 5 347 5 236 4 563 4 712 5 062
Federal income taxes 14 737 13 262 14 702 15 455 16 458 17 230
Interest charges 17 809 21 635 22 585 24 030 26 883 30 020
Other income, net (11) (328) (21) (24) (17) (24)
Net income $29 717 $27 182 $30 724 $ 32 929 $ 33 716 $ 35 678
Return on
average common equity 13.14% 11.72% 12.79% 13.09% 12.78% 12.95%
PROPERTY, PLANT, AND EQUIPMENT at Dec. 31 (in thousands):
Gross $824 714 $824 904 $825 493 $822 332 $821 424 $820 376
Accumulated
depreciation (143 965) (128 375) (114 684) (97 915) (81 514) (64 906)
Net $680 749 $696 529 $710 809 $724 417 $739 910 $755 470
GROSS ADDITIONS TO PROPERTY
(in thousands) $1 065 $2 729 $3 251 $1 391 $1 214 $532
TOTAL ASSETS at Dec. 31
(in thousands) $714 236 $735 929 $727 820 $742 223 $757 084 $777 047
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $222 729 $228 512 $235 530 $244 593 $254 664 $265 648
Long-term debt 267 165 277 196 287 139 299 502 311 461 326 600
$489 894 $505 708 $522 669 $544 095 $566 125 $592 248
Ratios:
Common stock 45.5% 45.2% 45.1% 45.0% 45.0% 44.9%
Long-term debt 54.5 54.8 54.9 55.0 55.0 55.1
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
KILOWATTHOURS IN THOUSANDS:
Pumping energy supplied by
parents 1 564 044 1 384 912 1 340 111 1 906 477 1 567 896 1 973 433
Pumped-storage
generation 1 218 446 1 079 985 1 047 015 1 504 310 1 233 782 1 554 767
</TABLE>
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Page No.
APS M-1
Monongahela M-5
Potomac Edison M-13
West Penn M-21
AGC M-30
<PAGE>
M-1
APS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Earnings per share were $2.23 in 1994, including $.37 of
non-recurring income from the cumulative effect of an
accounting change to record unbilled revenues. The 1994 results
also reflect the write-off ($.05 per share)
of previously accumulated costs related to future facilities no
longer considered meaningful in the industry's
more competitive environment. Earnings per share were $1.88 and
$1.83 in 1993 and 1992, respectively.
Consolidated net income was $263.2 million including the $43.4
million non-recurring cumulative effect of an
accounting change and net of the $5.3 million asset write-off
described above. Consolidated net income was
$215.8 million and $203.5 million in 1993 and 1992, respectively.
The 1994 and 1993 increases in consolidated
net income resulted primarily from kWh sales and retail rate
increases. These revenue increases, in both years,
were offset in part by higher expenses.
The subject of competition for customers, particularly industrial
customers, has been receiving a lot of
attention. In 1994 the Maryland, Ohio, and Pennsylvania
commissions started proceedings described as inquiries
into the subject, which are still in progress. The inquiries are
not expected to result in immediately
meaningful changes in current relations with our customers. All
customers, except wholesale customers regulated
by the Federal Energy Regulatory Commission (FERC), continue to
be required to purchase their electricity
requirements from the utility in whose franchised territory they
reside. This is not to say that competition
does not exist. Utilities continue to compete for the siting of
new industrial and commercial customers, to
retain existing customers in the franchised territory, and, for
those businesses with multiple plants in
multiple territories, to maintain or shift their production to
local facilities. As in the past, electric
utilities continue to compete with suppliers of other forms of
energy. Because the subsidiaries are the lowest
or among the lowest cost suppliers of electricity in their
regions, they should not experience the competitive
concerns of other utilities who use cost-based pricing. However,
the subsidiaries continue to face competition
from utilities with excess generation that are willing to sell at
prices intended only to recover variable
costs.
SALES AND REVENUES
KWh sales to and revenues from residential, commercial, and
industrial customers are shown on page 35. Such kWh
sales increased 2.8% and 3.3% in 1994 and 1993, respectively.
The increases in revenues from sales to residential, commercial,
and industrial customers resulted from the
following:
Increase from Prior Year
1994 1993
(Millions of Dollars)
Increased kWh sales $ 23.6 $ 46.6
Fuel and energy cost adjustment clauses* 48.3 57.0
Rate increases:
Pennsylvania 22.7 25.2
Maryland 11.9 12.7
West Virginia 9.7 5.3
Virginia 8.5 2.5
Ohio 2.1
52.8 47.8
Other 4.3 6.2
$129.0 $157.6
* Changes in revenues from fuel and energy cost adjustment
clauses have little effect on consolidated net income.
The increased kWh sales in 1994 reflect growth in both
residential and commercial customers and higher use by
commercial customers. The 1994 residential use was down slightly
from 1993 levels reflecting a decrease in both
heating and cooling degree days. The increased kWh sales to
residential and commercial customers in 1993
reflect both growth in number of customers and higher use. While
1993 heating degree days showed only a slight
increase over 1992, and were approximately normal, cooling degree
days increased 69% over 1992 and were 25% over
normal, contributing to the 1993 kWh sales increases.
Rate case decisions in almost all jurisdictions, representing
revenue increases in excess of $120 million on
an annual basis, were issued for the subsidiaries in 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
expense. See Rate Matters on pages 7-9 for
further information on rate changes.
KWh sales to industrial customers increased 4.4% in 1994 and .3%
in 1993. The 1994 increase occurred in almost
all industrial groups, particularly coal mining (142
gigawatt-hours [GWh], 9.2%); paper, printing and publishing
(130 GWh, 24.9%); iron and steel (130 GWh, 3.8%); and chemical
customers (112 GWh, 5.0%). The relatively flat
industrial sales growth in 1993 included one particular group,
coal mines staffed by union personnel, which
recorded reduced usage because of selective work stoppages by the
United Mine Workers of America (UMWA) for most
of the year prior to the settling of the dispute in December
1993.
KWh sales to and revenues from nonaffiliated utilities are
comprised of the following items:
1994 1993 1992
KWh sales (in billions):
From subsidiaries' generation 1.1 1.2 3.2
From purchased power 8.8 11.2 14.6
9.9 12.4 17.8
Revenues (in millions):
From subsidiaries'generation $ 29.0 $ 28.5 $ 91.7
From sales of purchased power 302.6 318.2 373.8
$331.6 $346.7 $465.5
<PAGE>
M-2
Decreased sales to nonaffiliated utilities resulted primarily
from decreased demand and continuing price
competition. Sales supplied by subsidiaries' generation in 1994
continued at less than 15% of 1988 levels
because of continuing growth of kWh sales to retail customers,
which reduces the amount available for sale, and
because other suppliers were willing or able to make the sales at
lower prices. A significant factor affecting
the subsidiaries' ability to compete in the market for sales to
nonaffiliated utilities has been the approximate
290% increase (from about 67 cents per MWh to $2.60 per MWh) in taxes
on generation in West Virginia since March
1989--a significant cost not experienced by utilities not
generating in West Virginia. Further decreases in
these sales are anticipated. About 95% of the aggregate benefits
from sales to nonaffiliated utilities is passed
on to retail customers and has little effect on consolidated net
income.
The increase in other revenues in 1994 resulted from increased
revenues from wholesale customers. The decrease
in other revenues in 1993 resulted from an agreement with the
FERC to record in 1993 about $14 million of
revenues as sales to nonaffiliated utilities. Similar
transactions were recorded as other revenues in prior
years. About $46 million of other revenues in 1994 were derived
from wholesale customers regulated by the FERC
who have the ability to obtain their electricity requirements
from other suppliers. In 1994, customers
representing about 40% of these revenues signed seven-year
contracts to remain as customers. In the event that
the other customers were to select another supplier, the
subsidiaries would retain transmission revenues with
the result that any net income loss would not be significant.
OPERATING EXPENSES
Fuel expenses increased .5% in 1994 and decreased 4% in 1993,
both primarily due to changes 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 other utilities and
qualified facilities under the Public Utility Regulatory Policies
Act of 1978 (PURPA) and is comprised of the
following items:
1994 1993 1992
(Millions of Dollars)
Purchased power:
For resale to other utilities $267.1 $280.9 $344.0
From PURPA generation 134.0 105.2 94.0
Other 40.4 33.8 12.7
Total power purchased 441.5 419.9 450.7
Power exchanges, net (.6) (2.5) .7
$440.9 $417.4 $451.4
The amount of power purchased from other utilities for use by
subsidiaries and for resale to other utilities
depends upon the availability of the subsidiaries' generating
equipment, transmission capacity, and fuel, and
their cost of 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 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. The increases in
purchases from PURPA generation reflect additional generation
from new PURPA projects. None of the
subsidiaries' purchased power contracts is capitalized since
there are no minimum payment requirements absent
associated kWh generation. The 1993 increase in other purchased
power reflects efforts to conserve coal during
the UMWA dispute. Other purchased power continued to increase in
1994 because of increased sales to retail
customers combined with generating unit outages in the first
quarter of 1994.
The increase in other operation expense in 1994 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 due to an
increase in aged outstanding receivables caused by customers
taking advantage of rate regulations which make
it difficult if not impossible to curtail service to non-paying
customers during the winter months. In a
continuing effort to control salary and wage expenses and to
improve the overall efficiency of the Company in
a competitive environment, the Company has an ongoing program to
consolidate various related functions within
the subsidiaries. The increase in pension expense occurred
because the subsidiaries in 1994 discontinued the
practice of deferring SFAS No. 87 pension expense in Pennsylvania
and West Virginia to reflect recent rate case
decisions in those states. Pension expense in 1994 also includes
a charge of $3.1 million for write-off of
prior SFAS No. 87 deferrals in West Virginia because recovery of
those deferrals was denied in the most recent
rate cases.
During 1992, the subsidiaries implemented significant changes to
their benefits plans, including cost caps, in
an effort to both control and reduce employee benefits costs.
The cost caps provide for future post-retirement
medical benefit costs to be capped at two times 1993 levels.
Approximately $1 million of the $3 million increase
in postretirement benefit expenses for 1994 was due to the 1993
cost cap being greater than actuarily projected.
The adoption of SFAS No. 106 in 1993 increased 1993
postretirement benefit expense by approximately $5 million.
The increase in other operation expense for 1993 resulted
primarily from increases in employee benefit costs
and salaries and wages.
Another FASB standard, SFAS No. 112, "Employers' Accounting for
Postemployment Benefits", effective in 1994,
requires companies to accrue for other postemployment benefits
such as disability benefits, health care benefits
<PAGE>
M-3
for disabled employees, severance pay, and workers' compensation
claims. The subsidiaries currently accrue for
workers' compensation claims, and the estimated liability for the
other benefits is not material.
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, the amount of work found necessary
when the equipment is dismantled, and outage requirements to
comply with the CAAA. Maintenance expense in 1993
includes the effects of an ice storm and blizzard in March 1993.
Depreciation expense increases resulted primarily from additions
to electric plant. On November 16, 1994, the
subsidiaries declared the Harrison scrubbers available for
service and started depreciation on them amounting
to $32 million annually.
Taxes other than income increased $4 million in 1994 primarily
due to increases in gross receipts taxes
resulting from higher revenues from retail customers. The 1993
increase ($4 million) resulted from increases
in gross receipts taxes ($5 million) and increased property taxes
($2 million) offset by decreased
West Virginia Business and Occupation taxes due to decreased
generation in that state.
The net increase of $2 million in federal and state income taxes
in 1994 resulted primarily from an increase
in income before taxes. The net increase in 1993 of $13 million
resulted primarily from an increase in income
before taxes ($9 million) and an increase in the tax due to the
Revenue Reconciliation Act of 1993 ($3 million).
Note B to the consolidated financial statements provides a
further analysis of income tax expenses.
The 1994 combined decrease of $2 million in allowances for funds
used during construction (AFUDC), as well as
the 1993 combined increase of $4 million, reflect variations in
construction expenditures including those
associated with the CAAA, net of CAAA amounts included in rate
base and earning a cash return. Future levels
of AFUDC can be expected to decrease upon substantial completion
of Phase I of the CAAA compliance program.
Other income and deductions in 1994 reflect 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. Fluctuations in other income, net, were
individually insignificant. Other interest
expense reflects changes in the levels of short-term debt
maintained by the companies throughout the year, as
well as the associated interest rates.
The increase in dividends on preferred stock of the subsidiaries
reflects the issuance in May 1994 of $50
million of preferred stock with a dividend rate of $7.73 per
share.
LIQUIDITY AND CAPITAL RESOURCES
SEC regulations define "liquidity" as "the ability of an
enterprise to generate adequate amounts of cash to meet
the enterprise's need for cash". System companies need cash for
operating expenses, the payment of interest and
dividends, retirement of debt and certain preferred stocks, and
for their construction programs. To meet these
needs, the companies have used internally generated funds and
external financings, such as the sale of common
and preferred stock, debt instruments, installment loans, and
lease arrangements. The timing and amount of
external financings depend primarily upon economic and financial
market conditions, the companies' cash needs,
and capitalization ratio objectives. The availability and cost of
external financing depend upon the financial
health of the companies seeking those funds.
CAPITAL REQUIREMENTS
Construction expenditures for 1994 were $508 million and for 1995
and 1996 are estimated at $341 million and
$284 million, respectively. These estimates include $61 million
and $7 million, respectively, for substantial
completion of the program of complying with Phase I of the CAAA
discussed under ENVIRONMENTAL MATTERS on page
10. Annual construction expenditures through 1998 are not
expected to significantly exceed 1995 estimated
levels. Construction expenditure levels in 1999 and beyond will
depend upon the strategy eventually selected
for complying with Phase II of the CAAA, as well as future
generation requirements.
The Harrison Scrubber Project was completed on schedule and the
final cost was approximately 24% below the
original budget. Primary factors contributing to the reduced
cost include: (1) the absence of any major
construction problems, (2) financing and material and equipment
costs lower than expected, and (3) favorable
rulings of state commissions allowing the inclusion of carrying
costs of construction in rates in lieu of AFUDC.
The possibility of new legislation which could restrict or
discourage carbon dioxide emissions, either through
taxation or caps, further complicates the CAAA Phase II planning
process. The subsidiaries have additional
capital requirements of an annual preferred stock sinking fund
($1.2 million) and debt maturities (see Note H
to the consolidated financial statements).
In a further effort to meet the challenges of the new competitive
environment in the industry, AYP Capital,
Inc., an unregulated wholly-owned subsidiary of the Company, was
formed. It is intended that AYP Capital
operate as an innovative and flexible organization, pursuing and
developing new opportunities in unregulated
markets that will strengthen the long-term competitiveness and
profitability of the System. The Company has
been authorized by the SEC to purchase common stock of and make
capital contributions to AYP Capital in the
amount of $3 million.
INTERNAL CASH FLOWS
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $246 million
in 1994 compared with $270 million in 1993. In 1994 the
subsidiaries financed approximately 48% of their capital
expenditure program through internal cash generation. Based upon
the new rate case authorizations received in
1994, it is expected that close to 100% of the capital
expenditure program can be financed through internal
cash generation in 1995.
The increase in other investments reflects the 1994 cash
surrender values for secured benefit plans and a
related prepayment. Materials and supplies, primarily fuel,
constituted a significant use of cash in 1994 ($21
million). A new five-year National Bituminous Coal Wage
Agreement was signed with the union in December 1993.
<PAGE>
M-4
System coal inventory declined during the renegotiations due to
selective mine shutdowns, and has returned to
a more appropriate level. December 1992 levels reflected
increases to provide for an adequate coal supply in
the event of a strike.
FINANCINGS
During 1994, the Company issued 1,629,372 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. During 1994,
the subsidiaries issued an aggregate of $140 million of first
mortgage bonds having interest rates of 8% to
8.125%, an aggregate of $35 million of tax-exempt solid waste
disposal notes to Harrison County, West Virginia,
and $50 million of $7.73 preferred stock. Debt redemption costs
are amortized over the life of the associated
new bonds. Due to the significant number of refinancings which
have occurred over the past three years, this
balance is now about $41 million. Reduced future interest expense
will more than offset these expenses.
Short-term debt is used to meet temporary cash needs until the
timing is considered appropriate to issue
long-term securities. Short-term debt decreased $3.8 million to
$126.8 million in 1994. In 1992, the Company and its subsidiaries established
an internal money pool whereby surplus funds of the
Company and certain subsidiaries may be borrowed on a short-term
basis by the Company's subsidiaries. This has
contributed to the continued low temporary cash investment
amounts.
At December 31, 1994, unused lines of credit with banks were $202
million. In addition, a multi-year credit
program established in January 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 1994.
During 1995, the subsidiaries have no current plans to issue new
securities; however, if economic and market
conditions make it desirable, they may refinance up to $783
million of first mortgage bonds, preferred stock,
and pollution control revenue notes. The subsidiaries may also
engage in additional Harrison County tax-exempt
solid waste disposal financings to the extent that funds and
qualified properties are available. 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, and
possibly through alternative financing
procedures.
ENVIRONMENTAL MATTERS AND OTHER CONTINGENCIES
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 above and under
Note J to the consolidated financial statements.
The subsidiaries previously reported that the Environmental
Protection Agency (EPA) had identified them and
approximately 875 others as potentially responsible parties in a
Superfund site subject to cleanup. A Remedial
Investigation/Feasibility Study prepared by the EPA indicates
remedial alternatives which range as high as $113
million, to be shared by all responsible parties. The EPA has
not yet selected which remedial alternatives it
will use. The subsidiaries believe they have defenses to
allegations of liability and intend to vigorously
defend this matter. Although it is not possible at this time to
determine what costs, if any, the subsidiaries
may incur, they have recorded provisions for liabilities based on
the range of remediation cost estimates and
their relative participation, along with the approximately 875
others. The subsidiaries believe that provisions
for liabilities and insurance recoveries are such that final
resolution of this matter will not have a material
effect on their financial position.
Monongahela has been named as a defendant along with multiple
other defendants in 1,625 pending asbestos cases
involving one or more plaintiffs; Monongahela, Potomac Edison,
and West Penn have been named as defendants along
with multiple other defendants in an additional 716 cases by one
or more plaintiffs. Because these cases are
filed by "shotgun" complaints naming many plaintiffs and many
defendants, it is currently impossible to
determine the actual number of claims against the subsidiaries.
However, based on past experience and data
available to date, it is estimated that less than 500 cases
actually involve claims against any or all of the
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. All
plaintiffs claiming exposure at subsidiary-operated stations were
employed by third-party contractors, with the
exception of three known plaintiffs who claim to have been
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 that 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 of the multiple defendants, the
subsidiaries believe their potential liability is a very small
percentage of the total amount of the damages
sought. A total of 94 cases have been previously settled by
Monongahela for an amount substantially less than
the anticipated cost of defense.
The subsidiaries believe that the remaining cases involving them
are without merit and that provisions for
liabilities and insurance recoveries are such that these suits
will not have a material effect on their
financial position.
<PAGE>
M-5
Monongahela
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Net Income
Net income was $67.9 million in 1994, including $7.9 million of
non-recurring income from the cumulative effect of an accounting
change to record unbilled revenues. Net income was $61.7 million
and $58.3 million in 1993 and 1992, respectively. Net income in
1994 and 1993 continue to reflect increases in revenues from
retail customers resulting from increased kWh sales and retail
rate increases. The decrease in 1994 income before the accounting
change resulted primarily from higher expenses, including taxes,
pension expense, and depreciation.
The subject of competition for customers, particularly
industrial customers, has been receiving a lot of attention. In
1994 the Ohio commission started a proceeding described as an
informal roundtable discussion into the subject, which is still
in progress. This process is not expected to result in
immediately meaningful changes in current relations with our
customers. All customers, except wholesale customers regulated by
the Federal Energy Regulatory Commission (FERC), continue to be
required to purchase their electricity requirements from the
utility in whose franchised territory they reside. This is not to
say that competition does not exist. Utilities continue to
compete for the siting of new industrial and commercial
customers, to retain existing customers in the franchised
territory, and, for those businesses with multiple plants in
multiple territories, to maintain or shift their production to
local facilities. As in the past, electric utilities continue to
compete with suppliers of other forms of energy. Because the
Company is among the lowest cost suppliers of electricity in its
region, it should not experience the competitive concerns of
other utilities who use cost-based pricing. However, the Company
continues to face competition from utilities with excess
generation that are willing to sell at prices intended only to
recover variable costs.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and
industrial customers are shown on pages 16 and 17. Such kWh sales
increased 3.2% and .3% in 1994 and 1993, respectively. The
increases in revenues from sales to residential, commercial, and
industrial customers resulted from the following:
Increase from Prior Year
1994 1993
(Millions of Dollars)
Increased kWh sales $ 3.8 $ 6.6
Fuel and energy cost
adjustment clauses* 13.0 11.8
Rate increases:
West Virginia 7.9 4.1
Ohio 2.1
7.9 6.2
Other 1.0 .2
$25.7 $24.8
* Changes in revenues from fuel and energy cost adjustment
clauses have little effect on net income.
<PAGE>
M-6
The increased kWh sales in 1994 reflect growth in both
residential and commercial customers. The 1994 residential use
was down slightly from 1993 levels reflecting a decrease in both
heating and cooling degree days. The increased kWh sales to
residential and commercial customers in 1993 reflect both growth
in number of customers and higher use. While 1993 heating degree
days showed only a slight increase over 1992, and were only 6%
above normal, cooling degree days increased 54% over 1992,
contributing to the 1993 kWh sales increase.
Rate case decisions in West Virginia and by the FERC for
wholesale customers, representing revenue increases in excess of
$30 million on an annual basis, were issued for the Company in
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 expense.
KWh sales to industrial customers increased 6.1% in 1994 and
decreased 4.4% in 1993. The 1994 increase occurred primarily from
coal mining (128 gigawatt-hours [GWh], 16.1%); chemical (91 GWh,
5.3%); and primary metals customers (77 GWh, 8.3%). The increase
in sales to primary metals customers was due in part to the
discontinuance of one customer's use of its own generation, which
contributed to 1993 decreased sales. The 1993 decrease also
reflects a decline in sales to coal customers. Coal mines staffed
by union personnel recorded reduced usage because of selective
work stoppages by the United Mine Workers of America (UMWA) for
most of the year prior to the settling of the dispute in December
1993.
KWh sales to and revenues from nonaffiliated utilities are
comprised of the following items:
1994 1993 1992
KWh sales (in billions):
From Company generation .3 .3 1.0
From purchased power 2.1 2.8 3.6
2.4 3.1 4.6
Revenues (in millions):
From Company generation $ 7.7 $ 8.4 $ 26.7
From sales of purchased power 72.0 77.6 92.9
$79.7 $86.0 $119.6
Decreased sales to nonaffiliated utilities resulted primarily
from decreased demand and continuing price competition. Sales
supplied by the Company's generation in 1994 continued at less
than 15% of 1988 levels because of growth of kWh sales to retail
customers, which reduces the amount available for sale, and
because other suppliers were willing or able to make the sales at
lower prices. A significant factor affecting the Company's
ability to compete in the market for sales to nonaffiliated
utilities has been the approximate 290% increase (from about 67
cents per MWh to $2.60 per MWh) in taxes on generation in West
Virginia since March 1989 a significant cost not experienced
by utilities not generating in West Virginia. Further decreases
in these sales are anticipated.
<PAGE>
M-7
The increase in other revenues in 1994 and 1993 resulted from
continued increases in sales of capacity, energy, and spinning
reserve to other affiliated companies because of additional
capacity and energy available from qualified facilities under the
Public Utility Regulatory Policies Act of 1978 (PURPA). This
increase was offset in part in 1993 by an agreement with the FERC
to record in 1993 about $3 million of revenues as sales to
nonaffiliated utilities. Similar transactions were recorded as
other revenues in prior years. About 90% of the aggregate
benefits from sales to affiliated and nonaffiliated utilities is
passed on to retail customers and has little effect on net
income. About $4 million of other revenues in 1994 were derived
from wholesale customers regulated by the FERC who have the
ability to obtain their electricity requirements from other
suppliers. In the event that these customers were to select
another supplier, the Company would retain transmission revenues
with the result that any net income loss would not be
significant.
Operating Expenses
Fuel expenses increased 4% in 1994 and decreased 3% in 1993,
both primarily due to changes 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.
"Purchased power and exchanges, net" represents power purchases
from and exchanges with nonaffiliated utilities and qualified
facilities under PURPA, capacity charges paid to Allegheny
Generating Company (AGC), and other transactions with affiliates
made pursuant to a power supply agreement whereby each company
uses the most economical generation available in the System at
any given time, and is comprised of the following items:
1994 1993 1992
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other utilities $ 63.7 $ 68.6 $ 85.5
From PURPA generation 68.3 55.7 37.4
Other 9.4 8.1 3.1
Power exchanges, net (.2) (.6) .3
Affiliated transactions:
AGC capacity charges 20.1 23.3 24.2
Energy and spinning reserve charges .5 .5 2.8
$161.8 $155.6 $153.3
The amount of power purchased from nonaffiliated utilities for
use by the Company and for resale to nonaffiliated utilities
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 utilities
from which such purchases are made. The primary reason for the
fluctuations in purchases for resale to nonaffiliated utilities
is described under Sales and Revenues above. 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
<PAGE>
M-8
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 increases in purchases from
PURPA generation reflects additional generation from new PURPA
projects. None of the Company's purchased power contracts is
capitalized since there are no minimum payment requirements
absent associated kWh generation. The 1993 increase in other
purchased power reflects efforts to conserve coal during the UMWA
dispute. Other purchased power continued to increase in 1994
because of increased sales to retail customers combined with
generating unit outages in the first quarter of 1994. Energy and
spinning reserve charges decreased in 1993 primarily because of
additional generation available from PURPA projects.
The increase in other operation expense in 1994 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 expense occurred
because the Company in 1994 discontinued the practice of
deferring SFAS No. 87 pension expense in West Virginia to reflect
the recent rate case decision. Pension expense in 1994 also
includes a charge of $2.5 million for write-off of prior SFAS No.
87 deferrals in West Virginia because recovery of those deferrals
was denied in the most recent rate case. In a continuing effort
to control salary and wage expenses and to improve the overall
efficiency of the Company in a competitive environment, the
Allegheny Power System has an ongoing program to consolidate
various related functions within the System.
The increase in other operation expense for 1993 resulted
primarily from increases in salaries and wages and employee
benefit costs. During 1992, the Company implemented significant
changes to its benefits plans, including cost caps, in an effort
to both control and reduce employee benefit costs. The cost caps
provide for future postretirement medical benefit costs to be
capped at two times 1993 levels. The adoption of SFAS No. 106 in
1993 increased 1993 postretirement benefit expense by
approximately $2 million.
Another FASB standard, SFAS No. 112, "Employers' Accounting for
Postemployment Benefits", effective in 1994, requires companies
to accrue for other postemployment benefits such as disability
benefits, health care benefits for disabled employees, severance
pay, and workers' compensation claims. The Company currently
accrues for workers' compensation claims, and the estimated
liability for the other benefits is not material.
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
<PAGE>
M-9
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. In early January
1994, the Company experienced the worst storm in its history. The
expenses were deferred and are being amortized over a five-year
period beginning in November 1994, concurrent with recovery from
customers. 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, the
amount of work found necessary when the equipment is dismantled,
and outage requirements to comply with the CAAA.
Depreciation expense increases resulted primarily from
additions to electric plant. On November 16, 1994, the Company
declared the Harrison scrubbers available for service and started
depreciation on them amounting to $8 million annually. The 1994
depreciation expense increase was offset in part by a decrease in
depreciation rates in West Virginia of about $7 million annually
effective in November 1994, concurrent with the base rate
increase. 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.
Taxes other than income increased $6 million in 1994 primarily
due to an increase in West Virginia Business and Occupation taxes
resulting from prior period adjustments recorded in 1993 and
1992. The 1993 increase ($1 million) was due primarily to
increases in gross receipts taxes resulting from higher revenues
from retail customers.
The net decrease of $3 million in federal and state income
taxes in 1994 resulted primarily from a decrease in income before
taxes ($2 million) and the reversal of a provision for prior
years which is no longer needed ($2 million). The net increase in
1993 of $6 million resulted primarily from an increase in income
before taxes ($4 million), and an increase in the tax rate due to
the Revenue Reconciliation Act of 1993 ($1 million). Note B to
the financial statements provides a further analysis of income
tax expenses.
The 1994 combined decrease of $3 million in allowances for
funds used during construction (AFUDC), as well as the 1993
combined increase of $2 million, reflect variations in
construction expenditures including those associated with the
CAAA, net of CAAA amounts included in rate base and earning a
cash return. Future levels of AFUDC can be expected to decrease
upon substantial completion of Phase I of the CAAA compliance
program. The changes in other income, net, in 1994 and 1993
resulted primarily from the Company's share of earnings of AGC
(see Note D to the financial statements). Other fluctuations in
other income, net, were individually insignificant. 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.
Liquidity and Capital Resources
SEC regulations define "liquidity" as "the ability of an
enterprise to generate adequate amounts of cash to meet the
enterprise's need for cash". The Company needs cash for operating
expenses, the payment of interest and dividends, retirement of
debt, and for its construction program. To meet these needs, 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.
Capital Requirements
Construction expenditures for 1994 were $104 million and for 1995
and 1996 are estimated at $74 million and $70 million,
respectively. These estimates include $11 million and $2 million,
respectively, for substantial completion of the program of
complying with Phase I of the CAAA. Annual construction
expenditures through 1998, on average, are not expected to
significantly exceed 1995 estimated levels. Construction
expenditure levels in 1999 and beyond will depend upon the
strategy eventually selected for complying with Phase II of the
CAAA, as well as future generation requirements.
The Harrison Scrubber Project was completed on schedule and the
final cost was approximately 24% below the original budget.
Primary factors contributing to the reduced cost include: (1) the
absence of any major construction problems, (2) financing and
material and equipment costs lower than expected, and (3)
favorable rulings of state commissions allowing the inclusion of
carrying costs of construction in rates in lieu of AFUDC. The
possibility of new legislation which could restrict or discourage
carbon dioxide emissions, either through taxation or caps,
further complicates the CAAA Phase II planning process. The
Company has additional capital requirements of 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 $67 million in 1994 compared
with $69 million in 1993. In 1994 the Company financed
<PAGE>
M-10
approximately 64% of its capital expenditure program through
internal cash generation. Based upon the new rate case
authorizations received in 1994 and an Ohio rate case filed in
January 1995, it is expected that close to 100% of the capital
expenditure program can be financed through internal cash
generation in 1995.
Materials and supplies, primarily fuel, constituted a
significant use of cash in 1994 ($6 million). A new five-year
National Bituminous Coal Wage Agreement was signed with the union
in December 1993. System coal inventory declined during the
renegotiations due to selective mine shutdowns, and has returned
to a more appropriate level. December 1992 levels reflected
increases to provide for an adequate coal supply in the event of
a strike.
Financings
During 1994, the Company issued $50 million of $7.73 preferred stock and $8.83
million of tax-exempt solid waste disposal notes to Harrison County, West
Virginia. Due to the significant number of refinancings which have occurred
over the past three years, the balance of debt redemption costs is now
about $11 million. These costs are being amortized over the life
of the associated new bonds. Reduced future interest expense will
more than offset these expenses.
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 $23.6 million to $39.5 million in 1994. In
1992, the Company and its affiliates established 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. The internal money pool has contributed to the
continued low temporary cash investment amounts.
At December 31, 1994, the Company had SEC authorization to
issue up to $100 million of short-term debt. In addition, a
multi-year credit program established in January 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 1994. During 1995, the Company has no
current plans to issue new securities; however, if economic and
market conditions make it desirable, it may refinance up to $300
million of first mortgage bonds, preferred stock, and pollution
control revenue notes. The Company may also engage in additional
Harrison County tax-exempt solid waste disposal financings to the
extent that funds and qualified properties are available.
<PAGE>
M-11
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, and possibly through
alternative financing procedures.
Environmental Matters and Other Contingencies
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
above and under Note K to the financial statements.
The Company previously reported that the Environmental
Protection Agency (EPA) had identified it and its affiliates and
approximately 875 others as potentially responsible parties in a
Superfund site subject to cleanup. A Remedial
Investigation/Feasibility Study prepared by the EPA indicates
remedial alternatives which range as high as $113 million, to be
shared by all responsible parties. The EPA has not yet selected
which remedial alternatives it will use. The Company believes it
has defenses to allegations of liability and intends to
vigorously defend this matter. Although it is not possible at
this time to determine what costs, if any, the Company may incur,
it has recorded provisions for liabilities based on the range of
remediation cost estimates and its relative participation, along
with the approximately 875 others. The Company believes that
provisions for liabilities and insurance recoveries are such that
final resolution of this matter will not have a material effect
on its financial position.
The Company has been named as a defendant along with multiple
other defendants in 1,625 pending asbestos cases involving one or
more plaintiffs, and the Company and its affiliates have been
named as defendants along with multiple other defendants in an
additional 716 cases by one or more plaintiffs. Because these
cases are filed by "shotgun" complaints naming many plaintiffs
and many defendants, it is currently impossible to determine the
actual number of claims against the Company and its affiliates.
However, based on past experience and data available to date, it
is estimated that less than 500 cases actually involve claims
against the Company or its affiliates. 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. All plaintiffs claiming exposure at
<PAGE>
M-12
System-operated stations were employed by third-party
contractors, with the exception of three known plaintiffs who
claim to have been employees of the Company. 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 that 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 of the multiple defendants, the Company believes its
potential liability is a very small percentage of the total
amount of the damages sought. A total of 94 cases have been
previously settled by the Company for an amount substantially
less than the anticipated cost of defense. The Company believes
that the remaining cases involving it are also without merit and
that provisions for liabilities and insurance recoveries are such
that these suits will not have a material effect on its financial
position.
<PAGE>
M-13
Potomac Edison
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Net Income
Net income was $98.5 million in 1994, including $16.5 million
of non-recurring income from the cumulative effect of an
accounting change to record unbilled revenues. Net income was
$73.5 million and $67.5 million in 1993 and 1992, respectively.
The 1994 and 1993 increases in net income resulted primarily from
kWh sales and retail rate increases. These revenue increases, in
both years, were offset in part by higher expenses.
