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, 1993
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
<PAGE>
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. [ ]
<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(a) 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 3, 1994 February 3, 1994
Allegheny Power System, Inc. $2,941,589,550 117,663,582
($1.25 par value)(a)
Monongahela Power Company None. (b) 5,891,000
($50 par value)
The Potomac Edison Company None. (b) 22,385,000
(no par value)
West Penn Power Company None. (b) 22,361,586
(no par value)
Allegheny Generating Company None. (c) 1,000
($1.00 par value)
(a) Allegheny Power System, Inc. split its common stock two-for-one effective
November 4, 1993.
(b) All such common stock is held by Allegheny Power System, Inc., the parent
Company.
(c) 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
Sales 3
Electric Facilities 7
System Map 10
Research and Development 12
Construction and Financing 13
Fuel Supply 18
Rate Matters 19
Environmental Matters 23
Air Standards 23
Water Standards 25
Hazardous and Solid Wastes 26
Emerging Environmental Issues 27
Regulation 28
ITEM 2. Properties 31
ITEM 3. Legal Proceedings 32
ITEM 4. Submission of Matters to a
Vote of Security Holders 35
Executive Officers of the
Registrants 36
PART II:
ITEM 5. Market for the Registrants'
Common Equity and
Related Stockholder Matters 39
ITEM 6. Selected Financial Data 40
ITEM 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 41
ITEM 8. Financial Statements and
Supplementary Data 42
<PAGE>
CONTENTS (Cont'd)
Page
ITEM 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure 44
PART III:
ITEM 10. Directors and Executive Officers of the
Registrants 45
ITEM 11. Executive Compensation 46
ITEM 12. Security Ownership of Certain Beneficial Owners
and Management 54
ITEM 13. Certain Relationships and Related Transactions 55
PART IV:
ITEM 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 55
<PAGE>
- 1 -
THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY
POWER SYSTEM, INC., MONONGAHELA POWER COMPANY, THE POTOMAC
EDISON COMPANY, WEST PENN POWER COMPANY, AND ALLEGHENY
GENERATING COMPANY. INFORMATION CONTAINED HEREIN RELATING
TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT ON
ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS
TO INFORMATION RELATING TO THE OTHER REGISTRANTS.
PART I
ITEM 1. BUSINESS
Allegheny Power System, Inc. (APS), incorporated in
Maryland in 1925, is an electric utility holding company
that derives substantially all of its income from the
electric utility operations of its direct and indirect
subsidiaries (Subsidiaries), Monongahela Power Company
(Monongahela), The Potomac Edison Company (Potomac Edison),
West Penn Power Company (West Penn), and Allegheny
Generating Company (AGC). 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).
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 340,700 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, 1993, Monongahela
had 1,962 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
354,300 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, 1993, Potomac Edison had 1,152
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 cooperatives,
one of which purchases power from Potomac Edison. There are
also several large federal government installations served
by Potomac Edison.
<PAGE>
- 2 -
West Penn, incorporated in Pennsylvania in 1916,
operates in southwestern and north and south central
Pennsylvania. It also owns generating capacity in West
Virginia. West Penn serves about 646,700 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,
1993, West Penn had 2,043 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 operating assets are 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).
APS has no employees. Its officers are employed by
Allegheny Power Service Corporation (APSC), a wholly-owned
subsidiary of APS. On December 31, 1993, the Subsidiaries
and APSC had 6,025 employees.
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 utility emissions
of sulfur dioxides and nitrogen oxides.
Additional concerns include proposals to restructure
and, to some extent, deregulate portions of the industry and
increase competition, particularly as a result of the
National Energy Policy Act of 1992 (EPACT). EPACT may
increase competition by allowing the formation of Exempt
Wholesale Generators (EWGs), with the approval of the FERC,
and providing mandatory access to the interconnected
electric grid for wholesale transactions. It further
provides for expansion of the grid where constraints are
determined to exist - at the expense of the requestor of
such transmission service and provided necessary authority
to construct such facilities can be obtained. 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, ELECTRIC FACILITIES and REGULATION for a further
discussion of the impact of EPACT.)
<PAGE>
- 3 -
In an effort to meet the challenges of the new
competitive environment in the industry, APS is considering
forming a new nonutility subsidiary, subject to regulatory
approval, to pursue new business opportunities which have a
meaningful relationship to the core utility business. APS
would also consider establishing or acquiring its own EWGs,
if that is feasible, particularly in view of the possible
constraints imposed by regulations under the Public Utility
Holding Company Act of 1935 (PUHCA) on nonexempt public
utility holding companies such as APS and its Subsidiaries.
Further concerns of the industry include possible
restrictions on carbon dioxide emissions, uncertainties in
demand due to economic conditions, energy conservation,
market competition, weather, and interruptions in fuel
supply because of weather and strikes. (See ITEM 1.
CONSTRUCTION AND FINANCING, RATE MATTERS, and ENVIRONMENTAL
MATTERS for information concerning the effect on the
Subsidiaries of the CAAA.)
SALES
In 1993, consolidated kilowatthour (kWh) sales to the
Operating Subsidiaries' retail customers increased 3.3%
from those of 1992, as a result of increases of 6.5%, 5.2%
and 0.3% in residential, commercial and industrial sales,
respectively. The increased Kwh sales in 1993 reflect both
growth in number of customers and higher use. Consolidated
revenues from residential, commercial, and industrial sales
increased 11.4%, 9.8%, and 5.6%, respectively, primarily
because of several rate increases effective in 1993 as
described in 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 30.2% and 25.5%,
respectively, due to increased native load, decreased
demand, and price competition.
The System's all-time peak load of 7,153 MW occurred
on January 18, 1994. The peak loads in 1993 and 1992 were
6,678 MW and 6,530 MW, respectively. The increased 1994
peak was due in part to record cold temperatures throughout
the Operating Subsidiaries' service areas and would have
been higher except for voluntary curtailments. The average
System load (Yearly Net Power Supply divided by number of
hours in the year) was 4,674 megawatthours (MWh) and 4,526
MWh in 1993 and 1992, 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 1993 were
derived as follows: Pennsylvania, 44.8%; West Virginia,
28.4%; Maryland, 20.2%; Virginia, 5.0%; Ohio, 1.6%
(residential, 35.1%; commercial, 18.4%; industrial, 28.9%;
nonaffiliated utilities, 14.9%; and other, 2.7%). The
following percentages of such revenues were derived from
these industries: iron and steel, 6.0%; chemicals, 3.3%;
fabricated products, 3.3%; aluminum and other nonferrous
metals, 3.2%; coal mines, 3.1%; cement, 1.8%; and all other
industries, 8.2%. The coal mine percentage decreased in
1993 principally due to the coal strike. More information
concerning the coal strike may be found in ITEM 1. FUEL
SUPPLY. Revenues from each of 16 industrial customers
exceeded $5 million, including one coal customer of both
Monongahela and West Penn with total revenues exceeding $15
million, three steel customers with revenues exceeding $26
million each, and one aluminum customer with revenues
exceeding $63 million.
<PAGE>
- 4 -
During 1993, Monongahela's kWh sales to retail
customers increased 0.3% as a result of increases of 6.4%
and 4.7% in residential and commercial sales, respectively,
and a decrease of 4.4% in industrial sales, primarily due to
the coal strike and lower sales to one iron and steel
customer because of increased use of its own generation.
Revenues from such customers increased 9.2%, 7.8% and 0.7%,
respectively, and revenues from kWh sales to affiliated and
nonaffiliated utilities decreased 7.8%. Monongahela's all-
time peak load of 1,667 MW occurred on December 21, 1989.
(For a discussion of the coal strike, See ITEM 1. FUEL
SUPPLY.)
Monongahela's electric operating revenues were derived
as follows: West Virginia, 94.0% and Ohio, 6.0%
(residential, 28.8%; commercial, 17.3%; industrial, 29.2%;
nonaffiliated utilities, 13.4 %; and other, 11.3%).
Revenues from each of five industrial customers exceeded $8
million, including one coal customer with revenues exceeding
$13 million and one steel customer with revenues exceeding
$26 million. The decreases in the revenues of these
customers from 1992 levels were primarily due to the coal
strike.
During 1993, Potomac Edison's kWh sales to retail
customers increased 6.3% as a result of increases of 8.4%,
7.1%, and 4.3% in residential, commercial, and industrial
sales, respectively. Revenues from such customers increased
12.7%, 11.8%, and 11.8%, respectively, and revenues from kWh
sales to affiliated and nonaffiliated utilities decreased
23.1%. Potomac Edison's all-time peak load of 2,595 MW
occurred on January 19, 1994.
Potomac Edison's electric operating revenues were
derived as follows: Maryland, 66.6%; West Virginia, 16.8%;
and Virginia 16.6% (residential, 38.5%; commercial, 17.5%;
industrial, 24.7%; nonaffiliated utilities, 15.2%; and
other, 4.1%). Revenues from one industrial customer, the
Eastalco aluminum reduction plant near Frederick, Maryland,
amounted to $63.4 million (8.9% 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 $19.3 million in 1993. Said
agreement may be canceled before the year 2000 upon 90 days
notice of a governmental decision resulting in a material
modification of the agreement.
During 1993, West Penn's kWh sales to retail customers
increased 3.1% as a result of increases of 5.2%, 4.4% and
0.8% in residential, commercial, and industrial sales,
respectively. Revenues from residential, commercial, and
industrial customers increased 11.5%, 9.6%, and 5.4%,
respectively, and revenues from kWh sales to affiliated and
nonaffiliated utilities decreased 24.3%. West Penn's all-
time peak load of 3,068 MW occurred on January 18, 1994.
<PAGE>
- 5 -
West Penn's electric operating revenues were derived
as follows: Pennsylvania, 100% (residential, 33.1%;
commercial, 18.0%; industrial, 28.5%; nonaffiliated
utilities, 14.1%; and other, 6.3%). Revenues from each of
three steel customers exceeded $10 million, including two
with revenues exceeding $31 million each.
On average, the Operating Subsidiaries are the lowest
or among the lowest cost producers of electricity in their
regions and therefore the Operating Subsidiaries' delivered
power prices should compete favorably with those of
potential alternate suppliers who use cost-based pricing.
However, the Operating Subsidiaries 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 1993, the Operating Subsidiaries provided
approximately 13.3 billion kWh of energy to nonaffiliated
utility companies, of which 1.5 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, fuel, and
regional transmission facilities; and the availability and
price of competitive sources of power. System sales
decreased in 1993 relative to 1992 primarily because of
continued decreased demand, increased Operating
Subsidiaries' native load, coal conservation because of the
coal strike, and increased willingness of other suppliers to
make sales at lower prices. Further decreases in kWh sales
to nonaffiliated utilities are expected in 1994 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.
The Operating Subsidiaries reactivated a peak
diversity exchange arrangement with Virginia Power effective
June 1993 which continues indefinitely. The Operating
Subsidiaries will annually supply Virginia Power with 200 MW
during each June, July, and August, in return for which
Virginia Power will supply the Operating Subsidiaries with
200 MW during each December, January, and February, at least
through February 1997. 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 MWh to be delivered by each to
the other over the term of the arrangement is expected to be
equal.
<PAGE>
- 6 -
The Operating Subsidiaries and Duquesne Light Company
(Duquesne Light) in 1991 entered into an exchange
arrangement under which the Operating Subsidiaries will
supply Duquesne Light with up to 200 MW for a specified
number of weeks, generally during each March, April, May,
September, October, and November. In return, Duquesne Light
will supply the Operating Subsidiaries with up to 100 MW,
generally during each December, January, and February. The
total number of MWh delivered by each utility to the other
over the term of the arrangement is expected to be the same.
West Penn supplies power to the Borough of Tarentum
(Tarentum) using in part 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 approval.
The System provides wholesale transmission services to
applicants under its Federal Energy Regulatory Commission
(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
reliability in general and on the reliability of the
Operating Subsidiaries' service to their retail and full-
requirements wholesale customers in particular. (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.
EPACT permits wholesale generators, utility-owned and
otherwise, and wholesale consumers to request from System
and other owners of bulk power transmission facilities a
commitment to supply transmission services. Generators
include nonaffiliated utilities and nonutility generators
(NUG) of electricity (including classifications of
generators known as Independent Power Producers (IPP) and
EWGs). Consumers of wholesale power include qualifying
nonaffiliated utilities or groups of utilities including the
many small electric systems owned by municipalities and
rural electric cooperative associations in the service areas
of the Operating Subsidiaries. Many of these small systems
currently purchase substantially all of their power from the
Operating Subsidiaries. Under EPACT, these small systems
may now seek an order from the FERC to force the Operating
Subsidiaries to wheel power over the System to them from
sources outside the System service area. All of the small
electric wholesale customers in the Operating Subsidiaries'
service areas which might avail themselves of this
opportunity produced $42 million of total revenues in 1993.
<PAGE>
- 7 -
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 approved by appropriate
state commissions. The System's total generation capacity
includes 292 MW of on-line PURPA capacity. Payments for
PURPA capacity and energy in 1993 totaled approximately $105
million at an average cost to the System of 5.04 cents per
kWh. The System projects an additional 180 MW of PURPA
capacity to come on-line in future years. In addition,
lapsed purchase agreements totaling 203 MW and other PURPA
complaints totaling 520 MW (none of which are included in
the System's integrated resource plan as of August 20,
1993), are the subject of pending litigation. (See ITEM 3.
LEGAL PROCEEDINGS for a description of litigation and
regulatory proceedings in Pennsylvania, Maryland, and West
Virginia affecting PURPA capacity.) In the future, ratings
of the Operating Subsidiaries' first mortgage bonds and
preferred stock may be affected by increased concern of
rating agencies that purchased power contracts are a risk
factor deserving consideration in assessing the credit-
worthiness of electric utilities.
ELECTRIC FACILITIES
The following table shows the System's December 31, 1993,
generating capacity, based on the maximum monthly normal seasonal
operating capacity of each unit. The System-owned capacity totaled
7,991 MW, of which 7,089 MW (88.7%) are coal-fired, 840 MW (10.5%)
are pumped-storage, and 62 MW (0.8%) 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 average age of the System-owned coal-fired stations shown
below, based on generating capacity at December 31, 1993, was about
23.6 years. In 1993, their average heat rate was 10,020 Btu's/kWh,
and their availability factor was 87.0%.
<PAGE>
- 8 -
<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(c) 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 2 141 141 1943-51
R. Paul Smith 2 114 114 1947-58
Willow Island 2 243 243 1949-60
Pumped-Storage
and Hydro:
Bath County 6 840 227(d) 235(d) 378(d) 1985
Lake Lynn(e) 4 52 52 1926
Potomac
Edison(e) 22 10 10 Various
Total System-Owned
Capacity 54 7,991 2,325 2,076 3,590
</TABLE>
<TABLE>
<CAPTION>
Nonutility Generation
Maximum Generating Capacity
(Megawatts)(f)
Contract
Project Monon- Potomac West Commencement
Project Total gahela Edison Penn Date
Coal-fired
<S> <C> <C> <C> <C> <C>
AES Beaver Valley 120 120 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 29 29 1988
Total
Nonutility Capacity 292 159 0 133
Total Maximum System
Generating Capacity (a)(f) 8,283 2,484 2,076 3,723
</TABLE>
<PAGE>
- 9 -
(a) Excludes 361 MW of West Penn oil-fired capacity, which was placed on cold
reserve status as of June 1, 1983. Current plans call for the
reactivation of these units within the next five years.
(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) The installation of flue-gas desulfurization equipment (See ITEM 1.
ENVIRONMENTAL MATTERS) is expected to reduce the net generating
capacity of each unit by about 3%.
(d) Capacity entitlement through percentage ownership of AGC.
(e) The FERC issued an annual license to West Penn for Lake Lynn for 1994.
A relicensing application has been filed with the FERC for Lake Lynn
and a license with a 30 to 50 year term is expected to be issued in
late 1994. 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.
(f) Nonutility generating capacity available through contractual arrangements
pursuant to PURPA.
<PAGE>
- 10 -
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>
- 11 -
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, 1993:
<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 19,700 284 228
Potomac Edison 17,150 202 202
West Penn 21,969 273 542
AGC 85(c) 85(c)
Total System 58,904 844 972
</TABLE>
(a) The System has a total of 5,203 miles of underground distribution lines.
(b) The substations have an aggregate transformer capacity of 37,512,771
kilovoltamperes.
(c) Total Bath County transmission lines, of which AGC owns an undivided 40%
interest and Virginia Power owns the remainder.
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, continues to
experience periods of heavy loading in a west-to-east
direction. Increases in customer load, power transfers by the
Subsidiaries and by nonaffiliated entities, and parallel flows
caused by transactions to which the Operating Subsidiaries are
not a party, all contribute to the heavy west-to-east power
flows. In late 1992 and early 1993, a substantial amount of
reactive power sources (shunt capacitors) were added to
neighboring eastern utilities' EHV systems. These capacitors
complement the capacitors added in 1991 and 1992 on the System
and together they serve to increase transfer capability by
improving voltage on the transmission system during heavy
loading periods.
While the additional capacitors installed by the
Subsidiaries' eastern neighbors have enhanced transfer
capability, the interregional transmission facilities are
still expected periodically to operate up to their reliability
limits; therefore, restrictions on transfers may still be
necessary at times as was the case in recent years.
Under certain provisions of EPACT, wholesale
generators, utility-owned or otherwise, may seek from System
and other owners of bulk power transmission facilities a
commitment to supply power transmission services, so long as
the FERC finds reliability and native load and existing
contractual customers are not adversely affected (See
discussion under ITEM 1. SALES and REGULATION). Such demand
on the System for transmission service may add periodically to
heavy power flows on the System's facilities.
<PAGE>
- 12 -
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 with purchasers of transmission service.
As a result of EPACT, the FERC is investigating the
continued desirability of traditional methods of pricing and
providing transmission service. The FERC may choose to
maintain existing methods, implement new methodologies which
the Operating Subsidiaries and their ratepayers may or may not
find to be beneficial, or a combination thereof. The
Operating Subsidiaries are participating fully in the FERC
proceedings with the principal intent of safeguarding the
reliability of the System's transmission facilities, and the
rights and interests of its native load customers. The
outcome of those deliberations cannot be predicted.
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $4.6 million, $2.7
million, and $2.8 million in 1993, 1992, and 1991,
respectively, for research programs. Of these amounts, $3.2
million and $0.6 million were for Electric Power Research
Institute (EPRI) dues in 1993 and 1992, respectively. The
Operating Subsidiaries plan to spend approximately $7.5
million for research in 1994, with EPRI dues representing $5.9
million of that total.
The Operating Subsidiaries joined EPRI, an industry-
sponsored research and development institution, effective
October 1, 1992, contingent upon the approval by state
commissions of recovery of the dues in rates, which approval
was subsequently received in all jurisdictions except Ohio and
West Virginia, where the matter is pending. Ongoing
participation in EPRI depends upon continued approval by state
commissions of recovery of dues in rates. Dues are based on a
three-year, new-member ramping formula.
Independent research conducted by the Operating
Subsidiaries in 1993, which will be completed or continued in
1994, concentrated on environmental protection, generating
unit performance, future generating technologies, delivery
systems, and customer-related research.
Two U.S. Department of Energy Clean Coal Technology
nitrogen oxide control projects, which the Operating
Subsidiaries cofounded, have recently been completed. Based
upon the results of one of the projects, retrofitting of low
nitrogen oxide cell burners at the Hatfield's Ferry Power
Station units has been undertaken at much lower costs than
would otherwise have been required.
<PAGE>
- 13 -
Research is also being directed to help address major
issues facing the Operating Subsidiaries including electric
and magnetic field (EMF) risk, waste disposal, greenhouse gas,
client-server information system prospects, renewable
resources, fuel cells, new combustion turbines and other
cogeneration technologies. In addition, evaluation of
technical proposals for business opportunities is also
ongoing.
EMF research includes monitoring work done by EPRI,
Department of Energy (DOE), the Environmental Protection
Agency (EPA) and other government researchers. It also
includes monitoring literature, law and litigation, and
standards as developed. This research enables the Operating
Subsidiaries to evaluate any potential health risks to
employees and customers which may exist.
Research activities related to alleged global climate
change include monitoring government activity, studying
possible joint implementation activities in connection with
the Clinton Climate Change Action Plan, and studying demand-
side management, electro- technologies and possible joint
implementation plans.
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 1993
amounted to $574 million and for 1994 and 1995 are expected to
aggregate $500 million and $400 million, respectively. In
1993, these expenditures included $240 million for compliance
with the CAAA. The 1994 and 1995 estimated expenditures
include $161 million and $53 million, respectively, to
cover the costs of compliance with the CAAA. (See ITEM 1.
ENVIRONMENTAL MATTERS.) 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>
- 14 -
<TABLE>
<CAPTION>
Construction Expenditures
1993 1994 1995
Millions of Dollars
(Actual) (Estimated)
Monongahela
<S> <C> <C> <C>
Generation $ 93.9 $ 53.4 $ 31.0
Transmission and Distribution 45.0 47.0 48.2
Other 1.8 3.1 4.1
Total* $ 140.7 $ 103.5 $ 83.3
</TABLE>
<TABLE>
Potomac Edison
<S> <C> <C> <C>
Generation $ 107.5 $ 56.9 $ 29.8
Transmission and Distribution 66.0 73.4 73.0
Other 5.9 5.7 3.6
Total* $ 179.4 $ 136.0 $ 106.4
</TABLE>
<TABLE>
West Penn
<S> <C> <C> <C>
Generation $ 152.0 $ 165.7 $ 118.2
Transmission and Distribution 81.0 69.5 70.9
Other 18.0 22.7 18.9
Total* $ 251.0 $ 257.9 $ 208.0
</TABLE>
<TABLE>
AGC
<S> <C> <C> <C>
Generation $ 2.6 $ 2.1 $ 2.5
Transmission and Distribution
Other .1
Total $ 2.7 $ 2.1 $ 2.5
</TABLE>
<TABLE>
<S> <C> <C> <C>
Total Construction Expenditures $ 573.8 $ 499.5 $ 400.2
</TABLE>
* Includes allowance for funds used during construction for 1993, 1994 and 1995
of: Monongahela $5.8, $4.1 and $1.9; Potomac Edison $7.1, $5.7 and
$2.7; and West Penn $8.6, $12.7 and $6.2.
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. It is anticipated that the Harrison scrubber
project will be completed on schedule and that the
final costs will be approximately 24% below the
original budget. Primary factors contributing to the
reduced cost are: a) the absence of any major
construction problems to date; 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. In order to avoid unnecessary and
uneconomic additional outages, power station
construction and long-range maintenance schedules and
the expenditures associated therewith will have to be
coordinated over the next several years with outages to
meet the in-service dates of the new emission control
facilities.
<PAGE>
- 15 -
On a System basis, total expenditures for 1993,
1994, and 1995 include $270 million, $191 million, and
$93 million, respectively, for construction of
environmental control technology.
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 average annual
winter and summer peak load growth rates of 1.47% and
1.28%, respectively, in the period 1994-2004. After
giving effect to the reactivation of West Penn capacity
in cold reserve (see page 9), peak diversity exchange
arrangements described in ITEM 1. SALES above, demand-
side management and conservation programs, and the
capacity of an anticipated new PURPA plant, the
System's integrated resource plan indicates that new
System-owned generating capacity will not be required
until the year 2000 or beyond. If future customer
demand materially exceeds that forecast or anticipated
supply-side resources do not become available or
demand-side management efforts do not succeed, or under
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, as well as their projected
ownership of future generating stations, are subject to
continuing review and substantial change.
<PAGE>
- 16 -
The Subsidiaries have financed their construction
programs through internally generated funds, first
mortgage bond, debenture, medium-term note and
preferred stock issues, pollution control and solid
waste disposal notes, instalment 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 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.
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 May 1993, Monongahela, Potomac Edison, and
West Penn issued $10.68 million, $13.99 million, and
$18.04 million, respectively, in solid waste disposal
notes to Harrison County, West Virginia. Harrison
County in turn issued $24.67 million of 6-1/4% and
$18.04 million of 6.3% tax-exempt 30-year solid waste
disposal revenue bonds. The Operating Subsidiaries are
using the proceeds from the issuance to finance certain
solid waste disposal facilities which comprise a
portion of the scrubbers located at the Harrison Power
Station.
On November 3, 1993, the holders of more than
two-thirds of the shares of APS common stock voted to
split the common stock by amending the charter to
reclassify each share of common stock, par value $2.50,
issued or unissued, into two shares of common stock,
par value $1.25 each. The stock split became effective
on November 4, 1993. All references to APS common
stock herein reflect the two-for-one stock split.
On October 14, 1993, APS issued and sold
2,400,000 shares of its common stock in an underwritten
offering with net proceeds to APS of $64.1 million, and
in 1993 sold 1,364,846 shares of its common stock for
$36.1 million through its Dividend Reinvestment and
Stock Purchase Plan and its Employee Stock Ownership
and Savings Plan.
In October 1993, Potomac Edison and West Penn
issued and sold to APS 2,500,000 and 5,000,000
additional shares of each of their common stock,
respectively, at a price of $20 per share.
During 1993, 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
2.62%, 2.55%, 2.595% and 2.7%. The rate set at auction
on January 14, 1994, was 2.52%.
In August 1993, Potomac Edison redeemed the
remaining $404,600 of 4.70% Series B Preferred Stock
outstanding.
<PAGE>
- 17 -
In 1993, the Subsidiaries issued $651.9 million
of securities having interest rates between 4.95% and
7.75%, to refund outstanding debt with rates of 7.0% to
9.75%, with an annual after-tax savings in interest
cost of almost $9 million. In February 1993, Potomac
Edison issued $45 million of 7-3/4%, 30-year first
mortgage bonds to refund $25 million, 8-5/8% series due
2007 and $15 million, 8-5/8% series due 2003. In March
1993, West Penn issued $61.5 million of 10-year, 4.95%
Pollution Control Revenue Notes to refund $30 million,
9-3/4% series due 2003 and $31.5 million, 9-1/2% series
due 2003. In March 1993, AGC issued $50 million of 5-
3/4% medium-term notes due in 1998 to refund $50
million, 8% debentures due in 1997. In March 1993,
Potomac Edison issued $75 million of 5-7/8% first
mortgage bonds due 2000 to refund $72 million of four
series due 1998-2002 with rates ranging from 7% to 8-
3/8%. In April 1993, Monongahela, Potomac Edison and
West Penn issued $7.05 million, $8.6 million, and $7.75
million, respectively, in 20-year Pollution Control
Revenue Notes to Monongalia County, West Virginia.
Monongalia County, in turn issued $23.4 million of
5.95%, 20-year Pollution Control Revenue Bonds to
refund $23.4 million of three series due in 2013 with
rates ranging from 9.375% to 9.5%. In April 1993,
Monongahela issued $65 million of 5-5/8% first mortgage
bonds due in 2000 to refund $60 million of three series
due 1998-2002 with rates ranging from 7.5% to 8.125%.
In June 1993, West Penn issued $102 million of 5-1/2%
first mortgage bonds due in 1998 to refund $102 million
of three series due 1997-1999 with rates ranging from
7% to 7-7/8%. Also in June 1993, West Penn issued $80
million of 6-3/8% first mortgage bonds due 2003 to
refund $75 million of two series due 2001-2002 with
rates of 7-5/8% and 8-1/8%. In September 1993, AGC
issued $50 million of 5-5/8% debentures due 2003 and
$100 million of 6-7/8% debentures due 2023 to refund
$50 million, 8-3/4% debentures due 2017 and $100
million, 9-1/8% debentures due 2016.
At December 31, 1993, APS had $67.5 million and
Monongahela had $63.1 million outstanding in short-term
debt, and AGC had $50.87 million outstanding in
commercial paper and notes payable to affiliates, while
Potomac Edison and West Penn had short-term investments
of $4.6 million and $24.9 million, respectively.
The Subsidiaries' ratios of earnings to fixed
charges for the year ended December 31, 1993, were as
follows: Monongahela, 3.49; Potomac Edison, 3.34; West
Penn, 3.49; and AGC, 2.88.
APS and the Subsidiaries' consolidated
capitalization ratios as of December 31, 1993, were:
common equity, 46.1%; preferred stock, 6.5%; and long-
term debt, 47.4%. 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.
<PAGE>
- 18 -
During 1994, Monongahela, Potomac Edison and West
Penn plan to issue up to $50 million, $75 million, and
$105 million, respectively, of new securities,
consisting of both debt and preferred and common
equity, for general corporate purposes, including their
construction programs. In addition, the Operating
Subsidiaries may engage in tax-exempt solid waste
disposal financings to the extent funds are available
to Harrison County from the West Virginia cap
allocation. APS plans to fund Operating Subsidiaries'
sales of common stock to it through the issuance of
short-term debt and the sale of APS' 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
1994 up to $550 million of first mortgage bonds, up to
$100 million of preferred stock, and up to $78 million
of pollution control revenue notes through tender
offers or optional redemptions.
FUEL SUPPLY
System-operated stations burned approximately
15.7 million tons of coal in 1993. Of that amount, 67%
was cleaned (6.7 million tons) or used in stations
equipped with scrubbers (3.9 million tons). Use of
desulfurization equipment and cleaning and blending of
coal make burning local higher-sulfur coal practical,
and in 1993 about 96% 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 1994. The System depends on
short-term arrangements and spot purchases for its
remaining requirements. Through the year 1999, the
total coal requirements of present System-operated
stations are expected to be met with coal acquired
under existing contracts or from known suppliers.
The Operating Subsidiaries will meet the
requirements of Phase I of the CAAA by installing
scrubbers at Harrison Power Station. This will allow
the continued use of local, high-sulfur coal there. A
long-term contract for the supply of lime for use in
the scrubber operation and for fixation of the scrubber
byproduct has been negotiated and is expected to be
signed in early 1994. It is expected that the use of
lime will increase the costs of operating the station.
For each of the years 1989 through 1992, the
average cost per ton of coal burned was, respectively,
$34.64, $35.97, $36.74 and $36.31. For the year 1993,
the cost per ton decreased to $36.19, and in December
1993 the cost per ton was $36.45.
<PAGE>
- 19 -
The labor agreement between the United Mine
Workers of America (UMWA) and the Bituminous Coal
Operators' Association (BCOA) expired on February 1,
1993. As a result, the UMWA initiated selective
strikes against BCOA member companies on February 2,
1993. In late May and early June, numerous mines which
serve the Operating Subsidiaries' power stations were
closed down to various degrees. The UMWA and BCOA
agreed to a new five year contract on December 14,
1993, and mining operations resumed at most mines
during the week of December 20, 1993. The Operating
Subsidiaries continued to meet customer needs during
this approximately seven-month period through the use
of existing low cost inventories, additional spot and
substitute contract coal purchases, and some
conservation measures, primarily at the Harrison Power
Station.
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 Pennsylvania and Maryland
were issued for West Penn and Potomac Edison in May and
February, 1993.
West Penn
On May 14, 1993, the Pennsylvania Public Utility
Commission (PUC) issued an order in West Penn's base
rate case effective May 18, 1993, authorizing an
increase in revenues of $61.6 million, of which $26.1
million was for recovery of carrying charges (return on
investment and taxes) associated with West Penn's CAAA
compliance plan through June 30, 1993. West Penn had
originally filed for a base rate increase designed to
produce $101.4 million. West Penn received all
maintenance expenses that it had requested, and a
return on equity (ROE) of 11.5%.
West Penn filed a petition on January 12, 1994
with the 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 are recognized in
rates. West Penn cannot predict the outcome of this
proceeding.
West Penn plans to file an application with the
PUC on or about March 31, 1994, for a base rate
increase to recover 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. It is expected that the
new rates will become effective on or about December
31, 1994. West Penn cannot predict the precise amount
to be requested or the outcome of this proceeding.
On February 20, 1992, the Commonwealth Court of
Pennsylvania affirmed the PUC's December 13, 1990,
decision relating to West Penn's challenge to the PUC's
methodology for calculation of ROE. Three industrial
customers also appealed to the Commonwealth Court that
part of the PUC order which failed to allocate capacity
costs of PURPA projects on a demand basis in West
Penn's Energy Cost Rate. On June 25, 1992, the
Commonwealth Court reversed the PUC's decision on this
issue and remanded the case to the PUC for further
proceedings. West Penn and other parties have
negotiated a settlement on capacity costs of PURPA
projects and other demand-related costs in West Penn's
Energy Cost Rate, which settlement does not affect West
Penn's revenues. The settlement agreement was approved
by the PUC and was implemented in 1993.
<PAGE>
- 20 -
Monongahela
On January 18, 1994, Monongahela filed an
application with the West Virginia Public Service
Commission (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. It is
expected that a decision will be rendered about
November 15, 1994, with increases to be effective
immediately. Monongahela cannot predict the outcome of
this proceeding.
Monongahela filed a petition on January 11, 1994,
with the Public Utilities Commission of Ohio (PUCO)
requesting authorization to accrue post-in-service
carrying charges on the Harrison scrubbers until its
investment in such scrubbers is recognized in rates.
The petition also requested authorization for
Monongahela to defer depreciation, and operating and
maintenance expenses, including property taxes (but not
including fuel costs) with respect to the scrubbers
until the recovery of the deferrals can be addressed in
Monongahela's next base rate case or otherwise, as the
PUCO may deem appropriate. Monongahela is currently
awaiting a decision on this petition. If the petition
is approved, Monongahela will file its Ohio base rate
case in early 1995.
Potomac Edison
The Maryland Public Service Commission (Maryland
PSC) issued a final order in Potomac Edison's base rate
case on February 24, 1993, authorizing an annual
increase of $11.3 million, effective February 25, 1993,
which included CAAA carrying charges through February
28, 1993. The original filing in July of 1992 was
designed to produce approximately $23.0 million in
additional annual revenues. Subsequent adjustments
reduced this request to $17.6 million. Potomac Edison
received most of the maintenance expenses that it had
requested and a ROE of 11.9%.
On April 30, 1993, Potomac Edison filed with the
Virginia State Corporation Commission (SCC) for a rate
increase designed to produce $10.0 million in
additional annual revenues. The new rates went into
effect on September 28, 1993, subject to refund.
Hearings have been held and a final SCC decision is
expected by April 1994. Potomac Edison cannot predict
the outcome of this proceeding.
<PAGE>
- 21 -
On January 14, 1994, Potomac Edison filed an
application with the West Virginia PSC for a base rate
increase designed to produce $12.2 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. It is expected that a decision will
be rendered about November 15, 1994, with increases to
be effective immediately. Potomac Edison cannot
predict the outcome of this proceeding.
On or about April 15, 1994, and June 30, 1994,
Potomac Edison plans to file new rate cases in Maryland
and Virginia, respectively. The amounts of the
requested increases have not yet been determined, but
they will include 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. It is expected
that the Maryland decision will be rendered in late
1994, and the Virginia decision in mid-1995. However,
in both jurisdictions, it is expected that increases
will be effective in late 1994.
Monongahela and Potomac Edison
Pursuant to its order of December 12, 1991,
approving Monongahela and Potomac Edison's plan for
compliance with Phase I of the CAAA, the West Virginia
PSC authorized recovery by Monongahela and Potomac
Edison of $5.6 million and $1.4 million, respectively,
of carrying charges on Phase I CAAA compliance costs
through March 31, 1993, effective July 1, 1993. This
brings the annual Phase I CAAA recovery for Monongahela
and Potomac Edison to $8.7 million and $2.2 million,
respectively. Pursuant to the order, Monongahela and
Potomac Edison will submit requests for recovery of
carrying charges through March 31, 1994, on Phase I
CAAA compliance costs in the annual energy cost review
proceedings with any increase to be effective July 1,
1994. The annual values of all CAAA revenues
authorized in these proceedings will be removed from
this collection process effective when full Phase I
CAAA costs are included in base rates as a result of
the 1994 rate case filings.
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 has been
issued by an Administrative Law Judge (ALJ) on December
21, 1993, for an ROE of 10.83%, which the other parties
argue should be further adjusted to reflect changes in
capital market conditions since the hearings.
Exceptions to this recommendation have been filed by
all parties for consideration by the full Commission.
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% are unjust and unreasonable. This
new complaint requests an ROE of 8.53% with rates
subject to refund beginning April 1, 1994. AGC cannot
predict the outcome of these proceedings.
<PAGE>
- 22 -
FERC
West Penn, Potomac Edison, and Monongahela
implemented settlement agreements in 1993 covering
wholesale rates in effect for their municipal, co-op,
and borderline agreement customers subject to the
jurisdiction of the FERC. Each included carrying
charges for work in progress on the scrubbers at the
Harrison Power Station, additional expenses for
postretirement benefits other than pensions (see
below), and future automatic rate changes resulting
from changes to taxes or tax rates (federal, state and
local for Monongahela and West Penn, and federal for
Potomac Edison). The amounts of the increases and the
effective dates for West Penn, Potomac Edison, and
Monongahela were $1.6 million on June 15, 1993; $1.5
million on September 15, 1993; and $0.6 million on
December 1, 1993, respectively. It is anticipated that
additional filings to include 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 for
each Operating Subsidiary will be made in 1994 with
increases to be effective around the end of 1994.
Postretirement Benefits Other Than Pensions (SFAS No.
106)
The Operating Subsidiaries and APSC adopted SFAS
No. 106 as of January 1, 1993. This requires all
companies to accrue for the cost of postretirement
benefits other than pensions (principally health care
and life insurance) for the employee and covered
dependents during the years that the employee renders
the necessary service to receive such benefits. Prior
to 1993, medical expenses and life insurance premiums
paid by the Operating Subsidiaries and APSC for retired
employees and their dependents were recovered in rates
on a pay-as-you-go basis.
Recovery of SFAS No. 106 costs has been
authorized for retail customers in Maryland effective
in February 1993, in Pennsylvania effective in May
1993, and for FERC wholesale customers effective on the
rate case effective date described above under ITEM 1.
RATE MATTERS, FERC. Regulatory actions have been taken
by the PUCO and Virginia PSC, which indicate that
substantial recovery is probable. The West Virginia
PSC considers recovery of SFAS No. 106 costs on a case-
by-case basis and therefore Monongahela and Potomac
Edison cannot predict the outcome of such proceedings.
Recovery has been requested in rate cases filed in
Virginia and West Virginia for which final commission
decisions are expected in 1994. Recovery of these
costs in Ohio will be requested in the next base rate
case which is expected to be filed in early 1995. The
Operating Subsidiaries are currently recovering
approximately 85% of SFAS No. 106 expenses in rates.
This reflects for West Virginia and Ohio only the
recovery of the previously authorized pay-as-you-go
component. The Operating Subsidiaries have recorded
regulatory assets relating to those regulatory
jurisdictions where full recovery of SFAS No. 106 level
of expenses has not yet been granted recovery in rates.
The Operating Subsidiaries do not anticipate that SFAS
No. 106 will have a substantial effect on consolidated
net income.
<PAGE>
- 23 -
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 $361 million
in capital expenditures over the next three years,
including $254 million for compliance with Phase I of
the CAAA, described below, and initial cost for
anticipated compliance with Phase II. The full costs
of compliance with Phase II cannot be estimated at this
time, but may be substantial. Additional legislation
or regulatory control requirements, if enacted, may
well require modifying, supplementing, or replacing
equipment at existing stations at substantial
additional cost.
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. In February 1994, three notices of
violation were received by the Operating Subsidiaries
from the West Virginia Division of Environmental
Protection (WVDEP) regarding opacity excursions for
three power stations in West Virginia. The Operating
Subsidiaries are working with the WVDEP to resolve the
alleged violations. It is not anticipated that the
alleged violations will result in substantial
penalties. At the major stations (other than Mitchell
Unit No. 3 and Pleasants, which have scrubbers), the
Operating Subsidiaries meet current emission standards
as to sulfur dioxide by using low-sulfur coal, by
purchasing cleaned coal to lower the sulfur content, or
by blending 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 sulfur dioxide and two
million tons of nitrogen oxides 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 five coal-fired plants and
any coal-fired plants or units reactivated in the
future will be affected in Phase II. Installation of
scrubbers at the Harrison Power Station is the strategy
undertaken by the Operating Subsidiaries to meet the
required sulfur dioxide emission reductions for Phase I
(1995). Continuing studies will determine the
compliance strategy for Phase II (2000). It is
expected that burner modifications at all power
stations will satisfy the nitrogen oxide 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 units and is being installed on Phase II units.
Studies to evaluate cost effective options to comply
with Phase II of the CAAA, including those which may be
available from the use of Operating Subsidiaries'
banked emission allowances and from the emission
allowance trading market, are continuing.
<PAGE>
- 24 -
In an effort to introduce market forces into
pollution control, the CAAA created sulfur dioxide
emission allowances. An allowance is defined as an
authorization for an owner to emit one ton of sulfur
dioxide into the atmosphere during or following a
specified calendar year. Subject to regulatory
limitations, allowances (including bonus and extension
allowances) not used by an owner for its own compliance
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 570,000 bonus and extension allowances
during Phase I. These allowances are in addition to
the Table A allowances of approximately 356,000 per
year.
As a result of EPA's 1993 auctioning of a number
of Table A allowances retained from each utility's
annual allotment, approximately 16,000 allowances were
sold for the Operating Subsidiaries. Such auctions
will be held every year for the foreseeable future and
allowances sold thereby will result in a prorational
allocation of revenues back to the Operating
Subsidiaries. If some allowances offered at auction
remain unsold, the balance will also be prorationally
rebated to the utilities which contributed them. The
proceeds from these auctions are expected to be
relatively minimal and the Operating Subsidiaries plan
to credit these proceeds against the capital cost of
emission compliance activities, subject to regulatory
approval. Other allowance trading activities may be
undertaken by the Operating Subsidiaries once certain
tax questions are answered and once studies to
determine Phase II compliance strategy are completed.
In 1989, the West Virginia Air Pollution Control
Commission approved the construction of a 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 National Ambient Air
Quality Standards (NAAQS) for sulfur dioxide. 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 was submitted to the WVDEP in
June 1993. Costs associated with the GEP stack are
approximately $7 million. Monongahela is awaiting
action by the WVDEP.
<PAGE>
- 25 -
Under an EPA-approved consent order with
Pennsylvania, West Penn completed construction of a GEP
stack at the Armstrong 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 sulfur dioxide would follow.
As a result of the 1985 revision of its stack height
rules, EPA refused to reclassify the area to attainment
status. West Penn appealed the EPA's decision. In
1988, the U. S. Court of Appeals for the Third Circuit
dismissed West Penn's appeal for lack of jurisdiction,
stating that West Penn's request for reconsideration
before EPA made EPA's denial a non-final agency action.
West Penn's request for reconsideration before EPA
remains pending. West Penn cannot predict the outcome
of this proceeding.
Water Standards
Under the National Pollutant Discharge
Elimination System (NPDES) permitting procedures,
permits for all System-owned stations are in place.
However, in proposed NPDES renewal permits for some
stations which are currently being sought, some
conditions are being appealed through the regulatory
process since the Operating Subsidiaries believe the
effluent limitations being applied are overly
stringent. The Operating Subsidiaries continue to work
with the appropriate state agencies to resolve these
issues. In the meantime, the existing permits remain
in effect during the appeal process.
The EPA and states are now implementing
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 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.
Pursuant to the National Groundwater Protection
Strategy, which supplements existing West Virginia
groundwater protection policy, West Virginia has
adopted a Groundwater Protection Act. 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 which cannot be exceeded. The Operating
Subsidiaries anticipate that some facilities will not
be able to meet the new compliance limits. Variance
requests and requests for stays of implementation have
been made for all affected facilities. However,
variance rules have not yet been promulgated and action
on the requests has not been taken. Therefore, it is
not possible to predict the difficulty and costs
associated with obtaining variances. If variances are
not granted, costs may be incurred by the Operating
Subsidiaries for groundwater remediation. Such costs,
if any, cannot be predicted at this time.
<PAGE>
- 26 -
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. The 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
anticipated at this time.
In 1993, two notices of violation were received
by the Operating Subsidiaries from the WVDEP regarding
excursions above limits contained in NPDES permits for
discharge of leachate from fly ash landfills in West
Virginia. One violation notice was withdrawn by the
state agency and the other was resolved without payment
of substantial penalty. On January 27, 1994 and
February 9, 1994, the Operating Subsidiaries received
two separate notices of violation from PADER regarding
excursions above limits contained in the NPDES permit
for discharge of leachate from Hatfield's Ferry Power
Station fly ash landfill. One violation notice was
resolved without payment of substantial penalty. The
Operating Subsidiaries are working with the PADER to
resolve the other alleged violation. It is not
anticipated that the alleged violation will result in
substantial penalties.
Hazardous and Solid Wastes
Pursuant to the Resource Conservation and
Recovery Act of 1976 and the Hazardous and Solid Waste
Management Amendments of 1984 (RCRA), EPA regulates the
disposal of hazardous and solid waste materials.
Pennsylvania, West Virginia, Maryland, Ohio, and
Virginia have also enacted hazardous and solid waste
management legislation.
With the installation of the scrubbers at the
Harrison Power Station, approximately 2.8 million tons
per year of scrubber sludge, consisting principally of
limestone and ash, will be generated and disposed of in
a disposal facility owned and operated by the Operating
Subsidiaries. The expected capacity of the site is 30
years. Pleasants Power Station processes its scrubber
sludge using a wet-fixation and slurry system, with the
treated sludge disposed of in a properly permitted
sludge pond. Mitchell and Harrison Power Stations
process their scrubber sludge by a dry-fixation process
with the stabilized sludge disposed of in a properly
permitted landfill. Coal combustion byproducts from
all other facilities are either sold for beneficial
reuse or landfilled in properly permitted and currently
adequate disposal facilities owned and operated by the
Operating Subsidiaries. The Operating Subsidiaries are
in the process of permitting additional capacity to
meet future disposal needs.
<PAGE>
- 27 -
Costs are being incurred as the Operating
Subsidiaries progress with implementation of both West
Virginia's and Pennsylvania's 1992 solid waste
regulatory changes. A predominant portion of the costs
are attributable to two major factors: 1) liner
systems for new disposal sites and the expansion
portion of existing disposal sites, and 2) the
assessment of groundwater impacts via monitoring wells.
Because past operating practices, while in compliance
with then existing regulations, may not meet the
current criteria, as measured by new standards, it is
possible that groundwater remediation may be required
at some of the Operating Subsidiaries' facilities. In
addition, under West Virginia's Solid Waste Rules, it
is possible that certain active disposal sites may have
to be retrofitted with liner systems to address
potential groundwater degradation. The draft permit
renewal from WVDEP for the currently active disposal
site at Albright Power Station requires, on a portion
of the site, retrofitting with a new liner system with
possible removal of already placed coal combustion
byproducts. The Operating Subsidiaries are working to
have this proposed permit condition removed; however if
it is not, it is anticipated that this condition will
be appealed.
EPA regulations on the burning of hazardous waste
in utility boilers are expected to be amended in 1994
making the practice cost prohibitive for the Operating
Subsidiaries. Until such time as the regulations are
amended, the Operating Subsidiaries will continue to
minimize their hazardous waste and to burn small
quantities of hazardous waste generated in accordance
with EPA boiler and industrial furnace disposal rules.
Once such regulations are amended, the low volume
wastes will be disposed of in incinerators or landfills
which are owned by third parties. None of the
Operating Subsidiaries are required to obtain hazardous
waste treatment, storage or disposal permits under
RCRA. With a continued effort to reduce hazardous
waste, disposal costs and potential environmental
liability should be minimized.
Potomac Edison has received a notice from the
Maryland Department of the Environment (MDE) 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 currently
being implemented by the current owner of the facility
in Frederick, Maryland. It is not anticipated that
Potomac Edison's share of remediation costs, if any,
will be substantial.
Emerging Environmental Issues
Title I of the CAAA establishes an ozone
transport region consisting of 11 northeast states
including Maryland and Pennsylvania. Sources within
the region will be required to reduce nitrogen oxide
emissions, a precursor of ozone, to a level conducive
to attainment of the ambient ozone standard. The first
step for Title I compliance will result in the
installation of low nitrogen oxide burners and
potentially overfire air at all Pennsylvania and
Maryland stations by 1995. This is compatible with
Title IV nitrogen oxide reduction requirements.
Modeling studies being conducted by the states will
determine if a second step of reductions will be
necessary which could require installation of post-
combustion control technologies.
<PAGE>
- 28 -
Title III of the CAAA requires EPA to conduct
studies of toxic air pollutants from utility plants to
determine if emission controls are necessary. EPA's
reports are expected to be submitted to Congress in
late 1995.
The impact of Titles I and III on the Operating
Subsidiaries is unknown at this time.
Both the CWA and the RCRA are expected to be
reauthorized in 1994. It is anticipated that coal
combustion byproducts will continue to be regulated as
nonhazardous waste, minimizing the Operating
Subsidiaries' disposal costs.
An additional issue which could impact the
Operating Subsidiaries and which is undergoing intense
study, is the 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 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
utility systems submitted similar letters.
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.
EPACT became law on October 24, 1992. This broad
legislation, among other things, amends PUHCA to permit
utilities subject to PUHCA to compete in the wholesale
generation business with other wholesale generators
which it exempts from 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.
EPACT also 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).