The subject of competition for customers, particularly
industrial customers, has been receiving a lot of attention. In
1994 the Maryland commission started a proceeding described as an
inquiry into the subject, which is still in progress. The inquiry
is not expected to result in immediately meaningful changes in
current relations with our customers. All customers, except
wholesale customers regulated by the Federal Energy Regulatory
Commission (FERC), continue to be required to purchase their
electricity requirements from the utility in whose franchised
territory they reside. This is not to say that competition does
not exist. Utilities continue to compete for the siting of new
industrial and commercial customers, to retain existing customers
in the franchised territory, and, for those businesses with
multiple plants in multiple territories, to maintain or shift
their production to local facilities. As in the past, electric
utilities continue to compete with suppliers of other forms of
energy. Because the Company is the lowest or among the lowest
cost suppliers of electricity in its region, it should not
experience the competitive concerns of other utilities who use
cost-based pricing. However, the Company continues to face
competition from utilities with excess generation that are
willing to sell at prices intended only to recover variable
costs.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and
industrial customers are shown on pages 16 and 17. Such kWh sales
increased 2.3% and 6.3% in 1994 and 1993, respectively. The
increases in revenues from sales to residential, commercial, and
industrial customers resulted from the following:
Increase from Prior Year
1994 1993
(Millions of Dollars)
Increased kWh sales $10.3 $24.4
Fuel and energy cost adjustment clauses* 18.6 19.1
Rate increases:
Maryland 11.9 12.7
Virginia 8.5 2.5
West Virginia 1.9 1.1
22.3 16.3
Other 1.0 2.9
$52.2 $62.7
* Changes in revenues from fuel and energy cost adjustment
clauses have little effect on net income.
<PAGE>
M-14
The increased kWh sales in 1994 reflect growth in the number of
customers and higher use by industrial customers. The 1994
residential use was down slightly from 1993 levels reflecting a
decrease in both heating and cooling degree days. The increased
kWh sales to residential and commercial customers in 1993 reflect
both higher use and growth in number of customers. While 1993
heating degree days showed only a slight increase over 1992, and
were only 7% above normal, cooling degree days increased 82% over
1992 and were 12% over normal, contributing to the 1993 kWh sales
increases.
Rate case decisions in all retail jurisdictions, representing
revenue increases in excess of $33 million on an annual basis,
were issued for the Company in 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
expense.
KWh sales to industrial customers increased 2.8% in 1994 and
4.3% in 1993. The increase in both years occurred in almost all
industrial groups, the most significant of which in 1994 was from
rubber and plastics customers (61 gigawatt-hours [GWh], 22%) and
in 1993 was from cement customers (59 GWh, 12%).
KWh sales to and revenues from nonaffiliated utilities are
comprised of the following items:
1994 1993 1992
KWh sales (in billions):
From Company generation .3 .4 1.0
From purchased power 2.9 3.5 4.4
3.2 3.9 5.4
Revenues (in millions):
From Company generation $ 8.9 $ 8.6 $ 27.5
From sales of purchased power 98.1 99.5 113.6
$107.0 $108.1 $141.1
Decreased sales to nonaffiliated utilities resulted primarily
from decreased demand and continuing price competition. Sales
supplied by the Company's generation in 1994 continued at less
than 15% of 1988 levels because of continuing growth of kWh sales
to retail customers, which reduces the amount available for sale,
and because other suppliers were willing or able to make the
sales at lower prices. A significant factor affecting the
Company's ability to compete in the market for sales to
nonaffiliated utilities has been the approximate 290% increase
(from about 67 cents MWh to $2.60 per MWh) in taxes on generation
in West Virginia since March 1989 - a significant cost not
experienced by utilities not generating in West Virginia. Further
decreases in these sales are anticipated. About 95% of the
aggregate benefits from sales to nonaffiliated utilities is
passed on to retail customers and has little effect on net
income.
<PAGE>
M-15
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. A final order for the 1993 case has been received and
refunds will be made to customers in early 1995. Commission
approval of a settlement agreement for the 1994 request is
pending. About $23 million of other revenues in 1994 were derived
from wholesale customers regulated by the FERC who have the
ability to obtain their electricity requirements from other
suppliers. In the event that these customers were to select
another supplier, the Company would retain transmission service
revenues.
The decrease in other revenues in 1993 resulted from an
agreement with the FERC to record in 1993 about $4 million of
revenues as sales to nonaffiliated utilities. Similar
transactions were recorded as other revenues in prior years.
Operating Expenses
Fuel expenses increased 1% in 1994 and decreased 4% in 1993,
both primarily due to changes 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. "Purchased power and exchanges, net" represents power
purchases from and exchanges with nonaffiliated utilities,
capacity charges paid to Allegheny Generating Company (AGC), and
other transactions with affiliates made pursuant to a power
supply agreement whereby each company uses the most economical
generation available in the System at any given time, and is
comprised of the following items:
1994 1993 1992
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other
utilities $ 86.5 $ 87.9 $104.6
Other 12.7 10.5 3.7
Power exchanges, net (.2) (.8) .2
Affiliated transactions:
AGC capacity charges 29.4 28.0 29.6
Other affiliated capacity
charges 37.6 28.4 21.9
Energy and spinning reserve
charges 51.1 51.1 41.2
$217.1 $205.1 $201.2
The amount of power purchased from nonaffiliated utilities for
use by the Company and for resale to nonaffiliated utilities
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 utilities
from which such purchases are made. The primary reason for the
fluctuations in purchases for resale to nonaffiliated utilities
is described under Sales and Revenues above. 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
<PAGE>
M-16
subject to deferred power cost procedures with the result that
changes in such costs have little effect on net income. The 1993
increase in other purchased power reflects efforts to conserve
coal because of selective work stoppages by the United Mine
Workers of America for most of the year. Other purchased power
continued to increase in 1994 because of increased sales to
retail customers combined with generating unit outages in the
first quarter of 1994. While the Company does not currently
purchase generation from qualified facilities under the Public
Utility Regulatory Policies Act of 1978 (PURPA), several projects
have been proposed, and an agreement has been reached with one
facility to commence purchasing generation in 1999. This project
and others may significantly increase the cost of power purchases
passed on to customers. The increase in affiliated capacity in
1994 and 1993 and energy and spinning reserve charges in 1993 was
due to growth of kWh sales to retail customers and an increase in
affiliated energy available because of energy purchased by an
affiliate from PURPA projects. The increase in other operation
expense in 1994 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. In a continuing effort to control salary
and wage expenses and to improve the overall efficiency of the
Company in a competitive environment, the Allegheny Power System
has an ongoing program to consolidate various related functions
within the System. The increase in pension expense occurred
because the Company in 1994 discontinued the practice of
deferring SFAS No. 87 pension expense in West Virginia to reflect
a recent rate case decision. Pension expense in 1994 also
includes a charge of $.9 million for write-off of prior SFAS No.
87 deferrals in Virginia and West Virginia because recovery of
those deferrals was denied in the most recent rate cases.
During 1992, the Company implemented significant changes to its
benefits plans, including cost caps, in an effort to both control
and reduce employee benefits costs. The cost caps provide for
future postretirement medical benefit costs to be capped at two
times 1993 levels. Approximately $.6 million of the increase in
postretirement benefit expenses for 1994 was due to the 1993 cost
cap being greater than actuarily projected. The adoption of SFAS
No. 106 in 1993 increased 1993 postretirement benefit expense by
approximately $1.5 million. The increase in other operation
expense for 1993 resulted primarily from increases in employee
benefit costs and salaries and wages.
Another FASB standard, SFAS No. 112, "Employers' Accounting for
Postemployment Benefits", effective in 1994, requires companies
to accrue for other postemployment benefits such as disability
benefits, healthcare benefits for disabled employees, severance
<PAGE>
M-17
pay, and workers' compensation claims. The Company currently
accrues for workers' compensation claims, and the estimated
liability for the other benefits is not material.
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, the amount of work found necessary when
the equipment is dismantled, and outage requirements to comply
with the CAAA.
Depreciation expense increases resulted primarily from
additions to electric plant. On November 16, 1994, the Company
declared the Harrison scrubbers available for service and started
depreciation on them amounting to $10 million annually.
Taxes other than income increased $1 million in 1993 due to
increases in gross receipts taxes resulting from higher revenues
from retail customers ($1 million) and increased property taxes
($1 million), offset by decreased West Virginia Business and
Occupation taxes due to decreased generation in that state ($1
million).
The net increase of $3 million in federal and state income
taxes in 1994 resulted primarily from an increase in income
before taxes. The net increase in 1993 of $2 million in federal
and state income taxes resulted primarily from an increase in
income before taxes ($3 million) and an increase in the tax rate
due to the Revenue Reconciliation Act of 1993 ($1 million),
offset by plant removal tax deductions for which deferred taxes
were not provided ($1 million). Note B to the financial
statements provides a further analysis of income tax expenses.
The 1994 combined decrease of $1 million in allowances for
funds used during construction (AFUDC), as well as the 1993
combined increase of $2 million, reflect variations in
construction expenditures including those associated with the
CAAA, net of CAAA amounts included in rate base and earning a
cash return. Future levels of AFUDC can be expected to decrease
upon substantial completion of Phase I of the CAAA compliance
program. The changes in other income, net, in 1994 and 1993
resulted primarily from the Company's share of earnings of AGC
(see Note D to the financial statements) and in 1994 also from
lost revenue and interest income for demand-side management
programs. Other fluctuations in other income, net, were
individually insignificant. 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.
<PAGE>
M-18
Liquidity and Capital Resources
SEC regulations define "liquidity" as "the ability of an
enterprise to generate adequate amounts of cash to meet the
enterprise's need for cash". The Company needs cash for operating
expenses, the payment of interest and dividends, retirement of
debt and certain preferred stock, and for its construction
program. To meet these needs, 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.
During 1994, the Company continued its participation in the
Collaborative Process for Demand-Side Management in Maryland.
Through December 31, 1994, the Company had received applications
for $16.1 million in rebates related to the commercial lighting
program. Program costs, including rebates and lost revenues, are
deferred and are to be recovered through an energy conservation
surcharge over a seven-year period.
Capital Requirements
Construction expenditures for 1994 were $143 million and for
1995 and 1996 are estimated at $92 million and $98 million,
respectively. These estimates include $12 million and $5 million,
respectively, for substantial completion of the program of
complying with Phase I of the CAAA. Annual construction
expenditures through 1998, on average, are not expected to
significantly exceed 1995 estimated levels. Construction
expenditure levels in 1999 and beyond will depend upon the
strategy eventually selected for complying with Phase II of the
CAAA, as well as future generation requirements.
The Harrison Scrubber Project was completed on schedule and the
final cost was approximately 24% below the original budget.
Primary factors contributing to the reduced cost include: (1) the
absence of any major construction problems, (2) financing and
material and equipment costs lower than expected, and (3)
favorable rulings of state commissions allowing the inclusion of
carrying costs of construction in rates in lieu of AFUDC. The
possibility of new legislation which could restrict or discourage
carbon dioxide emissions, either through taxation or caps,
further complicates the CAAA Phase II planning process. The
Company has additional annual capital requirements of an annual
preferred stock sinking fund ($1.2 million) and debt maturities
(see Note I to the financial statements).
<PAGE>
M-19
Internal Cash Flows
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $67 million in 1994 compared
with $75 million in 1993. In 1994 the Company financed
approximately 47% of its capital expenditure program through
internal cash generation. Based upon the new rate case
authorizations received in 1994, it is expected that close to
100% of the capital expenditure program can be financed through
internal cash generation in 1995.
Materials and supplies, primarily fuel, constituted a
significant use of cash in 1994 ($5 million). A new five-year
National Bituminous Coal Wage Agreement was signed with the union
in December 1993. System coal inventory declined during the
renegotiations due to selective mine shutdowns, and has returned
to a more appropriate level. December 1992 levels reflected
increases to provide for an adequate coal supply in the event of
a strike.
Financings
During 1994, the Company issued $75 million of 8% first
mortgage bonds and $11.56 million of tax-exempt solid waste
disposal notes to Harrison County, West Virginia. Due to the
significant number of refinancings which have occurred over the
past three years, the balance of debt redemption costs is now
about $8 million. These costs are being amortized over the life
of the associated new bonds. Reduced future interest expense will
more than offset these expenses.
Short-term debt is used to meet temporary cash needs until the
timing is considered appropriate to issue long-term securities.
In 1992, the Company and its affiliates established 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. The internal money pool has contributed to the
continued low temporary cash investment amounts.
At December 31, 1994, the Company had SEC authorization to
issue up to $115 million of short-term debt. In addition, a
multi-year credit program established in January 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 1994. During 1995, the Company has no
current plans to issue new securities; however, if economic and
market conditions make it desirable, it may refinance up to $231
million of first mortgage bonds, preferred stock, and pollution
control revenue notes. The Company may also engage in addi-
tional Harrison County tax-exempt solid waste disposal financings
to the extent that funds and qualified properties are available.
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, and possibly through
alternative financing procedures.
<PAGE>
M-20
Environmental Matters and Other Contingencies
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
above and under Note K to the financial statements.
The Company previously reported that the Environmental
Protection Agency (EPA) had identified it and its affiliates and
approximately 875 others as potentially responsible parties in a
Superfund site subject to cleanup. A Remedial
Investigation/Feasibility Study prepared by the EPA indicates
remedial alternatives which range as high as $113 million, to be
shared by all responsible parties. The EPA has not yet selected
which remedial alternatives it will use. The Company believes it
has defenses to allegations of liability and intends to
vigorously defend this matter. Although it is not possible at
this time to determine what costs, if any, the Company may incur,
it has recorded provisions for liabilities based on the range of
remediation cost estimates and its relative participation, along
with the approximately 875 others. The Company believes that
provisions for liabilities and insurance recoveries are such that
final resolution of this matter will not have a material effect
on its financial position.
Monongahela Power Company (MP), an affiliated company, has been
named as a defendant along with multiple other defendants in
1,625 pending asbestos cases involving one or more plaintiffs,
and the Company and its affiliates have been named as defendants
along with multiple other defendants in an additional 716 cases
by one or more plaintiffs. Because these cases are filed by
"shotgun" complaints naming many plaintiffs and many defendants,
it is currently impossible to determine the actual number of
claims against the Company and its affiliates. However, based on
past experience and data available to date, it is estimated that
less than 500 cases actually involve claims against the Company
or its affiliates. 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. All plaintiffs claiming exposure at System-operated
stations were employed by third-party contractors, with the
exception of three known plaintiffs who claim to have been
employees of MP. The Company is joint owner with MP in five
generating plants, including four operated by MP in West
Virginia. 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 that 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 of the multiple defendants, the Company
believes its potential liability is a very small percentage of
the total amount of the damages sought. A total of 94 cases have
been previously settled by MP for an amount substantially less
than the anticipated cost of defense. The Company believes that
the remaining cases involving it are also without merit and that
provisions for liabilities and insurance recoveries are such that
these suits will not have a material effect on its financial
position.
<PAGE>
M-21
West Penn
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
Consolidated Net Income
Consolidated net income was $120.0 million in 1994, including
$19.0 million of non-recurring income from the cumulative effect
of an accounting change to record unbilled revenues. The 1994
results also reflect the write-off ($5.2 million after tax) of
previously accumulated costs related to future facilities no
longer considered meaningful in the industry's more competitive
environment. Consolidated net income was $102.1 million and $98.2
million in 1993 and 1992, respectively. The 1994 and 1993
increases in consolidated net income resulted primarily from kWh
sales and retail rate increases. These revenue increases, in both
years, were offset in part by higher expenses.
The subject of competition for customers, particularly
industrial customers, has been receiving a lot of attention. In
1994 the Pennsylvania commission initiated an investigation into
the subject, which is still in progress. The inquiry is not
expected to result in immediately meaningful changes in current
relations with our customers. All customers, except wholesale
customers regulated by the Federal Energy Regulatory Commission
(FERC), continue to be required to purchase their electricity
requirements from the utility in whose franchised territory they
reside. This is not to say that competition does not exist.
Utilities continue to compete for the siting of new industrial
and commercial customers, to retain existing customers in the
franchised territory, and, for those businesses with multiple
plants in multiple territories, to maintain or shift their
production to local facilities. As in the past, electric
utilities continue to compete with suppliers of other forms of
energy. Because the Company is the lowest or among the lowest
cost suppliers of electricity in its region, it should not
experience the competitive concerns of other utilities who use
cost-based pricing. However, the Company continues to face
competition from utilities with excess generation that are
willing to sell at prices intended only to recover variable costs.
Sales and Revenues
KWh sales to and revenues from residential, commercial, and
industrial customers are shown on pages 16 and 17. Such kWh sales
increased 2.9% and 3.1% in 1994 and 1993, respectively. The
increases in revenues from sales to residential, commercial, and
industrial customers resulted from the following:
Increase from Prior Year
1994 1993
(Millions of Dollars)
Increased kWh sales $ 9.4 $15.5
Fuel and energy cost
adjustment clauses* 16.8 26.2
Rate increases 22.7 25.2
Other 2.3 3.1
$51.2 $70.0
* Changes in revenues from fuel and energy cost adjustment
clauses have little effect on consolidated net income.
<PAGE>
M-22
The increased kWh sales to residential and commercial customers
in 1994 and 1993 reflect growth in number of customers and higher
commercial use. Residential usage increased in 1994 despite a
decrease in both heating and cooling degree days. While 1993
heating degree days remained about the same as 1992, and were
only 6% below normal, cooling degree days increased 70% over 1992
and were 46% over normal, contributing to the 1993 kWh sales
increases.
Rate case decisions in all jurisdictions, representing revenue
increases in excess of $57 million on an annual basis, were
issued for the Company in 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. Rate increases also include a $61.6 million annual base
rate increase in Pennsylvania effective May 18, 1993, including
$26.1 million for recovery of carrying charges on CAAA compliance
costs.
KWh sales to industrial customers increased 4.4% in 1994 and
.8% in 1993. The 1994 increase occurred in almost all industrial
groups, particularly paper, printing and publishing (118
gigawatt-hours [GWh], 47.4%); fabricated metals (72 GWh, 6.9%);
and iron and steel customers (53 GWh, 2.1%). The relatively flat
industrial sales growth in 1993 included one particular group,
coal mines staffed by union personnel, which recorded reduced
usage because of selective work stoppages by the United Mine
Workers of America (UMWA) for most of the year prior to the
settling of the dispute in December 1993.
KWh sales to and revenues from nonaffiliated utilities are
comprised of the following items:
1994 1993 1992
KWh sales (in billions):
From Company generation .5 .4 1.3
From purchased power 3.8 5.0 6.5
4.3 5.4 7.8
Revenues (in millions):
From Company generation $ 12.3 $ 11.5 $ 37.5
From sales of purchased power 132.5 141.0 167.2
$144.8 $152.5 $204.7
Decreased sales to nonaffiliated utilities resulted primarily
from decreased demand and continuing price competition. Sales
supplied by the Company's generation in 1994 continued at less
than 15% of 1988 levels because of continuing growth of kWh sales
to retail customers, which reduces the amount available for sale,
and because other suppliers were willing or able to make the
sales at lower prices. A significant factor affecting the
Company's ability to compete in the market for sales to
nonaffiliated utilities has been the approximate 290% increase
(from about 67 cents per MWh to $2.60 per MWh) in taxes on
generation in West Virginia since March 1989 - a significant cost
not experienced by utilities not generating in West Virginia.
Further decreases in these sales are anticipated.
<PAGE>
M-23
The decrease in other revenues in 1994 and 1993 resulted from
continued decreases in sales of energy and spinning reserve to an
affiliated company because of additional energy available to it
from qualified facilities under the Public Utility Regulatory
Policies Act of 1978 (PURPA). The 1993 decrease was also due in
part to an agreement with the FERC to record in 1993 about $6
million of revenues as sales to nonaffiliated utilities. Similar
transactions were recorded as other revenues in prior years. Most
of the aggregate benefits from sales to affiliated and
nonaffiliated utilities is passed on to retail customers and has
little effect on consolidated net income. About $19 million of
other revenues in 1994 were derived from wholesale customers
regulated by the FERC who have the ability to obtain their
electricity requirements from other suppliers. In 1994, these
customers signed seven-year contracts to remain as customers.
Operating Expenses
Fuel expenses decreased 2% in 1994 and 4% in 1993 primarily due
to decreases 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 utilities and qualified facilities under PURPA,
capacity charges paid to AGC, and other transactions with
affiliates made pursuant to a power supply agreement whereby each
company uses the most economical generation available in the
System at any given time, and is comprised of the following
items:
1994 1993 1992
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other utilities $116.9 $124.5 $153.9
From PURPA generation 65.7 49.6 56.5
Other 18.3 15.2 5.9
Power exchanges, net (.2) (1.2) .3
Affiliated transactions:
AGC capacity charges 37.2 42.3 43.5
Energy and spinning
reserve charges 8.6 4.7 3.5
Other affiliated
capacity charges .7 .7 .6
$247.2 $235.8 $264.2
The amount of power purchased from nonaffiliated utilities for
use by the Company and for resale to nonaffiliated utilities
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 utilities
from which such purchases are made. The primary reason for the
fluctuations in purchases for resale to nonaffiliated utilities
is described under Sales and Revenues above. 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
<PAGE>
M-24
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. The decrease in
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.
The 1993 increase in other purchased power reflects efforts to
conserve coal during the UMWA dispute. Other purchased power
continued to increase in 1994 because of increased sales to
retail customers combined with generating unit outages in the
first quarter of 1994.
The increase in other operation expense in 1994 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 provisions for environmental liabilities ($1
million). Allowances for uncollectible accounts were increased
due to an increase in aged outstanding receivables caused by
customers taking advantage of rate regulations which make it
difficult if not impossible to curtail service to non-paying
customers during the winter months. In a continuing effort to
control salary and wage expenses and to improve the overall
efficiency of the Company in a competitive environment, the
Allegheny Power System has an ongoing program to consolidate
various related functions within the System. The increase in
pension expense occurred because the Company in 1994 discontinued
the practice of deferring SFAS No. 87 pension expense to reflect
a recent rate case decision.
During 1992, the Company implemented significant changes to its
benefits plans, including cost caps, in an effort to both control
and reduce employee benefit costs. The cost caps provide for
future post-retirement medical benefit costs to be capped at two
times 1993 levels. Approximately $.3 million of the increase in
postretirement benefit expenses for 1994 was due to the 1993 cost
cap being greater than actuarily projected. The adoption of SFAS
No. 106 in 1993 increased 1993 postretirement benefit expenses by
approximately $3 million. The increase in other operation expense
for 1993 resulted primarily from increases in salaries and wages
and employee benefit costs. Another FASB standard, SFAS No.
112, "Employers' Accounting for Postemployment Benefits",
effective in 1994, requires companies to accrue for other
postemployment benefits such as disability benefits, health care
benefits for disabled employees, severance pay, and workers'
compensation claims. The Company currently accrues for workers'
compensation claims, and the estimated liability for the other
benefits is not material.
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
<PAGE>
M-25
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, the amount of work found necessary when
the equipment is dismantled, and outage requirements to comply
with the CAAA. Maintenance expense in 1993 includes the effects
of an ice storm and blizzard in March 1993.
Depreciation expense increases resulted primarily from
additions to electric plant and from a change in depreciation
rates and net salvage amortization in May 1993. On November 16,
1994, the Company declared the Harrison scrubbers available for
service and started depreciation on them amounting to $14 million
annually.
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 resulting from higher revenues from retail
customers ($2 million). The 1993 increase ($2 million) was
primarily due to increases in gross receipts taxes ($3 million)
offset by decreased West Virginia B&O taxes ($2 million).
The net decrease of $1 million in federal and state income
taxes in 1994 resulted primarily from plant removal cost tax
deductions for which deferred taxes were not provided. The net
increase in 1993 of $7 million resulted primarily from an
increase in income before taxes ($6 million), and an increase in
the tax rate due to the Revenue Reconciliation Act of 1993 ($1
million). Note B to the consolidated financial statements
provides a further analysis of income tax expenses.
The 1994 combined increase of $2 million in allowances for
funds used during construction (AFUDC), reflects increased
construction expenditures including those associated with the
CAAA, net of CAAA amounts included in rate base and earning a
cash return. Future levels of AFUDC can be expected to decrease
upon substantial completion of Phase I of the CAAA compliance
program. Other income and deductions in 1994 reflect the
write-off of $5.2 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. The changes in other income, net, in 1994 and 1993
resulted primarily from the Company's share of earnings of AGC
(see Note D to the consolidated financial statements). Other
fluctuations in other income, net, were individually
insignificant. Other interest expense reflects change in the
levels of short-term debt maintained by the Company throughout
the year, as well as the associated interest rates.
<PAGE>
M-26
Liquidity and Capital Resources
SEC regulations define "liquidity" as "the ability of an
enterprise to generate adequate amounts of cash to meet the
enterprise's need for cash". The Company needs cash for operating
expenses, the payment of interest and dividends, retirement of
debt, and for its construction program. To meet these needs, 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.
Capital Requirements
Construction expenditures for 1994 were $260 million and for 1995
and 1996 are estimated at $172 million and $115 million,
respectively. These estimates include $38 million and $1 million,
respectively, for substantial completion of the program of
complying with Phase I of the CAAA. Annual construction
expenditures through 1998, on average, are not expected to
significantly vary from 1995 estimated levels. Construction
expenditure levels in 1999 and beyond will depend upon the
strategy eventually selected for complying with Phase II of the
CAAA, as well as future generation requirements.
The Harrison Scrubber Project was completed on schedule and the
final cost was approximately 24% below the original budget.
Primary factors contributing to the reduced cost include: (1) the
absence of any major construction problems, (2) financing and
material and equipment costs lower than expected, and (3)
favorable ruling of the Pennsylvania PUC allowing the inclusion
of carrying costs of construction in rates in lieu of AFUDC. The
possibility of new legislation which could restrict or discourage
carbon dioxide emissions, either through taxation or caps,
further complicates the CAAA Phase II planning process. The
Company has additional capital requirements of 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 $109 million in 1994
compared with $119 million in 1993. In 1994 the Company financed
approximately 42% of its capital expenditure program through
internal cash generation. Based upon the new rate case
authorizations received in 1994, it is expected that close to
100% of the capital expenditure program can be financed through
internal cash generation in 1995.
<PAGE>
M-27
Materials and supplies, primarily fuel, constituted a
significant use of cash in 1994 ($9 million). A new five-year
National Bituminous Coal Wage Agreement was signed with the union
in December 1993. System coal inventory declined during the
renegotiations due to selective mine shutdowns, and has returned
to a more appropriate level. December 1992 levels reflected
increases to provide for an adequate coal supply in the event of
a strike.
Financings
During 1994 the Company issued $65 million of 8-1/8% first
mortgage bonds and $14.91 million of tax-exempt solid waste
disposal notes to Harrison County, West Virginia. Due to the
significant number of refinancings which have occurred over the
past three years, the balance of debt redemption costs is now
about $10 million. These costs are being amortized over the life
of the associated new bonds. Reduced future interest expense will
more than offset these expenses.
Short-term debt is used to meet temporary cash needs until the
timing is considered appropriate to issue long-term securities.
In 1992, the Company and its affiliates established 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. The internal money pool has contributed to the
continued low temporary cash investment amounts.
At December 31, 1994, the Company had SEC authorization to
issue up to $170 million of short-term debt. In addition, a
multi-year credit program established in January 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 1994. During 1995, the Company has no
current plans to issue new securities; however, if economic and
market conditions make it desirable, it may refinance up to
$251.5 million of first mortgage bonds, preferred stock, and
pollution control revenue notes. The Company may also engage in
additional Harrison County tax-exempt solid waste disposal
financings to the extent that funds and qualified properties are
available.
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, and possibly through
alternative financing procedures.
Environmental Matters and Other Contingencies
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
<PAGE>
M-28
the regulatory process, laws, regulations and uncertainties
related to environmental matters, and legal actions.
Contingencies and uncertainties related to the CAAA are discussed
above and under Note K to the consolidated financial statements.
The Company previously reported that the Environmental
Protection Agency (EPA) had identified it and its affiliates and
approximately 875 others as potentially responsible parties in a
Superfund site subject to cleanup. A Remedial
Investigation/Feasibility Study prepared by the EPA indicates
remedial alternatives which range as high as $113 million, to be
shared by all responsible parties. The EPA has not yet selected
which remedial alternatives it will use. The Company believes it
has defenses to allegations of liability and intends to
vigorously defend this matter. Although it is not possible at
this time to determine what costs, if any, the Company may incur,
it has recorded provisions for liabilities based on the range of
remediation cost estimates and its relative participation, along
with the approximately 875 others. The Company believes that
provisions for liabilities and insurance recoveries are such that
final resolution of this matter will not have a material effect
on its financial position.
Monongahela Power Company (MP), an affiliated company, has been
named as a defendant along with multiple other defendants in
1,625 pending asbestos cases involving one or more plaintiffs,
and the Company and its affiliates have been named as defendants
along with multiple other defendants in an additional 716 cases
by one or more plaintiffs. Because these cases are filed by
"shotgun" complaints naming many plaintiffs and many defendants,
it is currently impossible to determine the actual number of
claims against the Company and its affiliates. However, based on
past experience and data available to date, it is estimated that
less than 500 cases actually involve claims against the Company
or its affiliates. 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. All plaintiffs claiming exposure at System-operated
stations were employed by third-party contractors, with the
exception of three known plaintiffs who claim to have been
employees of MP. The Company is joint owner with MP in four
generating plants, including three operated by MP in West
Virginia. 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 that include
a spousal claim for loss of consortium, damages are generally
<PAGE>
M-29
sought against all defendants in an amount of up to an additional
$1 million. Because of the multiple defendants, the Company
believes its potential liability is a very small percentage of
the total amount of the damages sought. A total of 94 cases have
been previously settled by MP for an amount substantially less
than the anticipated cost of defense. The Company believes that
the remaining cases involving it are also without merit and that
provisions for liabilities and insurance recoveries are such that
these suits will not have a material effect on its financial
position.
<PAGE>
M-30
AGC
MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Results of Operations
As described under Liquidity and Capital Resources, 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 1994 increased primarily
because of the return on equity settlement which resulted in an
adjustment of prior period provisions for rate refunds. Revenues
for 1993 decreased due to a reduction in interest charges and net
investment, and reduced operating expenses which are described
below. Additionally, revenues for 1993 were reduced by the
recording of estimated liabilities for possible refunds pending
final Federal Energy Regulatory Commission (FERC) decisions in
rate case proceedings (see Liquidity and Capital Resources).
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 operating
expenses in 1993 resulted from a decrease in federal income taxes
due to a decrease in income before taxes ($1.9 million) offset by
an increase in the tax rate due to the Revenue Reconciliation Act
of 1993 ($.5 million), partially offset by an increase in
operation and maintenance expense.
The decreases in interest on long-term debt in 1994 and 1993
were the combined result of decreases in the average amount of
and interest rates on long-term debt outstanding. The increase
in other interest in 1994 was due to amortization of the premium
paid to refund debentures in 1993. Liquidity and Capital
Resources SEC regulations define "liquidity" as "the ability of
an enterprise to generate adequate amounts of cash to meet the
enterprise's need for cash". 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 present 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, depreciation, taxes, and a return on its investment.
<PAGE>
M-31
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 argues 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 is currently pending, which would reduce
the Company's ROE to 11.13% for the period from March 1, 1992,
through December 31, 1994, and increase the Company's ROE to
11.20% for the period from January 1, 1995, through December 31,
1995. During 1995, the parties have agreed to negotiate in good
faith to approve a mechanism for setting ROE in the future. This
settlement is subject to FERC approval. If approved, this
settlement will require a refund to customers for the period
through December 31, 1994, of about $4.42 million for which
adequate reserves have been provided.
Through a filing completed on October 31, 1994, the Company
sought to add a prior tax payment of approximately $12 million to
rate base which will produce about $1.4 million in additional
annual revenues. On December 30, 1994, the FERC accepted the
Company's filing, ordered that the increase in rates go into
effect on June 1, 1995, subject to refund, and set the Company's
ROE for hearing in 1995. A settlement agreement is currently
pending. This settlement is subject to FERC approval.
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>
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 F-1 F-17 F-34 F-51 F-68
Statement of Income for F-2 F-18 F-35 F-52 F-69
the three years ended
December 31, 1994
Statement of Retained Earnings - F-19 F-36 F-53 F-70
for the three years ended
December 31, 1994
Statement of Cash Flows for F-3 F-20 F-37 F-54 F-71
the three years ended
December 31, 1994
Balance Sheet at December 31, F-4 F-21 F-38 F-55 F-72
1994 and 1993
Statement of Capitalization at F-5 F-22 F-39 F-56 F-73
December 31, 1994 and 1993
Statement of Common Equity for F-6 - - - -
the three years ended
December 31, 1994
Notes to financial statements F-7 F-23 F-40 F-57 F-74
Financial Statement Schedules -
Schedules - for the three years
ended December 31, 1994
II Valuation and qualifying
accounts S-1 S-2 S-3 S-4 -
All other schedules are omitted because they are not applicable or the required information is shown in the
Financial Statements or Notes thereto.
</TABLE>
<PAGE>
F-1
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, 1994 and 1993, and the results of
their operations and their cash flows for each of the three years
in the period ended December 31, 1994, 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 Notes A, B and E to the consolidated financial
statements, the Company changed its method of accounting for
revenue recognition in 1994 and for income taxes and postretirement
benefits other than pensions in 1993.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 2, 1995
<PAGE>
F-2
APS
CONSOLIDATED STATEMENT OF INCOME
Year ended December 31
(Dollar amounts in thousands except for per share data)
1994 1993 1992
Electric Operating Revenues:
Residential $ 863 725 $ 818 400 $ 734 874
Commercial 459 303 430 202 391 912
Industrial 728 009 673 418 637 656
Nonaffiliated utilities 331 557 346 705 465 491
Other 69 090 62 801 76 725
TOTAL OPERATING REVENUES 2 451 684 2 331 526 2 306 658
Operating Expenses:
Operation:
Fuel 547 241 544 659 567 833
Purchased power and exchanges, net 440 880 417 449 451 408
Deferred power costs, net (Note A) 11 805 (11 462) 89
Other 285 010 257 732 232 672
Maintenance 241 913 231 163 210 878
Depreciation 223 883 210 428 197 763
Taxes other than income taxes 183 060 178 788 174 578
Federal and state income taxes (Note B) 129 751 128 130 115 373
TOTAL OPERATING EXPENSES 2 063 543 1 956 887 1 950 594
OPERATING INCOME 388 141 374 639 356 064
Other Income and Deductions:
Allowance for other than borrowed funds
used during construction (Note A) 11 966 12 499 10 221
Asset write-off, net (Note A) (5 338)
Other income, net 1 510 (6) 1 265
TOTAL OTHER INCOME AND DEDUCTIONS 8 138 12 493 11 486
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 396 279 387 132 367 550
Interest Charges and Preferred Dividends:
Interest on long-term debt 153 668 157 449 147 427
Other interest 10 394 5 812 5 672
Allowance for borrowed funds used during
construction (Note A) (7 630) (8 983) (7 331)
Dividends on preferred stock of
subsidiaries 20 096 17 098 18 235
TOTAL INTEREST CHARGES AND PREFERRED
DIVIDENDS 176 528 171 376 164 003
Consolidated Income Before Cumulative
Effect of Accounting Change 219 751 215 756 203 547
Cumulative Effect of Accounting Change,
net (Note A) 43 446
Consolidated Net Income $ 263 197 $ 215 756 $ 203 547
Common Stock Shares Outstanding
(average) (Note G) 118 272 373 114 937 032 111 226 318
Earnings Per Average Share (Note G):
Consolidated income before cumulative
effect of accounting change $1.86 $1.88 $1.83
Cumulative effect of accounting
change, net (Note A) .37
Consolidated net income $2.23 $1.88 $1.83
See accompanying notes to consolidated financial statements.