<PAGE>
- 29 -
Pursuant to the requirements of Section 712 of
EPACT, the Maryland, Ohio, Pennsylvania, Virginia, and
West Virginia commissions issued orders regarding four
broad economic and regulatory policy issues related to
the purchase of wholesale power. All of the
commissions decided to evaluate these issues on a case-
by-case basis or within their existing regulatory
framework, instead of establishing generic standards.
On January 24, 1994, the Maryland PSC issued an
order which instituted a proceeding for the purpose of
determining whether to implement standards which, under
EPACT, a state commission must consider in order to
encourage integrated resource planning and investments
in conservation and energy efficiency by electric
utilities. The order provides for the filing of
initial and reply comments and for a hearing on May 3,
1994. Potomac Edison intervened and will be submitting
comments in this proceeding.
Under EPACT, the FERC has initiated several
proceedings, one of the most significant being the
request for comments on transmission pricing, including
pricing as it may apply to parallel power flows. The
Operating Subsidiaries have developed and submitted a
pricing philosophy intended to meet certain goals,
including reliable operation of the transmission system
and protection of native load customers, while
promoting accurate price signals and offering third-
party transmission service at the lowest reasonable
rates. Other FERC initiatives included the issuance of
guidelines governing open access transmission requests
and rules governing the establishment of Regional
Transmission Groups.
The Operating Subsidiaries founded and continue
to participate in, along with other utilities, an
organization whose primary purpose is to develop a
mutually acceptable method of resolving the inequities
imposed on transmission network owners by parallel
power flows.
The SEC has also issued regulations and proposed
regulations to implement EPACT, including the
integration of EPACT with PUCHA and the effect of EPACT
on nonexempt PUCHA companies such as APS and its
Subsidiaries.
In July 1993, the 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. In
November 1993, West Penn filed a petition with the PUC
requesting an Order that, pending the revision and
replacement of the existing state PURPA regulations,
any proceedings or orders regarding purchase by West
Penn of capacity from a qualifying facility under PURPA
shall be based on competitive bidding. The Office of
Consumer Advocate, the Office of Small Business
Advocate, the West Penn Power Industrial Intervenors,
and West Penn's two largest industrial customers have
intervened in support of West Penn's position. Several
PURPA developers and a group purporting to represent
PURPA interests have filed in opposition to certain
parts of the petition. West Penn cannot predict the
outcome of this proceeding.
<PAGE>
- 30 -
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. The West Virginia PSC has taken no
further action since the filing of comments.
On December 17, 1992, the PUCO 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 PUCO invited comments by March 3, 1993 and
reply comments by March 24, 1993. A number of
interested parties, including Monongahela, submitted
comments. The PUCO has taken no further action
following the filing of comments.
Maryland and Virginia have not mandated
compulsory competitive bidding at this date.
The Omnibus Budget Reconciliation Act of 1993
increased the marginal corporate income tax rate from
34% to 35%, retroactive to January 1, 1993. As a
result, the Operating Subsidiaries' income tax expense
for 1993 increased by about $3 million.
On June 13, 1990, the Maryland PSC began an
investigation to determine whether Potomac Edison's
methodology for calculating avoided costs under PURPA
is appropriate. On October 11, 1991, the Maryland PSC
incorporated this review of avoided costs into a
collaborative process already formed between its Staff,
the Maryland Department of Natural Resources, Potomac
Edison, Eastalco Aluminum, the Maryland Energy
Administration, and the Office of People's Counsel.
Although the group's primary mission was to avoid
litigation by working cooperatively to develop demand-
side management programs, the issue of avoided costs
was addressed because avoided costs are needed for
determining the cost-effectiveness of programs. These
negotiations culminated in a Settlement Agreement which
was signed by the six parties and filed with the
Maryland PSC on October 14, 1993. The Hearing Examiner
issued a proposed order accepting the Settlement
Agreement on November 17, 1993. The proposed order
became final on December 17, 1993, thereby concluding
this proceeding.
In October 1990, the 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 PUC's order
proposed that the affected utilities receive full
recovery of the costs of approved programs, as well as
financial incentives for implementing such programs,
including recovery of lost revenues. West Penn filed
its proposed programs with the PUC. On December 13,
1993, the PUC entered an order which provides for the
recovery of program costs either through a surcharge or
deferral to a base rate case; the recovery of revenues
lost due to the implementation of demand-side
management programs through a base rate case; and the
award of incentives for good program performance or
the assessment of penalties for poor performance. Two
parties to this proceeding have petitioned the PUC for
reconsideration and clarification and the Pennsylvania
Industrial Energy Coalition has filed an appeal with
the Commonwealth Court of Pennsylvania. West Penn
cannot predict the final outcome of this proceeding.
<PAGE>
- 31 -
During 1993, 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 received the Maryland PSC's approval to
implement a Commercial and Industrial Lighting Rebate
Program as of July 1, 1993. Through December 31, 1993
Potomac Edison had received applications for $7.5
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 five-year
period.
ITEM 2. PROPERTIES
Substantially all of the properties of the
Operating Subsidiaries are held subject to the lien
securing each company'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.)
<PAGE>
- 32 -
ITEM 3. LEGAL PROCEEDINGS
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 the plaintiff's use of
electric power during the United Mine Workers' strike
of 1977-8. A jury verdict in favor of the defendants
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 four PURPA projects:
Milesburg (43 MW), Burgettstown (80 MW), Shannopin (80
MW) and Point Marion (2 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 costs at the time the agreements were
negotiated, as defined by PURPA. Yearly capacity
payments under the four agreements would total in
excess of $50 million. Each agreement was subject to
prior PUC approval of the pass-through to West Penn's
customers of the total cost incurred under each
agreement, on a current basis. In 1987 and 1988, West
Penn filed a separate petition with the PUC for each
agreement requesting an appropriate PUC order, and
various parties intervened. Since that time, all four
agreements have been, in varying degrees, the subject
of complex and continuing regulatory and judicial
proceedings. During 1993, West Penn entered into a
settlement agreement with Point Marion and that project
has been terminated.
On November 24, 1993, the Pennsylvania Supreme
Court issued a per curiam opinion regarding the
Milesburg project which upheld the decision of the
Commonwealth Court concerning the time frame for the
calculation of avoided cost and upheld the decision
that the PUC had the authority under PURPA to revise
and reinstate a lapsed power purchase contract. West
Penn is considering its options as a result of this
ruling, including a petition for certiorari to the
United States Supreme Court.
On December 30, 1993, the Pennsylvania Supreme
Court issued a per curiam opinion regarding the
Shannopin project which upheld the decision of the
Commonwealth Court affirming the PUC's authority under
PURPA to revise voluntarily negotiated power purchase
contracts. West Penn is considering its options as a
result of this ruling, including a petition for
certiorari to the United States Supreme Court. As of
December 31, 1993, petitions for allowance of an appeal
of the decision of the Pennsylvania Commonwealth Court
on the Burgettstown project were pending before the
Pennsylvania Supreme Court. West Penn cannot predict
the outcome of these proceedings.
On October 28, 1993, South River Power Partners,
L.P. ("South River") filed a complaint against West
Penn with the PUC. The complaint seeks to require West
Penn to purchase 240 MW from a proposed coal-fired
PURPA project which South River proposes to build in
Fayette County, Pennsylvania. South River's proposed
initial price for this power would be over $0.09 per
kWh. West Penn is opposing this complaint as the power
is not needed and the price is in excess of avoided
cost. The Pennsylvania Consumer Advocate, the Small
Business Advocate, the PUC Trial Staff and various
industrial customers have also intervened in opposition
to the complaint. West Penn cannot predict the outcome
of this proceeding.
<PAGE>
- 33 -
Two previously reported complaints had been filed
with the West Virginia PSC by developers of
cogeneration projects in Marshall and Barbour Counties,
West Virginia 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 have asked the West Virginia PSC to consider
issues 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 this order, both developers requested the
start of negotiations. Monongahela and Potomac Edison
cannot predict the outcome of these proceedings.
On November 16, 1992, Potomac Edison and the
developer of a proposed cogeneration project located in
Cumberland, Maryland, requested that the Maryland PSC
approve an amendment to a previously approved agreement
for the sale of 180 MW of capacity and associated
energy from the project to Potomac Edison. The
amendment provides for the relocation of the proposed
project within the Cumberland area; a delay of one year
in the project's earliest in-service date to October 1,
1996, without increase in the initial capacity rate
(which otherwise escalates annually at one-half the
rate of actual inflation); and other changes consistent
with the site and in-service date modifications. The
Maryland PSC commenced an investigation of the
amendment in December 1992. After hearings, the
parties reached a settlement which was approved by the
Maryland PSC on March 17, 1993. The settlement
agreement resulted in a further delay of the project's
in-service date to October 1, 1999, modified the
initial capacity rate with only a slight escalation,
and provided that Potomac Edison would pay, and recover
from customers by a surcharge, a portion of the
project's costs resulting from the delay. On December
22, 1993, the Maryland PSC approved the surcharge and
these costs are being recovered from customers
effective January 1, 1994.
As previously reported, effective March 1, 1989,
West Virginia enacted a new method for calculating the
Business and Occupation Tax (B & O Tax) on electricity
generated in that state, which disproportionately
increased the B & O Tax on shipments of electricity to
other states. In 1989, West Penn, the Pennsylvania
Consumer Advocate, and several West Penn industrial
customers filed a joint complaint in the Circuit Court
of Kanawha County, West Virginia seeking to have the B
& O Tax declared illegal and unconstitutional on the
grounds that it violates the Interstate Commerce Clause
and the Equal Protection Clause of the federal
Constitution and certain provisions of federal law that
bar the states from imposing or assessing taxes on the
generation or transmission of electricity that
discriminate against out-of-state entities. In 1991,
West Penn amended the complaint to include a 1990
increase in the rate of the B & O Tax. The trial was
held in July 1993 and briefs have been filed. West
Penn cannot predict the outcome of this litigation.
<PAGE>
- 34 -
As of January 1994, Monongahela has been named as
a defendant along with multiple other defendants in
1,429 pending asbestos cases involving multiple
plaintiffs and Monongahela, Potomac Edison and West
Penn have been named as defendants along with multiple
defendants in an additional 626 cases by multiple
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
600 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
Subsidiary-operated stations were employed by third-
party contractors, with the exception of three 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 $1 million for the loss of
consortium claim. Therefore, because of the multiple
defendants, the Operating Subsidiaries believe
potential liability of the Operating Subsidiaries 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 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 ("CERCLA"), with
respect to the Jack's Creek/Sitkin Smelting Superfund
Site ("Site"). The Operating Subsidiaries are among
some 880 PRPs that have been identified at the Site.
EPA is planning to issue a Proposed Plan and Record of
Decision in September 1994 delineating the remedy
selected for the Site. At this time it is not possible
to determine what liability, if any, the Operating
Subsidiaries may have regarding the Site.
<PAGE>
- 35 -
In 1970, the Operating Subsidiaries filed with
the Federal Power Commission (FPC) an application for a
license to build a 1,000-MW energy-storage facility
near Davis, West Virginia. In 1977, FPC issued a
license for the project, but various parties, including
the State of West Virginia and the U.S. Department of
Interior, filed appeals, which are now pending before
the U.S. Court of Appeals for the District of Columbia.
The U.S. Army Corps of Engineers (Corps) denied a
dredge and fill permit for the project, which decision
was appealed. The U.S. District Court for the District
of Columbia decided that the Corps had no jurisdiction
in the matter. The Corps filed an appeal with the U.S.
Court of Appeals for the District of Columbia. In
1987, the appellate Court decided that the Corps did
have jurisdiction and remanded the case to the U.S.
District Court for further consideration of the Corps'
denial of the permit. The U. S. Supreme Court refused
to review that decision. In 1988, the U.S. District
Court reversed the Corps' denial of the dredge and fill
permit. The District Court's decision, which has now
been appealed, found, among other things, that 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, and as a result the Court remanded the matter
to the Corps for further proceedings. Negotiations are
ongoing to settle this matter. The Operating
Subsidiaries cannot predict the outcome of these
proceedings.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The holders of 46,537,924 shares of common stock of APS voted
at a special meeting held on November 3, 1993 to amend APS' charter
to reclassify each share of common stock, par value $2.50 per
share, issued or unissued, into two shares of common stock, par
value $1.25 each. The holder of 259,451 shares voted against the
proposal and the holders of 296,598 shares abstained. The charter
amendment became effective at the close of business on November 4,
1993. The amount of APS' stated capital was not changed as a
result of the amendment.
The holder of the common stock of Monongahela on December 13,
1993, waived the holding of a meeting and consented in writing to
the amendment of its Charter to reflect the redemption of 50,000
shares of $9.64 series cumulative preferred stock.
No other company submitted matters to a vote of shareholders
during the fourth quarter.
<PAGE>
- 36 -
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:
<TABLE>
<CAPTION>
Position (a) and Period of Service
Name Age APS APSC MP PE WP AGC
<S> <C> <C>
Charles S. Ault 55 V.P.
(1990- )
Previously,
Dir., Per.
(1986-90)
</TABLE>
<TABLE>
<S> <C> <C>
Thomas A. Barlow 59 V.P.
(1987- )
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
Eileen M. Beck 52 Sec. Sec. Asst. Sec. Asst. Sec. Asst. Sec. Sec. (1982- )
(1988- ) (1988- ) (1988- )& (1988- ) (1988- )
Asst. Treas.
(1981- )
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
Klaus Bergman 62 Pres., CEO, Pres., 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- )
</TABLE>
<TABLE>
<S> <C> <C>
Charles V. Burkley 62 Comptroller
(1984- )
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Nancy L. Campbell 54 V.P. V.P. Asst. Treas. Treas. &
(1994- ) (1993- ) & Asst. Sec. Asst. Sec.
Treas. Treas. (1988- ) (1988- )
(1988- ) (1988- )
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C>
Richard J. Gagliardi 43 V.P. V.P. Asst. Sec. Asst. Treas.
(1991- ) (1990- ) (1990- ) (1982- )
Previously,
Asst. V.P. &
Dir. Taxes
(1988-90)
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
Stanley I. Garnett,II 50 V.P. - Fin. V.P. - Fin. Dir. Dir. Dir. Dir. & V.P.
(1990- ) (1990- ) (1990- ) (1990- ) (1990- ) (1990- )
& Asst. Sec. & Asst. Sec. V.P. (1985- )
(1982- ) (1982- ) & Asst. Treas.
Previously, Previously, & Asst. Sec.
V.P. V.P. - Legal (1981- )
& Regulatory
</TABLE>
(a) All officers and directors are elected annually.
<PAGE>
- 37 -
<TABLE>
<CAPTION>
Position (a) and Period of Service
Name Age APS APSC MP PE WP AGC
<S> <C> <C> <C> <C> <C>
Nancy H. Gormley 61 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
</TABLE>
<TABLE>
<S> <C> <C>
Benjamin H. Hayes 59 Pres.
(1987- ) &
Dir.
(1992- )
</TABLE>
<TABLE>
<S> <C> <C>
Thomas K. Henderson 53 V.P.
(1985- )
</TABLE>
<TABLE>
<S> <C> <C> <C> <C>
Kenneth M. Jones 56 V.P. & V.P. & Dir. & V.P.
Comptroller Comptroller (1991- )
(1991- ) (1991- )
Previously,
Comptroller
</TABLE>
<TABLE>
<S> <C> <C> <C>
Thomas J. Kloc 41 Comptroller Comptroller
(1988- ) (1988- )
</TABLE>
<TABLE>
<S> <C> <C>
James D. Latimer 55 V.P.
(1988- )
</TABLE>
(a) All officers and directors are elected annually.
<PAGE>
- 48 -
<TABLE>
<CAPTION>
Position (a) and Period of Service
Name Age APS APSC MP PE WP AGC
<S> <C> <C>
Kenneth D. Mowl 54 Sec. & Treas.
(1986- )
</TABLE>
<TABLE>
<S> <C> <C>
Charles S. Mullett 62 Sec. & Treas.
(1983- )
</TABLE>
<TABLE>
<S> <C> <C>
Robert B. Murdock 61 V.P.
(1972- )
</TABLE>
<TABLE>
<S> <C> <C>
Richard E. Myers 57 Comptroller
(1980- )
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
Alan J. Noia 46 V.P.-Fin. V.P.-Fin. Dir. Pres. & Dir. Dir. Dir. (1984-90)
(1987-90) (1987-90) (1987-90) (1990- ) (1987-90) & V.P. (1982-90)
Previously,
Dir. & Exec. V.P.
(3/90 - 5/90);
Previously,
Dir. & V.P.
(1987-1990)
</TABLE>
<TABLE>
<S> <C> <C>
Jay S. Pifer 56 Pres.
(1990- ) &
Dir.
(1992- )
Previously,
V.P.
</TABLE>
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
Peter J. Skrgic 52 V.P. V.P. Dir. Dir. & V.P. Dir. Dir. & V.P.
(1989- ) (1989- ) (1990- ) (1990- ) (1990- ) (1989- )
Previously,
Exec. Dir.,
Operating
</TABLE>
<TABLE>
<S> <C> <C>
Robert R. Winter 50 V.P.
(1987- )
</TABLE>
<TABLE>
<S> <C> <C>
Dale F. Zimmerman 60 Sec. & Treas.
(1990 - )
Previously
Asst. Sec. &
Asst. Treas.
</TABLE>
(a) All officers and directors are elected annually.
<PAGE>
- 39 -
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, 1993, there were 63,396 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>
1993 1992
Dividend High Low Dividend High Low
<S> <C> <C> <C> <C> <C> <C> <C>
1st Quarter 40-1/2 cents $25-15/16 $23-7/16 40 cents $22-1/2 $20-3/4
2nd Quarter 40-1/2 26-3/4 25 40 22-7/8 20-3/4
3rd Quarter 41 28-7/16 26-5/8 40 24-3/8 22
4th Quarter 41 28 25-1/2 40-1/2 24-1/4 22-15/16
</TABLE>
The high and low prices in 1994 were 26-1/2 and
24-1/8 through February 3. The last reported sale on
that date was at 25.
Monongahela, Potomac Edison, and West Penn. The
information required by this Item is not applicable as
all the common stock of these 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>
- 40 -
ITEM 6. SELECTED FINANCIAL DATA
Page No.
APS D-1
Monongahela D-3
Potomac D-5
West Penn D-7
AGC D-9
D-1
<TABLE>
<CAPTION>
APS
CONSOLIDATED STATISTICS
Year ended December 31
1993 1992 1991 1990 1989 1988 1983
Summary of Operations (in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Operating revenues $2 331.5 $2 306.7 $2 282.2 $2 301.9 $2 260.7 $2 173.8 $1 737.6
Operation expense 1 208.4 1 252.0 1 252.2 1 338.6 1 337.1 1 259.7 987.4
Maintenance 231.2 210.9 204.2 182.0 185.5 166.6 122.6
Depreciation 210.4 197.8 189.7 180.9 172.3 165.7 113.4
Taxes other than income 178.8 174.6 167.5 152.5 139.5 127.5 100.4
Taxes on income 128.1 115.4 119.1 106.4 89.0 103.7 128.7
Allowance for funds used during
construction (21.5) (17.5) (7.9) (7.2) (7.7) (4.3) (26.0)
Interest charges and preferred
dividends 180.3 171.3 165.0 161.1 156.0 155.1 147.1
Other income, net (1.3) (1.6) (3.8) (5.9) (5.3) (5.7)
Consolidated net income $ 215.8 $ 203.5 $ 194.0 $ 191.4 $ 194.9 $ 205.1 $ 169.7
Common Stock Data (a)
Shares outstanding at Dec. 31
(in thousands) 117 664 113 899 108 451 106 984 105 579 104 268 96 950
Average shares outstanding
(in thousands) 114 937 111 226 107 548 106 102 104 787 103 460 95 839
Earnings per average share $1.88 $1.83 $1.80 $1.80 $1.86 $1.98 $1.77
Dividends paid per share $1.63 $1.60 1/2 $1.58 1/2 $1.58 $1.55 $1.51 $1.25
Dividend pay-out ratio 86.9% 88.3% 87.8% 87.6% 83.3% 76.2% 70.6%
Stockholders at Dec. 31 63 396 63 918 62 095 63 201 68 156 71 748 87 264
Market price range per share:
High 28 7/16 24 3/8 23 1/4 21 1/16 21 1/4 20 3/4 14 1/2
Low 23 7/16 20 3/4 17 7/16 17 17 13/16 17 15/16 11 3/16
Book value per share at Dec. 31 $16.62 $16.05 $15.54 $15.26 $14.99 $14.62 $11.85
Return on average common equity 11.40% 11.59% 11.70% 11.90% 12.55% 13.78% 15.24%
Capitalization Data at Dec. 31
Capitalization (in millions):
Common stock $1 955.8 $1 827.8 $1 685.6 $1 632.3 $1 582.4 $1 524.9 $1 417.7
Preferred stock:
Not subject to mandatory
redemption 250.1 250.1 235.1 235.1 235.1 235.1 240.1
Subject to mandatory redemption 26.4 28.0 29.3 30.6 30.6 30.7 81.1
Long-term debt 2 008.1 1 951.6 1 747.6 1 642.2 1 578.4 1 586.0 1 149.1
Total capitalization $4 240.4 $4 057.5 $3 697.6 $3 540.2 $3 426.5 $3 376.7 $2 888.0
Capitalization ratios:
Common stock 46.1% 45.0% 45.6% 46.1% 46.2% 45.1% 49.1%
Preferred stock:
Not subject to mandatory
redemption 5.9 6.2 6.3 6.6 6.8 7.0 8.3
Subject to mandatory redemption .6 .7 .8 .9 .9 .9 2.8
Long-term debt 47.4 48.1 47.3 46.4 46.1 47.0 39.8
Total Assets at Dec. 31
(in millions) $5 949.2 $5 039.3 $4 855.0 $4 561.3 $4 433.3 $4 334.4 $3 561.4
Property Data at Dec. 31 (in millions)
Gross property $7 176.9 $6 679.9 $6 255.7 $5 986.2 $5 721.5 $5 493.1 $4 135.4
Accumulated depreciation (2 388.8) (2 240.0) (2 093.7) (1 946.1) (1 807.1) (1 680.2) (1 087.2)
Net property $4 788.1 $4 439.9 $4 162.0 $4 040.1 $3 914.4 $3 812.9 $3 048.2
Gross additions during year $ 574.0 $ 487.6 $ 337.7 $ 321.8 $ 302.5 $ 199.5 $ 206.9
Ratio of provisions for depreciation
to depreciable property 3.37% 3.31% 3.28% 3.27% 3.26% 3.23% 3.10%
</TABLE>
D-2
<TABLE>
<CAPTION>
APS
1993 1992 1991 1990 1989 1988 1983
Revenues (in millions)
<S> <C> <C> <C> <C> <C> <C> <C>
Residential $ 818.4 $ 734.9 $ 708.3 $ 649.5 $ 626.2 $ 635.1 $ 489.6
Commercial 430.2 391.9 375.4 343.0 327.5 328.8 247.5
Industrial 673.4 637.7 600.2 571.5 553.5 564.8 476.2
Nonaffiliated utilities 346.7 465.5 525.0 679.9 698.5 589.0 479.9
Other 62.8 76.7 73.3 58.0 55.0 56.1 44.4
Total revenues $2 331.5 $2 306.7 $2 282.2 $2 301.9 $2 260.7 $2 173.8 $1 737.6
Sales--kWh (in millions)
Residential 12 514 11 746 11 755 11 264 11 042 10 772 8 891
Commercial 7 440 7 071 7 003 6 670 6 479 6 260 4 990
Industrial 16 967 16 910 16 430 16 511 16 239 16 005 13 916
Nonaffiliated utilities 12 388 17 753 18 211 21 796 24 383 22 543 14 036
Other 1 240 1 186 1 146 1 101 1 110 1 088 905
Total sales 50 549 54 666 54 545 57 342 59 253 56 668 42 738
Output--kWh (in millions)
Steam generation 38 247 40 373 42 307 41 933 43 497 42 955 38 998
Hydro and pumped-storage
generation 1 233 1 204 1 654 1 426 1 774 1 644 172
Pumped-storage input (1 385) (1 340) (1 907) (1 568) (1 973) (1 904)
Purchased power and
exchanges, net 15 245 17 279 15 321 17 924 19 169 16 998 5 963
Losses and system uses (2 791) (2 850) (2 830) (2 373) (3 214) (3 025) (2 823
Total sales as above 50 549 54 666 54 545 57 342 59 253 56 668 42 310
Energy Supply
Generating capability--
MW at Dec. 31
System-owned 7 991 7 991 7 992 7 991 7 906 7 906 7 138
Nonutility contracts (b) 292 212 162 160 160 160
Maximum hour peak--MW 6 678 6 530 6 238 6 070 6 489 6 045 5 198
Load factor 70.0% 69.3% 71.7% 71.3% 67.0% 70.0% 69.3%
Heat rate--Btu's per kWh 10 020 9 910 9 956 9 944 9 967 9 938 10 107
Fuel costs--cents per
million Btu's 142.12 141.93 143.19 140.97 136.70 135.66 161.28
Customers at Dec. 31
(in thousands)
Residential 1 176.6 1 161.5 1 146.6 1 133.4 1 118.1 1 102.3 1 032.2
Commercial 140.1 137.4 134.7 132.2 128.9 125.6 111.0
Industrial 23.8 23.6 23.1 22.8 22.4 21.8 19.7
Other 1.2 1.2 1.3 1.3 1.2 1.2 1.1
Total customers 1 341.7 1 323.7 1 305.7 1 289.7 1 270.6 1 250.9 1 164.0
Average Annual Use--
kWh per customer
Residential--APS 10 715 10 181 10 316 10 011 9 950 9 850 8 685
--National 9 318(c) 8 961(c) 9 280 9 056 9 063 9 082 8 379
All retail service--APS 27 800 27 259 27 205 26 996 26 866 26 715 24 163
Average Rate--cents per kWh
Residential--APS 6.54 6.26 6.03 5.77 5.67 5.90 5.51
--National 8.71(c) 8.63(c) 8.46 8.17 7.95 7.78 7.15
All retail service--APS 5.23 4.96 4.80 4.56 4.48 4.65 4.39
</TABLE>
(a) Reflects a two-for-one common stock split effective November 4, 1993.