<PAGE>
<TABLE>
<CAPTION>
F-3
CONSOLIDATED STATEMENT OF CASH FLOWS
Year ended December 31
1994 1993 1992
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Consolidated net income $263 197 $215 756 $203 547
Depreciation 223 883 210 428 197 763
Deferred investment credit and income
taxes, net 25 684 (2 388) 19 579
Deferred power costs, net 11 805 (11 462) 89
Allowance for other than borrowed funds
used during construction (11 966) (12 499) (10 221)
Cumulative effect of accounting change
before income taxes (Note A) (72 333)
Asset write-off before income taxes (Note A) 9 178
Changes in certain current assets and
liabilities:
Accounts receivable, net, excluding
cumulative effect of accounting change
(Note A) 9 666 (15 393) 12 452
Materials and supplies (20 519) 53 614 (30 359)
Accounts payable 3 119 (305) 34 525
Taxes accrued (5 792) 3 619 (5 692)
Interest accrued 3 452 (2 164) 5 139
Other, net 779 18 087 (19 431)
440 153 457 293 407 391
Cash Flows from Investing:
Construction expenditures (508 254) (573 970) (487 587)
Allowance for other than borrowed funds
used during construction 11 966 12 499 10 221
(496 288) (561 471) (477 366)
Cash Flows from Financing:
Sale of common stock 34 709 99 875 119 884
Sale of preferred stock 49 635 39 450
Retirement of preferred stock (1 190) (1 611) (27 250)
Issuance of long-term debt 197 098 691 343 398 619
Retirement of long-term debt (26 000) (632 000) (360 408)
Deposit with trustees for redemption of
long-term debt 115 785
Short-term debt, net (3 818) 119 431 (62 985)
Cash dividends on common stock (193 951) (187 475) (179 739)
56 483 89 563 43 356
Net Change in Cash and Temporary Cash
Investments (Note F) 348 (14 615) (26 619)
Cash and Temporary Cash Investments at
January 1 2 417 17 032 43 651
Cash and Temporary Cash Investments at
December 31 $ 2 765 $ 2 417 $ 17 032
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $148 016 $153 455 $138 724
Income taxes 122 343 124 979 103 635
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-4
CONSOLIDATED BALANCE SHEET
As of December 31
1994 1993
ASSETS (Thousands of Dollars)
Property, Plant, and Equipment:
At original cost, including $215,756,000 and
<S> <C> <C>
$638,920,000 under construction $7 586 780 $7 176 847
Accumulated depreciation (2 529 354) (2 388 758)
5 057 426 4 788 089
Investments and Other Assets:
Subsidiaries consolidated--excess of cost over
book equity at acquisition (Note A) 15 077 15 077
Securities of associated company--at cost, which
approximates equity 1 250 1 250
Other (Note A) 36 284 24 357
52 611 40 684
Current Assets:
Cash and temporary cash investments (Note F) 2 765 2 417
Accounts receivable:
Electric service, net of $11,353,000 and
$3,418,000 uncollectible allowance (Note A) 250 367 188 139
Other 8 175 7 736
Materials and supplies--at average cost:
Operating and construction 94 478 86 766
Fuel 84 199 71 392
Deferred power costs (Note A) 4 443 14 054
Prepaid taxes 43 880 43 139
Other 19 287 10 391
507 594 424 034
Deferred Charges:
Regulatory assets (Note B) 643 791 577 817
Unamortized loss on reacquired debt 40 991 44 435
Other 59 812 74 109
744 594 696 361
Total $6 362 225 $5 949 168
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes C and G) $2 059 304 $1 955 815
Preferred stock (Note G) 325 286 276 486
Long-term debt (Note H) 2 178 472 2 008 104
4 563 062 4 240 405
Current Liabilities:
Short-term debt (Note I) 126 818 130 636
Long-term debt and preferred stock due within
one year (Notes G and H) 29 200 27 200
Accounts payable 190 809 187 690
Taxes accrued:
Federal and state income 13 873 14 689
Other 52 782 57 758
Interest accrued 42 078 38 626
Other 62 073 73 467
517 633 530 066
Deferred Credits and Other Liabilities:
Unamortized investment credit 158 018 166 328
Deferred income taxes 972 113 873 695
Regulatory liabilities (Note B) 105 076 107 372
Other 46 323 31 302
1 281 530 1 178 697
Commitments and Contingencies (Note J)
Total $6 362 225 $5 949 168
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-5
CONSOLIDATED STATEMENT OF CAPITALIZATION
As of December 31
1994 1993 1994 1993
Common Stock: (Thousands of Dollars) (Capitalization
Ratios)
Common stock of Allegheny Power System, Inc.--$1.25 par value
per share, 260,000,000 shares authorized, outstanding
<S> <C> <C> <C> <C>
119,292,954 and 117,663,582 shares (Note G) $ 149 116 $ 147 079
Other paid-in capital 963 269 931 063
Retained earnings (Note C) 946 919 877 673
TOTAL 2 059 304 1 955 815 45.1% 46.1%
Preferred Stock of Subsidiaries--cumulative, par value $100
per share, authorized 9,997,123 shares (Note G):
Not subject to mandatory redemption:
December 31, 1994
Shares Regular Call Price
Series Outstanding Per Share
3.60%- 4.80% 650 861 $102.205 to $110.00 65 086 65 086
$5.88 -$7.92 1 300 000 102.85 to 103.94 130 000 80 000
$8.00 -$8.80 650 000 103.25 to 104.20 65 000 65 000
Auction 2.52%- 4.28% 400 000 100.00 40 000 40 000
TOTAL (annual dividend requirements $19,554,469) 300 086 250 086 6.6% 5.9%
Subject to mandatory redemption:
December 31, 1994
Shares Regular Call Price
Series Outstanding Per Share
$7.16% 264 000 $105.37 26 400 27 600
TOTAL (annual dividend requirements $1,890,240) 26 400 27 600
Less current sinking fund requirement (1 200) (1 200)
TOTAL 25 200 26 400 0.6% 0.6%
Long-Term Debt of Subsidiaries (Note H):
First mortgage bonds:
December 31, 1994
Maturity Interest Rate-%
1994-1998 4 7/8-6 1/2 180 000 196 000
2000-2004 5 5/8-7 7/8 315 000 315 000
2006-2007 7 1/4-8 120 000 120 000
2019 8 7/8-9 1/4 165 000 165 000
2020-2024 7 3/4-9 5/8 760 000 620 000
Debentures due 2003-2023 5 5/8-6 7/8 150 000 150 000
Secured notes due 1998-2024 4.95-9.375 368 300 333 005
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 6.25 41 736 21 362
Medium-term notes due 1994-1998 5.75-7.93 77 975 87 975
Unamortized debt discount and
premium, net (18 134) (16 943)
TOTAL (annual interest requirements $162,558,089) 2 206 472 2 037 994
Less current maturities (28 000) (26 000)
Less amounts on deposit with trustee (3 890)
TOTAL 2 178 472 2 008 104 47.7% 47.4%
Total Capitalization $4 563 062 $4 240 405 100.0% 100.0%
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-6
CONSOLIDATED STATEMENT OF COMMON EQUITY
Year ended December 31
Shares Other Retained Total
Outstanding Common Paid-In Earnings Common
(Note G) Stock Capital (Note C) Equity
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1992 108 451 312 $135 564 $723 520 $826 570 $1 685 654
Add:
Sale of common stock, net of expenses:
Public offerings 3 960 000 4 950 81 544 86 494
Dividend Reinvestment and Stock
Purchase Plan and Employee Stock
Ownership and Savings Plan 1 487 424 1 859 31 530 33 389
Consolidated net income 203 547 203 547
Deduct:
Dividends on common stock of the
Company (cash) 179 739 179 739
Expenses related to subsidiary companies'
preferred stock transactions 556 980 1 536
Balance at December 31, 1992 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
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
F-7
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 and its subsidiaries (companies) are subject to
regulation by the Securities and Exchange
Commission. 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.
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 and 1992, 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 and transmission services
to other utilities, 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.
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 by the subsidiaries for
computing AFUDC in 1994, 1993, and 1992 averaged 9.00%, 9.37%,
and 9.19%, respectively. AFUDC is not included
in the cost of such construction when the cost of financing the
construction is being recovered through rates.
<PAGE>
F-8
DEPRECIATION AND MAINTENANCE:
Provisions for depreciation are determined generally on a
straight-line method based on estimated service lives
of depreciable properties and amounted to approximately 3.3% of
average depreciable property in 1994, 3.4% in
1993, and 3.3% in 1992. 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 acquisition cost over book equity
(goodwill) prior to 1966. Goodwill is not being amortized
because, in management's opinion, there has been no
reduction in its value.
Other investments primarily represent the estimated cash
surrender values and prepayments of purchased life
insurance contracts on certain qualifying management employees
under an executive life insurance plan and a
supplemental executive retirement plan (Secured Benefit 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
recorded in accordance with the Financial Accounting
Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) No. 109, "Accounting for Income
Taxes", 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, balances of which are
being amortized over 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.
<PAGE>
F-9
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
to Voluntary Employee Beneficiary Association (VEBA) trust funds
an amount equal to the annual cost as
determined by SFAS No. 106 (described below). Medical benefits
are self-insured; the life insurance plan is paid
through insurance premiums.
The FASB has prescribed the determination of annual pension and
other postretirement benefits expenses in SFAS
No. 87, "Employers' Accounting for Pensions", and SFAS No. 106,
"Employers' Accounting for Postretirement
Benefits Other Than Pensions", respectively. The subsidiaries
record annual pension expense in accordance with
SFAS No. 87. Prior to 1994, regulatory deferrals of these
benefit expenses were recorded pursuant to SFAS No.
71, "Accounting for the Effects of Certain Types of Regulation",
for those jurisdictions which reflected as net
expense the funding of pensions and cash payments of other
benefits in the ratemaking process. Regulatory
deferrals of SFAS No. 106 benefits expenses were recorded for
those jurisdictions in which SFAS No. 106 costs
were not yet included in rates.
ASSET WRITE-OFF:
In 1994, the subsidiaries wrote off $9.2 million ($5.3 million
net of income taxes) 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 is no longer reasonable to assume
future recovery of these costs in rates.
ACCOUNTING CHANGES:
Effective January 1, 1994, the 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
ratemaking 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 the current year's consolidated income before
the cumulative effect of accounting change, as
well as on 1993 and 1992 consolidated net income, is not
material.
Effective January 1, 1993, the subsidiaries adopted SFAS No. 106,
"Employers' Accounting for Postretirement
Benefits Other Than Pensions". Prior to 1993, medical expenses
and life insurance premiums paid for retired
employees and their dependents were recorded as expense in the
period they were paid. Also effective January 1, 1993,
<PAGE>
F-10
the subsidiaries adopted SFAS No. 109, "Accounting for
Income Taxes". This standard mandated a change
from the previous income-based deferral approach to a balance
sheet-based liability approach for computing
deferred income taxes.
NOTE B--INCOME TAXES:
Details of federal and state income tax provisions are:
1994 1993 1992
(Thousands of Dollars)
Income taxes--current:
Federal $114 263 $110 815 $ 92 937
State 15 633 20 732 4 144
Total 129 896 131 547 97 081
Income taxes--deferred,
net of amortization 33 994 6 034 28 318
Investment credit disallowed (404)
Amortization of deferred
investment credit (8 310) (8 422) (8 335)
Total income taxes 155 580 129 159 116 660
Income taxes--credited (charged)
to other income and deductions 3 058 (1 029) (1 287)
Income taxes--charged to
accounting change (including
state income taxes) (28 887)
Income taxes--charged to
operating income $129 751 $128 130 $115 373
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:
1994 1993 1992
(Thousands of Dollars)
Financial accounting income
before cumulative effect of
accounting change, preferred
dividends, and income taxes $369 598 $360 984 $337 155
Amount so produced $129 400 $126 300 $114 600
Increased (decreased) for:
Tax deductions for which
deferred tax was not provided:
Lower tax depreciation 8 000 8 800 7 600
Plant removal costs (5 600) (6 000) (6 500)
State income tax, net of
federal income tax benefit 11 600 15 000 12 600
Amortization of deferred
investment credit (8 310) (8 422) (8 335)
Other, net (5 339) (7 548) (4 592)
Total $129 751 $128 130 $115 373
<PAGE>
F-11
Federal income tax returns through 1991 have been examined and
substantially settled.
In adopting SFAS No. 109, the subsidiaries recognized a
significant increase in both deferred tax assets and
liabilities. At December 31, the deferred tax assets and
liabilities were comprised of the following:
1994 1993
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit $ 99 821 $ 105 289
Unbilled revenue 13 043 38 363
Tax interest capitalized 33 773 22 236
Contributions in aid of construction 18 742 17 176
State tax loss carryback/carryforward 8 256 14 560
Other 40 927 21 658
214 562 219 282
Deferred tax liabilities:
Book vs. tax plant basis differences, net 1 123 763 1 051 500
Other 51 996 42 122
1 175 759 1 093 622
Total net deferred tax liabilities 961 197 874 340
Add portion above included in current
assets (liabilities) 10 916 (645)
Total long-term net deferred tax liabilities $ 972 113 $ 873 695
It is expected that regulatory commissions will allow recovery of
the deferred tax liabilities in future years
as they are paid, and accordingly, the subsidiaries have recorded
regulatory assets of $605 million which offset
the increase in deferred tax liabilities. Regulatory liabilities
of $105 million have been recorded which
offset the increase in deferred tax assets 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 C--DIVIDEND RESTRICTION:
Supplemental indentures relating to most outstanding bonds of the
subsidiaries contain dividend restrictions
under the most restrictive of which $461,539,000 of consolidated
retained earnings at December 31, 1994, 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.
<PAGE>
F-12
NOTE D--PENSION BENEFITS:
Net pension costs, a portion of which (about 25% to 30%) was
charged to plant construction, included the
following components:
1994 1993 1992
(Thousands of Dollars)
Service cost--benefits earned $14 940 $13 361 $12 402
Interest cost on projected benefit
obligation 38 630 37 387 36 049
Actual return on plan assets (61) (89 680) (65 641)
Net amortization and deferral (48 983) 43 653 21 344
SFAS No. 87 pension cost 4 526 4 721 4 154
Regulatory reversal (deferral) 6 681 (1 509) (3 862)
Net pension cost $11 207 $ 3 212 $ 292
The benefits earned to date and funded status at December 31
using a measurement date of September 30 were as
follows:
1994 1993
(Thousands of Dollars)
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of $403,610,000
and $401,986,000) $429 998 $429 360
Funded status:
Actuarial present value of projected
benefit obligation $529 411 $546 776
Plan assets at market value, primarily
common stocks and fixed income securities 573 122 602 194
Plan assets in excess of projected benefit
obligation (43 711) (55 418)
Add:
Unrecognized cumulative net gain from
past experience different from that
assumed 52 078 58 402
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987 18 882 22 028
Less unrecognized prior service cost due
to plan amendments 10 650 12 939
Pension cost liability at September 30 16 599 12 073
Fourth quarter contributions 7 800 --
Pension liability at December 31 $ 8 799 $ 12 073
In determining the actuarial present value of the projected
benefit obligation at September 30, 1994, 1993, and
1992, the discount rates used were 7.75%, 7.25%, and 7.75%, and
the rates of increase in future compensation
levels were 4.75%, 4.75%, and 5.25%, respectively. The expected
long-term rate of return on
assets was 9% in each of the years 1994, 1993, and 1992.
<PAGE>
F-13
NOTE E--POSTRETIREMENT BENEFITS OTHER THAN PENSIONS:
The subsidiaries adopted SFAS No. 106 as of January 1, 1993,
which requires accrual of postretirement benefits
other than pensions (principally health care and life insurance)
for employees and covered dependents during
the years the employees render the necessary service to receive
such benefits. Prior to 1993, medical expenses
and life insurance premiums paid by the subsidiaries for retired
employees and their dependents were recorded
in expense in the period in which they were paid ($6,553,000 in
1992).
SFAS No. 106 postretirement cost in 1994 and 1993, a portion of
which (about 25% to 30%) was charged to plant
construction, included the following components:
1994 1993
(Thousands of Dollars)
Service cost--benefits earned $ 3 058 $ 2 000
Interest cost on accumulated postretirement
benefit obligation 13 732 11 300
Actual loss (return) on plan assets 135 (24)
Amortization of unrecognized transition
obligation 7 300 7 300
Other net amortization and deferral 206 24
SFAS No. 106 postretirement cost 24 431 20 600
Regulatory deferral (3 908) (4 790)
Net postretirement cost $20 523 $15 810
The benefits earned to date and funded status at December 31
using a measurement date of September 30 were as
follows:
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $118 518 $115 019
Fully eligible employees 24 791 24 135
Other employees 52 914 55 255
Total obligation 196 223 194 409
Plan assets at market value 19 791 4 646
Accumulated postretirement benefit obligation
in excess of plan assets 176 432 189 763
Less:
Unrecognized cumulative net loss from past
experience different from that assumed 34 190 41 450
Unrecognized transition obligation, being
amortized over 20 years beginning
January 1, 1993 130 900 138 200
Postretirement benefit liability at
September 30 11 342 10 113
Fourth quarter contributions and benefit
payments 5 826 4 549
Postretirement benefit liability at
December 31 $ 5 516 $ 5 564
<PAGE>
F-14
The plan assets at market value are comprised of fixed income
securities, common stocks, and a short-term
investment fund in 1994; and a short-term investment fund in
1993.
The unfunded accumulated postretirement benefit obligation (APBO)
at January 1, 1993, of $145,500,000
(transition obligation) is being amortized prospectively over 20
years as permitted by SFAS No. 106.
In determining the APBO at September 30, 1994, 1993, and 1992,
the discount rates used were 7.75%, 7.25%, and
8%, and the rates of increase in future compensation levels were
4.75%, 4.75%, and 5.5%, respectively. The 1994
expected long-term rate of return on assets was 8.25% net of tax.
For measurement purposes, a health care trend
rate of 9% for 1995, declining 1% each year thereafter to 6.75%
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,
1994, by $13.5 million and the aggregate of the
service and interest cost components of net periodic
postretirement benefit cost for 1994 by $1.3 million. The
subsidiaries have been authorized recovery of approximately 90%
of SFAS No. 106 expenses in rates.
NOTE F--FAIR VALUE OF FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair value of financial
instruments at December 31, 1994 and 1993 were as
follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Assets:
<S> <C> <C> <C> <C>
Temporary cash investments $ 73 $ 73 $ 244 $ 244
Life insurance contracts 35 584 33 884 23 971 24 032
Liabilities:
Short-term debt 126 818 126 818 130 636 130 636
Mandatorily redeemable
preferred stock 26 400 25 542 27 600 28 566
Long-term debt 2 224 606 2 114 871 2 054 937 2 129 923
</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 mandatorily redeemable preferred stock
was estimated based on quoted market prices. The fair value of
long-term debt 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.
<PAGE>
F-15
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 G--STOCKHOLDERS' EQUITY:
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 May 1994, Monongahela issued 500,000 shares of Series L, $7.73
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. 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.
MANDATORILY REDEEMABLE PREFERRED STOCK:
The Potomac Edison Company's $7.16 preferred stock is entitled to
a cumulative sinking fund sufficient to retire
12,000 shares each year at $100 a share plus accrued dividends.
That subsidiary has the noncumulative option
in each year to retire up to an additional 12,000 shares at the
same price. The call price declines in future
years.
NOTE H--LONG-TERM DEBT:
Maturities for long-term debt for the next five years are: 1995,
$28,000,000; 1996, $43,575,000; 1997,
$26,900,000; 1998, $227,136,000; and 1999, $5,300,000.
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.
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
1998. Each bank has the option to discontinue its loans after
1998 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 companies, Allegheny Generating Company
borrowings are made through an internal money pool
as described in Note I.
<PAGE>
F-16
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 companies have fee arrangements on all of
their lines of credit and no compensating
balance requirements. At December 31, 1994, unused lines of
credit with banks were $202,150,000. 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 subsidiaries may borrow up to
$300 million on a standby revolving credit
basis. Short-term debt outstanding for 1994 and 1993 consisted
of:
1994 1993
(Thousands of Dollars)
Balance at end of year:
Commercial Paper $103,968 -- 6.06% $54,811 -- 3.31%
Notes Payable to Banks 22,850 -- 5.92% 75,825 -- 3.45%
Average amount outstanding
during the year:
Commercial Paper 67,290 -- 4.25% 21,567 -- 3.24%
Notes Payable to Banks 33,273 -- 4.17% 25,597 -- 3.19%
NOTE J--COMMITMENTS AND CONTINGENCIES:
CONSTRUCTION PROGRAM:
The subsidiaries have entered into commitments for their
construction programs, for which expenditures are
estimated to be $341 million for 1995 and $284 million for 1996.
These estimates include expenditures for the
program of complying with the Clean Air Act Amendments of 1990
(CAAA) as discussed below.
ENVIRONMENTAL MATTERS:
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.
Construction estimates for 1995 and 1996 include $61 million and
$7 million, respectively, for compliance with
Phase I of the CAAA. Through 1998, annual construction
expenditures are not expected to significantly exceed
1995 estimated levels. Construction expenditure levels in 1999
and beyond will depend upon the strategy
eventually selected for complying with Phase II of the CAAA, as
well as future generation requirements.
LITIGATION:
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.
<PAGE>
F-17
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, 1994 and 1993, and
the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1994, 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 Notes A, B and F to the financial
statements, the Company changed its method of accounting for
revenue recognition in 1994 and for income taxes and
postretirement benefits other than pensions in 1993.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 2, 1995
<PAGE>
<TABLE>
<CAPTION>
F-18
Monongahela
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential $190 861 $185 141 $169 589
Commercial 116 201 110 762 102 709
Industrial 202 181 187 669 186 442
Nonaffiliated utilities 79 701 86 032 119 628
Other, including affiliates 91 186 72 240 53 595
Total Operating Revenues 680 130 641 844 631 963
Operating Expenses:
Operation:
Fuel 150 088 144 408 149 219
Purchased power and exchanges, net 161 839 155 602 153 272
Deferred power costs, net (Note A) 7 604 (2 489) 5 468
Other 74 907 66 506 64 043
Maintenance 69 389 67 770 62 909
Depreciation 57 952 56 056 53 865
Taxes other than income taxes 40 404 34 076 33 207
Federal and state
income taxes (Note B) 30 712 33 612 27 919
Total Operating Expenses 592 895 555 541 549 902
Operating Income 87 235 86 303 82 061
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A) 1 566 3 092 2 007
Other income, net 7 911 7 203 8 388
Total Other Income and Deductions 9 477 10 295 10 395
Income Before Interest Charges 96 712 96 598 92 456
Interest Charges:
Interest on long-term debt 35 187 35 555 34 241
Other interest 2 969 2 033 1 772
Allowance for borrowed funds used
during construction (Note A) (1 380) (2 688) (1 901)
Total Interest Charges 36 776 34 900 34 112
Income Before Cumulative Effect
of Accounting Change 59 936 61 698 58 344
Cumulative Effect of
Accounting Change, net (Note A) 7 945
Net Income $67 881 $61 698 $58 344
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-19
STATEMENT OF RETAINED EARNINGS
<S> <C> <C> <C>
Balance at January 1 $185 486 $178 084 $171 307
Add:
Net income 67 881 61 698 58 344
253 367 239 782 229 651
Deduct:
Dividends on capital stock:
Preferred stock 7 260 4 458 4 845
Common stock 47 481 49 838 46 532
Charge on redemption of preferred stock 190
Total Deductions 54 741 54 296 51 567
Balance at December 31 (Note C) $198 626 $185 486 $178 084
See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-20
Monongahela Power Company
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income $67 881 $61 698 $58 344
Depreciation 57 952 56 056 53 865
Deferred investment credit and
income taxes, net 3 350 6 352 6 982
Deferred power costs, net 7 604 (2 489) 5 468
Unconsolidated subsidiaries'
dividends in excess of earnings 1 647 1 971 2 552
Allowance for other than borrowed
funds used during construction (1 566) (3 092) (2 007)
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) 4 756 (8 412) (1 386)
Materials and supplies (5 944) 12 917 (7 434)
Accounts payable (2 044) 129 10 599
Taxes accrued (950) (5 674) (8 441)
Interest accrued 286 290 1 178
Other, net 1 731 3 296 (558)
121 424 123 042 119 162
Cash Flows from Investing:
Construction expenditures (103 975) (140 748) (126 422)
Allowance for other than borrowed
funds used during construction 1 566 3 092 2 007
(102 409) (137 656) (124 415)
Cash Flows from Financing:
Sale of common stock 40 000
Sale of preferred stock 49 635
Retirement of preferred stock (5 194)
Issuance of long-term debt 9 718 82 331 156 311
Retirement of long-term debt (68 471) (89 414)
Short-term debt, net (26 530) 63 100 (53 117)
Notes payable to affiliates 2 900 (8 030) 8 030
Dividends on capital stock:
Preferred stock (7 260) (4 458) (4 845)
Common stock (47 481) (49 838) (46 532)
(19 018) 14 634 5 239
Net Change in Cash and
Temporary Cash Investments (Note G) (3) 20 (14)
Cash and Temporary Cash Investments
at January 1 135 115 129
Cash and Temporary Cash Investments
at December 31 $132 $135 $115
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $35 347 $33 941 $32 486
Income taxes 29 939 30 982 22 946
See accompanying notes to financial statements.
</TABLE>
<PAGE>
F-21
BALANCE SHEET
DECEMBER 31
1994 1993
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $35,856,000 and
$144,621,000 under construction $1 763 533 $1 684 322
Accumulated depreciation (701 271) (664 947)
1 062 262 1 019 375
Investments:
Allegheny Generating Company-common stock
at equity (Note D) 60 137 61 698
Other 509 595
60 646 62 293
Current Assets:
Cash 132 135
Accounts receivable:
Electric service, net of $1,912,000 and
$1,084,000 uncollectible allowance (Note A) 62 631 48 995
Affiliated and other 9 483 14 596
Materials and supplies-at average cost:
Operating and construction 24 563 22 393
Fuel 23 678 19 904
Prepaid taxes 17 599 19 788
Deferred power costs (Note A) 1 852 10 823
Other 5 328 3 772
145 266 140 406
Deferred Charges:
Regulatory assets (Note B) 186 109 162 842
Unamortized loss on reacquired debt 11 500 12 229
Other 10 700 10 308
208 309 185 379
Total $1 476 483 $1 407 453
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes C and H) $ 495 693 $ 483 030
Preferred stock, not subject to mandatory
redemption (Note H) 114 000 64 000
Long-term debt (Note I) 470 131 460 129
1 079 824 1 007 159
Current Liabilities:
Short-term debt (Note J) 36 570 63 100
Notes payable to affiliates (Note J) 2 900
Accounts payable 31 871 31 752
Accounts payable to affiliates 6 021 8 184
Taxes accrued:
Federal and state income 118
Other 20 193 21 261
Interest accrued 10 927 10 641
Other 16 455 18 994
125 055 153 932
Deferred Credits and Other Liabilities:
Unamortized investment credit 24 734 26 883
Deferred income taxes 216 264 192 466
Regulatory liabilities (Note B) 19 974 19 179
Other 10 632 7 834
271 604 246 362
Commitments and Contingencies (Note K)
Total $1 476 483 $1 407 453
See accompanying notes to financial statements.
<PAGE>
<TABLE>
<CAPTION>
F-22
STATEMENT OF CAPITALIZATION
DECEMBER 31
1994 1993 1994 1993
(Thousands of Dollars) (Capitalization Ratios)
Common Stock:
Common stock-par value $50 per share, authorized
8,000,000 shares, outstanding 5,891,000 shares
<C> <C> <C> <C> <C>
(issued 800,000 shares in 1992) $294 550 $294 550
Other paid-in capital (Note H) 2 517 2 994
Retained earnings (Note C) 198 626 185 486
Total 495 693 483 030 45.9% 48.0%
Preferred Stock (not subject to mandatory redemption):
Cumulative preferred stock-par value $100 per share,
authorized 1,500,000 shares, outstanding as follows
(Note H):
December 31, 1994
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 50 000 103.36 1968 5 000 5 000
$8.80 G 50 000 104.20 1971 5 000 5 000
$7.92 H 50 000 103.52 1972 5 000 5 000
$7.92 I 100 000 103.52 1973 10 000 10 000
$8.60 J 150 000 103.33 1976 15 000 15 000
$7.73 L 500 000 100.00 1994 50 000
Total (annual dividend requirements $8,323,000) 114 000 64 000 10.6 6.3
Long-Term Debt (Note I):
First mortgage
bonds: Date of Date Date
Issue Redeemable Due
5-1/2% 1966 1994 1996 18 000 18 000
6-1/2% 1967 1994 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 1994 2019 70 000 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
Interest Rate
Secured notes due 1998-2024
5.95%-7.75% 74 050 65 225
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 (3 579) (3 785)
Total (annual interest requirements $35,550,131) 470 131 461 100 42.8 42.7
Less amount on deposit with trustee 971
Total 470 131 460 129 43.5 45.7
Total Capitalization $1 079 824 $1 007 159 100.0 100.0%
See accompanying notes to financial statements.
</TABLE>
<PAGE>
F-23
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 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.
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 and transmission services to other
utilities, 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.
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
<PAGE>
F-24
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 1994, 1993,
and 1992 were 8.16%, 8.69%, and 8.23%, 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 3.6% of
average depreciable property in 1994 and 3.8% in each of the
years 1993 and 1992.
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 recorded
in accordance with the Financial Accounting Standards Board
(FASB) Statement of Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes", 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, balances of which are being amortized over
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>
F-25
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 to Voluntary Employee Beneficiary
Association (VEBA) trust funds an amount equal to the annual cost
as determined by SFAS No. 106 (described below). Medical benefits
are self-insured; the life insurance plan is paid through
insurance premiums.
The FASB has prescribed the determination of annual pension and
other postretirement benefits expenses in SFAS No. 87,
"Employers' Accounting for Pensions", and SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions", respectively. The Company records annual pension
expense in accordance with SFAS No. 87. Prior to 1994, regulatory
deferrals of these benefit expenses were recorded pursuant to
SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation", for West Virginia and Ohio jurisdictions. These
jurisdictions reflected as net expense the funding of pensions
and cash payments of other benefits in the ratemaking process.
Regulatory deferrals of SFAS No. 106 benefits expenses were
recorded for Ohio and West Virginia jurisdictions in which SFAS
No. 106 costs were not yet included in rates.
ACCOUNTING CHANGES:
Effective January 1, 1994, the Company changed its revenue
recognition method for revenues 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 the current year's
income before the cumulative effect of accounting change, as well
as on 1993 and 1992 net income, is not material.
Effective January 1, 1993, the Company adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions". Prior to 1993, medical expenses and life insurance
premiums paid for retired employees and their dependents were
recorded as expense in the period they were paid. Also effective
January 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes". This standard mandated a change from the
previous income-based deferral approach to a balance sheet-based
liability approach for computing deferred income taxes.
<PAGE>
F-26
Note B-Income Taxes:
Details of federal and state income tax provisions are:
1994 1993 1992
(Thousands of Dollars)
Income taxes-current:
Federal $27 793 $25 618 $20 365
State 4 841 1 692 830
Total 32 634 27 310 21 195
Income taxes-deferred, net of amortization 5 499 8 517 9 364
Investment credit disallowed (207)
Amortization of deferred investment credit (2 149) (2 165) (2 175)
Total income taxes 35 984 33 662 28 177
Income taxes-credited (charged) to other income 63 (50) (258)
Income taxes-charged to accounting change (including
state income taxes) (5 335)
Income taxes-charged to operating income $30 712 $33 612 $27 919
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:
1994 1993 1992
(Thousands of Dollars)
Financial accounting income before cumulative effect
of accounting change and income taxes $90 648 $95 310 $86 263
Amount so produced $31 700 $33 400 $29 300
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation 5 400 5 700 4 900
Plant removal costs (2 100) (3 000) (2 600)
State income tax, net of federal
income tax benefit 3 500 3 800 3 800
Amortization of deferred investment credit (2 149) (2 165) (2 175)
Equity in earnings of subsidiaries (2 800) (2 500) (2 800)
Adjustments of provisions for prior years (1 900) 400 (100)
Other, net (939) (2 023) (2 406)
Total $30 712 $33 612 $27 919
Federal income tax returns through 1991 have been examined and
substantially settled.
<PAGE>
F-27
In adopting SFAS No. 109, the Company recognized a significant
increase in both deferred tax assets and liabilities. At December
31, the deferred tax assets and liabilities were comprised of the
following:
<TABLE>
<CAPTION>
1994 1993
(Thousands of Dollars)
Deferred tax assets:
<S> <C> <C>
Unamortized investment tax credit $16 604 $18 043
Unbilled revenue 4 181
Tax interest capitalized 4 907 2 430
Contributions in aid of construction 2 223 2 058
Vacation pay 760 1 958
Advances for construction 1 771 1 601
Other 9 987 4 455
36 252 34 726
Deferred tax liabilities:
Book vs. tax plant basis differences, net 228 997 205 829
Other 22 425 23 411
251 422 229 240
Total net deferred tax liabilities 215 170 194 514
Add portion above included in
current assets (liabilities) 1 094 (2 048)
Total long-term net deferred tax liabilities $216 264 $192 466
</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
$174 million which offset the increase in deferred tax
liabilities. Regulatory liabilities of $20 million have been
recorded which offset the increase in deferred tax assets 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-Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $103,482,000 of retained earnings at
December 31, 1994, 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 D-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. Through February 29, 1992, AGC's return on equity
(ROE) was adjusted annually pursuant to a settlement agreement
approved by the FERC.