(b) Capability available through contractual arrangements with nonutility
generators.
(c) Preliminary.
D-3
<TABLE>
<CAPTION>
Monongahela
SUMMARY OF OPERATIONS
(Thousands of Dollars)
1993 1992 1991 1990 1989 1988
Electric operating
revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential $185 141 $169 589 $163 757 $151 658 $146 429 $148 971
Commercial 110 762 102 709 97 849 90 095 86 527 87 221
Industrial 187 669 186 442 177 688 169 654 165 940 161 801
Nonaffiliated utilities 86 032 119 628 140 029 177 573 185 122 156 770
Other,
including affiliates 72 240 53 595 45 803 41 348 44 881 43 985
Total 641 844 631 963 625 126 630 328 628 899 598 748
Operation expense 364 027 372 002 364 968 379 663 395 614 367 918
Maintenance 67 770 62 909 64 035 57 768 58 690 47 207
Depreciation 56 056 53 865 51 903 50 433 48 381 46 495
Taxes other than income 34 076 33 207 35 378 34 310 32 552 32 183
Taxes on income 33 612 27 919 31 173 31 005 19 293 26 263
Allowance for funds used
during construction (5 780) (3 908) (1 341) (1 559) (2 295) (1 025)
Interest charges 37 588 36 013 33 494 33 264 32 544 32 072
Other income, net (7 203) (8 388) (8 573) (9 505) (11 325) (11 328)
Net income $61 698 $58 344 $54 089 $54 949 $55 445 $58 963
Return on average
common equity 11.94% 11.83% 11.51% 11.97% 12.40% 13.55%
</TABLE>
D-3
<TABLE>
<CAPTION>
Monongahela
FINANCIAL AND OPERATING STATISTICS
1993 1992 1991 1990 1989 1988
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (in thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross $1 684 322 $1 567 252 $1 458 643 $1 389 906 $1 334 814 $1 274 584
Accumulated depreciation (664 947) (628 595) (590 311) (550 104) (512 439) (481 190)
Net $1 019 375 $ 938 657 $ 868 332 $ 839 802 $ 822 375 $ 793 394
GROSS ADDITIONS TO PROPERTY
(in thousands) $ 140 748 $ 126 422 $ 84 515 $ 74 575 $ 84 972 $ 49 199
TOTAL ASSETS at Dec. 31
(in thousands) $1 407 453 $1 166 410 $1 091 287 $1 054 497 $1 024 709 $1 031 028
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $ 483 030 $ 475 628 $ 428 855 $ 425 016 $ 410 409 $ 404 363
Preferred stock (not subject to
mandatory redemption) 64 000 64 000 69 000 69 000 69 000 69 000
Long-term debt 460 129 444 506 372 618 367 871 367 826 363 481
$1 007 159 $ 984 134 $ 870 473 $ 861 887 $ 847 235 $ 836 844
Ratios:
Common stock 48.0% 48.3% 49.3% 49.3% 48.4% 48.3%
Preferred stock (not subject to
mandatory redemption) 6.3 6.5 7.9 8.0 8.2 8.3
Long-term debt 45.7 45.2 42.8 42.7 43.4 43.4
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
</TABLE>
<TABLE>
GENERATING CAPABILITY -
kW at Dec. 31:
<S> <C> <C> <C> <C> <C> <C>
Company-owned 2 325 300 2 325 300 2 325 300 2 325 300 2 301 925 2 301 925
Nonutility contracts (a) 159 000 79 000 29 000 27 000 27 000 27 000
KILOWATTHOURS IN THOUSANDS:
Sales:
Residential 2 689 830 2 527 247 2 581 628 2 430 539 2 401 287 2 383 046
Commercial 1 825 127 1 742 469 1 744 881 1 656 961 1 606 830 1 581 981
Industrial 4 656 921 4 872 126 4 905 715 4 868 551 4 828 376 4 569 044
Nonaffiliated utilities 3 082 715 4 578 187 4 877 930 5 634 908 6 490 586 5 978 295
Other, including affiliates 1 565 561 824 393 584 677 590 920 942 404 1 173 214
Total sales 13 820 154 14 544 422 14 694 831 15 181 879 16 269 483 15 685 580
Output:
Steam generation 10 194 794 10 593 059 11 512 714 11 247 964 12 328 241 12 310 632
Pumped-storage generation 263 329 260 155 375 500 306 470 390 151 384 195
Pumped-storage input (337 737) (332 989) (475 898) (389 467) (530 642) (516 155)
Purchased power and
exchanges, net 4 381 916 4 705 418 3 969 954 4 618 564 4 815 449 4 205 561
Losses and system uses (682 148) (681 221) (687 439) (601 652) (733 716) (698 653)
Total sales as above 13 820 154 14 544 422 14 694 831 15 181 879 16 269 483 15 685 580
CUSTOMERS at Dec. 31:
Residential 297 865 294 595 291 578 288 990 286 823 285 226
Commercial 34 626 34 005 33 484 33 107 32 614 32 077
Industrial 8 014 8 005 7 994 7 946 7 870 7 823
Other 170 172 172 170 166 165
Total customers 340 675 336 777 333 228 330 213 327 473 325 291
RESIDENTIAL SERVICE:
Average use-
kWh per customer 9 093 8 636 8 905 8 457 8 406 8 392
Average revenue-
dollars per customer 625.87 579.51 564.87 527.70 512.62 524.63
Average rate-
cents per kWh 6.88 6.71 6.34 6.24 6.10 6.25
</TABLE>
(a) Capability available through contractual arrangements with nonutility
generators.
D-5
<TABLE>
<CAPTION>
Potomac
SUMMARY OF OPERATIONS
(Thousands of Dollars)
1993 1992 1991 1990 1989 1988
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential $274 358 $243 413 $227 851 $213 165 $208 663 $205 551
Commercial 124 667 111 506 104 642 97 902 94 648 91 929
Industrial 175 902 157 304 147 654 148 632 152 296 153 226
Nonaffiliated utilities 108 132 141 120 161 720 210 710 208 524 173 993
Other, including affiliates 29 526 34 544 32 210 27 135 26 287 25 458
Total 712 585 687 887 674 077 697 544 690 418 650 157
Operation expense 413 145 414 939 423 489 460 546 449 480 421 088
Maintenance 64 376 53 141 49 766 45 035 46 837 44 169
Depreciation 56 449 53 446 50 578 47 547 44 638 42 727
Taxes other than income 46 813 45 791 43 937 38 527 36 483 31 355
Taxes on income 30 086 28 422 24 194 25 132 27 680 27 353
Allowance for funds used
during construction (7 134) (5 368) (3 366) (2 908) (2 381) (1 180)
Interest charges 43 802 39 392 36 831 33 049 28 805 27 669
Other income, net (8 419) (9 352) (9 593) (10 964) (10 802) (11 536)
Net income $73 467 $67 476 $58 241 $61 580 $69 678 $68 512
Return on average common equity 11.56% 11.71% 11.08% 12.59% 15.32% 15.75%
</TABLE>
D-6
<TABLE>
<CAPTION>
Potomac
FINANCIAL AND OPERATING STATISTICS
1993 1992 1991 1990 1989 1988
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (in thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross $1 857 961 $1 698 711 $1 557 695 $1 454 250 $1 352 491 $1 265 352
Accumulated depreciation (632 269) (591 378) (546 867) (504 168) (466 428) (430 760)
Net $1 225 692 $1 107 333 $1 010 828 $ 950 082 $ 886 063 $ 834 592
GROSS ADDITIONS TO PROPERTY
(in thousands) $ 179 433 $ 153 485 $ 116 589 $ 116 627 $ 104 009 $ 68 706
TOTAL ASSETS at Dec. 31
(in thousands) $1 519 763 $1 355 385 $1 256 712 $1 140 623 $1 074 464 $1 018 067
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $ 626 467 $ 567 826 $ 480 931 $ 453 761 $ 421 583 $ 403 493
Preferred stock:
Not subject to mandatory redemption 36 378 36 378 56 378 56 378 56 378 56 378
Subject to mandatory redemption 26 400 28 005 29 280 30 555 30 630 30 705
Long-term debt 517 910 511 801 453 584 399 518 320 533 316 193
$1 207 155 $1 144 010 $1 020 173 $ 940 212 $ 829 124 $ 806 769
Ratios:
Common stock 51.9% 49.6% 47.1% 48.3% 50.8% 50.0%
Preferred stock:
Not subject to mandatory redemption 3.0 3.2 5.5 6.0 6.8 7.0
Subject to mandatory redemption 2.2 2.5 2.9 3.2 3.7 3.8
Long-term debt 42.9 44.7 44.5 42.5 38.7 39.2
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY -
kW at Dec. 31 2 076 592 2 076 592 2 077 192 2 076 292 2 059 292 2 059 292
KILOWATTHOURS IN THOUSANDS:
Sales:
Residential 4 144 958 3 822 387 3 753 884 3 561 824 3 466 647 3 308 364
Commercial 2 091 930 1 954 025 1 912 848 1 818 789 1 744 825 1 643 469
Industrial 5 194 909 4 979 219 4 881 835 4 928 433 4 896 273 4 847 068
Nonaffiliated utilities 3 860 791 5 394 006 5 649 050 6 818 528 7 311 705 6 777 924
Other, including affiliates 649 636 616 711 615 604 593 548 599 099 590 310
Total sales 15 942 224 16 766 348 16 813 221 17 721 122 18 018 549 17 167 135
Output:
Steam generation 10 103 411 10 713 987 11 192 300 11 094 016 11 538 206 11 331 957
Hydro and pumped-storage
generation 368 834 351 035 502 302 430 500 522 300 488 872
Pumped-storage input (433 885) (407 393) (593 879) (489 243) (550 944) (545 143)
Purchased power and exchanges, net 6 691 792 6 937 037 6 517 575 7 387 314 7 526 595 6 819 612
Losses and system uses (787 928) (828 318) (805 077) (701 465) (1 017 608) (928 163)
Total sales as above 15 942 224 16 766 348 16 813 221 17 721 122 18 018 549 17 167 135
CUSTOMERS at Dec. 31:
Residential 309 096 302 559 295 564 289 695 281 469 272 490
Commercial 40 173 39 236 38 522 37 708 36 237 34 808
Industrial 4 509 4 435 4 283 4 132 3 957 3 758
Other 510 510 501 471 442 432
Total customers 354 288 346 740 338 870 332 006 322 105 311 488
RESIDENTIAL SERVICE:
Average use-
kWh per customer 13 562 12 766 12 822 12 463 12 511 12 346
Average revenue-
dollars per customer 897.70 812.96 778.25 745.90 753.04 767.09
Average rate-
cents per kWh 6.62 6.37 6.07 5.98 6.02 6.21
</TABLE>
D-7
<TABLE>
<CAPTION>
West Penn
SUMMARY OF OPERATIONS
(Thousands of Dollars)
1993 1992 1991 1990 1989 1988
Electric operating revenues:
<S> <C> <C> <C> <C> <C> <C>
Residential $ 358 900 $ 321 871 $ 316 685 $ 284 691 $ 271 067 $ 280 586
Commercial 194 773 177 697 172 924 154 999 146 364 149 689
Industrial 309 847 293 910 274 896 253 184 235 286 249 751
Nonaffiliated utilities 152 541 204 743 223 225 291 636 304 822 258 194
Other, including affiliates 68 916 78 620 83 073 74 342 58 108 53 334
Total 1 084 977 1 076 841 1 070 803 1 058 852 1 015 647 991 554
Operation expense 625 269 647 989 649 422 684 508 673 158 646 531
Maintenance 96 706 93 067 87 717 77 516 78 167 72 325
Depreciation 80 872 73 469 70 334 66 122 62 428 59 669
Taxes other than income 89 249 87 300 80 630 72 114 62 846 56 752
Taxes on income 51 529 44 078 47 846 33 867 24 988 32 007
Allowance for funds used
during construction (8 566) (8 276) (3 224) (2 729) (2 991) (2 150)
Interest charges 60 585 55 592 51 977 49 268 45 953 46 806
Other income, net (12 728) (14 534) (15 077) (15 067) (17 153) (18 501)
Consolidated net income $102 061 $98 156 $101 178 $93 253 $88 251 $98 115
Return on average common equity 11.20% 11.67% 12.55% 12.15% 11.74% 13.39%
</TABLE>
D-8
<TABLE>
<CAPTION>
West Penn
FINANCIAL AND OPERATING STATISTICS
1993 1992 1991 1990 1989 1988
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (in thousands):
<S> <C> <C> <C> <C> <C> <C>
Gross $2 803 811 $2 581 641 $2 409 005 $2 312 425 $2 209 054 $2 126 753
Accumulated depreciation (962 623) (904 906) (857 999) (809 674) (762 700) (718 274)
Net $1 841 188 $1 676 735 $1 551 006 $1 502 751 $1 446 354 $1 408 479
GROSS ADDITIONS TO PROPERTY
(in thousands) $ 251 017 $ 204 409 $ 134 443 $ 128 762 $112 801 $ 79 834
TOTAL ASSETS at Dec. 31
(in thousands) $2 544 763 $2 083 127 $2 006 309 $1 842 766 $1 784 493 $1 759 246
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $ 893 969 $ 782 341 $ 774 707 $ 723 567 $ 694 107 $ 688 241
Preferred stock (not subject to
mandatory redemption) 149 708 149 708 109 708 109 708 109 708 109 708
Long-term debt 782 369 759 005 621 906 563 378 563 410 563 762
$1 826 046 $1 691 054 $1 506 321 $1 396 653 $1 367 225 $1 361 711
Ratios:
Common stock 49.0% 46.3% 51.4% 51.8% 50.8% 50.5%
Preferred stock (not subject to
mandatory redemption) 8.2 8.8 7.3 7.9 8.0 8.1
Long-term debt 42.8 44.9 41.3 40.3 41.2 41.4
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY-
kW at Dec. 31:
Company-owned 3 589 408 3 589 408 3 589 408 3 589 408 3 544 783 3 544 783
Nonutility contracts (a) 133 000 133 000 133 000 133 000 133 000 133 000
KILOWATTHOURS IN THOUSANDS:
Sales:
Residential 5 679 746 5 396 533 5 419 150 5 271 390 5 173 781 5 080 461
Commercial 3 522 566 3 374 355 3 345 255 3 194 141 3 127 641 3 034 344
Industrial 7 114 765 7 058 895 6 643 238 6 713 824 6 514 384 6 589 467
Nonaffiliated utilities 5 444 798 7 780 654 7 683 817 9 342 543 10 580 015 9 786 410
Other, including affiliates 1 821 189 2 247 844 2 485 366 2 426 414 1 868 121 1 483 272
Total sales 23 583 064 25 858 281 25 576 826 26 948 312 27 263 942 25 973 954
Output:
Steam generation 17 949 335 19 066 445 19 602 129 19 590 731 19 630 384 19 312 206
Hydro and pumped-storage generation 600 497 592 895 775 798 688 517 862 119 771 172
Pumped-storage input (613 290) (599 729) (836 700) (689 186) (891 847) (842 545)
Purchased power and exchanges, net 6 967 752 8 139 496 7 373 185 8 428 158 9 125 988 8 131 123
Losses and system uses (1 321 230)(1 340 826) (1 337 586) (1 069 908) (1 462 702)(1 398 002)
Total sales as above 23 583 064 25 858 281 25 576 826 26 948 312 27 263 942 25 973 954
CUSTOMERS at Dec. 31:
Residential 569 601 564 300 559 444 554 716 549 773 544 520
Commercial 65 337 64 212 62 674 61 396 60 062 58 680
Industrial 11 218 11 138 10 826 10 687 10 561 10 249
Other 576 569 692 680 660 652
Total customers 646 732 640 219 633 636 627 479 621 056 614 101
RESIDENTIAL SERVICE:
Average use-
kWh per customer 10 025 9 608 9 733 9 550 9 459 9 380
Average revenue-
dollars per customer 633.48 573.07 568.76 515.75 495.60 518.02
Average rate-
cents per kWh 6.32 5.96 5.84 5.40 5.24 5.52
</TABLE>
(a) Capability available through contractual arrangements
with nonutility generators.
D-9
<TABLE>
<CAPTION>
AGC
STATISTICS
1993 1992 1991 1990 1989 1988
SUMMARY OF OPERATIONS
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
Electric operating revenues $90 606 $96 147 $100 505 $104 482 $111 011 $112 457
Operation and maintenance expense 6 609 6 094 6 774 5 974 6 229 6 716
Depreciation 16 899 16 827 16 778 16 756 16 816 16 797
Taxes other than income taxes 5 347 5 236 4 563 4 712 5 062 4 739
Federal income taxes 13 262 14 702 15 455 16 458 17 230 17 959
Interest charges 21 635 22 585 24 030 26 883 30 020 29 688
Other income, net (328) (21) (24) (17) (24) (109)
Net income $27 182 $30 724 $32 929 $33 716 $35 678 $36 667
Return on average common equity 11.72% 12.80% 13.19% 12.96% 13.13% 12.98%
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (in thousands):
Gross $824 904 $825 493 $822 332 $821 424 $820 376 $821 608
Accumulated depreciation (128 375)(114 684) (97 915) (81 514) (64 906) (49 419)
Net $696 529 $710 809 $724 417 $739 910 $755 470 $772 189
GROSS ADDITIONS TO PROPERTY
(in thousands) $ 2 729 $ 3 251 $ 1 391 $ 1 214 $ 532 $ 1 700
TOTAL ASSETS at Dec. 31
(in thousands) $ 735 929 $ 727 820 $ 742 223 $ 757 084 $ 777 047 $ 796 479
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock $ 228 512 $ 235 530 $ 244 593 $ 254 664 $ 265 648 $ 277 920
Long-term debt 277 196 287 139 299 502 311 461 326 600 342 620
$ 505 708 $ 522 669 $ 544 095 $ 566 125 $ 592 248 $ 620 540
Ratios:
Common stock 45.2% 45.1% 45.0% 45.0% 44.9% 44.8%
Long-term debt 54.8 54.9 55.0 55.0 55.1 55.2
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
</TABLE>
<TABLE>
<CAPTION>
KILOWATTHOURS IN THOUSANDS:
<S> <C> <C> <C> <C> <C> <C>
Pumping energy supplied by parents 1 384 912 1 340 111 1 906 477 1 567 896 1 973 433 1 903 843
Pumped-storage generation 1 079 985 1 047 015 1 504 310 1 233 782 1 554 767 1 506 398
</TABLE>
<PAGE>
- 41 -
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Page No.
APS M-1
Monongahela M-9
Potomac M-18
West Penn M-27
AGC M-36
M-1
APS
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
CONSOLIDATED NET INCOME
Earnings per share were $1.88 in 1993 and were $1.83 and $1.80 in 1992
and 1991. Consolidated net income was $215.8 million, $203.5 million,
and $194.0 million. The increase in consolidated net income in 1993
resulted primarily from kWh sales and retail rate increases. The
increase in 1992 resulted primarily from retail rate increases. These
revenue increases, in both years, were offset in part by higher
expenses. All per share amounts have been adjusted to reflect the
November 4, 1993, two-for-one stock split (See Note F to the
consolidated financial statements).
SALES AND REVENUES
KWh sales to and revenues from residential, commercial, and industrial
customers are shown on page D-2. Such kWh sales increased 3.3% and 1.5%
in 1993 and 1992, respectively. The increases in revenues from sales to
residential, commercial, and industrial customers resulted from the
following:
Increase from Prior Year
1993 1992
(Millions of Dollars)
Increased kWh sales $ 46.6 $ 9.1
Fuel and energy cost adjustment clauses (a) 57.0 37.9
Rate increases (b):
Pennsylvania 25.2 5.8
Maryland 12.7 11.7
West Virginia 5.3 12.4
Virginia 2.5 1.8
Ohio 2.1 1.7
47.8 33.4
Other 6.2 .1
$157.6 $80.5
(a) Changes in revenues from fuel and energy cost adjustment clauses
have little effect on consolidated net income.
(b) See ITEM 1. RATE MATTERS for further information on rate
changes.
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. The
subsidiaries experienced a mild winter in the first quarter of 1992
followed by a much cooler than normal summer and early fall. As a
result, weather had a negative impact on 1992 sales to retail customers.
M -2
KWh sales to industrial customers increased .3% in 1993 and 2.9% in
1992. The relatively flat industrial sales growth in 1993 followed
record industrial sales in 1992 which occurred in almost all industrial
groups. One particular group, 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:
1993 1992 1991
KWh sales (in billions):
From subsidiaries' generation 1.2 3.2 5.8
From purchased power 11.2 14.6 12.4
12.4 17.8 18.2
Revenues (in millions):
From subsidiaries' generation $ 28.5 $ 91.7 $158.5
From sales of purchased power 318.2 373.8 366.5
$346.7 $465.5 $525.0
Decreased sales to nonaffiliated utilities resulted primarily from
decreased demand and continuing price competition. Sales supplied by
subsidiaries' generation in 1993 decreased to 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 in 1994 before leveling off. 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 decrease in other revenues in 1993 resulted from an agreement with
the Federal Energy Regulatory Commission to record in 1993 about $14
million of revenues as sales to nonaffiliated utilities. Similar
transactions were recorded as other revenues in prior years.
M -3
OPERATING EXPENSES
Fuel expenses decreased 4% in 1993 and 6% in 1992. Both decreases were
primarily due to decreases in kWh generated. The 1992 decrease also
included a 1% decrease in average coal prices. 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:
1993 1992 1991
(Millions of Dollars)
Purchased power:
For resale to other utilities $280.9 $344.0 $332.7
From PURPA generation 105.2 94.0 68.9
Other 33.8 12.7 29.0
Total power purchased 419.9 450.7 430.6
Power exchanges, net (2.5) .7 (1.4)
$417.4 $451.4 $429.2
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. The 1993 increase in other purchased power reflects
efforts to conserve coal during the UMWA dispute.
The increase in other operation expense for 1993 and 1992 resulted
primarily from increases in employee benefit costs and salaries and
wages. The Financial Accounting Standards Board's (FASB) standard, SFAS
No. 106, increased 1993 postretirement benefit expense by approximately
$5 million. The subsidiaries are currently recovering approximately 85%
of SFAS No. 106 expenses in rates and will be requesting recovery of
substantially all of the remainder in 1994 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 postretirement
medical benefit costs to be capped at two times 1993 levels. Because
1993 medical costs were more than actuarially projected, SFAS No. 106
costs for 1994 are expected to be approximately 20% greater than 1993
amounts.
M-4
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 subsidiaries currently accrue for workers'
compensation claims and the estimated liability for the other benefits
is not expected to be 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. Maintenance expense in 1993 includes the effects of an ice
storm and blizzard in March 1993. 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 Clean Air Act Amendments of 1990
(CAAA).
Depreciation expense increases resulted primarily from additions to
electric plant. Because of the increased levels of capital expenditures
as a result of the CAAA (see Note I to the consolidated financial
statements) and the replacement of aging equipment at the subsidiaries'
power stations, depreciation expense is expected to increase
significantly over the next few years.
Taxes other than income increased $4 million in 1993 primarily due to
increases in gross receipts taxes resulting from higher revenues from
retail customers ($5 million) and increased property taxes ($2 million).
These increases were offset by decreased West Virginia Business and
Occupation taxes (B&O taxes) due to decreased generation in that state.