<PAGE>
F-28
In December 1991, AGC filed for a continuation of the existing
ROE of 11.53% and other parties (the Consumer Advocate Division
of the West Virginia PSC, 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 argues
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 AGC 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 is currently pending, which
would reduce AGC's ROE to 11.13% for the period from March 1,
1992, through December 31, 1994, and increase AGC's ROE to 11.20%
for the period from January 1, 1995, through December 31, 1995.
Following is a summary of financial information for AGC:
<TABLE>
<CAPTION>
December 31
1994 1993
(Thousands of Dollars)
Balance sheet information:
<S> <C> <C>
Property, plant, and equipment $680 749 $696 529
Current assets 5 991 11 063
Deferred charges 27 496 28 337
Total assets $714 236 $735 929
Total capitalization $489 894 $505 708
Current liabilities 6 484 21 891
Deferred credits 217 858 208 330
Total capitalization and liabilities $714 236 $735 929
Year Ended December 31
1994 1993 1992
(Thousands of Dollars)
Income statement information:
Electric operating revenues $91 022 $90 606 $96 147
Operation and maintenance expense 6 695 6 609 6 094
Depreciation 16 852 16 899 16 827
Taxes other than income taxes 5 223 5 347 5 236
Federal income taxes 14 737 13 262 14 702
Interest charges 17 809 21 635 22 585
Other income, net (11) (328) (21)
Net income $29 717 $27 182 $30 724
</TABLE>
Results for 1994 reflect the effect of the pending settlement
agreement. The Company's share of the equity in earnings above
was $8.0 million, $7.3 million, and $8.3 million for 1994, 1993,
and 1992, respectively, and is included in other income, net, on
the Statement of Income.
<PAGE>
F-29
Note E-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:
<TABLE>
<CAPTION>
1994 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost - benefits earned $ 3 677 $ 3 198 $ 3 054
Interest cost on projected benefit obligation 9 045 8 577 8 470
Actual loss (return) on plan assets 87 (22 606) (14 863)
Net amortization and deferral (11 563) 12 048 4 453
SFAS No. 87 pension cost 1 246 1 217 1 114
Regulatory reversal (deferral) 3 718 (1 179) (1 114)
Net pension cost $ 4 964 $ 38 $ ----
</TABLE>
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:
1994 1993
(Thousands of Dollars)
Actuarial present value of accumulated benefit
obligation earned to date (including vested benefit
of $92,823,000 and $91,750,000) $ 99 605 $ 98 898
Funded status:
Actuarial present value of projected
benefit obligation $123 935 $128 201
Plan assets at market value, primarily
common stocks and fixed income securities 134 166 141 195
Plan assets in excess of projected
benefit obligation (10 231) (12 994)
Add:
Unrecognized cumulative net gain from past experience
different from that assumed 13 969 15 187
Unamortized transition asset, being amortized over
14 years beginning January 1, 1987 3 988 4 711
Less unrecognized prior service cost
due to plan amendments 2 471 2 891
Pension cost liability at September 30 5 255 4 013
Fourth quarter contributions 1 829 -
Pension liability at December 31 $3 426 $4 013
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, 1994, 1993, and 1992, the
discount rates used were 7.75%, 7.25%, and 7.75%, and the rates
of increase in future compensation levels were 4.75%, 4.75%, and
5.25%, respectively. The expected long-term rate of return on
assets was 9% in each of the years 1994, 1993, and 1992.
<PAGE>
F-30
Note F-Postretirement Benefits Other Than Pensions:
The Company adopted SFAS No. 106 as of January 1, 1993, which
requires accrual of postretirement benefits other than pensions
(principally health care and life insurance) for employees and
covered dependents during the years the employees render the
necessary service to receive such benefits. Prior to 1993,
medical expenses and life insurance premiums paid by the Company
for retired employees and their dependents were recorded in
expense in the period in which they were paid ($2,390,000 in
1992).
SFAS No. 106 postretirement cost in 1994 and 1993, a portion of
which (about 25% to 30%) was charged to plant construction,
included the following components:
1994 1993
(Thousands of Dollars)
Service cost - benefits earned $ 764 $ 478
Interest cost on accumulated postretirement
benefit obligation 3 655 2 819
Actual loss (return) on plan assets 38 (5)
Amortization of unrecognized transition
obligation 1 783 1 772
Other net amortization and deferral 50 5
SFAS No. 106 postretirement cost 6 290 5 069
Regulatory deferral (3 450) (1 981)
Net postretirement cost $2 840 $3 088
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:
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $33 528 $32 469
Fully eligible employees 4 947 4 348
Other employees 14 458 14 664
Total obligation 52 933 51 481
Plan assets at market value 5 338 1 230
Accumulated postretirement benefit obligation in excess of
plan assets 47 595 50 251
Less:
Unrecognized cumulative net loss from past
experience different from that assumed 12 752 14 161
Unrecognized transition obligation, being
amortized over 20 years beginning
January 1, 1993 32 368 34 059
Postretirement benefit liability at
September 30 2 475 2 031
Fourth quarter contributions and
benefit payments 1 437 997
Postretirement benefit liability at December 31 $1 038 $1 034
<PAGE>
F-31
The plan assets at market value are comprised of fixed income
securities, common stocks, and a short-term investment fund in
1994; and a short-term investment fund in 1993.
The unfunded accumulated postretirement benefit obligation
(APBO) at January 1, 1993, of $35,800,000 (transition
obligation), is being amortized prospectively over 20 years as
permitted by SFAS No. 106.
In determining the APBO at September 30, 1994, 1993, and 1992,
the discount rates used were 7.75%, 7.25%, and 8%, and the rates
of increase in future compensation levels were 4.75%, 4.75%, and
5.5%, respectively. The 1994 expected long-term rate of return on
assets was 8.25% net of tax. For measurement purposes, a health
care trend rate of 9% for 1995, declining 1% each year thereafter
to 6.75% 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, 1994, by $3.6 million and
the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for 1994 by $.3 million.
Note G-Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial
instruments at December 31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Liabilities:
<S> <C> <C> <C> <C>
Short-term debt $ 36 570 $ 36 570 $ 63 100 $ 63 100
Long-term debt 473 710 458 714 464 885 485 713
</TABLE>
The carrying amount of short-term debt approximates the fair
value because of the short maturity of those instruments. The
fair value of long-term debt 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 H-Stockholders' Equity:
COMMON STOCK AND OTHER PAID-IN CAPITAL:
In September 1992, the Company issued and sold to its parent,
800,000 shares of its common stock at $50 per share. Other
paid-in capital decreased $477,000 in 1994 as a result of
underwriting fees and commissions associated with the Company's
<PAGE>
F-32
sale of $50 million of preferred stock. Other paid-in capital
decreased $4,000 in 1992 as a result of a preferred stock
redemption.
PREFERRED STOCK:
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.
Note I-Long-Term Debt:
Maturities for long-term debt for the next five years are:
1995, none; 1996, $18,500,000; 1997, $15,500,000; 1998,
$20,100,000; and 1999, $1,000,000. 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.
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
1994 and 1993 consisted of:
1994 1993
(Thousands of Dollars)
Balance at end of year:
Commercial Paper $24,970-6.21% -
Notes Payable to Banks 11,600-6.43% $63,100-3.45%
Money Pool 2,900-5.49% -
Average amount outstanding during the year:
Commercial Paper 8,751-3.58% 3,467-3.19%
Notes Payable to Banks 15,283-3.89% 10,627-3.20%
Money Pool 11,363-4.51% 8,227-3.01%
<PAGE>
F-33
Note K-Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $74 million
for 1995 and $70 million for 1996. These estimates include
expenditures for the program of complying with the Clean Air Act
Amendments of 1990 (CAAA) as discussed below.
ENVIRONMENTAL MATTERS:
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.
Construction estimates for 1995 and 1996 include $11 million and
$2 million, respectively, for compliance with Phase I of the
CAAA. Through 1998, annual construction expenditures, on average,
are not expected to significantly exceed 1995 estimated levels.
Construction expenditure levels in 1999 and beyond will depend
upon the strategy eventually selected for complying with Phase II
of the CAAA, as well as future generation requirements.
LITIGATION AND OTHER:
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 is guarantor as to 27% of a $50 million revolving
credit agreement of AGC, which in 1994 was used by AGC solely as
support for its indebtedness for commercial paper outstanding.
<PAGE>
F-34
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
The Potomac Edison Company
In our opinion, the financial statements listed in the
accompanying index present fairly, in all material respects, the
financial position of The Potomac Edison Company (a subsidiary of
Allegheny Power System, Inc.) at December 31, 1994 and 1993, and
the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1994, 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 Notes A, B and F to the financial
statements, the Company changed its method of accounting for
revenue recognition in 1994 and for income taxes and
postretirement benefits other than pensions in 1993.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 2, 1995
<PAGE>
<TABLE>
<CAPTION>
F-35
Potomac Edison
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential $296 090 $274 358 $243 413
Commercial 135 937 124 667 111 506
Industrial 195 089 175 902 157 304
Nonaffiliated utilities 107 027 108 132 141 120
Other, including affiliates 25 222 29 526 34 544
Total Operating Revenues 759 365 712 585 687 887
Operating Expenses:
Operation:
Fuel 145 045 143 587 150 218
Purchased power and exchanges, net 217 137 205 073 201 220
Deferred power costs, net (Note A) 1 321 (9 953) (3 850)
Other 85 024 74 438 67 351
Maintenance 58 624 64 376 53 141
Depreciation 59 989 56 449 53 446
Taxes other than income taxes 46 740 46 813 45 791
Federal and state income taxes
(Note B) 33 163 30 086 28 422
Total Operating Expenses 647 043 610 869 595 739
Operating Income 112 322 101 716 92 148
Other Income and Deductions:
Allowance for other than borrowed
funds used during construction
(Note A) 3 671 4 329 3 204
Other income, net 10 243 8 419 9 352
Total Other Income and Deductions 13 914 12 748 12 556
Income Before Interest Charges 126 236 114 464 104 704
Interest Charges:
Interest on long-term debt 44 706 42 695 38 081
Other interest 1 750 1 107 1 311
Allowance for borrowed funds used
during construction (Note A) (2 203) (2 805) (2 164)
Total Interest Charges 44 253 40 997 37 228
Income Before Cumulative Effect
of Accounting Change 81 983 73 467 67 476
Cumulative Effect of Accounting
Change, net (Note A) 16 471
Net Income $98 454 $73 467 $67 476
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-36
STATEMENT OF RETAINED EARNINGS
<S> <C> <C> <C>
Balance at January 1 $176 053 $167 412 $160 515
Add:
Net income 98 454 73 467 67 476
274 507 240 879 227 991
Deduct:
Dividends on capital stock:
Preferred stock 4 331 4 434 6 059
Common stock 62 454 60 386 53 731
Charges on redemption of preferred stock 6 789
Total Deductions 66 785 64 826 60 579
Balance at December 31 (Note C) $207 722 $176 053 $167 412
See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-37
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income $98 454 $73 467 $67 476
Depreciation 59 989 56 449 53 446
Deferred investment credit
and income taxes, net 12 688 (3 119) 5 192
Deferred power costs, net 1 321 (9 953) (3 850)
Unconsolidated subsidiaries'
dividends in excess of earnings 1 704 2 042 2 642
Allowance for other than borrowed
funds used during construction (3 671) (4 329) (3 204)
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) 6 004 (7 640) (2 431)
Materials and supplies (5 367) 13 971 (7 464)
Accounts payable (9 981) 2 762 17 902
Taxes accrued (1 083) 240 (224)
Interest accrued 563 1 664 69
Other, net (198) 14 006 (1 850)
134 260 139 560 127 704
Cash Flows from Investing:
Construction expenditures (142 826) (179 433) (153 485)
Allowance for other than borrowed
funds used during construction 3 671 4 329 3 204
(139 155) (175 104) (150 281)
Cash Flows from Financing:
Sale of common stock 50 000 80 000
Retirement of preferred stock (1 190) (1 611) (22 056)
Issuance of long-term debt 86 877 142 171 58 101
Retirement of long-term debt (16 000) (123 888) (46 782)
Deposit with trustee for redemption
of long-term debt 47 431
Notes receivable from affiliates 2 700 33 400 (38 000)
Dividends on capital stock:
Preferred stock (4 331) (4 434) (6 059)
Common stock (62 454) (60 386) (53 731)
5 602 35 252 18 904
Net Change in Cash and Temporary
Cash Investments (Note G) 707 (292) (3 673)
Cash and Temporary Cash
Investments at January 1 1 489 1 781 5 454
Cash and Temporary Cash Investments
at December 31 $2 196 $1 489 $1 781
Supplemental cash flow information Cash paid during the year for:
Interest (net of amount capitalized) $42 680 $37 427 $36 371
Income taxes 30 771 30 378 25 180
See accompanying notes to financial statements.
</TABLE>
<PAGE>
F-38
BALANCE SHEET
DECEMBER 31
1994 1993
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $76,365,000
and $208,308,000 under construction $1 978 396 $1 857 961
Accumulated depreciation (673 853) (632 269)
1 304 543 1 225 692
Investments and Other Assets:
Allegheny Generating Company - common stock
at equity (Note D) 62 364 63 983
Other 938 819
63 302 64 802
Current Assets:
Cash 2 196 1 489
Accounts receivable:
Electric service, net of $1,177,000 and
$1,207,000 uncollectible allowance (Note A) 68 714 44 575
Affiliated and other 2 403 6 383
Notes receivable from affiliates (Note J) 1 900 4 600
Materials and supplies at average cost:
Operating and construction 27 800 26 153
Fuel 22 316 18 596
Prepaid taxes 13 168 12 523
Other 5 000 4 000
143 497 118 319
Deferred Charges:
Regulatory assets (Note B) 88 758 76 962
Unamortized loss on reacquired debt 8 344 9 188
Other 21 091 24 800
118 193 110 950
Total $1 629 535 $1 519 763
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and
retained earnings (Notes C and H) $658 146 $626 467
Preferred stock (Note H) 61 578 62 778
Long-term debt (Note I) 604 749 517 910
1 324 473 1 207 155
Current Liabilities:
Long-term debt and preferred stock
due within one year (Notes H and I) 1 200 17 200
Accounts payable 37 126 41 986
Accounts payable to affiliates 10 485 15 606
Taxes accrued:
Federal and state income 3 565 2 970
Other 11 874 13 552
Interest accrued 9 195 8 632
Other 17 399 22 445
90 844 122 391
Deferred Credits and Other Liabilities:
Unamortized investment credit 28 041 30 308
Deferred income taxes 149 299 133 027
Regulatory liabilities (Note B) 16 957 18 490
Other 19 921 8 392
214 218 190 217
Commitments and Contingencies (Note K)
Total $1 629 535 $1 519 763
See accompanying notes to financial statements.
<PAGE>
<TABLE>
<CAPTION>
F-39
Potomac Edison
STATEMENT OF CAPITALIZATION
DECEMBER 31
1994 1993 1994 1993
(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 shares
<S> <C> <C> <C> <C>
in 1993 and 4,000,000 shares in 1992) $447 700 $447 700
Other paid-in capital (Note H) 2 724 2 714
Retained earnings (Note C) 207 722 176 053
Total 658 146 626 467 49.7% 51.9%
Preferred Stock:
Cumulative preferred stock-par value $100 per share,
authorized 5,388,046 shares, outstanding as follows (Note H):
Not subject to mandatory redemption:
December 31, 1994
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 50 000 103.20 1968 5 000 5 000
$8.32 F 50 000 103.54 1971 5 000 5 000
$8.00 G 100 000 103.25 1972 10 000 10 000
Total (annual dividend requirements $2,383,622) 36 378 36 378 2.7 3.0
Subject to mandatory redemption:
$7.16 J 264 000 $105.37 1986 26 400 27 600
Total (annual dividend requirements $1,890,240) 26 400 27 600
Less current sinking fund requirement (1 200) (1 200)
25 200 26 400 1.9 2.2
Long-Term Debt (Note I):
First mortgage Date of Date Date
bonds: Issue Redeemable Due
4-5/8% 1964 1994 1994 16 000
5-7/8% 1966 1994 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 1994 2019 65 000 65 000
9-5/8% 1990 1995 2020 80 000 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
Interest Rate
Secured notes due 1998-2024 5.95%-7.30% 91 700 80 140
Unsecured note due 1996-2002 6.30% 5 500 5 500
Unamortized debt discount
and premium, net (5 451) (4 456)
Total (annual interest requirements $47,887,438) 604 749 535 184
Less current maturities (16 000)
Less amount on deposit with trustee (1 274)
604 749 517 910 45.7 42.9
Total Capitalization $1 324 473 $1 207 155 100.0% 100.0%
See accompanying notes to financial statements.
</TABLE>
<PAGE>
F-40
The Potomac Edison Company
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
Note A
Summary of Significant Accounting Policies:
The 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.
REVENUES:
Beginning in 1994, revenues, generally 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
and 1992, revenues were recorded for billings rendered to
customers. Revenues of $68.0 million from one industrial
customer, Eastalco Aluminum Company, were 9% of total electric
operating revenues in 1994.
DEFERRED POWER COSTS, NET:
The costs of fuel, purchased power, and certain other costs,
and revenues from sales and transmission services to other
utilities, 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
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.
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 1994, 1993,
<PAGE>
F-41
and 1992 were 9.73%, 9.97%, and 9.92%, 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 3.4% of
average depreciable property in 1994 and 3.6% in each of the
years 1993 and 1992. 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 recorded
in accordance with the Financial Accounting Standards Board
(FASB) Statement of Financial Accounting Standards (SFAS) No.
109, "Accounting for Income Taxes", 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, balances of which are being amortized over
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>
F-42
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 to Voluntary Employee Beneficiary
Association (VEBA) trust funds an amount equal to the annual cost
as determined by SFAS No. 106 (described below). Medical benefits
are self-insured; the life insurance plan is paid through
insurance premiums.
The FASB has prescribed the determination of annual pension and
other postretirement benefits expenses in SFAS No. 87,
"Employers' Accounting for Pensions", and SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions", respectively. The Company records annual pension
expense in accordance with SFAS No. 87. Prior to 1994, regulatory
deferrals of these benefit expenses were recorded pursuant to
SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation", for West Virginia and Virginia jurisdictions. These
jurisdictions reflected as net expense the funding of pensions
and cash payments of other benefits in the ratemaking process.
Regulatory deferrals of SFAS No. 106 benefits expenses were
recorded for the West Virginia jurisdiction in which SFAS No. 106
costs were not yet included in rates.
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 the current year's income
before the cumulative effect of accounting change, as well as on
1993 and 1992 net income, is not material.
Effective January 1, 1993, the Company adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions". Prior to 1993, medical expenses and life insurance
premiums paid for retired employees and their dependents were
recorded as expense in the period they were paid. Also effective
January 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes". This standard mandated a change from the
previous income-based deferral approach to a balance sheet-based
liability approach for computing deferred income taxes.
Note B
<PAGE>
F-43
Income Taxes:
Details of federal and state income tax provisions are:
1994 1993 1992
(Thousands of Dollars)
Income taxes-current:
Federal $34 193 $29 758 $26 366
State (2 849) 3 991 (2 635)
Total 31 344 33 749 23 731
Income taxes-deferred,
net of amortization 14 955 (770) 7 634
Investment credit disallowed (196)
Amortization of deferred
investment credit (2 267) (2 349) (2 246)
Total income taxes 44 032 30 630 28 923
Income taxes-charged to
other income (1 176) (544) (501)
Income taxes-charged to
accounting change (including
state income taxes) (9 693)
Income taxes-charged to
operating income $33 163 $30 086 $28 422
The total provision for income taxes is less than the amount
produced by applying the federal income statutory tax rate to
financial accounting income as set forth below:
1994 1993 1992
(Thousands of Dollars)
Financial accounting income
before cumulative effect of accounting
change and income taxes $115 146 $103 553 $ 95 898
Amount so produced $ 40 300 $ 36 200 $ 32 600
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation 100 2 300 2 300
Plant removal costs (1 700) (2 100) (1 500)
State income tax, net of
federal income tax benefit 1 300 1 600 1 200
Amortization of deferred
investment credit (2 267) (2 349) (2 246)
Equity in earnings
of subsidiaries (2 900) (2 600) (2 900)
Other, net (1 670) (2 965) (1 032)
Total $33 163 $30 086 $28 422
Federal income tax returns through 1991 have been examined and
substantially settled.
<PAGE>
F-44
In adopting SFAS No. 109, the Company recognized a significant
increase in both deferred tax assets and liabilities. At December
31, the deferred tax assets and liabilities were comprised of the
following:
1994 1993
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit $16 497 $17 922
Unbilled revenue 3 504 12 556
Tax interest capitalized 12 701 9 056
Contributions in aid of construction 11 653 10 530
State tax loss carryback/carryforward 2 721 5 770
Advances for construction 1 338 1 303
Other 5 800 3 279
54 214 60 416
Deferred tax liabilities:
Book vs. tax plant basis
differences, net 192 862 183 892
Other 13 367 10 122
206 229 194 014
Total net deferred tax liabilities 152 015 133 598
Less portion above included
in current liabilities 2 716 571
Total long-term net deferred
tax liabilities $149 299 $133 027
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
$76 million which offset the increase in deferred tax
liabilities. Regulatory liabilities of $17 million have been
recorded which offset the increase in deferred tax assets 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-Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $103,730,000 of retained earnings at
December 31, 1994, 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 D-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. Through February 29, 1992, AGC's return on equity
<PAGE>
F-45
(ROE) was adjusted annually pursuant to a settlement agreement
approved by the FERC. In December 1991, AGC filed for a continua-
tion of the existing ROE of 11.53% and other parties (the
Consumer Advocate Division of the West Virginia PSC, 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 argues 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 AGC 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 is currently pending, which
would reduce AGC's ROE to 11.13% for the period from March 1,
1992, through December 31, 1994, and increase AGC's ROE to 11.20%
for the period from January 1, 1995, through December 31, 1995.
Following is a summary of financial information for AGC:
December 31
1994 1993
(Thousands of Dollars)
Balance sheet information:
Property, plant, and equipment $680 749 $696 529
Current assets 5 991 11 063
Deferred charges 27 496 28 337
Total assets $714 236 $735 929
Total capitalization $489 894 $505 708
Current liabilities 6 484 21 891
Deferred credits 217 858 208 330
Total capitalization and liabilities $714 236 $735 929
Year Ended December 31
1994 1993 1992
(Thousands of Dollars)
Income statement information:
Electric operating revenues $91 022 $90 606 $96 147
Operation and maintenance expense 6 695 6 609 6 094
Depreciation 16 852 16 899 16 827
Taxes other than income taxes 5 223 5 347 5 236
Federal income taxes 14 737 13 262 14 702
Interest charges 17 809 21 635 22 585
Other income, net (11) (328) (21)
Net income $29 717 $27 182 $30 724
Results for 1994 reflect the effect of the pending settlement
agreement. The Company's share of the equity in earnings above
was $8.3 million, $7.6 million, and $8.6 million for 1994, 1993,
and 1992, respectively, and is included in other income, net, on
the Statement of Income.
<PAGE>
F-46
Note E-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:
<TABLE>
<CAPTION>
1994 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost - benefits earned $ 3 555 $ 3 225 $ 2 923
Interest cost on projected benefit obligation 9 867 9 612 9 142
Actual loss (return) on plan assets 304 (22 481) (15 951)
Net amortization and deferral (12 808) 10 669 4 743
SFAS No. 87 pension cost 918 1 025 857
Regulatory reversal (deferral) 1 194 537 (565)
Net pension cost $ 2 112 $ 1 562 $ 292
</TABLE>
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:
1994 1993
(Thousands of Dollars)
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of $103,546,000
and $102,917,000) $110 577 $110 278
Funded status:
Actuarial present value of
projected benefit obligation $135 060 $139 320
Plan assets at market value, primarily common stocks
and fixed income securities 146 211 153 440
Plan assets in excess of projected
benefit obligation (11 151) (14 120)
Add:
Unrecognized cumulative net gain from past experience
different from that assumed 13 165 14 927
Unamortized transition asset, being amortized
over 14 years beginning January 1, 1987 4 183 4 951
Less unrecognized prior service cost due to
plan amendments 2 732 3 218
Pension cost liability at September 30 3 465 2 540
Fourth quarter contributions 1 989
Pension liability at December 31 $1 476 $2 540
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, 1994, 1993, and 1992, the
discount rates used were 7.75%, 7.25%, and 7.75%, and the rates
of increase in future compensation levels were 4.75%, 4.75%, and
5.25%, respectively. The expected long-term rate of return on
assets was 9% in each of the years 1994, 1993, and 1992.
<PAGE>
F-47
Note F-Postretirement Benefits Other Than Pensions:
The Company adopted SFAS No. 106 as of January 1, 1993, which
requires accrual of postretirement benefits other than pensions
(principally health care and life insurance) for employees and
covered dependents during the years the employees render the
necessary service to receive such benefits. Prior to 1993,
medical expenses and life insurance premiums paid by the Company
for retired employees and their dependents were recorded in
expense in the period in which they were paid ($1,790,000 in
1992).
SFAS No. 106 postretirement cost in 1994 and 1993, a portion of
which (about 30% to 35%) was charged to plant construction,
included the following components:
1994 1993
(Thousands of Dollars)
Service cost-benefits earned $ 696 $ 383
Interest cost on accumulated
postretirement benefit obligation 4 047 3 042
Actual loss (return) on plan assets 47 (7)
Amortization of unrecognized transition
obligation 1 976 1 986
Other net amortization and deferral 53 7
SFAS No. 106 postretirement cost 6 819 5 411
Regulatory deferral (457) (846)
Net postretirement cost $6 362 $4 565
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:
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $36 927 $35 189
Fully eligible employees 8 152 7 741
Other employees 14 035 14 635
Total obligation 59 114 57 565
Plan assets at market value 5 962 1 375
Accumulated postretirement benefit
obligation in excess of plan assets 53 152 56 190
Less:
Unrecognized cumulative net loss from
past experience different from that assumed 14 223 15 695
Unrecognized transition obligation, being
amortized over 20 years beginning
January 1, 1993 35 928 37 995
Postretirement benefit liability at
September 30 3 001 2 500
Fourth quarter contributions and benefit
payments 1 634 1 132
Postretirement benefit liability at
December 31 $1 367 $1 368
<PAGE>
F-48
The plan assets at market value are comprised of fixed income
securities, common stocks, and a short-term investment fund in
1994; and a short-term investment fund in 1993.
The unfunded accumulated postretirement benefit obligation
(APBO) at January 1, 1993, of $40,000,000 (transition obligation)
is being amortized prospectively over 20 years as permitted by
SFAS No. 106. In determining the APBO at September 30, 1994,
1993, and 1992, the discount rates used were 7.75%, 7.25%, and
8%, and the rates of increase in future compensation levels were
4.75%, 4.75%, and 5.5%, respectively. The 1994 expected long-term
rate of return on assets was 8.25% net of tax. For measurement
purposes, a health care trend rate of 9% for 1995, declining 1%
each year thereafter to 6.75% 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,
1994, by $4.1 million and the aggregate of the service and
interest cost components of net periodic postretirement benefit
cost for 1994 by $.4 million.
Note G-Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial
instruments at December 31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Liabilities:
Mandatorily redeemable
<S> <C> <C> <C> <C>
preferred stock $ 26 400 $ 25 542 $ 27 600 $ 28 566
Long-term debt 610 200 594 519 539 640 566 070
</TABLE>
The fair value of mandatorily redeemable preferred stock was
estimated based on quoted market prices. The fair value of
long-term debt 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 H-Stockholders' Equity:
COMMON STOCK AND OTHER PAID-IN CAPITAL:
The Company issued and sold common stock to its parent, at $20
per share, 2,500,000 shares in October 1993 and 4,000,000 shares
in September 1992. Other paid-in capital increased $10,000 in
1994 and decreased $2,000 in 1992 as a result of preferred stock
transactions.
<PAGE>
F-49
PREFERRED STOCK:
All of the preferred stock is entitled on voluntary liquidation
to its then current call price and on involuntary liquidation to
$100 a share.
MANDATORILY REDEEMABLE PREFERRED STOCK:
The Company's $7.16 preferred stock is entitled to a cumulative
sinking fund sufficient to retire 12,000 shares each year at $100
a share plus accrued dividends. The Company has the noncumulative
option in each year to retire up to an additional 12,000 shares
at the same price. The call price declines in future years.
Note I-Long-Term Debt:
Maturities for long-term debt for the next five years are:
1995, none; 1996, $18,700,000; 1997, $800,000; 1998, $1,800,000;
and 1999, $1,800,000. 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.
Note J-Short-Term Financing:
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. There was no short-term debt
outstanding at the end of 1994 or 1993. Average short-term debt
outstanding during the year for 1994 and 1993 consisted of:
1994 1993
(Thousands of Dollars)
Average amount outstanding
during the year:
Commercial Paper $1,021-3.96% $ 36-2.97%
Notes Payable to Banks 2,499-3.96% 1,112-3.24%
Money Pool 87-4.10% -
<PAGE>
F-50
Note K-Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $92 million
for 1995 and $98 million for 1996. These estimates include
expenditures for the program of complying with the Clean Air Act
Amendments of 1990 (CAAA) as discussed below.
ENVIRONMENTAL MATTERS:
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.
Construction estimates for 1995 and 1996 include $12 million and
$5 million, respectively, for compliance with Phase I of the
CAAA. Through 1998, annual construction expenditures, on average,
are not expected to significantly exceed 1995 estimated levels.
Construction expenditure levels in 1999 and beyond will depend
upon the strategy eventually selected for complying with Phase II
of the CAAA, as well as future generation requirements.
LITIGATION AND OTHER:
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 is guarantor as to 28% of a $50 million revolving
credit agreement of AGC, which in 1994 was used by AGC solely as
support for its indebtedness for commercial paper outstanding.
<PAGE>
F-51
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, 1994
and 1993, and the results of its operations and its cash flows
for each of the three years in the period ended December 31,
1994, 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 Notes A, B and F to the consolidated
financial statements, the Company changed its method of
accounting for revenue recognition in 1994 and for income taxes
and postretirement benefits other than pensions in 1993.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 2, 1995
<PAGE>
F-52
CONSOLIDATED STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
Electric Operating Revenues:
Residential $ 376 776 $ 358 900 $ 321 871
Commercial 207 165 194 773 177 697
Industrial 330 739 309 847 293 910
Nonaffiliated utilities 144 829 152 541 204 743
Other, including affiliates 68 733 68 916 78 620
Total Operating Revenues 1 128 242 1 084 977 1 076 841
Operating Expenses:
Operation:
Fuel 252 108 256 664 268 395
Purchased power and
exchanges, net 247 194 235 772 264 208
Deferred power costs,
net (Note A) 2 880 979 (1 527)
Other 145 781 131 854 116 913
Maintenance 111 841 96 706 93 067
Depreciation 88 935 80 872 73 469
Taxes other than income
taxes 87 224 89 249 87 300
Federal and state income
taxes (Note B) 50 385 51 529 44 078
Total Operating Expenses 986 348 943 625 945 903
Operating Income 141 894 141 352 130 938
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A) 6 729 5 077 5 010
Asset write-off, net (Note A) (5 179)
Other income, net 13 797 12 728 14 534
Total Other Income
and Deductions 15 347 17 805 19 544
Income Before Interest
Charges 157 241 159 157 150 482
Interest Charges:
Interest on long-term debt 58 102 58 857 53 768
Other interest 2 172 1 728 1 824
Allowance for borrowed funds used during
construction (Note A) (4 048) (3 489) (3 266)
Total Interest Charges 56 226 157 096 52 326
Consolidated Income Before Cumulative
Effect of Accounting Change 101 015 102 061 98 156
Cumulative Effect of Accounting Change,
net (Note A) 19 031
Consolidated Net Income $120 046 $102 061 $ 98 156
<PAGE>
F-53
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Balance at January 1 $412 288 $400 515 $392 331
Add:
Consolidated net income 120 046 102 061 98 156
532 334 502 576 490 487
Deduct:
Dividends on capital stock of the Company:
Preferred stock 8 504 8 206 7 331
Common stock 90 029 82 082 82 641
Total Deductions 98 533 90 288 89 972
Balance at December 31 (Note C) $433 801 $412 288 $400 515
See accompanying notes to consolidated financial statements.
<PAGE>
F-54
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
Cash Flows from Operations:
Consolidated net income $120 046 $102 061 $98 156
Depreciation 88 935 80 872 73 469
Deferred investment credit
and income taxes, net 699 (10 115) 809
Deferred power costs, net 2 880 979 (1 527)
Unconsolidated subsidiaries'
dividends in excess of
earnings 2 773 3 311 4 287
Allowance for other than borrowed funds used
during construction (6 729) (5 077) (5 010)
Cumulative effect of accounting change
before income taxes (Note A) (32 891)
Asset write-off before income
taxes (Note A) 8 919
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative effect
of accounting change
(Note A) 18 951 (5 947) 8 799
Materials and supplies (9 205) 26 889 (15 593)
Accounts payable (675) 3 196 3 877
Taxes accrued (4 502) 9 198 1 875
Interest accrued 2 620 (5 146) 3 534
Other, net 16 100 8 878 (8 989)
207 921 209 099 163 687
Cash Flows from Investing:
Construction expenditures (260 366) (251 017) (204 409)
Allowance for other than
borrowed funds used during
construction 6 729 5 077 5 010
(253 637) (245 940) (199 399)
Cash Flows from Financing:
Sale of common stock 40 000 100 000
Sale of preferred stock 39 450
Issuance of long-term debt 80 129 268 766 181 843
Retirement of long-term debt (251 414) (158 500)
Deposit with trustee for
redemption of long-term debt 68 354
Notes receivable from
affiliates 23 900 (4 000) (20 900)
Dividends on capital stock:
Preferred stock (8 504) (8 206) (7 331)
Common stock (90 029) (82 082) (82 641)
45 496 23 064 20 275
Net Change in Cash and
Temporary Cash Investments
(Note G) (220) (13 777) (15 437)
Cash and Temporary Cash
Investments at January 1 565 14 342 29 779
Cash and Temporary Cash
Investments at December 31 $ 345 $ 565 $ 14 342
Supplemental cash flow information
Cash paid during the year for:
Interest (net of
amount capitalized) $ 51 745 $ 61 329 $ 48 135
Income taxes 54 958 55 111 45 868
See accompanying notes to consolidated financial statements.