The 1992 increase resulted from increased property taxes ($4 million),
increases in gross receipts taxes ($3 million), and increased capital
stock taxes ($2 million), offset by decreased B&O taxes ($2 million).
The net increase of $13 million in federal and state income taxes in
1993 resulted primarily from an increase in income before taxes ($9
million), and an increase in the tax rate due to the Revenue
Reconciliation Act of 1993 ($3 million). The net decrease in 1992 of $4
million resulted primarily from plant removal and certain bond
refinancing cost tax deductions for which deferred taxes were not
provided. Note B to the consolidated financial statements provides a
further analysis of income tax expenses.
M-5
The combined increase of $4 million in allowances for funds used during
construction (AFUDC) in 1993 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 increase slightly with increasing levels of
CAAA expenditures until late 1994 upon substantial completion of Phase I
of the CAAA compliance program. Fluctuations in other income, net, were
individually insignificant. Other interest expense reflects changes in
the levels of short-term debt maintained by the companies.
The decrease in dividends on preferred stock of subsidiaries reflects
the 1992 redemption of three series totaling $25 million with dividend
rates of 9.4% to 9.64% and the 1993 redemption of an additional $2
million of 4.7% to $7.16 series, offset by the 1992 sale of $40 million
of market auction preferred stock with an average dividend rate of 2.6%.
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, instalment
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 1993 were $574 million and for 1994 and
1995 are estimated at $500 million and $400 million, respectively.
These estimates include $161 million and $53 million, respectively, for
substantial completion of the program of complying with Phase I of the
CAAA discussed under ITEM 1. ENVIRONMENTAL MATTERS. It is anticipated
that the Harrison Scrubber Project will be completed on schedule (late
1994) and that the final cost will be approximately 24% below the
original budget. Primary factors contributing to the reduced cost
include: 1) the absence of any major construction problems to date; 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. Construction
expenditures through the year 2000 may include substantial amounts for
M-6
compliance with both Phase I and Phase II of the CAAA. The subsidiaries
are estimating amounts of approximately $1.4 billion, which includes
$482 million expended through 1993, depending upon the strategy
eventually selected for complying with Phase II. The mere possibility
of new legislation which restricts or discourages carbon dioxide
emissions, either through taxation or caps, further complicates the CAAA
Phase II planning process. The remaining amount of this CAAA
construction estimate, together with normal construction activity
assures that continuing external financings will be required. In
addition, the subsidiaries have additional capital requirements of an
annual preferred stock sinking fund ($1.2 million) and debt maturities
(see Note G to the consolidated financial statements).
INTERNAL CASH FLOWS
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, increased to $270 million in 1993. Regulatory
commission orders received in Maryland, Pennsylvania, Virginia, and West
Virginia provide for current cash recovery of the carrying costs of CAAA
expenditures in rates, albeit with various amounts of lag. Based upon
the authorizations received and requested and new rate cases planned in
1994, internal generation of cash can be expected to increase.
The increase in other investments reflects the 1993 cash surrender
values for secured benefit plans and a related prepayment. Materials and
supplies, primarily fuel, constituted a significant source of cash in
1993 ($54 million). The five-year National Bituminous Coal Wage
Agreement terminated on February 1, 1993. Coal inventories (fuel) as of
December 31, 1992, were increased over 1991 amounts to provide an
increased coal supply in the event of a strike. The union chose a
strategy of selective shutdowns including mines that accounted for
approximately 60% of the subsidiaries' regular coal supply. The union
signed a new five-year contract in December 1993. System coal inventory,
which declined during the dispute, and which is somewhat lower than the
seasonal norm, is considered adequate.
FINANCINGS
In October 1993, the Company issued 2,400,000 shares of its common stock
for $64.1 million. Also during 1993, the Company issued 1,364,846 shares
of common stock under its Dividend Reinvestment and Stock Purchase Plan
(DRISP), and Employee Stock Ownership and Savings Plan (ESOP) for $36.1
million. During 1993 the subsidiaries issued $43 million of 6.25% to
6.3% tax-exempt solid waste disposal notes to Harrison County, West
Virginia, and refunded an aggregate of $634 million of debt securities
having interest rates of 7% to 9.75% through the issuance of $652
million of securities having interest rates of 4.95% to 7.75%. The costs
M-7
associated with the debt redemptions are being amortized over the life
of the new bonds. Due to the significant number of refinancings which
have occurred over the past two years, this balance is now about $44
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
increased from $11.2 million in 1992 to $130.6 million in 1993. The
subsidiaries canceled or postponed approximately $152 million of debt
and equity financings in 1993 due to favorable short-term alternatives.
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 decrease in the 1993 temporary cash investment
amounts. Allegheny Generating Company in 1992 replaced its $65.7 million
of commercial paper with $50.9 million of money pool borrowings and $2.4
million of four-year, 6.05%-6.10% medium-term notes. Allegheny
Generating Company has available an established program to replace money
pool borrowings with medium-term notes or commercial paper.
At December 31, 1993, unused lines of credit with banks were $149
million. In addition, a multi-year credit program was established in
January 1994, which provides that the subsidiaries may 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. The borrowings have the support
of a long-term credit facility. During 1994, the subsidiaries plan to
issue about $230 million of new securities, consisting of both debt and
equity issues and, if economic and market conditions make it desirable,
may refinance up to $728 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 are available. The Company plans to
fund the subsidiaries' sale of common stock through the issuance of
short-term debt and DRISP/ESOP 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.
M-8
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 I to the consolidated
financial statements.
All of the state jurisdictions in which the subsidiaries operate have
enacted hazardous and solid waste management legislation. While the
subsidiaries do not have significant hazardous waste concerns, solid
wastes, such as fly ash and other coal by-products generated from power
stations, must be disposed in accordance with the state requirements.
The subsidiaries are incurring various costs, which are recoverable in
rates, to comply with these and other environmental matters. The level
of future expenditures for environmental matters is impossible to
determine with any degree of certainty. It is management's opinion that
the ultimate costs will not have a material effect on the financial
position of the subsidiaries.
As of January 1994, Monongahela has been named as a defendant along with
multiple other defendants in 1,429 pending asbestos cases involving
multiple plaintiffs and Monongahela, Potomac Edison, and West Penn have
been named as defendants along with multiple defendants in an additional
626 cases by multiple plaintiffs. Because these cases are filed by
"shotgun" complaints naming many plaintiffs and many defendants, it is
presently 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 600 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 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 $1 million
for the loss of consortium claim. Therefore, because of the multiple
defendants, the subsidiaries believe potential liability of the
subsidiaries 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 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.
M-9
Monongahela
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Net Income
Net income was $61.7 million, $58.3 million, and $54.1
million in 1993, 1992, and 1991, respectively. The increase
in net income in 1993 resulted primarily from kWh sales
and retail rate increases. The increase in 1992 resulted
primarily from retail rate increases. These revenue
increases, in both years, were offset in part by
higher expenses.
Sales and Revenues
KWh sales to and revenues from residential, commercial,
and industrial customers are shown on pages D-3 and D-4
Such kWh sales increased .3% in 1993 and decreased 1.0%
in 1992. The increases in revenues from sales to residential,
commercial, and industrial customers resulted from the
following:
Increase (Decrease)
from Prior Year
1993 1992
(Millions of Dollars)
Increased (decreased) kWh sales $ 6.6 $(5.3)
Fuel and energy cost
adjustment clauses (a) 11.8 12.3
Rate increases (b):
West Virginia 4.1 12.1
Ohio 2.1 1.6
6.2 13.7
Other .2 (1.3)
$24.8 $19.4
(a) Changes in revenues from fuel and energy cost adjustment
clauses have little effect on net income.
(b) Reflects a surcharge in West Virginia for recovery of carrying
charges on expenditures to comply with the Clean Air Act
Amendments of 1990 (CAAA), designed to produce $3.1 million on
an annual basis effective on July 1, 1992, which was increased to
$8.7 million on an annual basis effective on July 1, 1993, and a rate
increase in Ohio, designed to produce $3.3 million on an annual
basis, which became effective on July 21, 1992.
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 increases. The
Company experienced a mild winter in the first quarter of
1992 followed by a much cooler than normal summer and
early fall. As a result, weather had a negative impact on
1992 sales to retail customers.
M-10
KWh sales to industrial customers decreased 4.4% in
1993 and .7% in 1992. The 1993 decrease was primarily
due to continuing declines in sales to coal and primary
metals 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. Lower sales to primary metals
customers was due in part to one iron and steel customer's
increased use of its own generation.
KWh sales to and revenues from nonaffiliated utilities
are comprised of the following items:
1993 1992 1991
KWh sales (in billions):
From Company generation .3 1.0 1.8
From purchased power 2.8 3.6 3.1
3.1 4.6 4.9
Revenues (in millions):
From Company generation $ 8.4 $ 26.7 $ 48.5
From sales of purchased power 77.6 92.9 91.5
$86.0 $119.6 $140.0
Decreased sales to nonaffiliated utilities resulted
primarily from decreased demand and continuing price
competition. Sales supplied by the Company's generation
in 1993 decreased to 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 in 1994
before leveling off.
The increase in other revenues in 1993 and 1992
resulted from continued increases in sales of capacity,
energy, and spinning reserve to other affiliated companies
because of additional capacity and energy available from
new PURPA projects in both years. This increase was
offset in part in 1993 by an agreement with the Federal
Energy Regulatory Commission 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.
M-11
Operating Expenses
Fuel expenses decreased 3% in 1993 and 9% in 1992.
Both decreases were 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 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 the Public Utility
Regulatory Policies Act of 1978 (PURPA), capacity
charges paid to AGC, and other transactions with
affiliates made pursuant to a power supply agreement
whereby each company uses the most economical
generation available in the System at any given time, and
is comprised of the following items:
1993 1992 1991
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other utilities $ 68.6 $ 85.5 $ 83.0
From PURPA generation 55.7 37.4 13.2
Other 8.1 3.1 7.2
Power exchanges, net (.6) .3 (.5)
Affiliated transactions:
AGC capacity charges 23.3 24.2 25.1
Energy and spinning
reserve charges .5 2.8 5.3
$155.6 $153.3 $133.3
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 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. The
1993 increase in other purchased power reflects efforts to
conserve coal during the UMWA dispute. Energy and
spinning reserve charges decreased in 1993 and 1992
primarily because of additional generation available from
new PURPA projects.
M-12
The increase in other operation expense for 1993 and
1992 resulted primarily from increases in salaries and
wages and employee benefit costs. The Financial
Accounting Standards Board's (FASB) standard, SFAS
No. 106, will increase future employee benefit costs for
postretirement benefit expenses. The Company is
currently recovering approximately 50% of SFAS No.
106 expenses in rates and will be requesting recovery of
the remainder in 1994 and early 1995 rate cases. This
reflects for West Virginia and Ohio only the recovery of
the previously authorized pay-as-you-go component.
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.
Because 1993 medical costs were more than actuarially
projected, SFAS No. 106 costs for 1994 are expected to be
approximately 25% greater than 1993 amounts.
Another FASB standard, SFAS No. 112, "Employers'
Accounting for Postemployment Benefits", effective in
1994, requires companies to accrue for other post-
employment 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 expected to
be 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.
M-13
Depreciation expense increases resulted primarily from
additions to electric plant. Because of the increased levels
of capital expenditures as a result of the CAAA (see Note
J to the financial statements) and the replacement of
aging equipment at the Company's power stations,
depreciation expense is expected to increase significantly
over the next few years.
Taxes other than income increased $1 million in 1993
primarily 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
(B&O taxes) ($1 million) due to decreased generation in
that state. The 1992 decrease resulted from decreased
B&O taxes ($2 million) and prior period B&O tax
adjustments ($2 million), offset somewhat by increases in
gross receipts and property taxes ($2 million).
The net increase of $6 million in federal and state
income taxes in 1993 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). The net decrease in 1992 of $3 million
resulted primarily from plant removal and certain bond
refinancing cost tax deductions for which deferred taxes
were not provided. Note B to the financial statements
provides a further analysis of income tax expenses.
The combined increase of $2 million in allowances for
funds used during construction (AFUDC) in 1993 reflects
increased construction expenditures primarily 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 as the Company completes its
Phase I compliance program. The decrease in other
income, net, in 1993 resulted primarily from the
Company's share of decreases in the 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 level of short-term
debt maintained by the Company.
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
M-14
internally generated funds and external financings, such
as the sale of common and preferred stock, debt instruments,
instalment 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 1993 were $141 million
and for 1994 and 1995 are estimated at $103 million and
$83 million, respectively. These estimates include $39
million and $10 million, respectively, for substantial
completion of the program of complying with Phase I of
the CAAA. It is anticipated that the Harrison Scrubber
Project will be completed on schedule (late 1994) and that
the final cost will be approximately 24% below the
original budget. Primary factors contributing to the
reduced cost include: 1) the absence of any major
construction problems to date; 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.
Construction expenditures through the year 2000 may
include substantial amounts for compliance with both
Phase I and Phase II of the CAAA. The Company is
estimating amounts of approximately $400 million, which
includes $122 million expended through 1993, depending
upon the strategy eventually selected for complying with
Phase II. The mere possibility of new legislation which
restricts or discourages carbon dioxide emissions, either
through taxation or caps, further complicates the CAAA
Phase II planning process. The remaining amount of this
CAAA construction estimate, together with normal
construction activity assures that continuing external
financings will be required. In addition, the Company has
additional capital requirements of debt maturities (see
Note H to the financial statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows
from operations reduced by dividends, was about $69
million for 1993. A regulatory commission order has been
received in West Virginia authorizing procedures to
provide for current cash recovery of the carrying costs of
CAAA expenditures in rates, albeit with a certain amount
of lag. Based upon the authorization received and new
rate cases planned in 1994 and early 1995, internal
generation of cash can be expected to increase.
M-15
Materials and supplies, primarily fuel, constituted a
significant source of cash in 1993 ($13 million). The five-
year National Bituminous Coal Wage Agreement
terminated on February 1, 1993. Coal inventories (fuel) as
of December 31, 1992, were increased over 1991 amounts
to provide an increased coal supply in the event of a strike.
The union chose a strategy of selective shutdowns
including mines that accounted for approximately 60% of
the System's regular coal supply. The union signed a new
five-year contract in December 1993. System coal
inventory, which declined during the dispute, and which
is somewhat lower than the seasonal norm, is considered
adequate.
Financings
During 1993 the Company issued $10.68 million of
6.25% tax-exempt solid waste disposal notes to Harrison
County, West Virginia, and refunded an aggregate of $67
million of debt securities having interest rates of 7.5% to
9.5% through the issuance of $72 million of securities
having interest rates of 5.625% to 5.95%. The costs
associated with the debt redemptions are being amortized
over the life of the new bonds. Due to the significant
number of refinancings which have occurred over the past
two years, this balance is now about $12 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, including notes payable
to affiliates under the money pool, increased from $8.0
million in 1992 to $63.1 million in 1993. The Company
canceled or postponed approximately $69 million of debt
and equity financings in 1993 due to favorable short-term
alternatives. 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.
At December 31, 1993, the Company had SEC
authorization to issue up to $100 million of short-term
debt. In addition, a multi-year credit program was
established in January 1994, which provides that the
Company may 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. The borrowings have
the support of a long-term credit facility. During 1994, the
Company plans to issue about $50 million of new equity
securities and, if economic and market conditions make it
desirable, may refinance up to $285 million of first
M-16
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 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 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 financial statements.
All of the state jurisdictions in which the Company
operates have enacted hazardous and solid waste
management legislation. While the Company does not
have significant hazardous waste concerns, solid wastes,
such as fly ash and other coal by-products generated from
power stations, must be disposed in accordance with the
state requirements. The Company is incurring various
costs, which are recoverable in rates, to comply with these
and other environmental matters. The level of future
expenditures for environmental matters is impossible to
determine with any degree of certainty. It is management's
opinion that the ultimate costs will not have a material
effect on the financial position of the Company.
As of January 1994, the Company has been named as a
defendant along with multiple other defendants in 1,429
pending asbestos cases involving multiple plaintiffs and
the Company and its affiliates have been named as
defendants along with multiple defendants in an
additional 626 cases by multiple plaintiffs. Because these
cases are filed by "shotgun" complaints naming many
plaintiffs and many defendants, it is presently 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 600 cases actually involve claims against the
M-17
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 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 $1 million for the loss of consortium
claim. Therefore, 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. While the Company believes
that all of these cases are without merit, it cannot predict
the outcome of these cases or whether other cases will
be filed.
M-18
Potomac
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Net Income
Net income was $73.5 million, $67.5 million, and $58.2
million in 1993, 1992, and 1991, respectively. The increase
in net income in 1993 resulted primarily from kWh sales
and retail rate increases. The increase in 1992 resulted
primarily from retail rate increases. These revenue
increases, in both years, were offset in part by higher
expenses.
Sales and Revenues
KWh sales to and revenues from residential,
commercial, and industrial customers are shown on pages
D-5 and D-6. Such kWh sales increased 6.3% and 2.0% in
1993 and 1992, respectively. The increases in revenues
from sales to residential, commercial, and industrial
customers resulted from the following:
Increase from Prior Year
1993 1992
(Millions of Dollars)
Increased kWh sales $24.4 $ 7.7
Fuel and energy cost
adjustment clauses (a) 19.1 10.4
Rate increases (b):
Maryland 12.7 11.7
Virginia 2.5 1.8
West Virginia 1.1 .3
16.3 13.8
Other 2.9 .2
$62.7 $32.1
(a) Changes in revenues from fuel and energy cost adjustment
clauses have little effect on net income.
(b) Reflects a rate increase in Maryland, designed to produce $11.3
million on an annual basis, which became effective on
February 25, 1993, and a rate increase in Virginia, designed to
produce $10.0 million on an annual basis, which became
effective on September 28, 1993, subject to refund. The
Maryland surcharge for recovery of carrying charges on Clean
Air Act Amendments of 1990 (CAAA) compliance investment
of $1.7 million effective on June 4, 1992, which was increased
to $3.9 million effective on December 3, 1992, was rolled into base
rates effective with the February 1993 increase. Rate increases
also include a CAAA surcharge in West Virginia designed to
produce $.8 million on an annual basis effective July 1, 1992,
which was increased to $2.2 million on an annual basis effective
July 1, 1993.
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%
M-19
above normal, cooling degree days increased 82% over
1992 and were 12% over normal, contributing to the 1993
kWh sales increases. The Company experienced a normal
winter in the first quarter of 1992 followed by a much
cooler than normal summer and early fall. As a result,
weather had a negative impact on 1992 sales to retail
customers.
KWh sales to industrial customers increased 4.3% in
1993 and 2.0% in 1992. The increase in both years
occurred in almost all industrial groups, the most
significant of which in 1993 was from sales to cement
customers.
KWh sales to and revenues from nonaffiliated utilities
are comprised of the following items:
1993 1992 1991
KWh sales (in billions):
From Company generation .4 1.0 1.8
From purchased power 3.5 4.4 3.8
3.9 5.4 5.6
Revenues (in millions):
From Company generation $8.6 $27.5 $47.4
From sales of purchased power 99.5 113.6 114.3
$108.1 $141.1 $161.7
Decreased sales to nonaffiliated utilities resulted
primarily from decreased demand and continuing price
competition. Sales supplied by the Company's generation
in 1993 decreased to 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 67cents 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 in 1994 before leveling off. About 95% of the
aggregate benefits from sales to nonaffiliated utilities is
passed on to retail customers and has little effect on net
income.
The decrease in other revenues in 1993 resulted from
an agreement with the Federal Energy Regulatory
Commission to record in 1993 about $4 million of
revenues as sales to nonaffiliated utilities. Similar
transactions were recorded as other revenues in prior
years.
M-20
Operating Expenses
Fuel expenses decreased 4% in 1993 and 6% in 1992.
Both decreases were primarily due to decreases in kWh
generated. The 1992 decrease also included a 1%
decrease in average coal prices. 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 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:
1993 1992 1991
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other utilities $87.9 $104.6 $103.7
Other 10.5 3.7 8.9
Power exchanges, net (.8) .2 (.4)
Affiliated transactions:
AGC capacity charges 28.0 29.6 31.3
Other affiliated capacity charges 28.4 21.9 23.4
Energy and spinning
reserve charges 51.1 41.2 37.6
$205.1 $201.2 $204.5
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 and affiliated energy and spinning reserve
charges are mostly recovered from customers currently
through the regular fuel and energy cost recovery
procedures followed by the Company's regulatory
commissions and is primarily subject to deferred power
cost procedures with the result that changes in such costs
have little effect on net income. 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.
M-21
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 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 new PURPA projects in 1992 and 1993.
The increase in other operation expense for 1993 and
1992 resulted primarily from increases in employee
benefit costs and salaries and wages. The Financial
Accounting Standards Board's (FASB) standard, SFAS
No. 106, increased 1993 postretirement benefit expense
by approximately $1.5 million. The Company is currently
recovering approximately 90% of SFAS No. 106 expenses
in rates and will be requesting recovery of the remainder
in 1994 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. Because 1993 medical costs were
more than actuarially projected, SFAS No. 106 costs for
1994 are expected to be approximately 25% greater than
1993 amounts.
Another FASB standard, SFAS No. 112, "Employers'
Accounting for Postemployment Benefits", effective in
1994, requires companies to accrue for other post-
employment 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 expected to
be 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.
M-22
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. Because of the increased levels
of capital expenditures as a result of the CAAA (see Note
J to the financial statements) and the replacement of
aging equipment at the Company's power stations,
depreciation expense is expected to increase significantly
over the next few years.
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 1992
increase was due to increased property ($1 million) and
gross receipts ($1 million) taxes.
The net increase of $2 million in federal and state
income taxes in 1993 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). The
net increase in 1992 was primarily due to an increase in
income before taxes. Note B to the financial statements
provides a further analysis of income tax expenses.
The combined increase of $2 million in allowances for
funds used during construction (AFUDC) in 1993 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 increase slightly with
increasing levels of CAAA expenditures until late 1994
upon substantial completion of Phase I of the CAAA
compliance program. The decrease in other income, net in
1993 resulted primarily from the Company's share of
decreases in the 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 level of short-term debt maintained
by the Company.
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,
M-23
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, instalment 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 1993, the Company 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 the
Company's largest industrial customer. The Company
received the Maryland PSC's approval to implement a
Commercial and Industrial Lighting Rebate Program as
of July 1, 1993. Through December 31, 1993, the
Company had received applications for $7.5 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 five-year period.
Capital Requirements
Construction expenditures for 1993 were $179 million
and for 1994 and 1995 are estimated at $136 million and
$106 million, respectively. These estimates include $40
million and $10 million, respectively, for substantial
completion of the program of complying with Phase I of
the CAAA. It is anticipated that the Harrison Scrubber
Project will be completed on schedule (late 1994) and that
the final cost will be approximately 24% below the
original budget. Primary factors contributing to the
reduced cost include: 1) the absence of any major
construction problems to date; 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.
Construction expenditures through the year 2000 may
include substantial amounts for compliance with both
Phase I and Phase II of the CAAA. The Company is
estimating amounts of approximately $350 million, which
includes $153 million expended through 1993, depending
upon the strategy eventually selected for complying with
Phase II. The mere possibility of new legislation which
restricts or discourages carbon dioxide emissions, either
through taxation or caps, further complicates the CAAA
Phase II planning process. The remaining amount of this
CAAA construction estimate, together with normal
construction activity assures that continuing external
financings will be required. In addition, the Company has
M-24
additional annual capital requirements of an annual
preferred stock sinking fund ($1.2 million) and debt
maturities (see Note H to the financial statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows
from operations reduced by dividends, increased to $75
million in 1993. Regulatory commission orders received
in all of the state jurisdictions and the FERC provide for
current cash recovery of the carrying costs of CAAA
expenditures in rates, albeit with various amounts of lag.
Based upon the authorizations received and new rate
cases planned in 1994, internal generation of cash can be
expected to increase.
Materials and supplies, primarily fuel, constituted a
significant source of cash in 1993 ($14 million). The
five-year National Bituminous Coal Wage Agreement
terminated on February 1, 1993. Coal inventories (fuel) as
of December 31, 1992, were increased over 1991 amounts
to provide an increased coal supply in the event of a strike.
The union chose a strategy of selective shutdowns
including mines that accounted for approximately 60% of
the System's regular coal supply. The union signed a new
five-year contract in December 1993. System coal
inventory, which declined during the dispute, and which
is somewhat lower than the seasonal norm, is considered
adequate.