<PAGE>
F-55
CONSOLIDATED BALANCE SHEET
DECEMBER 31
1994 1993
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $103,514,000 and
$283,779,000 under construction $3 013 777 $2 803 811
Accumulated depreciation (1 009 565) (962 623)
2 004 212 1 841 188
Investments and Other Assets:
Allegheny Generating Company-common stock
at equity (Note D) 100 228 102 830
Other 1 474 1 537
101 702 104 367
Current Assets:
Cash and temporary cash investments (Note G) 345 565
Accounts receivable:
Electric service, net of $8,267,000 and $1,126,000
uncollectible allowance (Note A) 119 020 94 570
Affiliated and other 11 862 22 372
Notes receivable from affiliates (Note J) 1 000 24 900
Materials and supplies-at average cost:
Operating and construction 39 922 36 030
Fuel 38 205 32 892
Deferred income taxes 12 538 1 974
Prepaid and other 12 525 15 980
235 417 229 283
Deferred Charges:
Regulatory assets (Note B) 364 473 331 755
Unamortized loss on reacquired debt 10 494 11 645
Other 15 560 26 525
390 527 369 925
Total $2 731 858 $2 544 763
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes C and H) $ 955 482 $ 893 969
Preferred stock, not subject to
mandatory redemption (Note H) 149 708 149 708
Long-term debt (Note I) 836 426 782 369
1 941 616 1 826 046
Current Liabilities:
Long-term debt due within one year (Note I) 27 000
Accounts payable 107 792 105 493
Accounts payable to affiliates 6 477 9 451
Taxes accrued:
Federal and state income 9 217 11 533
Other 20 637 22 823
Interest accrued 16 475 13 855
Other 24 028 20 954
211 626 184 109
Deferred Credits and Other Liabilities:
Unamortized investment credit 52 946 55 524
Deferred income taxes 471 515 424 000
Regulatory liabilities (Note B) 39 881 40 834
Other 14 274 14 250
578 616 534 608
Commitments and Contingencies (Note K)
Total $2 731 858 $2 544 763
See accompanying notes to consolidated financial statements.
<PAGE>
<TABLE>
<CAPTION>
F-56
CONSOLIDATED STATEMENT OF CAPITALIZATION
DECEMBER 31
1994 1993 1994 1993
(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
2,000,000 shares in 1994 and 5,000,000 shares
<S> <C> <C> <C> <C>
in 1993) (Note H) $465 994 $425 994
Other paid-in capital (Note H) 55 687 55 687
Retained earnings (Note C) 433 801 412 288
Total 955 482 893 969 49.2% 49.0%
Preferred Stock of the Company (not subject to mandatory redemption):
Cumulative preferred stock-par value $100 per share,
authorized 3,097,077 shares, outstanding as follows (Note H):
December 31, 1994
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 100 000 103.94 1967 10 000 10 000
$7.12 E 100 000 103.49 1968 10 000 10 000
$8.08 G 100 000 103.27 1971 10 000 10 000
$7.60 H 100 000 103.23 1972 10 000 10 000
$7.64 I 100 000 103.16 1973 10 000 10 000
$8.20 J 200 000 103.30 1976 20 000 20 000
Auction 400 000 100.00 1992 40 000 40 000
Total (annual dividend requirements $8,847,847) 149 708 149 708 7.7 8.2
Long-Term Debt (Note I):
First mortgage
bonds of the Date of Date Date
Company: Issue Redeemable Due
4-7/8% U 1965 1995 1995 27 000 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 1994 2019 30 000 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
Interest Rate
Secured notes due 1998-2024 4.95%-9.375% 202 550 187 640
Unsecured notes due 2000-2007 6.10% 14 435 14 435
Unamortized debt discount and premium, net (7 559) (7 061)
Total (annual interest
requirements $61,854,043) 863 426 784 014
Less current maturities 27 000
Less amount on deposit with trustee 1 645
836 426 782 369 43.1 42.8
Total Capitalization $1 941 616 $1 826 046 100.0% 100.0%
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE>
F-57
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).
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 and 1992,
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 and transmission services to other
utilities, 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.
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
<PAGE>
F-58
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 1994, 1993,
and 1992 were 8.88%, 9.40%, and 9.25%, 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%, 3.4%,
and 3.3% of average depreciable property in 1994, 1993, and 1992,
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
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 recorded in accordance with the Financial Accounting
Standards Board (FASB) Statement of Financial Accounting
Standards (SFAS) No. 109, "Accounting for Income Taxes",
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, balances of which are being amortized over
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
<PAGE>
F-59
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 to Voluntary
Employee Beneficiary Association (VEBA) trust funds an amount
equal to the annual cost as determined by SFAS No. 106 (described
below). Medical benefits are self-insured; the life insurance
plan is paid through insurance premiums.
The FASB has prescribed the determination of annual pension and other
postretirement benefits expenses in SFAS No. 87, "Employers'
Accounting for Pensions", and SFAS No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions",
respectively. The Company records annual pension expense in
accordance with SFAS No. 87. Prior to 1994, regulatory deferrals
of these benefit expenses were recorded pursuant to SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation", for
its Pennsylvania jurisdiction which reflected as net expense the
funding of pensions and cash payments of other benefits in the
ratemaking process.
ASSET WRITE-OFF:
In 1994, the Company wroteoff $8.9 million ($5.2 million net
of income taxes) 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 is no
longer reasonable to assume future recovery of these costs in
rates.
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 the current
year's consolidated income before the cumulative effect of
accounting change, as well as on 1993 and 1992 consolidated net
income, is not material.
Effective January 1, 1993, the Company adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than
Pensions". Prior to 1993, medical expenses and life insurance
premiums paid for retired employees and their dependents were
recorded as expense in the period they were paid. Also effective
January 1, 1993, the Company adopted SFAS No. 109, "Accounting
for Income Taxes". This standard mandated a change from the
previous income-based deferral approach to a balance sheet-based
liability approach for computing deferred income taxes.
<PAGE>
<TABLE>
<CAPTION>
F-60
Note B-Income Taxes:
Details of federal and state income tax provisions are:
1994 1993 1992
(Thousands of Dollars)
Income taxes-current:
<S> <C> <C> <C>
Federal $46 964 $47 089 $37 965
State 13 282 14 983 5 884
Total 60 246 62 072 43 849
Income taxes-deferred,
net of amortization 3 277 (7 522) 3 403
Investment credit disallowed (2)
Amortization of deferred
investment credit (2 578) (2 592) (2 592)
Total income taxes 60 945 51 958 44 658
Income taxes-credited (charged) to other
income and deductions 3 300 (429) (580)
Income taxes-charged to accounting change
(including state income taxes) (13 860)
Income taxes-charged to
operating income $50 385 $51 529 $44 078
The total provision for income taxes is less than the amount
produced by applying the federal income statutory tax rate to
financial accounting income as set forth below:
1994 1993 1992
(Thousands of Dollars)
Financial accounting income
before cumulative effect
of accounting change and income taxes $151 400 $153 590 $142 234
Amount so produced $ 53 000 $ 53 800 $ 48 400
Increased (decreased) for:
Tax deductions for which deferred tax was not provided:
Lower (excess) tax depreciation 2 000 100 (200)
Plant removal costs (1 700) (900) (2 500)
State income tax, net of
federal income tax benefit 6 400 9 600 7 600
Amortization of deferred
investment credit (2 578) (2 592) (2 592)
Equity in earnings of subsidiaries (4 600) (4 300) (4 700)
Other, net (2 137) (4 179) (1 930)
Total $ 50 385 $ 51 529 $ 44 078
Federal income tax returns through 1991 have been examined and
substantially settled.
</TABLE>
<PAGE>
F-61
In adopting SFAS No. 109, the Company recognized a significant
increase in both deferred tax assets and liabilities. At December
31, the deferred tax assets and liabilities were comprised of the
following:
1994 1993
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit $ 38 560 $ 40 455
Unbilled revenue 9 539 21 626
Tax interest capitalized 16 165 10 750
State tax loss carryback/carryforward 5 535 8 790
Contributions in aid of construction 4 866 4 588
Other 18 905 7 416
93 570 93 625
Deferred tax liabilities:
Book vs. tax plant basis
differences, net 536 343 507 214
Other 16 204 8 437
552 547 515 651
Total net deferred tax liabilities 458 977 422 026
Add portion above included in
current assets 12 538 1 974
Total long-term net deferred
tax liabilities $471 515 $424 000
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
$351 million which offset the increase in deferred tax
liabilities. Regulatory liabilities of $39 million have been
recorded which offset the increase in deferred tax assets 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-Dividend Restriction:
Supplemental indentures relating to most outstanding bonds of
the Company contain dividend restrictions under the most
restrictive of which $285,914,000 of consolidated retained
earnings at December 31, 1994, 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 D-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.
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. Through February 29, 1992, AGC's return on equity
<PAGE>
F-62
(ROE) was adjusted annually pursuant to a settlement agreement
approved by the FERC. In December 1991, AGC 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 argues 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 AGC 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 is currently pending, which would reduce AGC's ROE to
11.13% for the period from March 1, 1992, through December 31,
1994, and increase AGC's ROE to 11.20% for the period from
January 1, 1995, through December 31, 1995.
Following is a summary of financial information for AGC:
December 31
1994 1993
(Thousands of Dollars)
Balance sheet information:
Property, plant, and equipment $680 749 $696 529
Current assets 5 991 11 063
Deferred charges 27 496 28 337
Total assets $714 236 $735 929
Total capitalization $489 894 $505 708
Current liabilities 6 484 21 891
Deferred credits 217 858 208 330
Total capitalization and liabilities $714 236 $735 929
<TABLE>
<CAPTION>
Year Ended December 31
1994 1993 1992
(Thousands of Dollars)
Income statement information:
<S> <C> <C> <C>
Electric operating revenues $91 022 $90 606 $96 147
Operation and maintenance expense 6 695 6 609 6 094
Depreciation 16 852 16 899 16 827
Taxes other than income taxes 5 223 5 347 5 236
Federal income taxes 14 737 13 262 14 702
Interest charges 17 809 21 635 22 585
Other income, net (11) (328) (21)
Net income $29 717 $27 182 $30 724
</TABLE>
Results for 1994 reflect the effect of the pending settlement
agreement. The Company's share of the equity in earnings above
was $13.4 million, $12.2 million, and $13.8 million for 1994,
1993, and 1992, respectively, and is included in other income,
net, on the Consolidated Statement of Income.
<PAGE>
F-63
Note E-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:
<TABLE>
<CAPTION>
1994 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost - benefits earned $ 5 124 $ 4 606 $ 4 272
Interest cost on projected
benefit obligation 14 051 13 773 13 312
Actual loss (return) on plan assets 358 (31 224) (24 750)
Net amortization and deferral (18 210) 14 262 (8 388)
SFAS No. 87 pension cost 1 323 1 417 1 222
Regulatory deferral $ - (1 309) (1 222)
Net pension cost $ 1 323 $ 108 $ -
</TABLE>
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:
1994 1993
(Thousands of Dollars)
Actuarial present value of
accumulated benefit obligation
earned to date (including
vested benefit of $150,168,000
and $151,394,000) $158 578 $160 097
Funded status:
Actuarial present value of
projected benefit obligation $191 787 $199 414
Plan assets at market value,
primarily common stocks and
fixed income securities 207 623 219 625
Plan assets in excess of
projected benefit obligation (15 836) (20 211)
Add:
Unrecognized cumulative net gain
from past experience different
from that assumed 15 103 17 586
Unamortized transition asset,
being amortized over 14 years
beginning January 1, 1987 8 427 9 678
Less unrecognized prior service
cost due to plan amendments 4 999 5 678
Pension cost liability at September 30 2 695 1 375
Fourth quarter contributions 2 843 -
Pension (prepayment) liability
at December 31 $ (148) $ 1 375
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, 1994, 1993, and 1992, the
discount rates used were 7.75%, 7.25%, and 7.75%, and the rates
of increase in future compensation levels were 4.75%, 4.75%, and
<PAGE>
F-64
5.25%, respectively. The expected long-term rate of return on
assets was 9% in each of the years 1994, 1993, and 1992.
Note F-Postretirement Benefits Other Than Pensions:
The Company adopted SFAS No. 106 as of January 1, 1993, which
requires accrual of postretirement benefits other than pensions
(principally health care and life insurance) for employees and
covered dependents during the years the employees render the
necessary service to receive such benefits. Prior to 1993,
medical expenses and life insurance premiums paid by the Company
for retired employees and their dependents were recorded in
expense in the period in which they were paid ($1,907,000 in
1992).
SFAS No. 106 postretirement cost in 1994 and 1993, a portion of
which (about 25% to 30%) was charged to plant construction,
included the following components:
1994 1993
(Thousands of Dollars)
Service cost - benefits earned $1 154 $ 939
Interest cost on accumulated
postretirement benefit obligation 4 461 4 389
Actual loss (return) on plan assets 31 (9)
Amortization of unrecognized
transition obligation 2 817 2 817
Other net amortization and deferral 83 9
SFAS No. 106 postretirement cost 8 546 8 145
Regulatory deferral - (1 963)
Net postretirement cost $8 546 $6 182
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:
1994 1993
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $35 895 $35 748
Fully eligible employees 8 290 9 030
Other employees 17 013 18 378
Total obligation 61 198 63 156
Plan assets at market value 6 173 1 510
Accumulated postretirement
benefit obligation in excess
of plan assets 55 025 61 646
Less:
Unrecognized cumulative net (gain)
loss from past experience
different from that assumed (543) 3 362
Unrecognized transition obligation,
being amortized over 20 years
beginning January 1, 1993 50 929 53 746
Postretirement benefit liability at
September 30 4 639 4 538
Fourth quarter contributions
and benefit payments 2 113 1 960
Postretirement benefit liability
at December 31 $2 526 $2 578
<PAGE>
F-65
The plan assets at market value are comprised of fixed income
securities, common stocks, and a short-term investment fund in
1994; and a short-term investment fund in 1993.
The unfunded accumulated postretirement benefit obligation
(APBO) at January 1, 1993, of $56,600,000 (transition obligation)
is being amortized prospectively over 20 years as permitted by
SFAS No. 106.
In determining the APBO at September 30, 1994, 1993, and 1992,
the discount rates used were 7.75%, 7.25%, and 8%, and the rates
of increase in future compensation levels were 4.75%, 4.75%, and
5.5%, respectively. The 1994 expected long-term rate of return on
assets was 8.25% net of tax. For measurement purposes, a health
care trend rate of 9% for 1995, declining 1% each year thereafter
to 6.75% 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, 1994, by $4.2 million and
the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for 1994 by $.4 million. The
Company has been authorized recovery of SFAS No. 106 expenses in
rates.
Note G-Fair Value of Financial Instruments:
The carrying amounts and estimated fair value of financial
instruments at December 31, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Assets:
<S> <C> <C> <C> <C>
Temporary cash investments $ 73 $ 73 $ 244 $ 244
Liabilities:
Long-term debt 870 985 826 003 791 075 823 333
</TABLE>
The carrying amount of temporary cash investments approximates
the fair value because of the short maturity of those
instruments. The fair value of long-term debt 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 H-Stockholders' Equity:
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 October 1993. Other paid-in capital decreased $145,000 in 1993
and $550,000 in 1992 as a result of the underwriting fees and
commissions and miscellaneous expenses associated with the
Company's sale of $40 million of preferred stock in 1992.
<PAGE>
F-66
PREFERRED STOCK:
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.
Note I-Long-Term Debt:
Maturities for long-term debt for the next five years are:
1995, $27,000,000; 1996 and 1997, none; 1998, $103,500,000; and
1999, $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.
Note J-Short-Term Financing:
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. There was no short-term debt
outstanding at the end of 1994 or 1993. Average short-term debt
outstanding during the year for 1994 and 1993 consisted of:
1994 1993
(Thousands of Dollars)
Average amount outstanding during the year:
Commercial Paper $2,216-4.38% -
Notes Payable to Banks 2,379-4.37% $9,081-3.18%
Money Pool 521-4.24% 1,166-3.01%
Note K-Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its construction
program, for which expenditures are estimated to be $172 million
for 1995 and $115 million for 1996. These estimates include
expenditures for the program of complying with the Clean Air Act
Amendments of 1990 (CAAA) as discussed below.
<PAGE>
F-67
ENVIRONMENTAL MATTERS:
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.
Construction estimates for 1995 and 1996 include $38 million and
$1 million, respectively, for compliance with Phase I of the
CAAA. Through 1998, annual construction expenditures, on average,
are not expected to significantly vary from 1995 estimated
levels. Construction expenditure levels in 1999 and beyond will
depend upon the strategy eventually selected for complying with
Phase II of the CAAA, as well as future generation requirements.
LITIGATION AND OTHER:
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 is guarantor as to 45% of a $50 million revolving
credit agreement of AGC, which in 1994 was used by AGC solely as
support for its indebtedness for commercial paper outstanding.
<PAGE>
F-68
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, 1994 and 1993, and
the results of its operations and its cash flows for each of the
three years in the period ended December 31, 1994, 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 Notes A and B to the financial statements,
the Company changed its method of accounting for income taxes in
1993.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 2, 1995
<PAGE>
<TABLE>
<CAPTION>
F-69
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C>
Electric Operating Revenues $91 022 $90 606 $96 147
Operating Expenses:
Operation and maintenance expense 6 695 6 609 6 094
Depreciation 16 852 16 899 16 827
Taxes other than income taxes 5 223 5 347 5 236
Federal income taxes (Note B) 14 737 13 262 14 702
Total Operating Expenses 43 507 42 117 42 859
Operating Income 47 515 48 489 53 288
Other Income and Deductions 11 328 21
Income Before Interest Charges 47 526 48 817 53 309
Interest Charges:
Interest on long-term debt 16 863 21 185 22 285
Other interest 946 450 300
Total Interest Charges 17 809 21 635 22 585
Net Income $29 717 $27 182 $30 724
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-70
STATEMENT OF RETAINED EARNINGS
<S> <C> <C> <C>
Balance at January 1 $18 512 $25 530 $34 593
Add:
Net income 29 717 27 182 30 724
48 229 52 712 65 317
Deduct:
Dividends on common stock 35 500 34 200 39 787
Balance at December 31 $12 729 $18 512 $25 530
See accompanying notes to financial statements.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
F-71
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1994 1993 1992
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income $29 717 $27 182 $30 724
Depreciation 16 852 16 899 16 827
Deferred investment credit
and income taxes, net 9 567 5 321 6 437
Changes in certain current assets and liabilities:
Accounts receivable 7 099 (6 118) (11)
Materials and supplies (2) (163) 131
Accounts payable 37 6 (242)
Taxes accrued (216) (153) (766)
Interest accrued (200) 632 361
Other, net (7 133) 4 851 1 853
55 721 48 457 55 314
Cash Flows from Investing:
Construction expenditures (1 065) (2 739) (3 251)
Cash Flows from Financing:
Issuance of long-term debt 198 075 2 364
Retirement of long-term debt (19 126) (209 598) (14 842)
Cash dividends on common stock (35 500) (34 200) (39 787)
(54 626) (45 723) (52 265)
Net Change in Cash 30 (5) (202)
Cash at January 1 15 20 222
Cash at December 31 $ 45 $ 15 $ 20
Supplemental cash flow information
Cash paid during the year for:
Interest $17 078 $21 109 $22 062
Income taxes 7 137 8 220 9 027
See accompanying notes to financial statements.
</TABLE>
<PAGE>
F-72
BALANCE SHEET DECEMBER 31
1994 1993
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $21,000 and $2,212,000 under
construction $824 714 $824 904
Accumulated depreciation (143 965) (128 375)
680 749 696 529
Current Assets:
Cash 45 15
Accounts receivable from parents 1 516 8 615
Materials and supplies -
at average cost 2 193 2 191
Other 2 237 242
5 991 11 063
Deferred Charges:
Regulatory assets (Note B) 4 449 4 489
Unamortized loss on reacquired debt 10 653 11 374
Other 12 394 12 474
27 496 28 337
Total $714 236 $735 929
<PAGE>
F-73
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 12 729 18 512
222 729 228 512
Long-term debt (Note D) 267 165 277 196
489 894 505 708
Current Liabilities:
Long-term debt due within one year
(Note D) 1 000 10 000
Accounts payable 48 11
Interest accrued 4 900 5 100
Taxes accrued 33 249
Other 503 6 531
6 484 21 891
Deferred Credits:
Unamortized investment credit 52 297 53 613
Deferred income taxes 137 297 125 848
Regulatory liabilities (Note B) 28 264 28 869
217 858 208 330
Total $714 236 $735 929
See accompanying notes to financial statements.
<PAGE>
F-74
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
regulation by the Securities and Exchange Commission (SEC) and by
the Federal Energy Regulatory Commission (FERC). Significant
accounting policies of the Company are summarized below.
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 1994, 1993, and 1992. 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
consolidated federal income tax return. The consolidated tax
liability is allocated among the participants generally in
proportion to the taxable income of each participant, except that
no subsidiary pays tax in excess of its separate return tax
liability.
Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions
for tax purposes are recorded in the financial income statement
in another period. Differences between income tax expense
computed on the basis of financial accounting income and taxes
payable based on taxable income are deferred. Deferred tax assets
and liabilities recorded in accordance with the Financial
Accounting Standards Board Statement of Financial Accounting
Standards (SFAS) No. 109, "Accounting for Income Taxes",
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.
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
<PAGE>
F-75
account, balances of which are being amortized over estimated
service lives of the related properties.
ACCOUNTING CHANGE:
Effective January 1, 1993, the Company adopted SFAS No. 109,
"Accounting for Income Taxes". This standard mandated a change
from the previous income-based deferral approach to a balance
sheet-based liability approach for computing deferred income
taxes.
Note B
Income Taxes:
Details of federal income tax provisions are:
<TABLE>
<CAPTION>
1994 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C>
Current income taxes payable $ 5 176 $ 8 112 $ 8 276
Deferred income taxes -
accelerated depreciation 10 883 6 637 7 758
Investment credit adjustment
Amortization of deferred
investment credit (1 316) (1 316) (1 322)
Total income taxes 14 743 13 433 14 713
Income taxes-charged to other income (6) (171) (11)
Income taxes-charged to operating income $14 737 $13 262 $14 702
</TABLE>
In 1994, the total provision for income taxes ($14,737,000) was
less than the amount produced by applying the federal income tax
statutory rate to financial accounting income before income taxes
($15,559,000), due primarily to amortization of deferred
investment credit ($1,316,000).
Federal income tax returns through 1991 have been examined and
substantially settled.
In adopting SFAS No. 109, the Company recognized a significant
increase in both deferred tax assets and liabilities. At December
31, the deferred tax assets and liabilities were comprised of the
following:
1994 1993
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit $ 28 160 $ 28 869
Other 104
28 264 28 869
Deferred tax liabilities:
Book vs. tax plant basis
differences, net 165 561 154 565
Other 152
165 561 154 717
Total net deferred tax liabilities $137 297 $125 848
<PAGE>
F-76
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 $4 million which
offset the increase in deferred tax liabilities. Regulatory
liabilities of $28 million have been recorded which offset the
increase in deferred tax assets 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, 1994 and 1993 were as follows:
<TABLE>
<CAPTION>
1994 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
(Thousands of Dollars)
Liabilities:
Long-term debt:
<S> <C> <C> <C> <C>
Debentures $150 000 $120 195 $150 000 $142 730
Medium-term notes 77 975 73 704 87 975 90 715
Commercial paper 41 736 41 736 21 362 21 362
Notes payable to
affiliates - - 29 500 29 500
</TABLE>
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 and notes payable to
affiliates 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.
<PAGE>
F-77
Note D
Long-Term Debt:
The Company had long-term debt outstanding as follows:
Interest December 31
Rate - % 1994 1993
(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 6.25 (1) 41 736 21 362
Medium-term notes
due 1994-1998 6.37 (1) 77 975 87 975
Notes payable to
affiliates 2.85 (2) 29 500
Unamortized
debt discount (1 546) (1 641)
Total $268 165 $287 196
Less current maturities 1 000 10 000
Total $267 165 $277 196
(1) Weighted average interest rate at December 31, 1994.
(2) Weighted average interest rate at December 31, 1993.
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 1998. Each bank has the option to
discontinue its loans after 1998 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. At the end of 1993, the Company had outstanding
$29,500,000 of money pool borrowings from affiliates.
Maturities for long-term debt for the next five years are:
1995, $1,000,000; 1996, $6,375,000; 1997, $10,600,000; 1998,
$101,736,000; and 1999, none.
<PAGE>
<TABLE>
<CAPTION>
S-1 SCHEDULE II
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1994, 1993, and 1992
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, 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
Year ended December 31, 1992 $ 3 744 270 $ 5 160 000 $ 2 253 279 $ 7 793 445 $ 3 364 104
(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, 1994, 1993, and 1992
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, 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
Year ended December 31, 1992 $ 1 080 499 $ 1 215 000 $ 597 147 $ 1 836 636 $ 1 056 010
(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, 1994, 1993, and 1992
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, 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
Year ended December 31, 1992 $ 1 214 562 $ 1 325 000 $ 684 931 $ 2 046 484 $ 1 178 009
(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, 1994, 1993, and 1992
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, 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
Year ended December 31, 1992 $ 1 449 209 $ 2 620 000 $ 971 201 $ 3 910 325 $ 1 130 085
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Supplementary Data
Quarterly Financial Data (Unaudited)
(Thousands of Dollars)
Income Before
Electric Operating Cumulative Effect of
1994 Revenues Operating Income Accounting Change
Quarter ended Reported Restated Reported Restated Reported Restated
APS
<C> <C> <C> <C> <C> <C> <C>
March 1994 $704 332 $697 299 $118 157 $115 118 $ 78 904 $ 75 865
June 1994 569 261 561 217 83 498 79 717 43 148 39 367
September 1994 595 313 591 123 92 946 90 855 51 898 49 807
December 1994 582 778 602 045 93 540 102 451 45 801 54 712
March 1993 614 678 107 524 67 609
June 1993 552 380 83 292 44 358
September 1993 583 311 94 119 54 527
December 1993 581 157 89 704 49 262
Monongahela
March 1994 187 909 24 294 17 580
June 1994 157 940 16 855 10 222
September 1994 165 932 20 613 13 523
December 1994 168 349 25 473 18 611
March 1993 165 542 24 289 18 252
June 1993 145 241 17 174 11 571
September 1993 165 489 22 038 15 787
December 1993 165 572 22 802 16 088
Potomac Edison
March 1994 226 901 223 648 39 028 37 350 32 285 30 607
June 1994 177 038 171 047 23 976 20 934 16 102 13 060
September 1994 180 971 179 114 24 359 23 109 16 278 15 028
December 1994 174 455 185 556 24 959 30 929 17 318 23 288
March 1993 196 182 33 963 26 779
June 1993 170 732 24 852 17 514
September 1993 172 780 23 605 17 372
December 1993 172 891 19 296 11 802
West Penn
March 1994 324 831 321 051 43 501 42 139 34 027 32 665
June 1994 266 000 263 946 31 616 30 877 22 745 22 006
September 1994 276 491 274 161 36 417 35 578 27 584 26 745
December 1994 260 920 269 084 30 360 33 300 16 659 19 599
March 1993 280 018 37 151 27 647
June 1993 259 873 29 284 20 311
September 1993 271 466 36 475 26 121
December 1993 273 620 38 442 27 982
AGC
March 1994 22 431 11 509 7 085
June 1994 21 869 11 253 6 771
September 1994 22 337 11 551 7 087
December 1994 24 385 13 202 8 774
March 1993 23 423 12 818 7 219
June 1993 23 730 12 745 7 478
September 1993 23 391 12 555 7 365
December 1993 20 062 10 371 5 120
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Supplementary Data (continued)
Quarterly Financial Data (Unaudited)
(Thousands of Dollars)
Earnings Per Share
Before Cumulative
Effect of
1994 Net Income Accounting Change Earnings Per Share
Quarter ended Reported Restated Reported Restated Reported Restated
APS
<C> <C> <C> <C> <C> <C> <C>
March 1994 $ 78 904 $119 311 $ .67 $ .65 $ .67 $ 1.02
June 1994 43 148 39 367 .37 .33 .37 .33
September 1994 51 898 49 807 .44 .42 .44 .42
December 1994 45 801 54 712 .38 .46 .38 .46
March 1993 67 609 .59 .59
June 1993 44 358 .39 .39
September 1993 54 527 .48 .48
December 1993 49 262 .42 .42
Monongahela
March 1994 17 580 25 525
June 1994 10 222 10 222
September 1994 13 523 13 523
December 1994 18 611 18 611
March 1993 18 252
June 1993 11 571
September 1993 15 787
December 1993 16 088
Potomac Edison
March 1994 32 285 47 078
June 1994 16 102 13 060
September 1994 16 278 15 028
December 1994 17 318 23 288
March 1993 26 779
June 1993 17 514
September 1993 17 372
December 1993 11 802
West Penn
March 1994 34 027 51 696
June 1994 22 745 22 006
September 1994 27 584 26 745
December 1994 16 659 19 599
March 1993 27 647
June 1993 20 311
September 1993 26 121
December 1993 27 982
AGC
March 1994 7 085
June 1994 6 771
September 1994 7 087
December 1994 8 774
March 1993 7 219
June 1993 7 478
September 1993 7 365
December 1993 5 120
</TABLE>
<PAGE>
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
For APS and the Subsidiaries, none.
<PAGE>
<TABLE>
<CAPTION>
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:
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) 54 1988 1988 1988 1988
William L. Bennett See below (b) 45 1991 1991 1991 1991
Klaus Bergman System employee (1) 63 1985 1985 1985 1979 1982
Stanley I. Garnett, II System employee (1) 51 1990 1990 1990 1990
Benjamin H. Hayes* System employee (1) 60 1992
Wendell F. Holland** See below (c) 42 1994 1994 1994 1994
Kenneth M. Jones System employee (1) 57 1991
Phillip E. Lint See below (d) 65 1989 1989 1989 1989
Edward H. Malone See below (e) 70 1985 1985 1985 1985
Frank A. Metz, Jr. See below (f) 60 1984 1984 1984 1984
Clarence F. Michalis*** See below (g) 72 1973 1973 1973 1973
Alan J. Noia System employee (1) 47 1994 1994 1987 1994 1994
Jay S. Pifer System employee (1) 57 1995 1995 1992
Steven H. Rice See below (h) 51 1986 1986 1986 1986
Gunnar E. Sarsten See below (i) 57 1992 1992 1992 1992
Peter L. Shea See below (j) 62 1993 1993 1993 1993
Peter J. Skrgic System employee (1) 53 1990 1990 1990 1989
(1) See Executive Officers of the Registrants in Part I of this report
for further details.
(a) Eleanor Baum. Dean of The Albert Nerken School of Engineering of
The Cooper Union for the Advancement of Science and Art. Director of
Avnet, Inc. and United States Trust Company. 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, Director and Chief Executive Officer
of Noel Group, Inc. Director of Belding Heminway Company, Inc.,
Global Natural Resources Inc., Lincoln Snacks Company, Simmons Outdoor
Corporation, Sylvan, Inc. and TDX Corporation. Formerly, general
partner, Discovery Funds, a venture capital affiliate of Rockefeller
& Company, 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, General 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) Clarence F. Michalis. Chairman of the Board of Directors of Josiah
Macy, Jr. Foundation, a tax-exempt foundation for medical research and
education. Director of Schroder Capital Funds Inc.
(h) Steven H. Rice. Bank consultant and attorney-at-law. Director and
Vice Chairman of the Board of Stamford Federal Savings Bank.
Formerly, President and Chief Operating Officer and Director of The
Seamen's Bank for Savings and Director of Royal Group, Inc. (The Royal
Insurance Companies).
(i) 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.
(j) 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.
* Benjamin H. Hayes retired effective January 1, 1995.
** Wendell F. Holland became a director effective September 8, 1994.
*** Clarence F. Michalis retired effective May 1, 1994.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
ITEM ll. EXECUTIVE COMPENSATION
During 1994, and for 1993 and 1992, the annual compensation paid by each of 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 each such
company whose cash compensation exceeded $100,000 was as follows:
Summary Compensation Tables
APS
Annual Compensation (a)
Other All
Name Annual Other
and Compen- Compen-
Principal sation sation
Position Year Salary($) Bonus($)(b) ($)(c) ($)(d)(e)
<S> <C> <C> <C> <C> <C>
Klaus Bergman, 1994 485,004 120,000 91,458
Chief Executive 1993 460,008 90,000 46,889
Officer (f) 1992 445,008 80,000 13,529
Alan J. Noia, 1994 236,336 57,000 47,867
President (f)(g) 1993 212,500 37,000 20,107
1992 200,000 38,000 7,975
Stanley I. Garnett, II 1994 219,336 47,000 70,213
Senior Vice President (f) 1993 206,004 40,000 24,006
1992 195,600 35,000 7,939
Peter J. Skrgic 1994 213,336 50,000 57,253
Senior Vice President (f) 1993 185,004 38,000 (h) 18,678
1992 175,008 31,000 (h) 8,325
Nancy H. Gormley 1994 175,008 37,000 22,478
Vice President (f) 1993 162,504 28,000 15,446
1992 150,000 28,000 8,159
(a) APS has no paid employees. All salaries and bonuses are paid by
APSC.
(b) Incentive awards are based upon performance in the year in which
the figure appears but are paid in the second quarter of the
following year. The incentive award plan will be continued for 1995.
(c) 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.
(d) 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. 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. 53. 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 1994, 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 $86,958 and
$4,500; Mr. Noia $43,367 and $4,500; Mr. Garnett $66,253 and
$3,960; and Mr. Skrgic $52,753 and $4,500; Ms. Gormley $17,978 and
$4,500, respectively.
(e) 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. After completion
of that cycle, performance share awards or cash may be granted if a
participant has met his or her performance criteria. Since the Plan
cycle will not be complete until 1997, no awards have
been granted and the amount which any named executive officer will
receive has not yet been determined.
(f) See Executive Officers of the Registrants for other positions held.
(g) Mr. Noia's compensation was paid by Potomac Edison through
August 31, 1994, after which time it was paid by APSC.
(h) Although less than 10% of total annual salary and bonus, Mr.