Financings
During 1993 the Company issued $13.99 million of
6.25% tax-exempt solid waste disposal notes to Harrison
County, West Virginia, and refunded an aggregate of
$121 million of debt securities having interest rates of 7%
to 9.5% through the issuance of $129 million of securities
having interest rates of 5.875% to 7.75%. The costs
associated with the debt redemptions are being amortized
over the life of the new bonds. Due to the significant
number of refinancings which have occurred over the past
two years, this balance is now about $9 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. The Company canceled or postponed
approximately $36 million of debt financings in 1993 due
to favorable short-term alternatives. 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.
M-25
At December 31, 1993, the Company had SEC
authorization to issue up to $115 million of short-term
debt. In addition, a multi-year credit program was
established in January 1994, which provides that the
Company may 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. The borrowings have
the support of a long-term credit facility. During 1994, the
Company plans to issue about $75 million of new debt
securities and, if economic and market conditions make it
desirable, may refinance up to $231 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 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 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
financial statements.
All of the state jurisdictions in which the Company
operates have enacted hazardous and solid waste
management legislation. While the Company does not
have significant hazardous waste concerns, solid wastes,
such as fly ash and other coal by-products generated from
power stations, must be disposed in accordance with the
state requirements. The Company is incurring various
costs, which are recoverable in rates, to comply with these
and other environmental matters. The level of future
expenditures for environmental matters is impossible to
determine with any degree of certainty. It is management's
opinion that the ultimate costs will not have a material
effect on the financial position of the Company.
M-26
As of January 1994, Monongahela Power Company
(MP), an affiliated company, has been named as a
defendant along with multiple other defendants in 1,429
pending asbestos cases involving multiple plaintiffs and
the Company and its affiliates have been named as
defendants along with multiple defendants in an
additional 626 cases by multiple plaintiffs. Because these
cases are filed by "shotgun" complaints naming many
plaintiffs and many defendants, it is presently 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 600 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 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 $1 million for the loss of consortium claim.
Therefore, 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. While the Company believes that all of these
cases are without merit, it cannot predict the outcome of
these cases or whether other cases will be filed.
M-27
West Penn
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Consolidated Net Income
Consolidated net income was $102.1 million, $98.2
million, and $101.2 million in 1993, 1992, and 1991,
respectively. The increase in consolidated net income in
1993 resulted primarily from kWh sales and retail rate
increases, offset in part by higher expenses. Higher retail
revenues in 1992 from a surcharge to recover increases in
various state taxes and greater kWh sales were more than
offset by higher expenses.
Sales and Revenues
KWh sales to and revenues from residential, commercial,
and industrial customers are shown on pages D-7 and D-8.
Such kWh sales increased 3.1% and 2.7% in 1993 and
1992, respectively. The increases in revenues from sales to
residential, commercial, and industrial customers resulted
from the following:
Increase
from Prior Year
1993 1992
(Millions of Dollars)
Increased kWh sales $15.5 $ 6.7
Fuel and energy cost
adjustment clauses (a) 26.2 15.2
Rate increases (b) 25.2 5.8
Other 3.1 1.3
$70.0 $29.0
(a) Changes in revenues from fuel and energy cost adjustment clauses
have little effect on consolidated net income.
(b) Reflects a base rate increase on an annual basis of about $61.6
million in Pennsylvania effective May 18, 1993, including $26.1
million for recovery of carrying charges on Clean Air Act
Amendments of 1990 (CAAA) compliance costs, and in 1992 also
reflects a surcharge effective August 24, 1991, to recover
Pennsylvania tax increases.
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
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. The Company experienced a mild
winter in the first quarter of 1992 followed by a much
cooler than normal summer and early fall. As a result,
weather had a negative impact on 1992 sales to retail
customers.
M-28
KWh sales to industrial customers increased .8% in
1993 and 6.3% in 1992. The relatively flat industrial sales
growth in 1993 followed increases in industrial sales in
1992 which occurred in almost all industrial groups. One
particular group, 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:
1993 1992 1991
KWh sales (in billions):
From Company generation .4 1.3 2.3
From purchased power 5.0 6.5 5.4
5.4 7.8 7.7
Revenues (in millions):
From Company generation $11.5 $37.5 $62.5
From sales of
purchased power 141.0 167.2 160.7
$152.5 $204.7 $223.2
Decreased sales to nonaffiliated utilities resulted
primarily from decreased demand and continuing price
competition. Sales supplied by the Company's generation
in 1993 decreased to 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 in 1994 before leveling off.
The decrease in other revenues in 1993 and 1992
resulted from continued decreases in sales of energy and
spinning reserve to an affiliated company because of
additional energy available to it from new PURPA
projects commencing in both years. The 1993 decrease
was also due in part to an agreement with the Federal
Energy Regulatory Commission 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.
M-29
Operating Expenses
Fuel expenses decreased 4% in each of the years of 1993
and 1992 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 the Public Utility
Regulatory Policies Act of 1978 (PURPA), capacity
charges paid to AGC, and other transactions with
affiliates made pursuant to a power supply agreement
whereby each company uses the most economical
generation available in the System at any given time, and
is comprised of the following items:
1993 1992 1991
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power:
For resale to other
utilities $124.5 $153.9 $146.0
From PURPA
generation 49.6 56.5 55.6
Other 15.2 5.9 12.9
Power exchanges, net (1.2) .3 (.5)
Affiliated transactions:
AGC capacity charges 42.3 43.5 44.1
Energy and spinning
reserve charges 4.7 3.5 3.8
Other affiliated
capacity charges .7 .6 .6
$235.8 $264.2 $262.5
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
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
M-30
income. The decrease in purchases from PURPA
generation in 1993 was due to a planned generating
outage at one PURPA project. The 1993 increase in other
purchased power reflects efforts to conserve coal during
the UMWA dispute.
The increase in other operation expense for 1993 and
1992 resulted primarily from increases in salaries and
wages and in 1993 also from employee benefit costs. The
Financial Accounting Standards Board's (FASB)
standard, SFAS No. 106, increased 1993 postretirement
benefit expense by approximately $3.1 million. The
Company is currently recovering all of SFAS No. 106
expenses in rates. 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. Because 1993 medical costs were
more than actuarially projected, SFAS No. 106 costs for
1994 are expected to be approximately 5% greater than
1993 amounts.
Another FASB standard, SFAS No. 112, "Employers'
Accounting for Postemployment Benefits", effective in
1994, requires companies to accrue for other post-
employment 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 expected to
be 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. Maintenance
expense in 1993 includes the effects of an ice storm and
blizzard in March 1993. 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.
M-31
Depreciation expense increases resulted primarily from
additions to electric plant and in 1993 also from a change
in depreciation rates and net salvage amortization as a
result of the May 1993 rate order. Because of the
increased levels of capital expenditures as a result of the
CAAA (see Note J to the consolidated financial
statements) and the replacement of aging equipment at
the Company's power stations, depreciation expense is
expected to increase significantly over the next few years.
Taxes other than income increased $2 million in 1993
primarily due to increases in gross receipts taxes resulting
from higher revenues from retail customers ($3 million)
offset in part by decreased West Virginia Business and
Occupation taxes (B&O taxes) ($2 million) due to
decreased generation in that state. The 1992 increase
resulted from increased property and capital stock taxes
($4 million), increased B&O taxes ($1 million), and
increases in gross receipts taxes ($1 million).
The net increase of $7 million in federal and state
income taxes in 1993 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). The net decrease in 1992 of $4 million
resulted primarily from a decrease in income before taxes.
Note B to the consolidated financial statements provides
a further analysis of income tax expenses.
The combined increase of $.3 million in allowances for
funds used during construction (AFUDC) in 1993 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 increase slightly with
increasing levels of CAAA expenditures until late 1994
upon substantial completion of Phase I of the CAAA
compliance program. The decrease in other income, net,
in 1993 resulted primarily from the Company's share of
decreases in the earnings of AGC (see Note D to the
consolidated financial statements). Other fluctuations in
other income, net, were individually insignificant. Other
interest expense reflects changes in the level of short-term
debt maintained by the Company.
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
M-32
as the sale of common and preferred stock, debt
instruments, instalment 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 1993 were $251 million
and for 1994 and 1995 are estimated at $258 million and
$208 million, respectively. These estimates include $82
million and $33 million, respectively, for substantial
completion of the program of complying with Phase I of
the CAAA. It is anticipated that the Harrison Scrubber
Project will be completed on schedule (late 1994) and that
the final cost will be approximately 24% below the
original budget. Primary factors contributing to the
reduced cost include: 1) the absence of any major
construction problems to date; 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.
Construction expenditures through the year 2000 may
include substantial amounts for compliance with both
Phase I and Phase II of the CAAA. The Company is
estimating amounts of approximately $700 million, which
includes $207 million expended through 1993, depending
upon the strategy eventually selected for complying with
Phase II. The mere possibility of new legislation which
restricts or discourages carbon dioxide emissions, either
through taxation or caps, further complicates the CAAA
Phase II planning process. The remaining amount of this
CAAA construction estimate, together with normal
construction activity assures that continuing external
financings will be required. In addition, the Company has
additional capital requirements of debt maturities (see
Note H to the consolidated financial statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows
from operations reduced by dividends, increased to $119
million in 1993. A regulatory commission order has been
received from the PUC which provides for current cash
recovery of the carrying costs of CAAA expenditures
in rates, albeit with a certain amount of lag. Based
upon the authorization received and a new rate case
planned in 1994, internal generation of cash can be
expected to increase.
M-33
Materials and supplies, primarily fuel, constituted a
significant source of cash in 1993 ($27 million). The
five-year National Bituminous Coal Wage Agreement
terminated on February 1, 1993. Coal inventories (fuel) as
of December 31, 1992, were increased over 1991 amounts
to provide an increased coal supply in the event of a strike.
The union chose a strategy of selective shutdowns
including mines that accounted for approximately 60% of
the System's regular coal supply. The union signed a new
five-year contract in December 1993. System coal
inventory, which declined during the dispute, and which
is somewhat lower than the seasonal norm, is considered
adequate.
Financings
During 1993 the Company issued $18.04 million of
6.30% tax-exempt solid waste disposal notes to Harrison
County, West Virginia, and refunded an aggregate of
$246 million of debt securities having interest rates of 7%
to 9.75% through the issuance of $251 million of securities
having interest rates of 4.95% to 6.375%. The costs
associated with the debt redemptions are being amortized
over the life of the new bonds. Due to the significant
number of refinancings which have occurred over the past
two years, this balance is now about $12 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. The Company canceled or postponed
approximately $47 million of debt financings in 1993 due
to favorable short-term alternatives. 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.
At December 31, 1993, the Company had SEC
authorization to issue up to $170 million of short-term
debt. In addition, a multi-year credit program was
established in January 1994, which provides that the
Company may 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. The borrowings have
the support of a long-term credit facility. During 1994, the
Company plans to issue about $105 million of new
securities, consisting of both debt and equity issues and, if
economic and market conditions make it desirable, may
refinance up to $212 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 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 program, 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.
Pennsylvania has enacted hazardous and solid waste
management legislation. While the Company does not
have significant hazardous waste concerns, solid wastes,
such as fly ash and other coal by-products generated from
power stations, must be disposed in accordance with the
state requirements. The Company is incurring various
costs, which are recoverable in rates, to comply with these
and other environmental matters. The level of future
expenditures for environmental matters is impossible to
determine with any degree of certainty. It is management's
opinion that the ultimate costs will not have a material
effect on the financial position of the Company.
M-35
As of January 1994, Monongahela Power Company
(MP), an affiliated company, has been named as a
defendant along with multiple other defendants in 1,429
pending asbestos cases involving multiple plaintiffs and
the Company and its affiliates have been named as
defendants along with multiple defendants in an additional
626 cases by multiple plaintiffs. Because these cases are
filed by "shotgun" complaints naming many plaintiffs
and many defendants, it is presently 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 600 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 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 sought against all
defendants in an amount of up to $1 million for the loss of
consortium claim. Therefore, 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. While the Company believes
that all of these cases are without merit, it cannot predict
the outcome of these cases or whether other cases will
be filed.
M-36
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. Revenues for 1993 and 1992
decreased due to a reduction in interest charges and net
investment, and reduced operating expenses which are
described below. Additionally, revenues for 1993 and
1992 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 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. 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 decrease in
operating expenses in 1992 resulted primarily from
reduced federal income taxes because of a decrease in
income before taxes, partially offset by increases in taxes
other than income.
The increase in taxes other than income in 1992 was due
to increased property taxes.
The decreases in interest on long-term debt in 1993 and
1992 were the combined result of decreases in the average
amount of and interest rates on long-term debt
outstanding.
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.
M-37
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.
Through February 29, 1992, the Company's return on
equity (ROE) was adjusted annually pursuant to a
settlement agreement approved by the FERC. On March
1, 1990, the ROE decreased from 12% to 11.25%, and on
March 1, 1991, it was increased to 11.53%. 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, with any resultant rate decreases
subject to refund from March 1, 1992 through May 31,
1993. 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 have been
filed by all parties for consideration by the full
Commission. On January 28, 1994, the JCA filed a joint
complaint claiming that both the existing ROE of 11.53%
and the ALJ's recommended ROE of 10.83% are unjust
and unreasonable. This new complaint requests an ROE
of 8.53%, with rates subject to refund beginning
April 1, 1994.
In 1993, the Company issued $50 million of 5.75%
medium-term notes due 1998, $50 million of 5.625%
debentures due 2003, and $100 million of 6.875%
debentures due 2023 to refund $50 million 8% debentures
due 1997, $50 million 8.75% debentures due 2017, and
$100 million 9.125% debentures due 2016. The Company
and its affiliates in 1992 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.
<PAGE>
- 42 -
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
<TABLE>
<CAPTION>
Index
Monon- Potomac West
APS gahela Penn AGC
<S> <C> <C> <C> <C> <C>
Report of Independent Accountants F-1 F-18 F-35 F-52 F-69
Statement of Income for
the three years ended
December 31, 1993 F-2 F-19 F-36 F-53 F-70
Statement of Retained Earnings
for the three years ended
December 31, 1993 - F-20 F-37 F-54 F-71
Statement of Cash Flows for
the three years ended
December 31, 1993 F-3 F-21 F-38 F-55 F-72
Balance Sheet at December 31,
1993 and 1992 F-4 F-22 F-39 F-56 F-73
Statement of Capitalization at
December 31, 1993 and 1992 F-5 F-23 F-40 F-57 -
Statement of Common Equity for
the three years ended
December 31, 1993 F-6 - - - -
Notes to financial statements F-7 F-24 F-41 F-58 F-74
</TABLE>
Financial Statement Schedules -
<TABLE>
<CAPTION>
Schedules - for the years
ended December 31, 1993,
1992, and 1991
V Property, plant and
<S> <C> <C> <C> <C> <C>
equipment S-1 S-10 S-19 S-28 S-37
VI Accumulated depreciation S-4 S-13 S-22 S-31 S-38
VIII Valuation and qualifying
accounts S-7 S-16 S-25 S-34 -
IX Short-term borrowings S-8 S-17 S-26 S-35 S-39
X Supplementary income
statement information S-9 S-18 S-27 S-36 S-40
</TABLE>
All other schedules are omitted because they are not applicable or the
required information is shown in the Financial Statements or Notes thereto.
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,
1993 and 1992, and the results of their operations and their cash flows for
each of the three years in the period ended December 31, 1993, 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 income taxes and
postretirement benefits other than pensions in 1993.
PRICE WATERHOUSE
PRICE WATERHOUSE
New York, New York
February 3, 1994
F-2
<TABLE>
<CAPTION>
APS
CONSOLIDATED STATEMENT OF INCOME
Year ended December 31
(Dollar amounts in thousands except for per share data)
1993 1992 1991
Electric Operating Revenues:
<S> <C> <C> <C>
Residential $ 818 400 $ 734 874 $ 708 292
Commercial 430 202 391 912 375 415
Industrial 673 418 637 656 600 239
Nonaffiliated utilities 346 705 465 491 524 974
Other 62 801 76 725 73 247
TOTAL OPERATING REVENUES 2 331 526 2 306 658 2 282 167
Operating Expenses:
Operation:
Fuel 544 659 567 833 603 100
Purchased power and exchanges, net 417 449 451 408 429 171
Deferred power costs, net (Note A) (11 462) 89 (7 726)
Other 257 732 232 672 227 709
Maintenance 231 163 210 878 204 177
Depreciation 210 428 197 763 189 715
Taxes other than income taxes 178 788 174 578 167 455
Federal and state income taxes (Note B) 128 130 115 373 119 065
TOTAL OPERATING EXPENSES 1 956 887 1 950 594 1 932 666
OPERATING INCOME 374 639 356 064 349 501
Other Income and Deductions:
Allowance for other than borrowed funds
used during construction (Note A) 12 499 10 221 3 755
Other income, net (6) 1 265 1 570
TOTAL OTHER INCOME AND DEDUCTIONS 12 493 11 486 5 325
INCOME BEFORE INTEREST CHARGES AND
PREFERRED DIVIDENDS 387 132 367 550 354 826
Interest Charges and Preferred Dividends:
Interest on long-term debt 157 449 147 427 141 054
Other interest 5 812 5 672 5 374
Allowance for borrowed funds used during
construction (Note A) (8 983) (7 331) (4 177)
Dividends on preferred stock of
subsidiaries 17 098 18 235 18 549
TOTAL INTEREST CHARGES AND PREFERRED
DIVIDENDS 171 376 164 003 160 800
Consolidated Net Income $ 215 756 $ 203 547 $ 194 026
Common Stock Shares Outstanding
(average) (Note F) 114 937 032 111 226 318 107 547 816
Earnings Per Average Share (Note F) $1.88 $1.83 $1.80
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-3
APS
CONSOLIDATED STATEMENT OF CASH FLOWS
Year ended December 31
1993 1992 1991
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Consolidated net income $215 756 $203 547 $194 026
Depreciation 210 428 197 763 189 715
Deferred investment credit and income
taxes, net (2 388) 19 579 11 636
Deferred power costs, net (11 462) 89 (7 726)
Allowance for other than borrowed funds used
during construction (12 499) (10 221) (3 755)
Changes in certain current assets and
liabilities:
Accounts receivable, net (15 393) 12 452 (21 641)
Materials and supplies 53 614 (30 359) 11 725
Accounts payable (305) 34 525 11 839
Taxes accrued 3 619 (5 692) (4 185)
Interest accrued (2 164) 5 139 6 460
Other, net 18 087 (19 431) 15 722
457 293 407 391 403 816
Cash Flows from Investing:
Construction expenditures (573 970) (487 587) (337 711)
Allowance for other than borrowed funds used
during construction 12 499 10 221 3 755
(561 471) (477 366) (333 956)
Cash Flows from Financing:
Sale of common stock 99 875 119 884 29 778
Sale of preferred stock 39 450
Retirement of preferred stock (1 611) (27 250) (75)
Issuance of long-term debt 691 343 398 619 351 582
Retirement of long-term debt (632 000) (360 408) (94 554)
Deposit with trustees for redemption of
long-term debt 115 785 (115 785)
Short-term debt, net 119 431 (62 985) (49 464)
Cash dividends on common stock (187 475) (179 739) (170 446)
89 563 43 356 (48 964)
Net Change in Cash and Temporary Cash
Investments (Note A) (14 615) (26 619) 20 896
Cash and Temporary Cash Investments at
January 1 17 032 43 651 22 755
Cash and Temporary Cash Investments at
December 31 $ 2 417 $ 17 032 $ 43 651
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $153 455 $138 724 $126 418
Income taxes 124 979 103 635 114 610
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-4
APS
CONSOLIDATED BALANCE SHEET
As of December 31
1993 1992
ASSETS (Thousands of Dollars)
Property, Plant, and Equipment:
At original cost, including $638,920,000 and
<C> <C>
$412,058,000 under construction $7 176 847 $6 679 886
Accumulated depreciation (2 388 758) (2 239 956)
4 788 089 4 439 930
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) 24 357 2 120
40 684 18 447
Current Assets:
Cash and temporary cash investments (Note A) 2 417 17 032
Accounts receivable:
Electric service, net of $3,418,000 and
$3,364,000 uncollectible allowance 188 139 171 021
Other 7 736 9 461
Materials and supplies--at average cost:
Operating and construction 86 766 86 388
Fuel 71 392 125 384
Deferred power costs (Note A) 14 054 13 624
Prepaid taxes 43 139 38 930
Other 10 391 22 666
424 034 484 506
Deferred Charges:
Regulatory assets (Note B) 577 817 9 115
Unamortized loss on reacquired debt 44 435 24 001
Other 74 109 63 341
696 361 96 457
Total $5 949 168 $5 039 340
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Note C) $1 955 815 $1 827 809
Preferred stock 276 486 278 091
Long-term debt 2 008 104 1 951 583
4 240 405 4 057 483
Current Liabilities:
Short-term debt (Note H) 130 636 11 205
Long-term debt and preferred stock due within
one year (Notes F and G) 27 200 1 200
Accounts payable 187 690 187 995
Taxes accrued:
Federal and state income 14 689 8 535
Other 57 758 60 293
Interest accrued 38 626 40 790
Other 73 467 59 578
530 066 369 596
Deferred Credits and Other Liabilities:
Unamortized investment credit 166 328 174 751
Deferred income taxes 873 695 412 434
Regulatory liabilities (Note B) 107 372
Other 31 302 25 076
1 178 697 612 261
Commitments and Contingencies (Note I)
Total $5 949 168 $5 039 340
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-5
APS
CONSOLIDATED STATEMENT OF CAPITALIZATION
As of December 31
1993 1992 1993 1992
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
<C> <C> <C> <C>
117,663,582 and 113,898,736 shares (Note F) $ 147 079 $ 142 373
Other paid-in capital 931 063 836 038
Retained earnings (Note C) 877 673 849 398
TOTAL 1 955 815 1 827 809 46.1% 45.0%
Preferred Stock of Subsidiaries--cumulative, par value $100
per share, authorized 9,997,123 shares (Note F):
Not subject to mandatory redemption:
December 31, 1993
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 -$7.92 800 000 $102.85 to $103.94 80 000 80 000
$8.00 -$8.80 650 000 $103.25 to $104.20 65 000 65 000
Auction 2.55%-2.7% 400 000 $100.00 40 000 40 000
TOTAL (annual dividend requirements $15,057,469) 250 086 250 086 5.9 6.2
Subject to mandatory redemption:
December 31, 1993
Shares Regular Call Price
Series Outstanding Per Share
4.70% 405
$7.16 276 000 $105.37 27 600 28 800
TOTAL (annual dividend requirements $1,976,160) 27 600 29 205
Less current sinking fund requirement 1 200 1 200
TOTAL 26 400 28 005 0.6 0.7
Long-Term Debt of Subsidiaries (Note G):
First mortgage bonds:
Interest rates at December 31
Maturity 1993 1992
1994-1998 4 5/8-6 1/2 4 5/8-7 1/2 196 000 216 000
1999-2003 5 5/8-7 3/8 7 3/8-8 5/8 245 000 227 000
2004-2007 7 1/4-8 7 1/4-8 5/8 190 000 215 000
2019-2023 7 3/4-9 5/8 7 7/8-9 5/8 785 000 740 000
Debentures redeemed in 1993 - 8-9 1/8 200 000
Debentures due 2003-2023 5 5/8-6 7/8 - 150 000
Secured notes due 1998-2023 4.95-9.375 6.125-9.75 333 005 290 300
Unsecured notes due 1996-2012 6.10-6.40 6.10-6.40 27 495 27 495
Instalment purchase obligations
due 1998 6.875 6.875 19 100 19 100
Commercial paper 3.53 - 21 362
Medium-term notes due 1994-1998 5.75-7.93 6.05-7.93 87 975 37 975
Unamortized debt discount and
premium, net (16 943) (13 878)
TOTAL (annual interest requirements $148,432,634) 2 037 994 1 958 992
Less current maturities 26 000
Less amounts on deposit with trustee 3 890 7 409
TOTAL 2 008 104 1 951 583 47.4 48.1
Total Capitalization $4 240 405 $4 057 483 100.0% 100.0%
See accompanying notes to consolidated financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-6
APS
CONSOLIDATED STATEMENT OF COMMON EQUITY
Year ended December 31
Shares Other Retained Total
Outstanding Common Paid-In Earnings Common
(Note F) Stock Capital (Note C) Equity
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C>
Balance at January 1, 1991 106 983 912 $133 730 $695 576 $803 000 $1 632 306
Add:
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
Purchase Plan and Employee Stock
Ownership and Savings Plan 1 467 400 1 834 27 944 29 778
Consolidated net income 194 026 194 026
Deduct:
Dividends on common stock of the
Company (cash) 170 446 170 446
Expenses related to a subsidiary
company's preferred stock transaction 10 10
Balance at December 31, 1991 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
See accompanying notes to consolidated financial statements.