Skrgic received a $15,000 housing allowance in 1993 and 1992.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Summary Compensation Tables
MONONGAHELA
Annual Compensation
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($)(a) ($)(b)(c)
<S> <C> <C> <C> <C>
Klaus Bergman, 1994
Chief Executive 1993
Officer (d) 1992
Benjamin H. Hayes, 1994 197,500 58,000 92,880(f)
President (e) 1993 189,996 35,000 19,668
1992 180,000 30,000 11,114
Thomas A. Barlow 1994 124,750 19,500 16,687
Vice President 1993 119,496 18,000 12,777
1992 113,247 16,000 7,145
Robert R. Winter 1994 126,000 20,000 35,404
Vice President 1993 119,502 18,000 19,529
1992 112,002 17,000 6,332
Richard E. Myers 1994 116,166 14,000 18,734
Comptroller 1993 110,121 11,000 17,246
1992 104,581 10,000 7,486
(a) Incentive awards are based upon performance in the year in which the figure appears but are paid in the
second quarter of the following year. The incentive award plan will be continued for 1995.
(b) 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. 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. 53. 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 1994, the figure shown includes amounts
representing (a) the aggregate of life insurance premiums on the Group Life Insurance program and the
Executive Life Insurance and Secured Benefit Plans and (b) 401(k) contributions as follows: Mr. Hayes
$47,798 and $4,500; Mr. Barlow $12,947 and $3,740; Mr. Winter $31,627 and $3,777; and Mr. Myers $15,251
and $3,483, respectively.
(c) 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.
After completion of that cycle, performance share awards or cash may be granted if a participant has met
his or her performance criteria. Since the Plan cycle will not be complete until 1997, no awards have
been granted and the amount which any named executive officer will receive has not yet been determined.
(d) The total compensation Mr. Bergman received for services in all capacities to APS, APSC and the
Subsidiaries is set forth in the Summary Compensation Table for APS.
(e) Mr. Hayes retired effective January 1, 1995.
(f) Included in this amount is $40,500 representing accrued vacation for which he was paid.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Summary Compensation Tables
POTOMAC EDISON
Annual Compensation
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($)(a) ($)(b)(c)
<S> <C> <C> <C> <C>
Klaus Bergman, 1994
Chief Executive 1993
Officer (d) 1992
Alan J. Noia, 1994
President (d)(e) 1993
1992
Robert B. Murdock 1994 139,500 21,500 36,983(g)
Vice President(f) 1993 135,000 21,000 12,936
1992 128,914 19,000 8,853
James D. Latimer 1994 136,871 22,500 15,171
Executive Vice President 1993 119,996 17,000 12,971
1992 111,666 15,000 7,625
Thomas J. Kloc 1994 117,000 14,500 13,736
Comptroller 1993 112,500 11,000 11,204
1992 107,004 10,000 5,366
(a) Incentive awards are based upon performance in the year in which the figure appears but are paid in the
second quarter of the following year. The incentive award plan will be continued for 1995.
(b) 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. 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. 53. 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 1994 the figure shown includes amounts
representing (a) the aggregate of life insurance premiums on the Group Life Insurance program and the
Executive Life Insurance and Secured Benefit Plans and (b) 401(k) contributions as follows: Mr. Murdock
$11,172 and $4,081; Mr. Latimer $11,205 and $3,966; and Mr. Kloc $10,226 and $3,510, respectively.
(c) 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.
After completion of that cycle, performance share awards or cash may be granted if a participant has met
his or her performance criteria. Since the Plan cycle will not be complete until 1997, no awards have
been granted and the amount which any named executive officer will receive has not yet been determined.
(d) The total compensation Messrs. Bergman and Noia received for services in all capacities to APS, APSC and
the Subsidiaries is set forth in the Summary Compensation Table for APS.
(e) Mr. Noia's compensation was paid by Potomac Edison through August 31, 1994, after which time it was paid
by APSC. See note (d) above.
(f) Mr. Murdock retired effective January 1, 1995.
(g) Included in this amount is $21,730 representing accrued vacation for which he was paid.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Summary Compensation Tables
WEST PENN
Annual Compensation
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($)(a) ($)(b)(c)
<S> <C> <C> <C> <C>
Klaus Bergman, 1994
Chief Executive 1993
Officer (d) 1992
Jay S. Pifer, 1994 189,996 39,000 50,630
President 1993 175,500 25,000 18,093
1992 156,495 28,000 9,870
Thomas K. Henderson, 1994 129,164 20,000 29,223
Vice President 1993 124,004 19,000 17,570
1992 117,838 17,000 6,887
Charles S. Ault, 1994 122,000 18,500 20,249
Vice President 1993 114,419 16,000 12,673
1992 107,129 15,000 6,764
Charles V. Burkley, 1994 118,083 14,500 15,691
Comptroller 1993 112,996 11,000 10,544
1992 106,913 10,000 6,748
(a) Incentive awards are based upon performance in the year in which the figure appears but are paid in the
second quarter of the following year. The incentive award plan will be continued for 1995.
(b) 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. 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. 53. 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 1994 the figure shown includes amounts
representing (a) the aggregate of life insurance premiums on the Group Life Insurance program and the
Executive Life Insurance and Secured Benefit Plans and (b) 401(k) contributions as follows: Mr. Pifer
$46,130 and $4,500; Mr. Henderson $25,348 and $3,875; Mr. Ault $16,589 and $3,660; and Mr. Burkley $12,149
and $3,542, respectively.
(c) In 1994, the Boards of Directors of APS, APSC and the Operating Subsidiaries implemented a Performance
Share Plan (the "Plan") for senior officers which was approved by the shareholders of APS at the annual
meeting in May 1994. The first Plan cycle began on January 1, 1994 and will end on December 31, 1996.
After completion of that cycle, performance share awards or cash may be granted if a participant has met
his or her performance criteria. Since the Plan cycle will not be complete until 1997, no awards have
been granted and the amount which any named executive officer will receive has not yet been determined.
(d) The total compensation Mr. Bergman received for services in all capacities to APS, APSC and the
Subsidiaries is set forth in the Summary Compensation Table for APS.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Summary Compensation Tables
AGC
Annual Compensation (a)
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($) ($)
<S> <C>
(a) AGC has no paid employees.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Estimated
Name and Capacities Annual Benefits
Company in Which Served on Retirement (a)
APS (b)
<S> <C>
Klaus Bergman, $242,000
Chairman of the Board and
Chief Executive Officer (c)
Alan J. Noia, President 183,000
and Chief Operating
Officer * (c)
Stanley I. Garnett, II, 125,000
Senior Vice President,
Finance (c)
Peter J. Skrgic, 143,000
Senior Vice President (c)
Nancy H. Gormley, 95,900
Vice President (c)(d)
Monongahela
Klaus Bergman, $
Chief Executive Officer (c)(e)
Benjamin H. Hayes, 102,500
President (f)
Thomas A. Barlow, 72,700
Vice President (d)
Robert R. Winter, 74,000
Vice President (c)
Richard E. Myers, 70,000
Comptroller
* Elected President and Chief Operating Officer effective
September 1, 1994.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Estimated
Name and Capacities Annual Benefits
Company in Which Served on Retirement (a)
Potomac Edison
<S> <C>
Klaus Bergman, $
Chief Executive Officer (c)(e)
Alan J. Noia,
President (c)(e)
Robert B. Murdock, 70,500
Vice President (f)
James D. Latimer, 90,500
Executive Vice President
Thomas J. Kloc, 72,000
Comptroller
West Penn
Klaus Bergman, $
Chief Executive Officer (c)(e)
Jay S. Pifer, 76,500
President (c)
Thomas K. Henderson, 68,000
Vice President (c)
Charles S. Ault, 77,000
Vice President
Charles V. Burkley, 71,800
Comptroller (d)
Allegheny
Generating Company
No paid employees.
(a) 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, except that years before 1959 are not
taken into account for purposes of this average. 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 Securities and Exchange
Commission is described and included in the "All Other Compensation" column on pages 46-49. 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 1994, 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.
(b) APS has no paid employees. These executives are employees of APSC.
(c) See Executive Officers of the Registrants for other positions held.
(d) Mrs. Gormley, Mr. Barlow and Mr. Burkley have elected to retire in 1995. The actual pension amounts
which they will receive are set forth in the table.
(e) The total estimated annual benefits on retirement payable to Messrs. Bergman and Noia for services in
all capacities to APS, APSC and the Subsidiaries is set forth in the table for APS.
(f) Mr. Hayes and Mr. Murdock retired effective January 1, 1995. The actual pension amounts which they
are receiving are set forth in the table.
</TABLE>
<PAGE>
Employment Contracts
In February 1995, APS entered into employment contracts with
certain of the APS System 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
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 will consist of a cash payment
equal to 2.99 times the employee's annualized compensation together
with APS maintaining 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.
<PAGE>
Compensation of Directors
In 1994, 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
attended, except Executive Committee meetings which 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,
subject to SEC approval, 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>
<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 January 13, 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>
Charles S. Ault WP 4,562 Less than .01%
Thomas A. Barlow MP 7,205 "
Eleanor Baum APS,MP,PE,WP 2,000 "
William L. Bennett APS,MP,PE,WP 2,453 "
Klaus Bergman APS,MP,PE,WP,AGC 10,463 "
Charles V. Burkley WP 2,469 "
Stanley I. Garnett, II APS,MP,PE,WP,AGC 4,390 "
Nancy H. Gormley APS, MP 5,604 "
Benjamin H. Hayes MP 5,697 "
Thomas K. Henderson MP,PE,WP 4,095 "
Wendell F. Holland APS,MP,PE,WP 140 "
Kenneth M. Jones APS,AGC 4,520 "
Thomas J. Kloc PE,AGC 3,210 "
James D. Latimer PE 5,324 "
Phillip E. Lint APS,MP,PE,WP 600 "
Edward H. Malone APS,MP,PE,WP 1,468 "
Frank A. Metz, Jr. APS,MP,PE,WP 1,936 "
Robert B. Murdock PE 6,530 "
Richard E. Myers MP 4,367 "
Alan J. Noia APS,MP,PE,WP,AGC 11,202 "
Jay S. Pifer MP,PE,WP 7,856 "
Steven H. Rice APS,MP,PE,WP 2,148 "
Gunnar E. Sarsten APS,MP,PE,WP 5,000 "
Peter L. Shea APS,MP,PE,WP 1,400 "
Peter J. Skrgic APS,MP,PE,WP,AGC 5,633 "
Robert R. Winter MP,PE 3,410 "
All directors and executive officers
of APS as a group (18 persons) 68,522 Less than .075%
All directors and executive officers
of MP as a group (22 persons) 92,644
All directors and executive officers
of PE as a group (21 persons) 88,664
All directors and executive officers
of WP as a group (18 persons) 70,175
All directors and executive officers
of AGC as a group (8 persons) 44,994
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).
</TABLE>
<PAGE>
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For APS and the Subsidiaries, none.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND
REPORTS ON FORM 8-K
(a)(1)(2) The financial statements and financial statement schedules
filed as part of this Report are set forth under ITEM 8. and reference
is made to the index on page 43.
(b) No reports on Form 8-K were filed by System companies during the
quarter ended December 31, 1994.
(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>
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 2, 1995
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, 2/2/95
KLAUS BERGMAN Chief Executive Officer
(Klaus Bergman) and Director
(ii) Principal Financial Officer:
STANLEY I. GARNETT, II Senior Vice President, 2/2/95
(Stanley I. Garnett, II) Finance
(iii) Principal Accounting Officer:
KENNETH M. JONES Vice President 2/2/95
(Kenneth M. Jones) and Comptroller
(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: NANCY H. GORMLEY 2/2/95
(Nancy H. Gormley)
<PAGE>
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 2, 1995
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, 2/2/95
KLAUS BERGMAN Chief Executive
(Klaus Bergman) Officer, and Director
(ii) Principal Financial Officer:
NANCY L. CAMPBELL Treasurer 2/2/95
(Nancy L. Campbell)
(iii) Principal Accounting Officer:
RICHARD E. MYERS Comptroller 2/2/95
(Richard E. Myers)
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Alan J. Noia
*Klaus Bergman *Jay S. Pifer
*Stanley I. Garnett, II *Steven H. Rice
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone *Peter J. Skrgic
*By: NANCY H. GORMLEY 2/2/95
(Nancy H. Gormley)
<PAGE>
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 2, 1995
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, 2/2/95
KLAUS BERGMAN Chief Executive
(Klaus Bergman) Officer, and Director
(ii) Principal Financial Officer:
DALE F. ZIMMERMAN Secretary and 2/2/95
(Dale F. Zimmerman) Treasurer
(iii) Principal Accounting Officer:
THOMAS J. KLOC Comptroller 2/2/95
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Alan J. Noia
*Klaus Bergman *Jay S. Pifer
*Stanley I. Garnett, II *Steven H. Rice
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone *Peter J. Skrgic
*By: NANCY H. GORMLEY 2/2/95
(Nancy H. Gormley)
<PAGE>
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 2, 1995
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, 2/2/95
KLAUS BERGMAN Chief Executive
(Klaus Bergman) Officer, and Director
(ii) Principal Financial Officer:
KENNETH D. MOWL Secretary and 2/2/95
(Kenneth D. Mowl) Treasurer
(iii) Principal Accounting Officer:
CHARLES V. BURKLEY Comptroller 2/2/95
(Charles V. Burkley)
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Alan J. Noia
*Klaus Bergman *Jay S. Pifer
*Stanley I. Garnett, II *Steven H. Rice
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone *Peter J. Skrgic
*By: NANCY H. GORMLEY 2/2/95
(Nancy H. Gormley)
<PAGE>
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 2, 1995
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, 2/2/95
(Klaus Bergman) Chief Executive
Officer, and Director
(ii) Principal Financial Officer:
NANCY L. CAMPBELL Treasurer and 2/2/95
(Nancy L. Campbell) Assistant Secretary
(iii) Principal Accounting Officer:
THOMAS J. KLOC Comptroller 2/2/95
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Klaus Bergman
*Stanley I. Garnett, II
*Kenneth M. Jones
*Alan J. Noia
*Peter J. Skrgic
*By: NANCY H. GORMLEY 2/2/95
(Nancy H. Gormley)
<PAGE>
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the
Prospectus 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 Statement on Form S-3 (No. 33-51301); in the Prospectus
constituting part of The Potomac Edison Company's Registration
Statement on Form S-3 (No. 33-51305); and in the Prospectus
constituting part of West Penn Power Company's Registration Statement
on Form S-3 (Nos. 33-51303 and 33-56997); of our reports dated
February 2, 1995 included in ITEM 8 of this Form 10-K. We also
consent to the references to us under the heading "Experts" in such
Prospectuses.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
March 15, 1995
<PAGE>
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 NANCY H. GORMLEY and STANLEY I. GARNETT, II 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, 1994 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 Securities and Exchange Commission, granting unto said
attorneys and each of them full power and authority to do and
perform any act and thing necessary and proper to be done in the
premises, as fully and to all intents and purposes as the
undersigned could do if personally present, and the undersigned
hereby ratifies and confirms all that said attorneys or any one of
them shall lawfully do or cause to be done by virtue hereof.
Dated: February 2, 1995
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>
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
NANCY H. GORMLEY and STANLEY I. GARNETT, II 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 the Annual Report on Form 10-K
for the year ended December 31, 1994 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 Securities and Exchange
Commission, 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 2, 1995
JAY S. PIFER
(Jay S. Pifer)
PETER J. SKRGIC
(Peter J. Skrgic)
<PAGE>
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 NANCY H. GORMLEY and STANLEY I. GARNETT, II 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 the Annual
Report on Form 10-K for the year ended December 31, 1994 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
Securities and Exchange Commission, 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 2, 1995
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 (1-267), June 1990, exh. (a)(3)
4 Subsidiaries' Indentures described below.
10.1 Directors' Deferred Compensation Plan
10.2 Executive Compensation Plan
10.3 Allegheny Power System Incentive Compensation Plan
10.4 Allegheny Power System Supplemental Executive
Retirement Plan
10.5 Executive Life Insurance Program
and Collateral Assignment Agreement
10.6 Secured Benefit Plan
and Collateral Assignment Agreement
10.7 Restricted Stock Plan for Outside Directors
10.8 Retirement Plan for Outside Directors
10.9 Allegheny Power System Performance Share Plan
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.
18 Letter re: Change in Accounting Principles
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
E-1 (Cont'd)
EXHIBIT INDEX
(Rule 601(a))
Allegheny Power System, Inc.
Incorporation
Documents by Reference
<S> <C> <C>
21 Subsidiaries of APS:
Name of Company State of Organization
Allegheny Generating Company (a) Virginia
Allegheny Power Service Corporation Maryland
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 62 herein.
24 Powers of Attorney See pages 63-65
herein.
27 Financial Data Schedules
</TABLE>
<PAGE>
Exhibit 10.1
ALLEGHENY POWER SYSTEM
Revised Plan for Deferral
of Compensation of Directors
1. Any director may elect in a writing delivered to the
Secretary of the Company on or before December 31st of any year to
defer receipt of all or a specified part of his retainer and attendance
fees for services as a director, including without limitation annual
retainers and board and committee attendance fees, for the succeeding
calendar year and for all succeeding calendar years.
2. An election to defer for a single succeeding calendar year
shall be irrevocable. Any election effective for all succeeding years
shall remain in effect unless terminated by a communication in writing
from the director; such termination shall become effective with respect
to all amounts payable in the calendar year commencing after receipt of
such communication and shall not affect the treatment of amounts
deferred prior to the start of such calendar year.
3. Any person elected to fill a vacancy on the Board of
Directors and who was not a director on the preceding December 31st,
may make such written election before taking office in which event the
election will be effective from the start of his service as director.
4. In his written deferred election, the director may select
from the following alternatives for payment of the deferred amounts:
(a) Lump sum payment on January 2 of the year following
termination of service as director.
<PAGE>
(b) Payment in annual installments commencing on such January
2. (Minimum 3 installments)
(c) Payment in annual installments equal in number to the
number of years of service.
Such payment method selection shall be irrevocable unless an
alternative selection is made in writing more than 24 months prior to
termination of service as a director. If termination of service occurs
prior to the passage of 24 months after such action, the alternative
selection shall not take effect.
Each annual installment payment shall be such portion of the
amount credited to his deferred account at the prior December 31 as
will be in accordance with his payout selection.
5. The Company shall maintain a separate memorandum account of
the amounts deferred by each director and shall credit such account at
the end of each quarter with interest at a rate equivalent to the yield
on the Company's common stock for the 12 months ended on the last day
of that quarter.
6. In the event of a director's death prior to his or her
receipt of all of the deferred amounts and interest thereon, such funds
shall be paid to a beneficiary designated by him or, if no such
designation shall have been made, to his estate in full on the first
day of the calendar year following the year in which the director dies.
A beneficiary shall be designated in the written election to defer and
may be changed from time to time by filing written notice of such
change with the Secretary of the Company.
7. The Secretary of the Company shall provide to each director
a copy of this Revised Plan together with a form of agreement whereby a
director may elect to defer all or any part of his fees, in accordance
herewith.
<PAGE>
8. All deferral agreements in effect under the Plan prior to
adoption of this Revised Plan shall remain in effect, provided,
however, that, within 30 days after adoption of this Revised Plan, a
director whose termination of service will occur more than 36 months
after such adoption may select in writing for previously deferred
amounts and future compensation a payment option set forth above in
lieu of the option then in effect.
9. It is the intention of the parties that the above
arrangements be unfunded for tax purposes and for purposes of Title I
of ERISA to the extent that such Title shall be applicable hereto. The
director shall have the status of a general creditor of the Company
with respect to the amount in his account. The director's rights to
payments under the plan are not subject in any manner to anticipation,
alienation, sale, transfer, assignment, pledge, encumbrance, attachment
or garnishment by creditors of the director or the director's benefi-
ciaries.
10. The provisions of this Revised Plan may be amended by the
Board of Directors at any time provided that no such amendment may be
made that would deprive a director of any rights with respect to
amounts accrued hereunder as of the date of such amendment without his
written consent.
March 2, 1995
<PAGE>
Election to Defer Receipt of Directors Fees
Under the Directors Elective Deferred Fees
Plan of Allegheny Power System
Pursuant to Section 4 of the captioned Plan, I hereby elect
to defer receipt of ________% of all retainer and attendance
fees payable to me on and after January 1, 19__.
I elect to have my deferred account, with accumulated
interest, paid as follows, commencing with the 2nd day of
January following the termination of my service as a member
of the Board of Directors of Allegheny:
In a single lump sum, to be paid within 60 days after
such January 2.
In annual installment payments of equal amounts
(adjusted for interest credits) over _______ years (at
least 3) with such installment payments to be made on
January 2 of each year.
In annual installments of equal amounts (adjusted for
interest credits) on January 2 of each year, such
annual payments to be equal in number to the number of
years of service.
In the event of my death prior to receipt of all amounts I
have deferred under this Plan, including interest credits,
the balance of such deferred funds shall be paid in a lump
sum to the following designees who survive me or to my
estate in proportion to the percentage shares indicated,
and, if I have indicated no designees or if all indicated
designees predecease me, entirely to my estate.
Designee Address Percentage Share
Dated:
Signature
<PAGE>
Exhibit 10.2
CONFIDENTIAL
EXECUTIVE COMPENSATION PLAN
OBJECTIVES
To attract, hold, and motivate executive personnel.
Prior approval of the chief executive officer is required
for inclusion in the Plan.
QUALIFICATIONS
An employee becomes eligible for inclusion when
1. the employee has held a position with a salary
grade of 28 or above for at least one year, is
assuming the full responsibility of the position,
is achieving satisfactory results and has a salary
which exceeds the mid point between the minimum
and standard amounts of salary grade 28, or
2. the employee has held the position of operating
division manager with a salary grade of 18 or
above for at least one year, is assuming the full
responsibility of the position, is achieving satis-
factory results and has a salary which exceeds the
mid point between the minimum and standard amounts
of salary grade 28.
COMPENSATION
1. Life insurance
2. Dependent medical insurance
3. Dependent dental insurance
4. Annual physical examination during employment
5. Five weeks vacation, unless length of service
would warrant more.* Participants in the Plan
are not entitled to pay for accrued vacation
(or to vacation in lieu of such pay) in excess
of what they would receive if they were not par-
ticipants.
*Language clarified.
<PAGE>
Exhibit 10.2 (cont'd)
6. Sick pay allowance of one year at full pay and
one year at half pay, regardless of length of
service.
PROCEDURE
1. The president of each of the operating companies,
the Executive Director, Central Services and the
APS, Inc. vice presidents shall submit to the chief
executive officer the names of all eligible
employees or reasons why an employee, otherwise
eligible, should not be included, not less than 30
days prior to the employee's eligibility date.
2. The Vice President, Employee and Consumer Relations
maintains an official list of employees included in
the Executive Compensation Plan for all companies.
January 1, 1987
<PAGE>
Exhibit 10.3
ALLEGHENY POWER SYSTEM, INC.
1993 ANNUAL INCENTIVE PLAN
I. PURPOSE OF THE INCENTIVE PLAN
To attract and retain first quality managers in a com-
petitive job market and to reward superior performance.
II. ELIGIBILITY
The annual incentive plan is designed to reward
participating executives for achieving key goals for
the System and for the units for which they are
responsible.
A prerequisite for participation in the plan shall be
an understanding of and commitment to
-- The System Management Plan and Policies
-- The System's expectation that employees will observe
the highest ethical standards in their conduct of
System business and stewardship of its property.
Eligibility will be determined by the Management Review
Committee upon the recommendation of the CEO from among
executives whose responsibilities can affect System
performance.
III. AWARDS
Awards will reflect the importance of the participants
to the System and the units for which they are
responsible.
Awards will be paid for the achievement of specific
measurable goals set for the System, including goals
set the individual and the units for which he or she is
responsible.
The plan's goals will be:
-- Determined and communicated annually
-- A reasonable number for each participant
<PAGE>
The types of goals which the Board will set with the
help of the Management Review Committee include:
-- Financial performance (return on equity, earnings,
dividends)
-- Customer satisfaction (cost, quality, and
reliability of service)
-- Cost and environmental consciousness (productivity,
efficiency, availability and utilization of equipment)
and conservation of resources
-- Safety
-- Development of personnel for management positions,
including women and minorities
IV. OVERALL LIMITATIONS ON AWARDS
The Board of Directors shall not authorize any
incentivepayment if, in the Board's opinion, the
System's financial performance is less than
satisfactory from the perspective of its stockholders.
V. PERFORMANCE MEASURES
Each year measures to evaluate participants'
performance will be determined. They may vary among
participants according to whether their principal
responsibilities are to:
-- The System as a whole
-- An Operating Company
-- Bulk Power Supply or Central Services.
Each category of performance measure will carry
appropriate weightings as shown on 1993 Participant
Performance Schedule. Examples of possible measures
include:
For System as a whole
-- Quantity and quality of earnings: return on equity,
measured against previous year, authorized return on
equity and as appropriate peer companies; financial
ratings; capital structure, dividend payout ratios and
total return
-- Productivity, cost control, efficient use of
equipment, natural resources, and other environmental
considerations
-- Quality and reliability of customer service
-- Safety
<PAGE>
-- Attainment of reasonable rates and maintenance of
competitive position
For Operating Companies
-- Balance for common stock: return on equity
-- Safety
-- Productivity and efficiency: revenues from regular
customers, and administrative, operating, and
maintenance expenditures
- Per employee, customer, and kwh
- Measured against previous year and peer companies
-- Customer satisfaction (quality of service): outage
rates, speedy restoration of service, customer
complaints, employee courtesy, conservation and demand-
side management programs
-- Cost of service: rate per kwh measured against past
period, economic indices, and peer companies
-- Community relations and relations with state and
local governments and their agencies
-- Completion of construction projects on time and
within budget
-- Adequacy of management development programs
For Bulk Power Supply and Central Services
-- Adequacy of planning and accuracy of forecasts
-- Completion of assignments and projects on time and
within budget
-- Availability, efficiency, and reliability of
generating units and transmission systems
-- Safety
-- Cost consciousness (avoidance of excessive staffing
and waste of work space and receptivity to cost saving
techniques)
-- Minimizing adverse effects in the environment
-- User satisfaction
-- Adherence to System Purchasing Policy and success in
buying material, equipment, and supplies at the best
possible price.
<PAGE>
For Individual Performance
-- Initiative
-- Resourcefulness
-- Responsiveness
-- Identifiable results
-- Other
VI. CALCULATION OF AWARDS
Target Incentive Awards and Total Estimated Cost
-- No awards will be paid for any year unless the Board
of Directors finds that the System's financial
performance is satisfactory from the perspective of its
stockholders
-- 100% of a target incentive award will be paid to a
participant only if System, Responsibility Unit, and
Individual target performance measures are fully
achieved
Performance Schedules
-- The Performance Schedule describes ratings and
weightings for each performance measure at all levels
of performance
-- As soon as practicable each year, Participant
Performance Schedules for that year will be issued
Performance Ratings
-- Target performance represents the full and complete
attainment of expectations in the performance area; it
is rated 1.0
-- Performance that is acceptable but does not fully
meet expectations can earn a rating but, of course,
less than 1.0
-- Exceeding expectations can result in a performance
rating as high as 1.25
-- Unacceptable individual performance will result in
no award regardless of System or Unit Performance.
Weightings
-- Weightings will be established each year for System,
Unit and Individual performance measures.
<PAGE>
Calculation of Award
-- A participant's award, if any, will be determined by
multiplying the participant's assigned incentive
percentage times his/her rounded total performance
rating times his/her salary at the close of the year
prior to the year for which the award is to be made.
The Management Review Committee or the Board of
Directors,at its discretion, may supplement or decrease
any partici-pant's calculated award to reflect
extraordinary circumstances provided that it records
its reason for doing so.
VII. FORM AND TIMING OF PAYOUT
Calculation of awards will be made as soon as
practicable after the close of books for the year
measured, but no award will be paid until it has been
approved by the Management Review Committee or the
Board of Directors, as appropriate.
Payment will be in current cash unless the Management
Review Committee or the Board at its discretion
provides for deferral.
VIII. TERMINATION AND TRANSFER PROVISIONS
Termination Provisions
-- Awards may at the discretion of the Management
Review Committee or the Board be calculated on the
basis of a full year's performance and prorated to the
number of whole months actually served, except in the
case of voluntary termination (other than retirement
after the second quarter of the year) or termination by
the company (with or without cause), in which case no
award is made for year of termination.
Designation of "Unit" in cases of transfer among
Operating Companies, Central Services, Bulk Power
Supply, and New York
-- Weighting will be based on the number of months
participant was in each unit.
IX. PLAN ADMINISTRATION
Administration of the plan is the responsibility of the
Management Review Committee of the Board of Directors.
-- The Committee is responsible for review and
administration of all Systemwide goals and has final
approval over these and other matters involving the
plan, including eligibility.
<PAGE>
Exhibit 10.4
ALLEGHENY POWER SYSTEM
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
(Effective July 1, 1990)
<PAGE>
ALLEGHENY POWER SYSTEM
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
1. Purpose of the Plan:
The purpose of the Plan, the "Allegheny Power System
Supplemental Executive Retirement Plan" (hereinafter
referred to as the "Plan") is to provide for the
payment of supplemental retirement benefits to or in
respect of senior executives of Allegheny Power
System companies (hereinafter sometimes referred to
as a "Company" or the "Companies") as part of an
integrated executive compensation program which is
intended to assist the Companies in attracting,
motivating and retaining executives of superior
ability, industry, and loyalty.
2. Eligibility to Participate in the Plan:
Each employee of a Company who was a participant in
the Predecessor Plan or who on or after the
Effective Date is assigned 1990 salary grade 28 or
higher shall be a participant in the Plan.
3. Definitions:
A. Average Compensation -
shall mean 12 times the highest average
monthly earnings (including overtime and
other salary payments actually earned,
whether or not payment thereof is deferred)
for any 36 consecutive months.
B. Committee -
shall mean the Finance Committee of the Board
of Directors of Allegheny Power System, Inc.
C. Effective Date -
shall mean July 1, 1990.
D. Participant -
shall mean an employee who meets the
eligibility requirements of Section 2.
Retired Participant shall mean a Participant
who has retired from service after at least
10 years of service with one or more
Companies and on or after his/her 55th
birthday.
E. Plan Year -
shall mean the 12-month period on which the
fiscal records of the Plan are kept, which is
now the period from July 1st to June 30th.
F. Predecessor Plan -
shall mean the Allegheny Power System
Supplemental Executive Retirement Plans
effective July 1, 1982 and July 1, 1988.
<PAGE>
G. Supplemental Retirement Benefit Reduction -
shall mean the retirement benefit payable to
the Participant under the Allegheny Power
System Retirement Plan excluding any
increases in this benefit which become
effective after the Participant has retired.
H. Years of Service -
shall mean the Participant's Years of
Service, and fractional parts thereof, as
computed under the terms of the Allegheny
Power System Retirement Plan.
4. Supplemental Retirement Benefits:
A. Eligibility for Benefits -
A Participant shall be eligible for a benefit
from this Plan only (a) if he/she has at
least 10 Years of Service with one or more of
the Companies and (b) on or after his/her
55th birthday: provided that, if a
Participant is discharged from employment for
cause or terminates employment with the
Companies prior to retirement under the
Allegheny Power System Retirement Plan for
any reason whatsoever, other than death, such
eligibility will terminate and no benefit
shall be payable to such Participant from
this Plan. A Participant who dies in active
employment on or after his/her 55th birthday
shall be deemed to have retired one day
before his/her death.
B. Amount of Benefits -
(1) Subject to paragraph (2) of
this Subsection, an eligible
Participant will be entitled to
receive a supplemental
retirement benefit under this
Plan equal to his/her Average
Compensation multiplied by the
sum of:
(a) 2% times his/her
number of Years of
Service up to 25
years,
(b) 1% times his/her
number of Years of
Service from 25 to 30
years, and
(c) 1/2% times his/her
number of Years of
Service from 30 to 40
years less (x) such
Participant's
Supplemental
<PAGE>
Retirement Benefit
Reduction and (y) 2%
per year for each
year that a
Participant retires
prior to his/her 60th
birthday.
(2) The supplemental
retirement benefits
contemplated by
paragraph (1) of this
Subsection shall be
payable only to the
extent such benefits,
together with (i)
all retirement
benefits payable to
the Participant by
reason of employment
with another employer
(other than a benefit
payable under the
Federal Social
Security Act)
converted to the same
form as the benefit
paid under this Plan
by using the
actuarial equivalence
factors of the
Allegheny Power
System Retirement
Plan and (ii) the
retirement benefit
payable to the
Participant under the
Allegheny Power
System Retirement
Plan excluding any
increases in this
benefit which become
effective after the
Participant has
retired do not exceed
sixty percent (60%)
of his/her Average
Compensation, less 2%
per year for each
year the Participant
retires prior to
his/her 60th
birthday.
<PAGE>
C. Form and Time of Payment -
A benefit payable under this Plan shall be paid in such
form as the Participant shall elect from those
available, and at the same time as the retirement
benefit payable to the Retired Participant, under the
Allegheny Power System Retirement Plan. If the Benefit
payable under this Plan is paid other than as a life
annuity, the amount of the benefit when paid in such
other form shall be determined by using the actuarial
equivalence factors of the Allegheny Power System
Retirement Plan.
5. Vesting:
A Participant shall have no vested interest in the
Plan until he/she becomes eligible to receive
benefits under Section 4A. In the event such
eligible Participant is discharged from employment
for cause or terminates employment, other than by
death or retirement under the Allegheny Power System
Retirement Plan, any such interest which may have
vested shall be discontinued and forfeited.
6. Funding:
The Plan shall be unfunded. Benefits of a
Participant shall be paid from the general assets of
the Company employing the Participant at the time of
his/her retirement and a Participant shall have no
interest in any such assets under the terms of this
Plan until he/she becomes a Retired Participant. An
eligible Participant shall be an unsecured creditor
of the Company as to the payment of any benefit
under this plan.
7. Administration and Governing Law:
This Plan will be administered by and under the
direction of the Committee. The Committee shall
adopt, and may from time to time modify or amend,
such rules and guidelines consistent herewith as it
may deem necessary or appropriate for carrying out
the provisions and purposes of the Plan, which, upon
their adoption and so long as in effect, shall be
deemed a part hereof to the same extent as if set
forth in the Plan (hereinafter referred to as the
"Rules and Guidelines"). Any interpretation and
construction by the Committee of any provision of,
and the determination of any question arising under,
the Plan or the Rules and Guidelines shall be final,
conclusive, and binding upon the Participant,
his/her surviving spouse and all other persons. The
provisions of the Plan shall be construed,
administered, and enforced according to and governed
by the laws of the United States and the State of
New York.
8. Entire Agreement:
This Plan shall not be deemed to constitute a
contract between any Company and any employee or
other person in the employ of any Company, nor shall
<PAGE>
anything herein contained be deemed to give any
employee or other person in the employ of any
Company any right to be retained in the employ of
any Company or to interfere with the right of any
Company to discharge any employee or such other
person at any time and to treat an employee without
regard to the effect which such treatment might have
upon such employee as a Participant in the Plan.
9. Non-Assignability:
Neither a Participant, nor his beneficiary or any
other person, shall have any right to commute, sell,
assign, transfer, or otherwise convey the right to
receive any payments hereunder; which payments and
the right thereto are expressly declared to be
nonassignable and nontransferable. In the event of
any attempted assignment or transfer, the Companies
shall have no further liability hereunder. Nor
shall any payments be subject to attachment,
garnishment, or execution, or be transferable by
operation of law in the event of bankruptcy or
insolvency, except to the extent otherwise provided
by applicable law.
10. Termination or Amendment:
This Plan may be terminated as to any Company at any
time and amended from time to time by the Board of
Directors of that Company; provided that neither
termination nor amendment of the Plan may reduce or
terminate any benefit to or in respect of a
Participant eligible to receive benefits under
Section 4A.
<PAGE>
Exhibit 10.5
AGREEMENT
EXECUTIVE LIFE INSURANCE PROGRAM
AND COLLATERAL ASSIGNMENT
THIS AGREEMENT is entered into this day of ,
19 , by and between Allegheny Power System, Inc.,
(hereinafter called "the Employer" in Part I or "Assignee"
in Part II), and
(hereinafter called "the Employee").
WHEREAS the Employee is currently a valued employee and
Executive of Employer; Whereas the Employer wishes to assist
the Employee with his (or her) personal life insurance
program and the Employee desires to accept such assistance;
and
WHEREAS in consideration of the Assignee agreeing to pay all
of the
premiums, the Owner agrees to grant the Assignee a security
for the recovery of the Assignee's premium outlay.
NOW, THEREFORE for value received, the Employer and the
Employee agree as follows:
PART I - Individual Life Insurance Agreement
A. Description of Policy - Policy Ownership
In furtherance of the purposes of the Agreement,
The Employee will purchase and own a certain
policy of life insurance on his own life, being
Policy No. issued
by Security Life of Denver Insurance Company.
Said policy is hereinafter called "the Policy" and
said life insurance company is hereinafter called
"the Insurer". The Employee's ownership of the
Policy shall be subject to all the terms and
conditions set forth in this Agreement.
B. Payment of Premiums
The Employer shall pay the entire annual premium
for the Policy directly to the Insurer.
C. Collateral Assignment and
Possession of Policy
To secure repayment of premiums paid by the
Employer provided for in Section B, above, Part II
of this Agreement includes an assignment of the
policy or the Employee's interest therein
<PAGE>
(hereinafter called "Collateral Assignment") and
provides for the transfer of possession of the
Policy to the Employer during the term specified
in Part II of this Agreement. Except as provided
in or as otherwise consistent with the provisions
of this Agreement, the Employer covenants that it
will not exercise its rights under the Collateral
Assignment provisions of this Agreement in such a
manner as to defeat the rights of the Employee or
the policy beneficiary under this Agreement.
Specifically, the Employer covenants that it will
not surrender the Policy unless Part I of the
Agreement has terminated as provided in Section F
and there has been a default in Employee's
obligation under Section G of this Part I. The
Employer shall have possession of the Policy
during the period that the Employer makes premium
payments and until all such payments are repaid.
The Employer shall make the Policy available to
the Insurer in order to make any change desired by
the Employee as to the designation of beneficiary
or the selection of a settlement option, subject,
however, to the Collateral Assignment provisions
hereof.
D. Beneficiary Designation and
Payment of Policy Proceeds
The Employee shall be entitled to a death benefit
from the Policy equal to one (1) times his base
salary, excluding bonuses, until his retirement.
At retirement, his death benefit shall increase to
two (2) times salary for the next 12 months, then
shall decrease by 20% of final salary each year
until the earlier of the fifth anniversary of
retirement or age 70, at which time it will be one
(1) times salary.
The Employee shall have the right to name the
Policy beneficiary. However, in the event of the
Employee's death, the Employer shall have an
interest in the Policy proceeds equal to the total
Policy proceeds in excess of the amount due to the
Employee pursuant to this Section above.
E. Procedure at Employee's Death
Upon the death of the Employee while the policy
and this Agreement are in force and subject to the
provisions of Parts I and II hereof, the Employer
shall promptly take all necessary steps, including
rendering of such assistance as may reasonably be
required by the Employee's beneficiary, to obtain
payment from the Insurer of the amounts payable
under the Policy to the respective parties, as
provided under Section D, above.
<PAGE>
F. Termination of Agreement
Part I of this Agreement shall terminate when the
first of any of the following events occur:
1. Termination of the Employee's employment with
the Employer prior to retirement;
2. The later of the Employee's actual retirement
or ten years from the date of issuance of the
Policy;
3. Performance of the Agreement's terms
following the death of the Employee;
4. Failure by the Employer, for any reason, to
make the premium contributions required under
Section B of this Agreement;
G. Disposition of Policy Upon Termination of
Agreement
Upon the termination of Part I of this Agreement
for any reason other than Section F3 above, the
Employee shall have a thirty (30) day option to
satisfy the Collateral Assignment regarding the
policy held by the Employer in accordance with the
terms of this Paragraph G. The amount necessary
to satisfy such Collateral Assignment shall be an
amount equal to the total premium payments made,
from time to time, greater than the amount of cash
value under the Policy and, at the option of the
Employee, either shall be paid directly by the
Employee or through the Employer's collection from
the cash value under the policy.
If the Policy shall then be encumbered by
assignment, policy loan, or other means which have
been the result of the Employer's actions, the
Employer shall either remove such encumbrance, or
reduce the amount necessary to satisfy the
Collateral Assignment by the total amount of
indebtedness outstanding against the Policy. If
the Employee exercises his option to satisfy the
Collateral Assignment, the Employer shall execute
all necessary documents required by the Insurer to
remove and satisfy the Collateral Assignment
outstanding on the Policy. If the Employee does
not exercise his option to satisfy the Collateral
Assignment outstanding on the Policy, the Employee
shall execute all documents necessary to transfer
ownership of the Policy to the Employer. Such
Transfer shall constitute satisfaction of any
obligation the Employee has to the Employer with
respect to this Agreement. The Employer shall
then pay to the Employee the amount, if any, by
which the cash surrender value of the Policy
exceeds the amount necessary to satisfy the
Collateral Assignment.
H. Employee's Right to Assign His/Her Interest
The Employee shall have the right to transfer
his/her entire interest in the Policy (other than
rights assigned to the Employer pursuant to this
<PAGE>
Agreement and subject to the obligations of any
outstanding Collateral Assignment). If the
Employee makes such a transfer, all his/her rights
shall be vested in the Transferee and the Employee
shall have no further interest in the Policy and
Agreement. Any assignee shall be subject to all
obligations of the Employee under both Parts I and
II of this Agreement.
I. Insurer's Obligations
The Insurer is not party to this Agreement. It is
understood by the parties hereto that in issuing
such Policy of insurance, the Insurer shall have
no liability except as set forth in the Policy and
except as set forth in any assignment of the
Policy filed at its Home Office and in Section J
of this Agreement. Except as set forth in Section
J, the Insurer shall not be bound to inquire into,
or take notice of, any of the covenants herein
contained as to the Policy of insurance or as to
application of proceeds of such Policy. Upon the
death of the Insured and payment of the proceeds
in accordance with Section J of this Agreement,
the insurer shall be discharged of all liability.
J. Claims Procedure
The following claims procedure shall apply to the
Policy and the Executive Life Insurance Program:
1. Filing of a claim for benefits. The Employee
or the beneficiary of the Policy shall make a
claim for the benefits provided under the
Policy in the manner provided in the Policy.
2. Claim denial. With respect to a claim for
benefits under said Policy, the Insurer shall
be the entity which reviews and makes
decisions on claim denials according to the
terms of the Policy.
3. Notification to claimant of decision. If a
claim is wholly or partially denied, notice
of the decision, meeting the requirements of
Section J4, following shall be furnished to
the claimant within a reasonable period of
time after a claim has been filed.
4. Content of notice. The Insurer shall
provide, to any claimant who is denied a
claim for benefits, written notice setting
forth in a manner calculated to be understood
by the claimant, the following:
a. The specific reason or reasons for the
denial;
b. Specific reference to pertinent Policy
provisions or provisions of this
Agreement on which the denial is based;
c. A description of any additional material
or information necessary for the
claimant to perfect the claim and an
explanation of which such material or
<PAGE>
information is necessary; and
d. An explanation of this Agreement's claim
review procedure, as set forth in
Sections J5 and J6.
5. Review procedure. The purpose of the review
procedure set forth in this subsection and
subsection 6, following, is to provide a
method by which a claimant under the Policy
may have a reasonable opportunity to appeal a
denial of claim for a full and fair review.
To accomplish that purpose, the claimant or
his/her duly authorized representative:
a. May request a review upon written
application to the Insurer;
b. May review the Policy; and
c. May submit issues and comments in
writing.
A claimant, (or his/her duly authorized
representative), shall request a review by
filing a written application of review at any
time within sixty (60) days after receipt by
the claimant of written notice of the denial
of the claim.
6. Decision on review. A decision on review of
a denial of a claim shall be made in the
following matter;
a. The decision on review shall be made by
the Insurer which may, at its
discretion, hold a hearing on the denied
claim. The Insurer shall make its
decision promptly, unless special
circumstances (such as the need to hold
a hearing) require an extension of time
for processing, in which case a decision
shall be rendered as soon as possible,
but not later than on hundred twenty
(120) days after receipt of the request
for review.
b. The decision on review shall be in
writing and shall include specific
reasons for the decision, written in a
manner calculated to be understood by
the claimant, and specific references to
the pertinent Policy provision or
provision of this Agreement on which the
decision is based.
Notwithstanding any provision of the Agreement or
the Policy, no Employee, assignee or beneficiary
may commence any action in any court regarding the
Policy prior to pursuing all rights of an Employee
under this Section J.
<PAGE>
PART II - Assignment of Life Insurance Policy as Collateral
A. For value received and in specific consideration of
the premium payments made by the Employer as set
forth in Section B of Part I hereof, the Employee
hereby assigns, transfers and sets over to the
Employer (herein in this Part II called the
"Assignee"), its successors and assigns, the Policy
issued by the Insurer upon the life of Employee and
all claims, options, privileges, rights, titles and
interest therein and thereunder (except as provided
in Paragraph C hereof), subject to all terms and
conditions of the Policy and to all superior liens,
if any, which the Insurer may have against the
Policy. The Employee by this instrument agrees and
the Assignee by the acceptance of this assignment
agrees to the conditions and provisions herein set
forth.
B. It is expressly agreed that, without detracting from
the generality of the foregoing, the following
specific rights are included in this Agreement and
Collateral Assignment and inure to the Assignee by
virtue hereof:
1. The sole right to collect from the Insurer
the net proceeds of the Policy in excess of
the proceeds due the Employee under Part I,
Section D when it becomes a claim by death or
maturity;
2. The sole right to surrender the Policy and
receive the surrender value thereof at any
time provided by the terms of the Policy and
at such other times as the Insurer may allow;
3. The sole right to obtain one or more loans or
advances on the policy, either from the
Insurer or, at any time, from other persons,
and to pledge or assign the Policy as
security for such loans or advances;
4. The sole right to collect and receive all
distributions or share of surplus, dividend
deposits or additions to he Policy now or
hereafter made or apportioned thereto, and to
exercise any and all options contained in the
Policy with respect thereto; provided, that
unless and until the Assignee shall notify
the Insurer in writing to the contrary, the
distributions or share of surplus, dividend
deposits and additions shall continue on the
Policy in force at the time of this
assignment; and
5. The sole right to exercise all nonforfeiture
rights permitted by the terms of the Policy
or allowed by the Insurer and to receive all
benefits and advantages derived therefrom.
C. It is expressly agreed that the following specific
rights, so long as the Policy has not been
surrendered, are reserved and excluded from this
Agreement and Collateral Assignment and do not pass
by virtue hereof:
<PAGE>
1. The right to designate and change the
beneficiary;
2. The right to elect any optional mode of
settlement permitted by the Policy or allowed
by the Insurer;
provided, however, that the reservation of these
rights shall in no way impair the right of the
Assignee to surrender the Policy completely with
all its incidents or impair any other right of the
Assignee hereunder, and any designation or change
of beneficiary or election of a mode of settlement
shall be made subject to this Agreement and
Collateral Assignment and to the rights of the
Assignee hereunder.
D. This Collateral Assignment is made and the Policy is
to be held as collateral security for any and all
liabilities of the Employee to the Assignee arising
under this Agreement (all of which liabilities
secured to or to become secured are herein called
"Liabilities"). It is expressly agreed that all
sums received by the Assignee hereunder either in
event of death of the Insured, the maturity or
surrender of the Policy, the obtaining of a loan or
advance on the Policy, or otherwise, shall first be
applied to the payment of the liability for premiums
paid by the Assignee on the Policy.
E. The Assignee covenants and agrees with the Employee
as follows:
1. That any balance of sums, if any, received
hereunder from the Insurer remaining after
payment of the existing Liabilities, matured
or unmatured, shall be paid by the Assignee
to the persons entitled thereto under the
terms of the policy had this Collateral
Assignment not been executed:
2. That the Assignee will not exercise either
the right to surrender the Policy or the
right to obtain policy loans from the
Insurer, until there has been either default
in any of the Liabilities pursuant to this
Agreement or termination of Part I of said
Agreement as therein provided; and
3. That the Assignee will, upon request, forward
without reasonable delay to the Insurer the
Policy for endorsement of any designation or
change of beneficiary or any election of an
optional mode of settlement.
F. The Employee declares that no proceedings in
bankruptcy are pending against him/her and that
his/her property is not subject to any assignment
for the benefit of creditors.
<PAGE>
PART III - Provisions Applicable to Parts I an II
A. Amendments
Amendments may be added to this Agreement by a
written agreement signed by each of the parties
and attached hereto.
B. Choice of Law
This agreement shall be subject to, and construed
according to, the laws of the State of
.
C. A Binding Agreement
This Agreement shall bind the Employer and the
Employer's successors and assigns, the Employee
and his/her heirs, executors, administrators, and
assigns, and any Policy beneficiary.
D. Provision
The Employer and the Employee agree that if any
provision of this Agreement is determined to be
invalid or unenforceable, in whole or part, then
all remaining provisions of this Agreement and, to
the extent valid or enforceable, the provision in
question shall remain valid, binding and fully
enforceable as if the invalid or unenforceable
provisions, to the extent necessary, was not a
part of this Agreement.
IN WITNESS WHEREOF, parties hereto have executed this
Agreement, including the provisions regarding Collateral
Assignment, on the day and year first above written.
Witness Employee
Address
Employer (Title)
<PAGE>
Exhibit 10.6
AGREEMENT
SECURED BENEFIT PLAN
AND COLLATERAL ASSIGNMENT
THIS AGREEMENT is entered into this _____ day of __________, 1992 by
and between Allegheny Power Service Corporation (hereinafter called the
"Employer" in Part I or "Assignee" in Part II), and
___________________________ (hereinafter called the "Employee").
WHEREAS the Employee is currently a valued employee and Executive of
Employer;
WHEREAS the Employer wishes to assist the Employee with his (or her)
personal future financial program and the Employee desires to accept
such
assistance; and
WHEREAS in consideration of the Employer agreeing to pay all of the
premiums, the Employee agrees to grant the Employer security for the
recovery
of the Employer's premium outlay and the excess, if any, over the
amounts due
the Employee under Part I of this Agreement.
NOW, THEREFORE, for value received, the Employer and the Employee
agree as follows:
Part I - Individual Life Insurance Agreement
A. Description of Policy - Policy Ownership
In furtherance of the purposes of the Agreement, the Employee will
purchase and own a certain policy of life insurance on his own
life, being Policy No. _____, issued by Pacific Mutual Life
Insurance Co. Said policy is hereinafter called the "Policy" and
said life insurance company is hereinafter called the "Insurer".
The Employee's ownership of the Policy shall be subject to all the
terms and conditions set forth in this Agreement.
B. Payment of Premiums
The Employer shall pay the entire annual premium for the Policy
directly to the Insurer.
C. Collateral Assignment and Possession of Policy
To secure repayment of premiums paid by and amounts due to the
Employer provided for in Section B, above, and Sections D and E,
below, Part II of this Agreement includes an assignment of the
policy or the Employee's interest therein (hereinafter called
"Collateral Assignment") and provides for the transfer of
possession of the policy, and the right to receive from the
carrier and possess billings and policy statements, to the
<PAGE>
Employer during the term specified in Part II of this Agreement.
Except as provided in or as otherwise consistent with the
provisions of this Agreement, the Employer covenants that it will
not exercise its rights under the Collateral Assignment provisions
of this Agreement in such a manner as to defeat the rights of the
Employee or the policy beneficiary under this Agreement.
Specifically, the Employer covenants that it will not surrender
the Policy unless Part I of the Agreement has terminated as
provided in Section G and there has been a default in Employee's
obligation under Section H of this Part I. The Employer shall
have possession of the Policy during the period that the Employer
makes premium payments and until all amounts due the Employer are
repaid. The Employer shall make the Policy available to the
Insurer in order to make any change desired by the Employee as to
the designation of beneficiary or the selection of a settlement
option, subject, however, to the provisions of this Agreement and
the Collateral Assignment.
D. Beneficiary Designation and Payment of Policy Proceeds
The Employee shall be entitled to a death benefit from the Policy
in the amount required to provide an annuity equal to (under then
current annuity settlement rates from the Insurer) the
supplemental retirement benefit that would be provided under
Sections 4A and 4B of the Allegheny Power System Supplemental
Executive Retirement Plan effective July 1, 1990, attached hereto
as Appendix I, excluding the provision in Section 4A that states,
"...provided that, if a Participant is discharged from employment
for cause or terminates employment with the Companies prior to
retirement under the Allegheny Power System Retirement Plan for
any reason whatsoever, other than death, such eligibility will
terminate and no benefit shall be payable to such Participant from
this Plan."
The Employer shall be the sole beneficiary of the policy until
such time as the Employee has at least 10 years of service and is
at least 55 years old. After that time and while this Agreement
is in force, the following shall occur:
1. the beneficiary of the Employee's death benefit shall be
the employee's spouse;
2. in the event of the Employee's death, the Employer shall be
entitled to Policy proceeds equal to the total Policy
proceeds in excess of the amount due to the Employee
pursuant to this Section, above; and
3. if the employee is not married, he/she is entitled to no
death benefit while this agreement is in force.
E. Policy Cash Values
The Employee shall be entitled to cash values of the Policy in
excess of the premiums paid by the Employer pursuant to Section B,
Above, but not to exceed the death benefits to which he/she is
entitled under Section D, above. If the Employee is not married,
he/she shall be entitled to cash values determined as if he/she
were married.
The Employer shall be entitled to Policy cash values in excess of
the amount due to the Employee under this Section, above.
<PAGE>
F. Procedure at Employee's Death
Upon the death of the Employee while the Policy and this Agreement
are in force and subject to the provisions of Parts I and II
hereof, the Employer shall promptly take all necessary steps,
including rendering of such assistance as may reasonably be
required, to obtain payment from the Insurer of the amounts
payable under the Policy to the respective parties, as provided
under Section D, above.
G. Termination of Agreement
Part I of this Agreement shall terminate when the first of any of
the following events occur:
1. Termination of the Employee's employment with the Employer
prior to retirement;
2. The later of the Employee's actual retirement or ten years
from the date of issuance of the policy;
3. Performance of the Agreement's terms following the death of
the Employee;
4. Failure by the Employer, for any reason, to make the
premium contributions required under Section B of this
Agreement.
H. Disposition of Policy Upon Termination of Agreement
Upon the termination of Part I of this Agreement for any reason
other than Section G3 above, the Employee shall have a thirty (30)
day option to satisfy the Collateral Assignment regarding the
policy held by the Employer in accordance with the terms of this
Paragraph H. The amount necessary to satisfy such Collateral
Assignment shall be an amount equal to the total premium payments
made by the Employer, plus any excess amounts as determined in
Section E, above, but no greater than the amount of cash value
under the Policy and, at the option of the Employee, either shall
be paid directly by the Employee or through the Employer's
collection from the cash value of the Policy.
If the Policy shall then be encumbered by assignment, policy loan,
or other means which have been the result of the Employer's
actions, the Employer shall either remove such encumbrance, or
reduce the amount necessary to satisfy the Collateral Assignment
by the total amount of indebtedness outstanding against the
Policy. If the Employee exercises his option to satisfy the
Collateral Assignment, the Employer shall execute all necessary
documents required by the Insurer to remove and satisfy the
Collateral Assignment outstanding on the Policy. If the Employee
does not exercise his option to satisfy the Collateral Assignment
outstanding on the Policy, the Employee shall execute all
documents necessary to transfer ownership of the Policy to the
Employer. Such transfer shall constitute satisfaction of any
obligation the Employee has to the Employer with respect to this
Agreement. The Employer shall then pay to the Employee the
amount, if any, by which the cash surrender value of the Policy
exceeds the amount necessary to satisfy the Collateral Assignment.
<PAGE>
I. Employee's Right to Assign His/Her Interest
Employee agrees not to sell, assign, surrender or otherwise
terminate the policy while this Agreement is in effect without
the consent of the Employer.
J. Insurer's Obligations
The Insurer is not a party to this Agreement. It is understood by
the parties hereto that in issuing such Policy of insurance, the
Insurer shall have no liability except as set forth in the Policy
and except asset forth in any assignment of the Policy filed at it
Home Office and in Section K of this Agreement. Except as set
forth in Section K, the Insurer shall not be bound to inquire
into, or take notice of, any of the covenants herein contained as
to the Policy of insurance or as to application of proceeds of
such policy. Upon the death of the Insured and payment of the
proceeds in accordance with Section K of this Agreement, the
Insurer shall be discharged of all liability.
K. Claims Procedure
The following claims procedure shall apply to the Policy and the
Secured Benefit Plan:
1. Filing of a claim for benefits. The Employee or the
Beneficiary shall make a claim for the benefits provided
under the policy in the manner provided in the Policy.
2. Claim denial. With respect to a claim for benefits under
said Policy, the Insurer shall be the entity which reviews
and makes decisions on claim denials according to the terms
of the Policy.
3. Notification to claimant of decision. If a claim is wholly
or partially denied, notice of the decision, meeting the
requirements of Section K4, following, shall be furnished
to the claimant within a reasonable period of time after a
claim has been filed.
4. Content of notice. The insurer shall provide, to any
claimant who is denied a claim for benefits, written notice
setting forth in a manner calculated to be understood by
the claimant, the following:
a. The specific reason or reasons for the denial;
b. Specific reference to pertinent Policy provisions
or provisions of this Agreement on which the denial
is based;
c. A description of any additional material or
information necessary for the claimant to perfect
the claim and an explanation of why such material
or information is necessary; and
d. An explanation of this Agreement's claim review
procedure, as set forth in Sections K5 and K6.
<PAGE>
5. Review procedure. The purpose of the review procedure set
forth in this subsection and subsection 6, following, is to
provide a method by which a claimant under the Policy may
have a reasonable opportunity to appeal a denial of claim
for a full and fair review. To accomplish that purpose,
the claimant or his/her duly authorized representative:
a. May request a review upon written application to
the Insurer;
b. May review the Policy; and
c. May submit issues and comments in writing.
A claimant, (or his/her duly authorized representative),
shall request a review by filing a written application of
review at any time within sixty (60) days after receipt by
the claimant of written notice of the denial of the claim.
6. Decision on review. A decision on review of a denial of a
claim shall be made in the following matter:
a. The decision on review shall be made by the Insurer
which may, at its discretion, hold a hearing on the
denied claim. The Insurer shall make its decision
promptly, unless special circumstances (such as the
need to hold a hearing) require an extension of
time for processing, in which case a decision shall
be rendered as soon as possible, but not later than
one hundred twenty (120) days after receipt of the
request for review.
b. The decision on review shall be in writing and
shall include specific reasons for the decision,
written in a manner calculated to be understood by
the claimant, and specific references to the
pertinent Policy provision or provision of this
Agreement on which the decision is based.
Notwithstanding any provision of the Agreement or
the Policy, no Employee, assignee or beneficiary
may commence any action in any court regarding the
Policy prior to pursuing all rights of an Employee
under this Section K.
<PAGE>
END OF PART I
Part II - Assignment of Life Insurance Policy as Collateral
A. For value received and in specific consideration of the premium
payments made by the Employer as set forth in Section B of Part
I hereof, the Employee hereby assigns, transfers and sets over
to the Employer (herein this Part II called the "Assignee"),
its successors and assigns, the Policy issued by the Insurer
upon the life of Employee and all claims, options, privileges,
rights, titles and interest therein and thereunder (except as
provided in Paragraph C hereof), subject to all terms and
conditions of the Policy and to all superior liens, if any,
which the Insurer may have against the Policy. The Employee by
this instrument agrees and the Assignee by the acceptance of
this Assignment agrees to the conditions and provisions herein
set forth.
B. It is expressly agreed that, without detracting from the
generality of the foregoing, the following specific rights are
included in this Agreement and Collateral Assignment and inure
to the Assignee by virtue hereof:
1. The sole right to collect from the Insurer the net proceeds
of the Policy in excess of the proceeds due the Employee
under Part I, Section D, when it becomes a claim by death
or maturity;
2. The sole right to surrender the Policy and receive the
surrender value thereof at any time provided by the terms
of the Policy and at such other times as the Insurer may
allow;
3. The sole right to obtain one or more loans or advances on
the policy, either from the Insurer or, at any time, from
other persons, and to pledge or assign the Policy as
security for such loans or advances;
4. The sole right to exercise all nonforfeiture rights
permitted by the terms of the Policy or allowed by the
Insurer and to receive all benefits and advantages derived
therefrom;
5. The sole right to direct investment of cash values as
provided under the insurance contract, and to make changes
and transfers in such fund allocations.
C. It is expressly agreed that the following specific rights, so
long as the Policy has not been surrendered, are reserved and
excluded from this Collateral Assignment and do not pass by
virtue hereof:
1. The right to designate and change the beneficiary;
2. The right to elect any optional mode of settlement
permitted by the Policy or allowed by the Insurer;
provided, however, that the reservation of these rights
shall in no way impair the right of the Assignee to
surrender the Policy completely with all its incidents or
impair any other right of the Assignee hereunder, and
any designation or change of beneficiary or election of a
mode of settlement shall be made subject to this Agreement
and Collateral Assignment and to the rights of the Assignee
hereunder.
D. This Collateral Assignment is made, and the Policy is to be
held as collateral security for, any and all liabilities of the
Employee to the Assignee arising under this Agreement (all of
which liabilities secured or to become secured are herein
called "Liabilities"). It is expressly agreed that all sums
received by the Assignee hereunder either in the event of death
of the Insured, the maturity or surrender of the Policy, the
obtaining of a loan or advance on the Policy, or otherwise,
shall first be applied to the payment of the liability for
premiums paid by the Assignee on the Policy and other amounts
due to Assignee under Part I of this Agreement.
<PAGE>
E. The Assignee covenants and agrees with the Employee as follows:
1. That any balance of sums, if any, received hereunder from
the Insurer remaining after payment of the existing
Liabilities, matured or unmatured, shall be paid by the
Assignee to the persons entitled thereto under the terms of
the policy had this Collateral Assignment not be executed;
2. That the Assignee will not exercise either the right to
surrender the Policy or the right to obtain policy loans
from the Insurer, until there has been either default in
any of the Liabilities pursuant to this Agreement or
termination of part I of said Agreement as therein
provided; and
3. That the Assignee will, upon request, forward without
unreasonable delay to the Insurer the Policy for
endorsement of any designation or change of beneficiary or
any election of an optional mode of settlement.
F. The Employee declares that no proceedings in bankruptcy are
pending against, him/her and that his/her property is not
subject to any assignment for the benefit of creditors.
Part III - Provisions Applicable to Parts I and
II
A. Amendments
Amendments may be added to this Agreement by a written
agreement signed by each of the parties and attached hereto.
B. Choice of Law
This Agreement shall be subject to, and construed according to,
the laws of the State of Maryland.
C. Binding Agreement
This Agreement shall bind the Employer and the Employer's
successors and assigns, the Employee and his/her heirs,
executors, administrators, and assigns, and any Policy
beneficiary.
D. Validity of Provisions
The Employer and the Employee agree that if any provision of
this Agreement is determined to be invalid or unenforceable, in
whole or part, then all remaining provisions of the Agreement
and, to the extent valid or enforceable, the provision in
question shall remain valid, binding and fully enforceable as
if the invalid or unenforceable provisions, to the extent
necessary, was not a part of this Agreement.
IN WITNESS WHEREOF, parties hereto have executed this Agreement,
including the provisions regarding Collateral Assignment, on the day
and year
first above written.
________________________ _________________________
Witness Employee
____________________________
_____________________________
Address
Allegheny Power Service Corporation
By: ____________________________
Richard J. Gagliardi
Vice President
<PAGE>
Exhibit 10.7
ALLEGHENY POWER SYSTEM, INC.
RESTRICTED STOCK PLAN FOR OUTSIDE DIRECTORS
1. Purpose. The purpose of this Restricted Stock Plan for
Outside Directors (the "Plan") is to enable Allegheny Power
System, Inc. ("APS") and its controlled subsidiaries
("Subsidiaries") to attract and retain persons of outstanding
competence to serve on the Boards of Directors of APS and its
Subsidiaries by paying such persons a portion of their
retainer fee in APS Common Stock pursuant to the terms hereof.
2. Definitions.
(a) The term "Change in Control" shall be deemed to
mean, and to occur at, the time when either (i) any
entity, person or group (other than APS, any subsidiary,
or any savings, pension or other benefit plan for the
benefit of employees of APS or its subsidiaries) which
theretofore owned less than 20% of the APS Common Stock
then outstanding acquires shares of Common Stock in a
transaction or series of transactions that results in
such entity, person or group directly or indirectly
owning beneficially 20% or more of the outstanding Common
Stock or (ii) the election or appointment, within a
twelve-month period, of persons to the APS Board of
Directors who were not directors of APS at the beginning
of such twelve-month period, whose election or
appointment was not voted or approved in advance by a
majority of those persons who were directors at the
beginning of such period, and which newly elected or
appointed directors shall constitute a majority of the
APS Board of Directors.
(b) The term "Outside Director" or "Participant"
means a member of the Boards of Directors of APS and its
Subsidiaries who is not, at any time during his service
as a director, an employee (within the meaning of Section
3(6) of the Employee Retirement Income Security Act of
1974) of APS or any of its Subsidiaries.
(c) The term "Subsidiary" means any corporation 50%
or more of the outstanding Common Stock of which is
owned, directly or indirectly, by APS.
(d) The term "Service" shall mean service as an
Outside Director.
3. Eligibility. All who serve as Outside Directors of APS
and any of its Subsidiaries after calendar year 1994 shall be
eligible to receive stock awards hereunder.
<PAGE>
4. Stock Awards.
(a) A total of 25,000 shares of APS Common Stock
shall be available for awards under the Plan. Such
shares shall be shares of APS Common Stock previously
unissued or previously issued and reacquired by APS. Any
restricted shares awarded under this Plan with respect to
which the restrictions do not lapse and which are
forfeited as provided herein shall be transferred into
the record name of APS and again be available for other
awards under the Plan.
(b) Unless he or she chooses otherwise pursuant to
Section 4(e), each Outside Director shall receive an
annual award of 200 shares of APS Common Stock with
respect to each calendar year or portion thereof during
which he or she serves as an Outside Director beginning
with the calendar year 1995. Awards shall be made in
January of each year or as soon thereafter as all
necessary regulatory approvals have been received.
However, for the calendar year in which an Outside
Director commences Service, the award of shares to such
Outside Director for such year shall be made in the month
in which his or her Service commences, if his or her
Service commences after January 31 of such year. All
awards of shares made hereunder shall be subject to the
restrictions set forth in Section 5.
(c) Subject to the provisions of Section 5, certifi-
cates representing shares of APS Common Stock awarded
hereunder shall be registered in the name of the
respective Participants. During the period of time such
shares are subject to the restrictions set forth in
Section 5, such certificates shall be endorsed with a
legend to that effect, and shall be held by APS or an
agent therefor. The Participant shall, nevertheless,
have all the other rights of a shareholder, including the
right to vote and the right to receive all cash dividends
paid with respect to such shares. Subject to the
requirements of applicable law, certificates representing
such shares shall be delivered to the Participant within
30 days after the lapse of the restrictions to which they
are subject.
(d) If as a result of a stock dividend, stock split,
recapitalization (or other adjustment in the stated
capital of APS) or as the result of a merger,
consolidation, or other reorganization, the common shares
of APS are increased, reduced, or otherwise changed, the
number of shares available and to be awarded hereunder
shall be appropriately adjusted, and if by virtue thereof
a Participant shall be entitled to new or additional or
different shares, such shares to which the Participant
shall be entitled shall be subject to the terms,
conditions, and restrictions herein contained relating to
the original shares. In the event that warrants or
rights are awarded with respect to shares awarded
hereunder, and the recipient exercises such rights or
warrants, the shares or securities issuable upon such
exercise shall be likewise subject to the terms,
conditions, and restriction herein contained relating to
the original shares.
<PAGE>
(e) (i) Each Outside Director may choose prior to the
effective date of the Plan or prior to his/her initial
election as a Director and annually thereafter to receive
Alternate Shares in lieu of the annual award of shares
subject to the restrictions set forth in Section 5. If
the Director chooses to receive Alternate Shares, he/she
shall receive certificates representing 200 shares of APS
Common Stock free of the restrictions set forth in
Section 5(a) and (b) but subject to the restriction set
forth in Section 5(c).
(ii) Any such choice will be effective only if
made in a writing delivered to the Secretary of APS prior
to the effective date of the Plan or, with respect to
awards for years subsequent to 1995, prior to the date of
the APS stockholders meeting held prior to the calendar
year of the award. An Outside Director elected other
than at an annual meeting who desires to choose not to
receive shares restricted by Section 5 shall do so in a
writing delivered to the APS Secretary prior to his/her
election. Any choice so made shall continue in effect
until the Outside Director shall timely deliver to the
Secretary a writing revoking the prior choice.