</TABLE>
F-7
APS
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 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:
Customers are billed on a cycle basis, and revenues, including amounts
resulting from the application of fuel and energy cost adjustment
clauses, are generally recorded when billed. In accordance with
ratemaking procedures followed by Monongahela Power Company in West
Virginia, revenues include service rendered but unbilled at year end.
Certain increases in rates being collected by subsidiaries are subject
to final commission approvals, and possible refunds, for which estimated
liabilities have been recorded.
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 1993, 1992, and 1991 averaged 9.37%,
9.19%, and 8.84%, respectively.
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 3.4% of average depreciable property in 1993
and 3.3% in each of the years 1992 and 1991. 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 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 that would be paid if taxes were
computed on the basis of financial accounting income instead of taxable
income are accounted for substantially in accordance with the accounting
procedures followed for ratemaking purposes.
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 in
which are being amortized over estimated service lives of the related
properties.
F-9
POSTRETIREMENT BENEFITS:
The subsidiaries have a noncontributory, defined benefit pension plan
covering substantially all employees, including officers. Benefits are
based on the employee's years of service and compensation. The funding
policy is to contribute annually at least the minimum amount required
under the Employee Retirement Income Security Act and not more than can
be deducted for federal income tax purposes.
The subsidiaries also provide partially contributory medical and life
insurance plans for eligible retirees and dependents. Medical benefits,
which comprise the largest component of the plans, are based upon an age
and years-of-service vesting schedule and other plan provisions. The
funding plan for these costs is to contribute to Voluntary Employee
Beneficiary Association (VEBA) trust funds an amount equal to the annual
cost as determined by Statement of Financial Accounting Standards (SFAS)
No. 106 (described below). Medical benefits are self-insured; the life
insurance plan is paid through insurance premiums.
The Financial Accounting Standards Board (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. Pursuant to SFAS No. 71, "Accounting for the
Effects of Certain Types of Regulation", regulatory deferrals of these
benefit expenses are recorded for those jurisdictions which reflect as
net expense the funding of pensions and cash payment of other benefits
in the ratemaking process.
TEMPORARY CASH INVESTMENTS:
For purposes of the Consolidated Statement of Cash Flows, temporary cash
investments with original maturities of three months or less, generally
in the form of commercial paper, certificates of deposit, and repurchase
agreements, are considered to be the equivalent of cash. The carrying
amount of temporary cash investments approximates the fair value because
of the short-term maturity of those instruments.
ACCOUNTING CHANGES:
Effective January 1, 1993, the subsidiaries adopted SFAS No. 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions".
This statement requires the costs of providing postretirement benefits,
such as medical and life insurance, to be accrued over the applicable
employees' service periods. 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 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 as further described in Note B.
F-10
<TABLE>
<CAPTION>
NOTE B--INCOME TAXES:
Details of federal and state income tax provisions are:
1993 1992 1991
(Thousands of Dollars)
Income taxes--current:
<S> <C> <C> <C>
Federal $110 815 $ 92 937 $ 92 630
State 20 732 4 144 15 493
Total 131 547 97 081 108 123
Income taxes--deferred,
net of amortization:
Accelerated depreciation 18 378 18 066 18 569
Deferred power costs 4 296 (60) 3 588
Tax interest capitalized (8 290) (4 214) (1 536)
Unbilled revenue (3 143) (2 169) 6 257
West Virginia pollution
control expenditures 96 15 082 2 701
Other (5 303) 1 613 (7 775)
Total 6 034 28 318 21 804
Investment credit disallowed (404) (2 213)
Amortization of deferred
investment credit (8 422) (8 335) (7 955)
Total income taxes 129 159 116 660 119 759
Income taxes--charged to
other income (1 029) (1 287) (694)
Income taxes--charged to
operating income $128 130 $115 373 $119 065
</TABLE>
The total provision for income taxes is different than the amount
produced by applying the federal income statutory tax rate to financial
accounting income before preferred dividends and income taxes, as set
forth below:
<TABLE>
<CAPTION>
1993 1992 1991
(Thousands of Dollars)
Financial accounting income
before preferred dividends
<S> <C> <C> <C>
and income taxes $360 984 $337 155 $331 640
Amount so produced $126 300 $114 600 $112 800
Increased (decreased) for:
Tax deductions for which
deferred tax was not provided:
Lower tax depreciation 8 800 7 600 7 900
Plant removal costs (6 000) (6 500) (4 900)
State income tax, net of
federal income tax benefit 15 000 12 600 8 900
Amortization of deferred
investment credit (8 422) (8 335) (7 955)
Other, net (7 548) (4 592) 2 320
Total $128 130 $115 373 $119 065
</TABLE>
F-11
Federal income tax returns through 1989 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,
1993, the deferred tax assets and liabilities were comprised of the
following:
(Thousands
of Dollars)
Deferred tax assets:
Unamortized investment tax credit $ 105 289
Unbilled revenue 38 363
Tax interest capitalized 22 236
Contributions in aid of construction 17 176
State tax loss carryback/carryforward 14 560
Other 21 658
219 282
Deferred tax liabilities:
Book vs. tax plant basis differences, net 1 051 500
Other 42 122
1 093 622
Total net deferred tax liabilities 874 340
Less portion above included in current liabilities 645
Total long-term net deferred tax liabilities $ 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 for an
amount equal to the $562 million increase in deferred tax liabilities.
Regulatory liabilities were recorded in an amount equal to the $108
million increase in deferred tax assets to reflect the subsidiaries'
obligation to pass such tax benefits on to their customers as the
benefits are realized in cash in future years. Based on the provisions
in the standard for recording these regulatory assets and liabilities on
the balance sheet, there was no effect on consolidated net income
resulting from adoption of the standard.
NOTE C--DIVIDEND RESTRICTION:
Supplemental indentures relating to most outstanding bonds of
subsidiaries contain dividend restrictions under the most restrictive of
which $461,539,000 of consolidated retained earnings at December 31,
1993, 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.
F-12
<TABLE>
<CAPTION>
NOTE D--PENSION BENEFITS:
Net pension costs, a portion of which (about 30%) was charged to plant
construction, included the following components:
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost--benefits earned $13 361 $12 402 $11 254
Interest cost on projected benefit
obligation 37 387 36 049 34 553
Actual return on plan assets (89 680) (65 641) (92 924)
Net amortization and deferral 43 653 21 344 50 320
SFAS No. 87 pension cost 4 721 4 154 3 203
Regulatory deferral (1 509) (3 862) (3 203)
Net pension cost $ 3 212 $ 292 $ -
</TABLE>
The benefits earned to date and funded status at December 31 using a
measurement date of September 30 were as follows:
<TABLE>
<CAPTION>
1993 1992
(Thousands of Dollars)
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of $401,986,000
<S> <C> <C>
and $363,723,000) $429 360 $387 932
Funded status:
Actuarial present value of projected
benefit obligation $546 776 $495 679
Plan assets at market value, primarily
common stocks and fixed income securities 602 194 540 407
Plan assets in excess of projected benefit
obligation (55 418) (44 728)
Add:
Unrecognized cumulative net gain from
past experience different from that
assumed 58 402 41 094
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987 22 028 25 174
Less unrecognized prior service cost due
to plan amendments 12 939 14 188
Pension cost liability $ 12 073 $ 7 352
</TABLE>
In determining the actuarial present value of the projected benefit
obligation at December 31, 1993, 1992, and 1991, the discount rates used
were 7.25%, 7.75%, and 8%, and the rates of increase in future
compensation levels were 4.75%, 5.25%, and 5.5%, respectively. The
expected long-term rate of return on assets was 9% in each of the years
1993, 1992, and 1991.
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 the employee and
covered dependents during the years the employee renders 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 and were $6,553,000 and $5,691,000 in 1992 and 1991,
respectively.
SFAS No. 106 postretirement cost in 1993, a portion of which (about 30%)
was charged to plant construction, included the following components:
(Thousands
of Dollars)
Service cost--benefits earned $ 2 000
Interest cost on accumulated postretirement
benefit obligation 11 300
Actual return on plan assets (24)
Amortization of unrecognized transition obligation 7 300
Other net amortization and deferral 24
SFAS No. 106 postretirement cost 20 600
Regulatory deferral (4 790)
Net postretirement cost $15 810
F-14
The benefits earned to date and funded status at December 31, 1993,
using a measurement date of September 30 were as follows:
(Thousands
of Dollars)
Accumulated postretirement benefit obligation:
Retirees $115 019
Fully eligible employees 24 135
Other employees 55 255
Total obligation 194 409
Plan assets at market value in short-term
investment fund 4 646
Accumulated postretirement benefit obligation
in excess of plan assets 189 763
Less:
Unrecognized cumulative net loss from past
experience different from that assumed 41 450
Unrecognized transition obligation, being
amortized over 20 years beginning January 1, 1993 138 200
Postretirement benefit liability at September 30, 1993 10 113
Fourth quarter 1993 contributions and benefit payments 4 549
Postretirement benefit liability at December 31, 1993 $ 5 564
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 the standard.
In determining the APBO at January 1 and December 31, 1993, the discount
rates used were 8% and 7.25%, the rates of increase in future
compensation levels were 5.5% and 4.75%, respectively. For measurement
purposes, a health care trend rate of 14% for 1993, declining 1% each
year thereafter to 7% in the year 2000 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, 1993, by $13.4 million and the
aggregate of the service and interest cost components of net periodic
postretirement benefit cost for 1993 by $1.0 million.
Recovery of SFAS No. 106 costs has been authorized for retail customers
in Maryland effective in February 1993, in Pennsylvania effective in May
1993, and for the FERC wholesale customers effective in mid-to-late
1993. Regulatory actions have been taken by the Virginia and Ohio
regulatory commissions which provide support that substantial recovery
is probable. Recovery has been requested in rate cases filed in
Virginia and West Virginia for which final commission decisions are
expected in 1994. The subsidiaries have recorded regulatory assets at
December 31, 1993, of $4.8 million relating to those regulatory
jurisdictions where full recovery of SFAS No. 106 level of expenses has
not yet been granted recovery in rates, with the result that adoption of
SFAS No. 106 has had no effect on consolidated net income.
F-15
NOTE F--STOCKHOLDERS' EQUITY:
COMMON STOCK:
In November 1993, the common shareholders approved a two-for-one split
of the Company's common stock which was 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:
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 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,
commencing in 1992, 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 estimated fair value of
this series of preferred stock at December 31, 1993 and 1992, was
$28,566,000 and $28,944,000, respectively, based on quoted market
prices. The call price declines in future years. In August 1993, The
Potomac Edison Company redeemed the remaining 4,046 outstanding shares
of Series B, 4.70% preferred stock.
F-16
NOTE G--LONG-TERM DEBT:
Maturities for long-term debt for the next five years are: 1994,
$26,000,000; 1995, $28,000,000; 1996, $43,575,000; 1997, $48,262,000;
and 1998, $185,400,000. 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 $75 million at any one time outstanding
through 1997. Each bank has the option to discontinue its loans after
1997 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 H.
The estimated fair value of long-term debt at December 31, 1993 and
1992, was $2,129,923,000 and $2,033,103,000, respectively, based on
actual market prices or market prices of similar issues.
NOTE H--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, 1993, unused lines
of credit with banks were $149,175,000. In addition to bank lines of
credit, in 1992 the companies 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. 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 at the end of 1993 consisted
of notes payable to banks ($75,825,000) and commercial paper
($54,811,000) and at the end of 1992 consisted of a note payable to a
bank ($11,205,000). The carrying amount of short-term debt approximates
the fair value because of the short-term maturity of those instruments.
F-17
NOTE I--COMMITMENTS AND CONTINGENCIES:
CONSTRUCTION PROGRAM:
The subsidiaries have entered into commitments for their construction
programs, for which expenditures are estimated to be $500 million for
1994 and $400 million for 1995. 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 laws, regulations, and uncertainties as to
environmental matters discussed under ITEM 1. 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 expenditures through the year 2000 will include substantial
amounts for compliance with Phase I and Phase II of the CAAA.
The subsidiaries are estimating expenditures of
approximately $1.4 billion, which includes $482 million expended through
1993, depending on the strategy eventually selected for complying with
Phase II. Construction estimates for 1994 and 1995 include $161 million
and $53 million, respectively, for the program of complying with the
CAAA.
In complying with the CAAA, the subsidiaries will face uncertainties,
including regulatory administrative interpretations and contingencies,
such as potential cost overruns, equipment performance, and cost
recovery in rates.
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.
F-18
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, 1993 and 1992, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 1993,
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 income taxes and postretirement
benefits other than pensions in 1993.
PRICE WATERHOUSE
PRICE WATERHOUSE
New York, New York
February 3, 1994
<TABLE>
<CAPTION>
F-19
Monongahela
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential $185 141 $169 589 $163 757
Commercial 110 762 102 709 97 849
Industrial 187 669 186 442 177 688
Nonaffiliated utilities 86 032 119 628 140 029
Other, including affiliates 72 240 53 595 45 803
Total Operating Revenues 641 844 631 963 625 126
Operating Expenses:
Operation:
Fuel 144 408 149 219 164 070
Purchased power and exchanges, net 155 602 153 272 133 346
Deferred power costs, net (Note A) (2 489) 5 468 3 982
Other 66 506 64 043 63 570
Maintenance 67 770 62 909 64 035
Depreciation 56 056 53 865 51 903
Taxes other than income taxes 34 076 33 207 35 378
Federal and state income taxes (Note B) 33 612 27 919 31 173
Total Operating Expenses 555 541 549 902 547 457
Operating Income 86 303 82 061 77 669
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A) 3 092 2 007
Other income, net 7 203 8 388 8 573
Total Other Income and Deductions 10 295 10 395 8 573
Income Before Interest Charges 96 598 92 456 86 242
Interest Charges:
Interest on long-term debt 35 555 34 241 30 918
Other interest 2 033 1 772 2 576
Allowance for borrowed funds used during
construction (Note A) (2 688) (1 901) (1 341)
Total Interest Charges 34 900 34 112 32 153
Net Income $61 698 $58 344 $54 089
See accompany notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-20
Monongahela
Year Ended December 31
1993 1992 1991
(Thousands of Dollars)
STATEMENT OF RETAINED EARNINGS
<S> <C> <C> <C>
Balance at January 1 $178 084 $171 307 $167 468
Add:
Net income 61 698 58 344 54 089
239 782 229 651 221 557
Deduct:
Dividends on capital stock:
Preferred stock 4 458 4 845 4 940
Common stock 49 838 46 532 45 310
Charge on redemption of preferred stock 190
Total Deductions 54 296 51 567 50 250
Balance at December 31 (Note C) $185 486 $178 084 $171 307
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-21
Monongahela
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income $61 698 $58 344 $54 089
Depreciation 56 056 53 865 51 903
Deferred investment credit and income taxes, net 6 352 6 982 1 448
Deferred power costs, net (2 489) 5 468 3 982
Unconsolidated subsidiaries' dividends
in excess of earnings 1 971 2 552 2 853
Allowance for other than borrowed funds used
during construction (3 092) (2 007)
Changes in certain current assets and liabilities:
Accounts receivable, net (8 412) (1 386) (9 831)
Materials and supplies 12 917 (7 434) 5 866
Accounts payable 129 10 599 5 740
Taxes accrued (5 674) (8 441) (3 986)
Interest accrued 290 1 178 304
Other, net 3 296 (558) 479
123 042 119 162 112 847
Cash Flows from Investing:
Construction expenditures (140 748) (126 422) (84 515)
Allowance for other than borrowed
funds used during construction 3 092 2 007
(137 656) (124 415) (84 515)
Cash Flows from Financing:
Sale of common stock 40 000
Issuance of long-term debt 82 331 156 311 49 625
Retirement of long-term debt (68 471) (89 414) (46 890)
Retirement of preferred stock (5 194)
Short-term debt, net 63 100 (53 117) 19 092
Notes payable to affiliates (8 030) 8 030
Dividends on capital stock:
Preferred stock (4 458) (4 845) (4 940)
Common stock (49 838) (46 532) (45 310)
14 634 5 239 (28 423)
Net Change in Cash and
Temporary Cash Investments (Note A) 20 (14) (91)
Cash and Temporary Cash Investments at January 1 115 129 220
Cash and Temporary Cash Investments at December 31 $135 $115 $129
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $33 941 $32 486 $31 354
Income taxes 30 982 22 946 31 218
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-22
Monongahela
BALANCE SHEET
DECEMBER 31
1993 1992
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $144,621,000 and
<S> <C> <C>
$99,177,000 under construction $1 684 322 $1 567 252
Accumulated depreciation (664 947) (628 595)
1 019 375 938 657
Investments:
Allegheny Generating Company - common stock
at equity (Note D) 61 698 63 593
Other 595 972
62 293 64 565
Current Assets:
Cash 135 115
Accounts receivable:
Electric service, net of $1,084,000 and
$1,056,000 uncollectible allowance 48 995 42 639
Affiliated and other 14 596 12 540
Materials and supplies - at average cost:
Operating and construction 22 393 22 109
Fuel 19 904 33 105
Prepaid taxes 19 788 15 665
Deferred power costs (Note A) 10 823 8 334
Other 3 772 4 562
140 406 139 069
Deferred Charges:
Regulatory assets (Note B) 162 842 2 349
Unamortized loss on reacquired debt 12 229 11 393
Other 10 308 10 377
185 379 24 119
Total $1 407 453 $1 166 410
</TABLE>
<TABLE>
<CAPTION>
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
<S> <C> <C>
earnings (Note C) $ 483 030 $ 475 628
Preferred stock
(not subject to mandatory redemption) 64 000 64 000
Long-term debt 460 129 444 506
1 007 159 984 134
Current Liabilities:
Short-term debt (Note I) 63 100
Notes payable to affiliates (Note I) 8 030
Accounts payable 31 752 32 866
Accounts payable to affiliates 8 184 6 941
Taxes accrued:
Federal and state income 802
Other 21 261 26 133
Interest accrued 10 641 10 351
Other 18 994 14 358
153 932 99 481
Deferred Credits and Other Liabilities:
Unamortized investment credit 26 883 29 048
Deferred income taxes 192 466 47 429
Regulatory liabilities (Note B) 19 179
Other 7 834 6 318
246 362 82 795
Commitments and Contingencies (Note J)
Total $1 407 453 $1 166 410
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-23
Monongahela
STATEMENT OF CAPITALIZATION
DECEMBER 31
1993 1992 1993 1992
(Thousands of Dollars) (Capitalization Ratios)
Common Stock:
Common stock - par value $50 per share, authorized
8,000,000 shares, outstanding 5,891,000 shares (issued
<S> <C> <C>
800,000 shares in 1992) $294 550 $294 550
Other paid-in capital (Note G) 2 994 2 994
Retained earnings (Note C) 185 486 178 084
Total 483 030 475 628 48.0% 48.3%
</TABLE>
Preferred Stock (not subject to mandatory redemption):
Cumulative preferred stock - par value $100 per share,
authorized 1,500,000 shares, outstanding as follows
(Note G):
<TABLE>
<CAPTION>
December 31, 1993
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
<S> <C> <C> <C> <C> <C> <C> <C>
4.40% 90 000 $106.50
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
Total (annual dividend requirements $4,458,000) 64 000 64 000 6.3 6.5
</TABLE>
<TABLE>
<CAPTION>
Long-Term Debt (Note H):
First
mortgage Date of Date Date
bonds: Issue Redeemable Due
<S> <C> <C> <C> <C> <C>
5-1/2% 1966 1994 1996 18 000 18 000
6-1/2% 1967 1994 1997 15 000 15 000
7-1/2% 1968 1998 20 000 20 000
8-1/8% 1969 1999 10 000 10 000
5-5/8% 1993 2000 2000 65 000
7-7/8% 1972 2002 30 000
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
</TABLE>
<TABLE>
<CAPTION>
Interest Rate
<S> <C> <C> <C> <C> <C>
Secured notes due 1998-2023 5.95%-7.75% 65 225 54 550
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 (3 785) (2 852)
Total (annual interest requirements $34,954,443) 461 100 446 358
Less amount on deposit with trustee 971 1 852
Total 460 129 444 506 45.7 45.2
Total Capitalization $1 007 159 $984 134 100.0% 100.0%
See accompanying notes to financial statements.
</TABLE>
F-24
Monongahela
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:
Customers are billed on a cycle basis, and revenues,
including amounts resulting from the application of fuel
and energy cost adjustment clauses, are generally recorded
when billed. In accordance with ratemaking procedures
in West Virginia, revenues include service rendered but
unbilled at year end.
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.
F-25
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
1993, 1992, and 1991 were 8.69%, 8.23%, and 6.17%,
respectively. In accordance with FERC guidelines, the 1991
rate was based solely on borrowed funds because the Company's
average outstanding short-term debt was greater than the
average construction work in progress balance.
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
3.8% of average depreciable property in each of the years
1993, 1992, and 1991. 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 that would be paid if
taxes were computed on the basis of financial accounting
income instead of taxable income are accounted for
substantially in accordance with the accounting
procedures followed for ratemaking purposes.
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 in
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.
F-26
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 Statement of Financial
Accounting Standards (SFAS) No. 106 (described below).
Medical benefits are self-insured; the life insurance plan is
paid through insurance premiums.
The Financial Accounting Standards Board (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. Pursuant to SFAS
No. 71, "Accounting for the Effects of Certain Types of
Regulation", regulatory deferrals of these benefit
expenses are recorded for those jurisdictions which reflect
as net expense the funding of pensions and cash payment
of other benefits in the ratemaking process.
TEMPORARY CASH INVESTMENTS:
For purposes of the Statement of Cash Flows,
temporary cash investments with original maturities
of three months or less, generally in the form of
commercial paper, certificates of deposit, and repurchase
agreements, are considered to be the equivalent of cash.
ACCOUNTING CHANGES:
Effective January 1, 1993, the Company adopted
SFAS No. 106, "Employers' Accounting for Post-
retirement Benefits Other Than Pensions". This statement
requires the costs of providing postretirement benefits,
such as medical and life insurance, to be accrued over the
applicable employees' service periods. 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 as further described in
Note B.
<TABLE>
<CAPTION>
F-27
Note B - Income Taxes:
Details of federal and state income tax provisions are:
1993 1992 1991
(Thousands of Dollars)
Income taxes-current:
<S> <C> <C> <C>
Federal $25 618 $20 365 $25 027
State 1 692 830 4 893
Total 27 310 21 195 29 920
Income taxes-deferred,
net of amortization:
Accelerated depreciation 5 639 4 623 4 674
Deferred power costs 1 000 (1 931) (1 408)
Tax interest capitalized (1 650) (555) (48)
Unbilled revenue (409) 3 103 2 450
West Virginia pollution
control expenditures 2 814 2 497 667
Other 1 123 1 627 (2 049)
Total 8 517 9 364 4 286
Investment credit disallowed (207) (979)
Amortization of deferred
investment credit (2 165) (2 175) (1 859)
Total income taxes 33 662 28 177 31 368
Income taxes-charged to
other income (50) (258) (195)
Income taxes-charged to
operating income $33 612 $27 919 $31 173
</TABLE>
The total provision for income taxes is different than
the amount produced by applying the federal income
statutory tax rate to financial accounting income before
income taxes, as set forth below:
<TABLE>
<CAPTION>
1993 1992 1991
(Thousands of Dollars)
Financial accounting income
<S> <C> <C> <C>
before income taxes $95 310 $86 263 $85 262
Amount so produced $33 400 $29 300 $29 000
Increased (decreased) for:
Tax deductions for which
deferred tax was not
provided:
Lower tax depreciation 5 700 4 900 5 200
Plant removal costs (3 000) (2 600) (1 700)
State income tax, net of federal
income tax benefit 3 800 3 800 3 100
Amortization of deferred
investment credit (2 165) (2 175) (1 859)
Equity in earnings of subsidiaries (2 500) (2 800) (3 000)
Other, net (1 623) (2 506) 432
Total $33 612 $27 919 $31 173
</TABLE>
Federal income tax returns through 1989 have been
examined and substantially settled.
F-28
In adopting SFAS No. 109, the Company recognized a
significant increase in both deferred tax assets and
liabilities. At December 31, 1993, the deferred tax assets
and liabilities were comprised of the following:
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit $18 043
Unbilled revenue 4 181
Tax interest capitalized 2 430
Contributions in aid of construction 2 058
Vacation pay 1 958
Advances for construction 1 601
Other 4 455
34 726
Deferred tax liabilities:
Book vs. tax plant basis differences, net 205 829
Other 23 411
229 240
Total net deferred tax liabilities 194 514
Less portion above included in current liabilities 2 048
Total long-term net deferred tax liabilities $192 466
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 for an amount equal to the $158 million
increase in deferred tax liabilities. Regulatory liabilities
were recorded in an amount equal to the $19 million
increase in deferred tax assets 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. Based on the
provisions in the standard for recording these
regulatory assets and liabilities on the balance sheet, there
was no effect on net income resulting from adoption of
the standard.