5. Restrictions.
(a) Shares are awarded to a Participant on the condi-
tion that he or she serves as an Outside Director until:
(i) the Participant's death or disability; or
(ii) the Participant's failure to stand for
re-election at the end of the term during
which the Participant reaches age 65; or
(iii) the Participant's resignation or failure
to stand for re-election prior to the end
of the term during which the Participant
reaches age 65 with the consent of the
Board, i.e., approval thereof by at least
80% of the Directors voting thereon, with
the affected Director abstaining; or
(iv) the Participant's failure to be re-
elected after being duly nominated.
<PAGE>
For purposes of this Plan, "disability" shall mean a
Participant's complete and permanent inability, by reason
of illness or accident, to perform his or her duties as
a member of the Board, as determined by the
Administration Committee based on medical evidence
acceptable to it.
Termination of Service of a Participant for any other
reason, including, without limitation, any involuntary
termination effected by Board action, shall result in
forfeiture of all shares awarded. Notwithstanding the
foregoing, upon the occurrence of a Change in Control,
the restrictions set forth in this Section 5 to which any
shares awarded to a Participant are then still subject
shall lapse, and termination of the Participant's Service
for any reason at any time after the occurrence of such
Change in Control shall not result in the forfeiture of
any such shares.
(b) Shares awarded hereunder may not be sold,
assigned, exchanged, transferred, pledged, hypothecated,
made subject to gift, or otherwise disposed of (herein,
"Transferred") other than to APS pursuant to Section 4(a)
during the period commencing on the date of the award of
such shares and ending on the date of termination of the
Outside Director's Service; provided, however, that in no
event, may any shares awarded hereunder be Transferred
for a period of six months following the date of the
award thereof, except in the case of the recipient's
death or disability, other than to APS pursuant to
Section 4(a) hereof.
(c) Each Participant shall represent and warrant to
and agree with APS that he or she (i) takes any shares
awarded under the Plan for investment only and not for
purposes of sale or other disposition and will also take
for investment only and not for purposes of sale or other
disposition any rights, warrants, shares or securities
which may be issued on account of ownership of such
shares, and (ii) will not sell or transfer any shares
awarded or any shares received upon exercise of any such
rights or warrants except in accordance with (A) an
opinion of counsel for APS (or other counsel acceptable
to APS) that such shares, rights, warrants or other
securities may be disposed of without registration under
the Securities Act of 1933, or (B) an applicable "no
action" letter issued by the Staff of the Securities and
Exchange Commission.
6. Administration Committee. An Administration Committee
(the "Committee") shall have full power and authority to
construe and administer the Plan. Any action taken under the
provisions of the Plan by the Committee arising out of or in
connection with the administration, construction, or effect of
the Plan or any rules adopted thereunder shall, in each case,
lie within the discretion of the Committee and shall be
conclusive and binding upon APS and upon all Participants, and
all persons claiming under or through any of them.
Notwithstanding the foregoing, any determination made by the
Committee after the occurrence of a Change in Control that
denies in whole or in part any claim made by any individual
for benefits under the Plan shall be subject to judicial
review, under a "de novo", rather than a deferential,
standard. The Committee shall have as members the Chief
Executive Officer of APS and two officers of APS or its
Subsidiaries designated by the Chief Executive Officer. In
the absence of such designation, the other members of the
Committee shall be, in order of automatic designation, the
Vice President Administration and the Secretary of APS.
<PAGE>
7. Successor Corporation. The obligations under this Plan
shall be binding upon any successor corporation or
organization resulting from the merger, consolidation or other
reorganization of APS, or upon any successor corporation or
organization succeeding to substantially all of the assets and
business of APS. APS agrees that it will make appropriate
provision for the preservation of Participants' rights under
this Plan in any agreement or plan which it may enter into or
adopt to effect any such merger, consolidation, reorganization
or transfer of assets.
8. Right to Continued Service. Neither this Plan nor any
action taken hereunder shall be construed as giving any
employee any right to continued service as a Director of APS.
9. No Liability of Committee Members. No member of the
Committee shall be personally liable by reason of any contract
or other instrument executed by such member or on his or her
behalf in his or her capacity as a member of the Committee nor
for any mistake of judgment made in good faith, and APS shall
indemnify and hold harmless each member of the Committee, and
each employee, officer, director or trustee of APS or any of
its Subsidiaries to whom any duty or power relating to the
administration or interpretation of this Plan may be allocated
or delegated, against any cost or expense (including counsel
fees) or liability (including any sum paid in settlement of a
claim with the approval of the Board of Directors) arising out
of any act or omission to act in connection with this Plan
unless arising out of such person's own fraud or bad faith.
10. Governing Law. This Plan shall be governed by and
construed in accordance with the laws of the state of
incorporation of APS, without reference to the principles of
conflicts of law thereof.
11. Approval: Effective Date. The Plan is subject to the
approval of the Securities and Exchange Commission under the
Public Utility Holding Company Act of 1935. Upon receipt of
such approval, the Plan shall be effective January 1, 1995.
<PAGE>
12. Amendment and Termination. The Plan may be amended or
terminated by the Board of Directors of APS, provided that, if
any such amendment requires shareholder approval to meet the
requirements of the then applicable rules under Section 16(b)
of the Securities Exchange Act of 1934, such amendment shall
require the approval of a majority of the holders of APS's
Common Stock present and entitled to vote at a meeting of
shareholders, and provided that such action shall not
adversely affect any Participant's rights under the Plan with
respect to awards which were made prior to such action.
Notwithstanding the foregoing, Section 4(b) of the Plan may
not be amended more often than once every six months other
than to comport with changes in the Internal Revenue Code or
the Employee Retirement Income Security Act, or the rules
thereunder.
<PAGE>
Exhibit 10.8
ALLEGHENY POWER SYSTEM
BOARD OF DIRECTORS RETIREMENT PLAN
(Effective January 1, 1995)
<PAGE>
ALLEGHENY POWER SYSTEM
BOARD OF DIRECTORS RETIREMENT PLAN
13. Purpose of the Plan:
The purpose of the Plan, the "Allegheny Power System
Board of Directors Retirement Plan" (hereinafter referred
to as the "Plan") is to provide for the payment of
retirement benefits to the outside directors of Allegheny
Power System, Inc. (hereinafter sometimes referred to as
"Company") and its controlled subsidiaries (the
"Subsidiaries") as part of their overall directors'
remuneration package. This will help to assist the
Companies in attracting, motivating and retaining
directors of superior ability, and loyalty.
14. Eligibility to Participate in the Plan:
Each person who is a Director of the Company and the
Subsidiaries on January 1, 1995 or, thereafter becomes a
Director and who is not, at any time during his/her
service as a Director, an employee of the Company or any
Subsidiary shall be eligible to participate in the Plan.
Any person who on January 1, 1995 is, or thereafter
becomes, eligible to receive a benefit under any present
or future basic pension plan established for the benefit
of employees of the Company or of any Subsidiary shall
not be eligible to participate in the Plan; and any
Participant who becomes an employee of the Company or a
Subsidiary and eligible to receive a benefit under such
basic pension plan shall cease to be eligible for
benefits under this Plan and shall forfeit any benefits
that the Participant may then have become entitled to
under the Plan without regard to his age or Plan Years of
Service.
<PAGE>
15. Definitions:
A. Retainer -
shall mean the aggregate of the annual Director's
retainer fees being paid on the date of the
Participant's retirement by the Company and those
Subsidiaries of which the Participant is a
Director.
B. Committee -
shall mean the Management Review Committee of the
Board of Directors of the Company ("the Board")
and such other committee to which the Board may,
from time to time, assign the Committee's
responsibilities.
C. Effective Date -
shall mean January 1, 1995.
D. Participant -
shall mean any Director who meets the eligibility
requirements of Section 2.
E. Plan Year -
shall mean the approximately 12-month period be-
tween annual meetings of the stockholders of the
Company.
F. Plan Years of Service -
shall mean the Participant's years of service as
a Company Director measured from the date of
first election as a Company Director, whether
occurring before or after the Effective Date.
<PAGE>
16. Plan Retirement Benefits:
A. Eligibility for Benefits -
I. Subject to the provisions of Section 5A,
a Participant shall be eligible to
receive upon retirement after attaining
age 65 a benefit from this Plan upon
completion of 5 Plan Years of Service as
a Director of the Company; provided that,
if a Participant ceases to serve as a
Director of the Company prior to
attaining age 65 for any reason
whatsoever other than because of the
occurrence of a Special Event (as defined
below), such eligibility will terminate
forthwith and no benefit shall be payable
to such Participant or such Participant's
spouse under this Plan.
II. (a) A Special Event shall be deemed to
have occurred if, before attaining age
65, a Participant shall
(a) Die after serving as a Director for 5
Plan Years.
(b) Become disabled after serving as a
Director for 5 Plan Years.
(c) With the consent of 80% of the Directors
voting thereon (with the Participant
<PAGE>
abstaining) resign or fail to stand for
reelection.
For purposes of this Plan, "disability" shall mean a
Participant's complete and permanent inability, by reason of
illness or accident, to perform his or her duties as a
Director, as determined by the Committee based on medical
evidence acceptable to it.
B. Amount of Benefits -
I. An eligible Participant retired other
than by reason of a Special Event will be
entitled to receive during his/her life
an annual pension benefit equal to
his/her Retainer; and upon his/her death,
his/her surviving spouse shall be
entitled to receive during his/her life
an annual benefit equal to 50% of that
payable to the Participant.
II. In the event a Director dies after
serving as a Director for 5 Plan Years
but before attaining age 65 the Director
shall be deemed to have retired one day
before the date of his death and the
surviving spouse shall be eligible to
receive an annual pension benefit equal
to that which would have been payable to
the surviving spouse of an eligible
Participant who had retired on the day
<PAGE>
before the date of death of the deceased
Participant.
III. In the event a Director shall retire
because of disability after serving as
Director for 5 Plan Years but before
attaining age 65, the Participant shall
retain his/her eligibility [and his/her
pension benefit (and the 50% benefit
payable to the Participant's surviving
spouse) shall commence in the month
following his retirement and be paid as
provided in Section 4C] [for a deferred
annual pension benefit commencing when
he/she attains age 65 in the amount of
the annual retainer fees being paid him
at the termination of his/her service and
the Participant's spouse at the time of
such termination shall receive an annual
benefit equal to 50% of such amount
commencing at the later of the
Participant's death or the date on which
the Participant would have attained age
65.]
IV. A Participant who, with the consent of
the Board, resigns or fails to stand for
reelection prior to attaining age 65
shall be eligible for a deferred annual
pension benefit commencing when he/she
<PAGE>
attains age 65 in the amount of the
annual retainer fees being paid him at
the termination of his/her service, and
the Participant's spouse at the time of
such termination shall receive an annual
benefit equal to 50% of such amount
commencing at the later of the
Participant's death or the date on which
the Participant would have attained age
65.
C. Form and Time of Payment -
The annual pension benefit payable under this
Plan shall be paid by the Company with the
Subsidiaries contributing in proportion to their
respective retirement retainer amounts in equal
monthly payments on the first day of the month,
commencing with the month following the month in
which the Participant's retirement occurs.
17. Vesting:
A. Absence of Vesting -
A Participant shall have no vested interest in
the Plan. In the event that a Participant ceases
for any reason other than the occurrence of a
Special Event to be a Director of the Company
prior to attaining age 65, any entitlement to
benefits shall end, and all his/her rights under
the Plan shall terminate without regard to
<PAGE>
whether the Participant has served as a Director
for 5 Plan Years.
B. Change of Control Vesting -
Notwithstanding Section 5A, a Participant shall
become eligible for Plan Retirement Benefits upon
the occurrence of a change of control regardless
of the Participant's then age or Plan Years of
Service, and Benefits shall be payable to the
Participant and his/her spouse in the amounts
provided in Section 4B at such time as the
Participant ceases to be a Director or dies. A
"change in control" is deemed to occur at the
time when either (i) any entity, person or group
(other than the Company, any Subsidiary or any
savings, pension or other benefit plan for the
benefit of employees of the Company or its
subsidiaries) which theretofore beneficially
owned less than 20% of the Company's Common Stock
then outstanding acquires shares of Common Stock
in a transaction or series of transactions that
results in such entity, person or group directly
or indirectly owning beneficially 20% or more of
the outstanding Common Stock or (ii) the election
or appointment, within a twelve-month period, of
persons to the Company's Board of Directors who
were not directors of the Company at the
beginning of such twelve-month period, whose
election or appointment was not voted or approved
<PAGE>
in advance by a majority of those persons who
were directors at the beginning of such period,
and which newly elected or appointed Directors
shall constitute a majority of the Board of
Directors of the Company.
18. Funding:
The Plan shall be unfunded and a Participant shall have
no interest in any assets of the Company or any
Subsidiary. Benefits shall be paid from the general
assets of the Company and the Subsidiaries and the rights
of a Participant and his/her spouse shall be limited to
those of an unsecured general creditor of the Company and
the Subsidiaries. No special or separate fund shall be
established or other segregation of assets made to assure
such payments; provided, however, that the Company and
the Subsidiaries may establish a bookkeeping reserve to
meet its obligations hereunder. Nothing contained in the
Plan, and no action taken pursuant to the provisions of
the Plan, shall create or be construed to create a trust
of any kind, or a fiduciary relationship between the
Company, the Subsidiaries or the Committee, and any
Director or other person. It is the intention of the
parties that this Plan shall constitute a mere promise by
the Company to make payments in the future of the
benefits provided for herein.
<PAGE>
19. Administration and Governing Law:
This Plan will be administered by and under the direction
of the Committee on behalf of the Company and the
Subsidiaries. The Committee may adopt, and may from time
to time modify or amend, such rules and guidelines
(hereinafter referred to as the "Rules and Guidelines")
consistent herewith as it may deem necessary or
appropriate for carrying out the provisions and purposes
of the Plan, which, upon their adoption and so long as in
effect, shall be deemed a part hereof to the same extent
as if set forth in the Plan. The Committee may also
adopt any amendment to this Plan which may be necessary
or appropriate to facilitate the administration,
management and interpretation of this Plan, provided that
any such amendment does not have a material effect on the
Plan's cost. Any interpretation and construction by the
Committee of any provision of, and the determination of
any question arising under, the Plan or the Rules and
Guidelines shall be final, conclusive, and binding upon
the Company, the Subsidiaries, each Participant and
his/her surviving spouse. The provisions of the Plan
shall be construed, administered, and enforced according
to and governed by the laws of the State of New York.
20. Limitation on Scope of Plan:
The Plan shall not be deemed to constitute a contract be-
tween the Company or any Subsidiary and any Director of
the Company, nor shall anything herein contained be
deemed to give any Director of the Company or a
<PAGE>
Subsidiary any right to be re-elected or otherwise
continue to serve as Director or deny to the Company or
any Subsidiary the right to remove any Director at any
time. Notwithstanding the preceding sentence, in the
event of a change of control of the Company, as defined
in Section 5B, the Plan shall be deemed to have created
on the effective date of such change of control, a
contract binding upon the Company and the Subsidiaries to
pay the Plan Retirement Benefits deemed vested by Section
5B.
21. Non-Assignability:
It is the intention of the parties that this Plan shall
constitute a mere promise by the Company to make payments
in the future of the benefits provided for herein. The
rights of a Participant and his/her surviving spouse
hereunder are not subject in any manner to anticipation,
alienation, sale, transfer, assignment, pledge,
encumbrance, attachment or garnishment by creditors of
the Participant or creditors of the Participant's spouse.
In the event of any attempted assignment or transfer, the
Company shall have no further liability hereunder. Nor
shall any payments be transferable by operation of law in
the event of bankruptcy or insolvency, except to the
extent otherwise provided by applicable law.
22. Tax Withholding:
The Company shall withhold from all amounts payable under
this Plan all federal, state, local or other taxes
<PAGE>
required by law to be withheld with respect to such
amounts.
23. Successors and Assigns:
Subject to the limitations and restrictions expressed
herein, this Plan shall be binding upon and inure to the
benefit of the Company and its successors and assigns and
the Participants, or their successors, assigns, designees
and estates. This Plan shall also be binding upon any
successor corporation or organization succeeding to
substantially all the assets and business of the Company,
but nothing in this Plan shall preclude the Company from
merging or consolidating into or with, or transferring
all or substantially all of the assets to, another
corporation which assumes this Plan and all obligattions
of the Company hereunder. Subject to the continuing
effectiveness of Sections 5A and 6, the Company agrees to
make appropriate provision for the continuation of this
Plan and preservation of Participants' rights under this
Plan in any agreement or plan which it may enter into to
effect any merger, consolidation, reorganization, or
transfer of assets and assumption. On the occurrence of
such event, the term "Company" shall refer to such other
corporation and this Plan shall continue in full force
and effect.
24. Termination or Amendment:
This Plan may be amended, suspended or terminated, in
whole or in part, with prospective or retroactive effect
<PAGE>
by action of the Board of Directors of the Company,
acting on behalf of the Company and the Subsidiaries, at
any time without the consent of any Participant or
beneficiary; provided, however, that no such amendment,
suspension or termination nor amendment of the Plan shall
reduce or terminate any benefit to or in respect of a
Participant who has attained age 65 and served five years
as Director.
<PAGE>
Exhibit 10.9
ALLEGHENY POWER SYSTEM PERFORMANCE SHARE PLAN
1. PURPOSE AND ADMINISTRATION
To more directly relate the compensation of the executives of the
Allegheny Power System Companies (the "Companies") to the
financial results and operating performance of the Companies and to
attract and retain key executives in a competitive job market, it is
desirable and necessary to create a long-term incentive plan to
supplement the Companies' salary and short-term incentive plans.
The Allegheny Power System Performance Share Plan (the "Plan")
was adopted by the Boards of Directors of the Companies on
__________________, and will be submitted to shareholders for
approval at the next annual meeting of Allegheny Power System, Inc.
(the Company). The Plan is designed to more directly relate the
compensation of participants to the long-term performance of the
Companies, to provide incentive rewards for the achievement of the
long-term performance which benefits both the customers and
shareholders of the Companies. The Plan will be administered by the
Management Review Committee of the Board of Directors of the
Company (the "Committee"). The Plan will become effective, upon
approval by shareholders, as of January 1, 1994, and will expire on
December 3l, 2007, unless otherwise suspended or terminated pursuant
to Article 10 hereof.
<PAGE>
2. DESIGN OF THE PLAN
The Plan will be made up of performance cycles:
(1) which may overlap
(2) which shall be described in Performance Cycle Guidelines
(Guidelines) detailing the appropriate terms, conditions and
performance criteria governing award payments for each
performance cycle and
(3) which shall be approved by the Boards of Directors, upon
recommendation of the Committee.
Each performance cycle shall be for a period of not less than three (3)
or more than five (5) calendar years. The Boards shall approve the
participants in each cycle, the performance criteria and performance
shares to be covered by each cycle based on recommendations
submitted by the Committee.
The first performance cycle shall, subject to approval of the Plan by
shareholders, begin on January 1, 1994. Future cycles shall commence
on such date as the Boards shall approve, upon the recommendation
of the Committee, but no future cycle shall begin sooner than January
1, 1995, nor end on a date after December 31, 2007, and shall be
governed by the Guidelines adopted for that cycle.
<PAGE>
3. PARTICIPANTS
Participation in the Plan will be restricted to senior officers of the
Companies as approved by the Boards. The Committee shall
determine, in advance of each cycle, the specific senior officers to be
included in that performance cycle. It is expected that not more than
15 officers will participate in any performance cycle. The Committee
will report named proxy executive officers participating in any
performance cycle to the Board for approval.
4. SHARES COVERED BY THE PLAN
The total number of shares of common stock of the Company that may
be granted under this Plan shall be 500,000. The number of
designated shares shall be adjusted to reflect stock splits, stock
dividends, and other similar matters affecting the number of
outstanding shares of the Company's common stock. In the event any
performance shares granted are not paid, whether by reason of the
participant's termination of employment, failure to meet performance
criteria or otherwise, such shares will be available for grants to
participants with respect to other performance cycles under the Plan.
5. PERFORMANCE SHARE GRANTS AND PERFORMANCE
The Committee will approve the granting of performance shares to
participants in any performance cycle as provided in this Plan. Actual
shares of common stock of the Company shall not be issued at the
time of grant, but the grant of such shares shall represent the
participant's right to receive such shares (or their equivalent value),
and dividends credited in shares, with respect to such shares, upon
achievement of performance criteria during each performance cycle,
measured relative to performance standards and other conditions
established by the Committee, and set forth in the Guidelines for that
cycle, pursuant to which the shares are granted. The performance
cycle over which the Companies' performance is to be measured
relative to these performance standards will be determined by the
Committee and approved by the Boards at the time of grant. During
any performance cycle, dividends will be credited on all performance
shares granted, and will be converted into additional shares payable
when the underlying performance shares are paid. Payment of any
shares granted is contingent on the participant's continued employment
during the performance cycle or such other terms as the Committee
shall specify in the event of the participant's death, disability,
retirement, or involuntary termination following a change in ownership
and/or control of the Company.
<PAGE>
6. PERFORMANCE CRITERIA AND STANDARDS
Performance criteria and standards to be included in the Guidelines for
each performance cycle shall include:
(a) Customer related criteria such as the cost and quality of service
provided to residential customers; and
(b) Shareholder related criteria.
The Committee shall determine appropriate customer related
performance standards such as the Companies' residential service cost
ranking and/or the change in the Companies' residential service cost
ranking measured, in each case, relative to a peer group of utilities
selected by the Committee and identified in the Guidelines.
The Committee shall select appropriate shareholder related
performance criteria such as total return, dividend return, earnings,
return on equity, cash flow related goals, or a combination of any such
criteria, measured in each case relative to the peer utility companies
used during the performance cycle for the proxy stock performance
graph required under the Securities and Exchange Commission's proxy
rules applicable at the time.
The weighting between customer performance and shareholder
performance criteria, for purposes of computing overall awards during
any performance cycle, shall be determined by the Committee in the
appropriate guidelines.
7. PERFORMANCE SHARE PAYMENTS
Payment of earned performance shares will be made in actual shares
of common stock of the Company, or a combination of cash and
shares, as determined by the Committee at time of grant or payment.
The Committee will determine the date as of which any conversion
of earned performance shares to cash (based on their fair market
value) will be made. Regardless of whether earned performance
shares are paid in actual shares of common stock of the Company, or
a combination of cash and shares, the full number of shares earned
will be deducted from the total number of such shares authorized
under the Plan.
Within sixty days after receiving a grant of performance shares, a
participant may make an irrevocable election, following procedures
established by the Committee, to have distribution of any amount he
may be entitled to receive with respect to such performance shares
deferred until such year as he may elect, after the year in which the
amount would otherwise be paid to him; at the same time, he may
elect to have such deferred amount, including dividends (or a
comparable factor), paid to him in annual installments over a specified
period of years.
Notwithstanding any election of any participant to receive payment
under the Plan on a deferred basis as above provided, the Committee,
in its sole discretion, may at any time terminate such election and
make immediate distribution of the amount to which the participant is
entitled.
<PAGE>
8. PAYMENT IN COMMON STOCK: SOURCE OF STOCK
It is anticipated that any shares of common stock of the Company paid
under the Plan will be made from treasury shares acquired prior to or
during the term of the Plan. The Committee may also utilize
authorized but unissued shares of the Company's common stock.
9. ADDITIONAL PROVISIONS
The grant of performance shares to a participant shall create no rights
as a shareholder of the Company until such time that shares of the
Company's common stock are delivered to the Participant. In the
event of stock dividends, stock splits or other similar matters affecting
the number of outstanding shares of the Company's common stock,
appropriate revision shall be made in performance shares, granted to
participants in order to reflect the effect of such action on the grants
to the participants under the Plan.
No participant in the Plan shall have any right to continue in the
employ of the Companies for any period of time. Rights and powers
the Companies now have or may have in the future, to dismiss or
discharge any participant from employment or to change the
assignment of any participant, are expressly reserved to the
Companies. The Companies are authorized to withhold from any
payments made under the Plan any amount necessary to satisfy income
tax withholding requirements in respect of such payments, and for this
purpose may withhold cash or shares of the Company's common
stock.
<PAGE>
10. PLAN AMENDMENT, SUSPENSION, OR TERMINATION
The Boards shall have the authority to amend, revise, or suspend, the
Plan, provided that no amendments or revisions shall be made without
the consent of shareholders if they would materially increase the
benefits accruing to participants, increase the number of Shares which
may be paid under the Plan pursuant to Article 5, or modify the
requirements as to eligibility for Plan participation. The Boards may
also terminate or suspend the operation of the Plan and provided
further that no such action will adversely affect the rights of
participants to payment of performance shares granted prior to
termination or suspension of the Plan, without the prior consent of
such participants.
11. NON-ASSIGNABILITY
Rights under the Plan and in respect of performance shares granted are
not transferable and may not be assigned or pledged by any participant
at any time.
<PAGE>
Exhibit 18
To the Board of Directors
Allegheny Power System, Inc.
We have audited the consolidated financial statements included
in the Annual Report on Form 10-K of Allegheny Power System, Inc.
(the "Corporation") for the year ended December 31, 1994
and issued our report thereon dated February 2, 1995.
Note A to the consolidated financial statements describes a change
in the Corporation's method of accounting for revenues from a
cycle billing basis to full recognition of unbilled revenues.
It should be understood that the preferability of one acceptable
method of revenue recognition over another has not been addressed in any
authoritative accounting literature and in arriving at our
opinion expressed below, we have relied on management's
business planning and judgment. Based on our discussions with
management and the stated reasons for the change, we believe
that such change represents, in your circumstances, the
adoption of a preferable alternative accounting principle for
revenue recognition in conformity with Accounting Principles
Board Opinion No. 20.
PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
New York, New York
February 2, 1995
<PAGE>
<TABLE>
<CAPTION>
E-2
Monongahela Power Company
Incorporation
Documents by Reference
<S> <C> <C>
3.1 Charter of the Company, Form S-3, 33-51301, exh. 4(a)
as amended and Form 8-K of the Company
(1-5164) dated May 12, 1994,
exh. 3.1
3.2 Code of Regulations, Form 10-Q of the Company
as amended (1-5164), September 1994,
exh. (a)(2)
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 August 8, 1989,
November 21, 1991, June 4, 1992,
July 15, 1992, September 1, 1992
and April 29, 1993
* 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
18 Letter re: Change in Accounting Principles
21 Subsidiaries: Monongahela Power Company has a 27% equity
ownership in Allegheny Generating Company, incorporated
in Virginia; and a 25% equity ownership in Allegheny
Pittsburgh Coal Company, incorporated in Pennsylvania.
23 Consent of Independent
Accountants See page 62 herein.
24 Powers of Attorney See pages 63-65 herein.
27 Financial Data Schedules
</TABLE>
<PAGE>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1994
(Dollar Amounts in Thousands)
Monongahela Power Company
Earnings:
Income before cumulative effect
of accounting change $ 59,936
Fixed charges (see below) 38,871
Income taxes 30,649
Total earnings $129,456
Fixed Charges:
Interest on long-term debt $ 35,187
Other interest 2,969
Estimated interest
component of rentals 715
Total fixed charges $ 38,871
Ratio of Earnings to
Fixed Charges 3.33
<PAGE>
Exhibit 18
To the Board of Directors
Monongahela Power Company
We have audited the financial statements included in the
Annual Report on Form 10-K of Monongahela Power Company (the "Corporation")
for the year ended December 31, 1994 and issued our report thereon dated
February 2, 1995. Note A to the financial statements describes a
change in the Corporation's method of accounting for revenues
from a cycle billing basis to full recognition of unbilled
revenues. It should be understood that the preferability of
one acceptable method of revenue recognition over another has
not been addressed in any authoritative accounting literature
and in arriving at our opinion expressed below, we have relied
on management's business planning and judgment. Based on our
discussions with management and the stated reasons for the
change, we believe that such change represents, in your
circumstances, the adoption of a preferable alternative
accounting principle for revenue recognition in conformity
with Accounting Principles Board Opinion No. 20.
PRICE WATERHOUSE LLP
New York, New York
February 2, 1995
<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 1993,
exh. (a)3
3.2 By-laws of the Company, Form 10-Q of the Company
as amended (1-3376-2), June 1990,
exh. (a)3
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 June 14,
Company defining rights 1989, June 25, 1990,
of security holders* August 21, 1991, December
11, 1991, December 15,
1992, February 17, 1993,
March 30, 1993 and June 22,
1994
* 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
18 Letter re: Change in Accounting Principles
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 62 herein.
Accountants
24 Powers of Attorney See pages 63-65 herein.
27 Financial Data Schedules
</TABLE>
<PAGE>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1994
(Dollar Amounts in Thousands)
The Potomac Edison Company
Earnings:
Income before cumulative effect
of accounting change $ 81,983
Fixed charges (see below) 47,329
Income taxes 34,339
Total earnings $163,651
Fixed Charges:
Interest on long-term debt $ 44,706
Other interest 1,750
Estimated interest
component of rentals 873
Total fixed charges $ 47,329
Ratio of Earnings to
Fixed Charges 3.46
<PAGE>
Exhibit 18
To the Board of Directors
The Potomac Edison Company
We have audited the financial statements included in the
Annual Report on Form 10-K of The Potomac Edison Company (the "Corporation")
for the year ended December 31, 1994 and issued our report thereon dated
February 2, 1995. Note A to the financial statements describes a
change in the Corporation's method of accounting for revenues
from a cycle billing basis to full recognition of unbilled
revenues. It should be understood that the preferability of
one acceptable method of revenue recognition over another has
not been addressed in any authoritative accounting literature
and in arriving at our opinion expressed below, we have relied
on management's business planning and judgment. Based on our
discussions with management and the stated reasons for the
change, we believe that such change represents, in your
circumstances, the adoption of a preferable alternative
accounting principle for revenue recognition in conformity
with Accounting Principles Board Opinion No. 20.
PRICE WATERHOUSE
New York, New York
February 2, 1995
<PAGE>
<TABLE>
<CAPTION>
E-4
West Penn Power Company
Incorporation
Documents by Reference
<S> <C> <C>
3.1 Charter of the Company, Form S-3, 33-51303, exh. 4(a)
as amended
3.2 By-laws of the Company, Form 8-K of the Company
as amended (1-255-2), dated June 9, 1993,
exh. (a)(3)
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 June 1989,
February 1991, December
1991, August 13, 1993,
September 15, 1992, June 9,
1993 and June 1993
* 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
18 Letter re: Change in Accounting Principles
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 62 herein.
Accountants
24 Powers of Attorney See pages 63-65 herein.
27 Financial Data Schedules
</TABLE>
<PAGE>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1994
(Dollar Amounts in Thousands)
West Penn Power Company
Earnings:
Income before cumulative effect
of accounting change $101,015
Fixed charges (see below) 61,583
Income taxes 47,085
Total earnings $209,683
Fixed Charges:
Interest on long-term debt $ 58,102
Other interest 2,172
Estimated interest
component of rentals 1,309
Total fixed charges $ 61,583
Ratio of Earnings to
Fixed Charges 3.40
<PAGE>
Exhibit 18
To the Board of Directors
West Penn Power Company
We have audited the consolidated financial statements included in the
Annual Report on Form 10-K of West Penn Power Company (the "Corporation")
for the year ended December 31, 1994 and issued our report thereon dated
February 2, 1995. Note A to the consolidated financial statements describes a
change in the Corporation's method of accounting for revenues from a cycle
billing basis to full recognition of unbilled revenues. It should be understood
that the preferability of one acceptable method of revenue recognition
over another has not been addressed in any authoritative accounting
literature and in arriving at our opinion expressed below, we have
relied on management's business planning and judgment. Based on our
discussions with management and the stated reasons for the change, we
believe that such change represents, in your circumstances, the adoption
of a preferable alternative accounting principle for revenue recognition
in conformity with Accounting Principles Board Opinion No. 20.
PRICE WATERHOUSE
New York, New York
February 2, 1995
<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 62 herein.
Accountants
24 Powers of Attorney See pages 63-65 herein.
27 Financial Data Schedules
* Incorporated by reference to the designated exhibit to AGC's
registration statement on Form 10, File No. 0-14688.
** Incorporated by reference to Form 10-Q of the Company
(0-14688) for June 1989, exh. (a).
*** Incorporated by reference to Forms 8-K of the Company
(0-14688) for December 1986, exh. 4(A), and December 1988, exh.
4.1.
<PAGE>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1994
(Dollar Amounts in Thousands)
Allegheny Generating Company
Earnings:
Net Income $ 29,717
Fixed charges (see below) 17,809
Income taxes 14,743
Total earnings $ 62,269
Fixed Charges:
Interest on long-term debt $ 16,863
Other interest 946
Estimated interest
component of rentals ----
Total fixed charges $ 17,809
Ratio of Earnings to
Fixed Charges 3.50
WARNING: THE EDGAR SYSTEM ENCOUNTERED ERROR(S) WHILE PROCESSING THIS SCHEDULE.
<TABLE> <S> <C>
<ARTICLE> 5
<RESTATED>
<NAME> THE POTOMAC EDISON COMPANY
<MULTIPLIER> 1,000
<CURRENCY> 0
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-START> JAN-01-1994
<PERIOD-END> DEC-31-1994
<EXCHANGE-RATE> 1
<CASH> 2,196
<SECURITIES> 0
<RECEIVABLES> 73,017
<ALLOWANCES> (1,177)
<INVENTORY> 50,116
<CURRENT-ASSETS> 143,497
<PP&E> 1,978,396
<DEPRECIATION> (673,853)
<TOTAL-ASSETS> 1,629,535
<CURRENT-LIABILITIES> 90,844
<BONDS> 604,749
<COMMON> 447,700
25,200
36,378
<OTHER-SE> 210,446
<TOTAL-LIABILITY-AND-EQUITY> 1,629,535
<SALES> 759,365
<TOTAL-REVENUES> 759,365
<CGS> 507,151
<TOTAL-COSTS> 613,880
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 44,253
<INCOME-PRETAX> 115,146
<INCOME-TAX> 33,163
<INCOME-CONTINUING> 81,983
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 16,471
<NET-INCOME> 98,454
<EPS-PRIMARY> 0.00<F1>
<EPS-DILUTED> 0.00<F1>
<FN>
<F1>All common stock is owned by parent. No EPS required.
</FN>
</TABLE>