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, 1993, 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, an unaffiliated utility.
F-29
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. 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, with any resultant rate decreases
subject to refund from March 1, 1992 through May 31,
1993. 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 have been
filed by all parties for consideration by the full
Commission. On January 28, 1994, the JCA filed a joint
complaint claiming that both the existing ROE of 11.53%
and the ALJ's recommended ROE of 10.83% are unjust
and unreasonable. This new complaint requests an ROE
of 8.53%, with rates subject to refund beginning
April 1, 1994.
Following is a summary of financial information
for AGC:
<TABLE>
<CAPTION>
December 31
1993 1992
(Thousands of Dollars)
Balance sheet information:
<S> <C> <C>
Property, plant, and equipment $696 529 $710 809
Current assets 11 063 4 722
Deferred charges 28 337 12 289
Total assets $735 929 $727 820
Total capitalization $505 708 $522 669
Current liabilities 21 891 6 631
Deferred credits 208 330 198 520
Total capitalization and liabilities $735 929 $727 820
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
1993 1992 1991
(Thousands of Dollars)
Income statement information:
<S> <C> <C> <C>
Electric operating revenues $90 606 $96 147 $100 505
Operation and maintenance expense 6 609 6 094 6 774
Depreciation 16 899 16 827 16 778
Taxes other than income taxes 5 347 5 236 4 563
Federal income taxes 13 262 14 702 15 455
Interest charges 21 635 22 585 24 030
Other income, net (328) (21) (24)
Net income $27 182 $30 724 $32 929
</TABLE>
The Company's share of the equity in earnings above
was $7.3 million, $8.3 million, and $8.9 million for 1993,
1992, and 1991, respectively, and was included in other
income, net, on the Statement of Income.
F-30
Note E - Pension Benefits:
The Company's share of net pension costs under the
System's pension plan, a portion of which (about 30%)
was charged to plant construction, included the following
components:
<TABLE>
<CAPTION>
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost - benefits earned $ 3 198 $ 3 054 $ 2 762
Interest cost on projected
benefit obligation 8 577 8 470 8 134
Actual return on plan assets (22 606) (14 863) (21 919)
Net amortization and deferral 12 048 4 453 11 893
SFAS No. 87 pension cost 1 217 1 114 870
Regulatory deferral (1 179) (1 114) (870)
Net pension cost $ 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:
<TABLE>
<CAPTION>
1993 1992
(Thousands of Dollars)
Actuarial present value of
accumulated benefit obligation
earned to date (including
vested benefit of $91,750,000
<S> <C> <C>
and $83,382,000) $ 98 898 $ 89 642
Funded status:
Actuarial present value of
projected benefit obligation $128 201 $115 938
Plan assets at market value,
primarily common stocks and
fixed income securities 141 195 126 399
Plan assets in excess of
projected benefit obligation (12 994) (10 461)
Add:
Unrecognized cumulative net
gain from past experience
different from that assumed 15 187 10 992
Unamortized transition asset,
being amortized over
14 years beginning
January 1, 1987 4 711 5 489
Less unrecognized prior service
cost due to plan amendments 2 891 3 191
Pension cost liability $ 4 013 $ 2 829
</TABLE>
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 December 31, 1993, 1992, and 1991,
the discount rates used were 7.25%, 7.75%, and 8%, and
the rates of increase in future compensation levels were
4.75%, 5.25%, and 5.5%, respectively. The expected
long-term rate of return on assets was 9% in each of the
years 1993, 1992, and 1991.
F-31
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 the employee and covered dependents
during the years the employee renders 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 and were $2,390,000 and $2,029,000 in 1992 and
1991, respectively.
SFAS No. 106 postretirement cost in 1993, a portion of
which (about 30%) was charged to plant construction,
included the following components:
(Thousands of Dollars)
Service cost - benefits earned $ 478
Interest cost on accumulated postretirement
benefit obligation 2 819
Actual return on plan assets (5)
Amortization of unrecognized transition
obligation 1 772
Other net amortization and deferral 5
SFAS No. 106 postretirement cost 5 069
Regulatory deferral (1 981)
Net postretirement cost $3 088
The benefits earned to date and funded status of the
Company's share of the System plan at December 31,
1993, using a measurement date of September 30 were
as follows:
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $32 469
Fully eligible employees 4 348
Other employees 14 664
Total obligation 51 481
Plan assets at market value in short-term
investment fund 1 230
Accumulated postretirement benefit obligation
in excess of plan assets 50 251
Less:
Unrecognized cumulative net loss from past
experience different from that assumed 14 161
Unrecognized transition obligation, being
amortized over 20 years beginning
January 1, 1993 34 059
Postretirement benefit liability
at September 30, 1993 2 031
Fourth quarter 1993 contributions and
benefit payments 997
Postretirement benefit liability at
December 31, 1993 $ 1 034
F-32
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 the standard.
In determining the APBO at January 1 and December
31, 1993, the discount rates used were 8% and 7.25%, and
the rates of increase in future compensation levels were
5.5% and 4.75%, respectively. For measurement purposes,
a health care trend rate of 14% for 1993, declining 1% each
year thereafter to 7% in the year 2000 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, 1993, by $3.5 million and the
aggregate of the service and interest cost components of
net periodic postretirement benefit cost for 1993 by
$.2 million.
Recovery of SFAS No. 106 costs has been authorized
for FERC wholesale customers effective in December
1993. Recovery has been requested in a rate case filed in
West Virginia for which a final commission decision is
expected in 1994. Regulatory action has been taken by the
Ohio regulatory commission which provides support that
substantial recovery is probable. The Company has
recorded regulatory assets at December 31, 1993, of $2.0
million for West Virginia and Ohio where full recovery of
SFAS No. 106 level of expenses has not yet been granted
recovery in rates, with the result that adoption of SFAS
No. 106 has had no effect on net income.
Note G - 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 $4,000 in 1992 as a
result of a preferred stock redemption.
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.
F-33
Note H - Long-Term Debt:
Maturities for long-term debt for the next five years
are: 1994 and 1995, none; 1996, $18,500,000; 1997,
$15,500,000; and 1998, $20,100,000. Substantially all of
the properties of the Company are held subject to the lien
securing its first mortgage bonds. Some properties are
also subject to a second lien securing certain pollution
control and solid waste disposal notes. Certain first
mortgage bond series are not redeemable by certain
refunding until dates established in the respective
supplemental indentures.
In 1993, the Company sold $65 million of 5-5/8%
7-year first mortgage bonds to refund a $10 million
8-1/8% issue due in 1999, a $30 million 7-7/8% issue due
in 2002, and a $20 million 7-1/2% issue due in 1998. The
Company also issued $7.05 million of 5.95% 20-year
Pollution Control Revenue Notes to Monongalia County,
West Virginia to refund a $7.05 million 9.5% issue due
in 2013.
The estimated fair value of long-term debt at December
31, 1993 and 1992, was $485,713,000 and $461,663,000,
respectively, based on actual market prices or market
prices of similar issues.
Note I - 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, 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. 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 at the end of 1993
consisted of $63.1 million of notes payable to banks and
at the end of 1992 consisted of money pool borrowings
from affiliates of $8.03 million. The carrying amount of
short-term debt approximates the fair value because of
the short-term maturity of those instruments.
F-34
Note J - Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its
construction program, for which expenditures are
estimated to be $103 million for 1994 and $83 million for
1995. 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 laws, regulations, and
uncertainties with respect to air and water quality, land
use, and other 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 expenditures through the year 2000 will
include substantial amounts for compliance with Phase I
and Phase II of the CAAA. The Company is estimating
expenditures of approximately $400 million, which
includes $122 million expended through 1993, depending
on the strategy eventually selected for complying with
Phase II. Construction estimates for 1994 and 1995
include $39 million and $10 million, respectively, for the
program of complying with the CAAA.
In complying with the CAAA, the Company will face
uncertainties, including regulatory administrative
interpretations and contingencies, such as potential cost
overruns, equipment performance, and cost recovery in
rates.
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 $75 million
revolving credit agreement of AGC, which in 1993 was
used by AGC solely as support for its indebtedness for
commercial paper outstanding.
F-35
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, 1993 and 1992, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1993, 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 income taxes and postretirement
benefits other than pensions in 1993.
PRICE WATERHOUSE
PRICE WATERHOUSE
New York, New York
February 3, 1994
<TABLE>
<CAPTION>
F-36
Potomac
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential $274 358 $243 413 $227 851
Commercial 124 667 111 506 104 642
Industrial 175 902 157 304 147 654
Nonaffiliated utilities 108 132 141 120 161 720
Other, including affiliates 29 526 34 544 32 210
Total Operating Revenues 712 585 687 887 674 077
Operating Expenses:
Operation:
Fuel 143 587 150 218 159 909
Purchased power and exchanges, net 205 073 201 220 204 469
Deferred power costs, net (Note A) (9 953) (3 850) (6 113)
Other 74 438 67 351 65 224
Maintenance 64 376 53 141 49 766
Depreciation 56 449 53 446 50 578
Taxes other than income taxes 46 813 45 791 43 937
Federal and state income taxes (Note B) 30 086 28 422 24 194
Total Operating Expenses 610 869 595 739 591 964
Operating Income 101 716 92 148 82 113
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A) 4 329 3 204 1 881
Other income, net 8 419 9 352 9 593
Total Other Income and Deductions 12 748 12 556 11 474
Income Before Interest Charges 114 464 104 704 93 587
Interest Charges:
Interest on long-term debt 42 695 38 081 35 053
Other interest 1 107 1 311 1 778
Allowance for borrowed funds used during
construction (Note A) (2 805) (2 164) (1 485)
Total Interest Charges 40 997 37 228 35 346
Net Income $ 73 467 $ 67 476 $ 58 241
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-37
Potomac
Year Ended December 31
1993 1992 1991
(Thousands of Dollars)
STATEMENT OF RETAINED EARNINGS
<S> <C> <C> <C>
Balance at January 1 $167 412 $160 515 $158 345
Add:
Net income 73 467 67 476 58 241
240 879 227 991 216 586
Deduct:
Dividends on capital stock:
Preferred stock 4 434 6 059 6 473
Common stock 60 386 53 731 49 588
Charges on redemption of preferred stock 6 789 10
Total Deductions 64 826 60 579 56 071
Balance at December 31 (Note C) $176 053 $167 412 $160 515
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-38
Potomac
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income $73 467 $67 476 $58 241
Depreciation 56 449 53 446 50 578
Deferred investment credit and income taxes, net (3 119) 5 192 2 962
Deferred power costs, net (9 953) (3 850) (6 113)
Unconsolidated subsidiaries' dividends
in excess of earnings 2 042 2 642 2 953
Allowance for other than borrowed funds used
during construction (4 329) (3 204) (1 881)
Changes in certain current assets and liabilities:
Accounts receivable, net (7 640) (2 431) (5 934)
Materials and supplies 13 971 (7 464) 2 170
Accounts payable 2 762 17 902 2 946
Taxes accrued 240 (224) 166
Interest accrued 1 664 69 2 085
Other, net 14 006 (1 850) 4 579
139 560 127 704 112 752
Cash Flows from Investing:
Construction expenditures (179 433) (153 485) (116 589)
Allowance for other than borrowed
funds used during construction 4 329 3 204 1 881
(175 104) (150 281) (114 708)
Cash Flows from Financing:
Sale of common stock 50 000 80 000 25 000
Retirement of preferred stock (1 611) (22 056) (75)
Issuance of long-term debt 142 171 58 101 99 029
Retirement of long-term debt (123 888) (46 782)
Deposit with trustee for redemption of long-term debt 47 431 (47 431)
Short-term debt, net (15 030)
Notes receivable from affiliates 33 400 (38 000)
Dividends on capital stock:
Preferred stock (4 434) (6 059) (6 473)
Common stock (60 386) (53 731) (49 588)
35 252 18 904 5 432
Net Change in Cash and
Temporary Cash Investments (Note A) (292) (3 673) 3 476
Cash and Temporary Cash Investments at January 1 1 781 5 454 1 978
Cash and Temporary Cash Investments at December 31 $1 489 $1 781 $5 454
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $37 427 $36 371 $32 994
Income taxes 30 378 25 180 23 500
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-39
Potomac
BALANCE SHEET
DECEMBER 31
1993 1992
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $208,308,000 and
<S> <C> <C>
$141,611,000 under construction $1 857 961 $1 698 711
Accumulated depreciation (632 269) (591 378)
1 225 692 1 107 333
Investments:
Allegheny Generating Company-common stock
at equity (Note D) 63 983 65 948
Other 819 1 140
64 802 67 088
Current Assets:
Cash 1 489 1 781
Accounts receivable:
Electric service, net of $1,207,000 and
$1,178,000 uncollectible allowance 44 575 38 104
Affiliated and other 6 383 5 214
Notes receivable from affiliates (Note I) 4 600 38 000
Materials and supplies-at average cost:
Operating and construction 26 153 25 834
Fuel 18 596 32 886
Prepaid taxes 12 523 11 913
Other 4 000 3 770
118 319 157 502
Deferred Charges:
Regulatory assets (Note B) 76 962 1 621
Unamortized loss on reacquired debt 9 188 5 897
Other 24 800 15 944
110 950 23 462
Total $1 519 763 $1 355 385
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Note C) $626 467 $567 826
Preferred stock 62 778 64 383
Long-term debt 517 910 511 801
1 207 155 1 144 010
Current Liabilities:
Long-term debt and preferred stock
due within one year (Notes G and H) 17 200 1 200
Accounts payable 41 986 44 414
Accounts payable to affiliates 15 606 10 416
Taxes accrued:
Federal and state income 2 970 3 149
Other 13 552 13 133
Interest accrued 8 632 6 968
Other 22 445 17 323
122 391 96 603
Deferred Credits and Other Liabilities:
Unamortized investment credit 30 308 32 657
Deferred income taxes 133 027 75 953
Regulatory liabilities (Note B) 18 490
Other 8 392 6 162
190 217 114 772
Commitments and Contingencies (Note J)
Total $1 519 763 $1 355 385
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-40
Potomac
STATEMENT OF CAPITALIZATION
DECEMBER 31
1993 1992 1993 1992
(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 in 1993, 4,000,000 shares in 1992,
<S> <C> <C> <C> <C>
and 1,250,000 shares in 1991) $447 700 $397 700
Other paid-in capital (Note G) 2 714 2 714
Retained earnings (Note C) 176 053 167 412
Total 626 467 567 826 51.9% 49.6%
Preferred Stock:
Cumulative preferred stock - par value $100 per share,
authorized 5,400,046 shares, outstanding as follows
(Note G):
Not subject to mandatory redemption:
</TABLE>
<TABLE>
<CAPTION>
December 31, 1993
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
<S> <C> <C> <C> <C> <C> <C> <C>
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 3.0 3.2
</TABLE>
<TABLE>
<CAPTION>
Subject to mandatory redemption:
<S> <C> <C> <C> <C> <C> <C> <C>
4.70% B 1948 405
$7.16 J 276 000 $105.37 1986 27 600 28 800
Total (annual dividend requirements $1,976,160) 27 600 29 205
Less current sinking fund requirement 1 200 1 200
26 400 28 005 2.2 2.5
</TABLE>
<TABLE>
<CAPTION>
Long-Term Debt (Note H):
First
Mortgage Date of Date Date
Bonds: Issue Redeemable Due
<S> <C> <C> <C> <C> <C>
4-5/8% 1964 1994 1994 16 000 16 000
5-7/8% 1966 1994 1996 18 000 18 000
7% 1968 1998 25 000
7-5/8% 1969 1999 15 000
5-7/8% 1993 2000 2000 75 000
8-3/8% 1971 2001 20 000
7-1/2% 1972 2002 12 000
8-5/8% 1973 2003 15 000
8% 1991 2001 2006 50 000 50 000
8-5/8% 1977 2007 25 000
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
</TABLE>
<TABLE>
<CAPTION>
Interest Rate
<S> <C> <C> <C> <C>
Secured notes due 1998-2023 5.95%-7.30
Unsecured note due 1996-2002 6.30% 5 500 5 500
Unamortized debt discount and premium, net (4 456) (3 424)
Total (annual interest requirements $41,847,138) 535 184 514 226
Less current maturities 16 000
Less amount on deposit with trustee 1 274 2 425
517 910 511 801 42.9 44.7
Total Capitalization $1 207 155 $1 144 010 100.0% 100.0%
See accompanying notes to financial statements.
</TABLE>
F-41
Potomac
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:
Customers are billed on a cycle basis, and revenues,
including amounts resulting from the application of fuel
and energy cost adjustment clauses, are recorded when
billed. Revenues of $63.4 million from one industrial
customer, Eastalco Aluminum Company, were 8.9% of
total electric operating revenues in 1993. Certain increases
in rates being collected by the Company in Virginia are
subject to final commission approval, and possible
refunds, for which estimated liabilities have been
recorded.
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.
F-42
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
1993, 1992, and 1991 were 9.97%, 9.92%, and 9.93%,
respectively. AFUDC is not recorded for construction
applicable to the state of Virginia, where construction
work in progress is included in rate base.
DEPRECIATION AND MAINTENANCE:
Provisions for depreciation are determined generally
on a straight-line method based on estimated service lives
of depreciable properties and amounted to approximately
3.6% of average depreciable property in each of the years
1993, 1992, and 1991. 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 that would be paid if
taxes were computed on the basis of financial accounting
income instead of taxable income are accounted for
substantially in accordance with the accounting
procedures followed for ratemaking purposes.
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 in
which are being amortized over estimated service lives of
the related properties.
F-43
POSTRETIREMENT BENEFITS:
The Company participates with affiliated companies in
the System in a noncontributory, defined benefit pension
plan covering substantially all employees, including
officers. Benefits are based on the employee's years of
service and compensation. The funding policy is to
contribute annually at least the minimum amount
required under the Employee Retirement Income Security
Act and not more than can be deducted for federal income
tax purposes.
The Company also provides partially contributory
medical and life insurance plans for eligible retirees and
dependents. Medical benefits, which comprise the largest
component of the plans, are based upon an age and
years-of-service vesting schedule and other plan
provisions. The funding plan for these costs is to
contribute to Voluntary Employee Beneficiary
Association (VEBA) trust funds an amount equal to the
annual cost as determined by Statement of Financial
Accounting Standards (SFAS) No. 106 (described below).
Medical benefits are self-insured; the life insurance plan is
paid through insurance premiums.
The Financial Accounting Standards Board (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. Pursuant to SFAS
No. 71, "Accounting for the Effects of Certain Types of
Regulation", regulatory deferrals of these benefit
expenses are recorded for those jurisdictions which reflect
as net expense the funding of pensions and cash payment
of other benefits in the ratemaking process.
TEMPORARY CASH INVESTMENTS:
For purposes of the Statement of Cash Flows,
temporary cash investments with original maturities of
three months or less, generally in the form of commercial
paper, certificates of deposit, and repurchase agreements,
are considered to be the equivalent of cash.
ACCOUNTING CHANGES:
Effective January 1, 1993, the Company adopted
SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions". This
statement requires the costs of providing postretirement
benefits, such as medical and life insurance, to be accrued
over the applicable employees' service periods. 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 as further described in
Note B.
<TABLE>
<CAPTION>
F-44
Note B - Income Taxes:
Details of federal and state income tax provisions are:
1993 1992 1991
(Thousands of Dollars)
Income taxes-current:
<S> <C> <C> <C>
Federal $29 758 $26 366 $20 799
State 3 991 (2 635) 749
Total 33 749 23 731 21 548
Income taxes-deferred,
net of amortization:
Accelerated depreciation 4 521 4 680 3 766
Contributions in aid
of construction (1 136) (1 000) (1 031)
Deferred power costs 3 706 1 269 2 129
Tax interest capitalized (2 735) (1 647) (670)
Unbilled revenue (1 710) (1 219) 2 784
West Virginia pollution
control expenditures (463) 5 380 897
Other (2 953) 171 (1 829)
Total (770) 7 634 6 046
Investment credit
disallowed (196) (929)
Amortization of deferred
investment credit (2 349) (2 246) (2 155)
Total income taxes 30 630 28 923 24 510
Income taxes-charged to
other income (544) (501) (316)
Income taxes-charged to
operating income $30 086 $28 422 $24 194
</TABLE>
The total provision for income taxes is less than the
amount produced by applying the federal income
statutory tax rate to financial accounting income before
income taxes, as set forth below:
<TABLE>
<CAPTION>
1993 1992 1991
(Thousands of Dollars)
Financial accounting income
<S> <C> <C> <C>
before income taxes $103 553 $95 898 $82 435
Amount so produced $ 36 200 $32 600 $28 000
Increased (decreased) for:
Tax deductions for which
deferred tax was
not provided:
Lower tax depreciation 2 300 2 300 2 200
Plant removal costs (2 100) (1 500) (1 100)
State income tax, net
of federal income tax
benefit 1 600 1 200 (70)
Amortization of deferred
investment credit (2 349) (2 246) (2 155)
Equity in earnings of
subsidiaries (2 600) (2 900) (3 100)
Other, net (2 965) (1 032) 419
Total $ 30 086 $28 422 $24 194
</TABLE>
Federal income tax returns through 1989 have been
examined and substantially settled.
F-45
In adopting SFAS No. 109, the Company recognized a
significant increase in both deferred tax assets and
liabilities. At December 31, 1993, the deferred tax assets
and liabilities were comprised of the following:
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit $17 922
Unbilled revenue 12 556
Contributions in aid of construction 10 530
Tax interest capitalized 9 056
State tax loss carryback/carryforward 5 770
Advances for construction 1 303
Other 3 279
60 416
Deferred tax liabilities:
Book vs. tax plant basis differences, net 183 892
Other 10 122
194 014
Total net deferred tax liabilities 133 598
Less portion above included in current liabilities 571
Total long-term net deferred tax liabilities $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 for an amount equal to the $74 million
increase in deferred tax liabilities. Regulatory liabilities
were recorded in an amount equal to the $19 million
increase in deferred tax assets 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. Based on
the provisions in the standard for recording these
regulatory assets and liabilities on the balance sheet, there
was no effect on net income resulting from adoption of
the standard.
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, 1993, 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, an
unaffiliated 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
F-46
29, 1992, AGC's return on equity (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 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, with any resultant rate decreases
subject to refund from March 1, 1992 through May 31,
1993. 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 have been
filed by all parties for consideration by the full
Commission. On January 28, 1994, the JCA filed a joint
complaint claiming that both the existing ROE of 11.53%
and the ALJ's recommended ROE of 10.83% are unjust
and unreasonable. This new complaint requests an ROE
of 8.53%, with rates subject to refund beginning
April 1, 1994.
Following is a summary of financial information
for AGC:
<TABLE>
<CAPTION>
December 31
1993 1992
(Thousands of Dollars)
Balance sheet information:
<S> <C> <C>
Property, plant, and equipment $696 529 $710 809
Current assets 11 063 4 722
Deferred charges 28 337 12 289
Total assets $735 929 $727 820
Total capitalization $505 708 $522 669
Current liabilities 21 891 6 631
Deferred credits 208 330 198 520
Total capitalization and liabilities $735 929 $727 820
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
1993 1992 1991
(Thousands of Dollars)
Income statement information:
<S> <C> <C> <C>
Electric operating revenues $90 606 $96 147 $100 505
Operation and maintenance
expense 6 609 6 094 6 774
Depreciation 16 899 16 827 16 778
Taxes other than
income taxes 5 347 5 236 4 563
Federal income taxes 13 262 14 702 15 455
Interest charges 21 635 22 585 24 030
Other income, net (328) (21) (24)
Net income $27 182 $30 724 $32 929
</TABLE>
The Company's share of the equity in earnings above
was $7.6 million, $8.6 million, and $9.2 million for 1993,
1992, and 1991, respectively, and was included in other
income, net, on the Statement of Income.
F-47
Note E - Pension Benefits:
The Company's share of net pension costs under the
System's pension plan, a portion of which (about 35%)
was charged to plant construction, included the following
components:
<TABLE>
<CAPTION>
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost - benefits earned $3 225 $2 923 $2 720
Interest cost on projected
benefit obligation 9 612 9 142 8 770
Actual return on
plan assets (22 481) (15 951) (23 301)
Net amortization and
deferral 10 669 4 743 12 514
SFAS No. 87 pension cost 1 025 857 703
Regulatory reversal (deferral) 537 (565) (703)
Net pension cost $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:
<TABLE>
<CAPTION>
1993 1992
(Thousands of Dollars)
Actuarial present value of
accumulated benefit obligation
earned to date (including
vested benefit of $102,917,000
<S> <C> <C>
and $91,892,000) $110 278 $ 98 542
Funded status:
Actuarial present value of
projected benefit obligation $139 320 $125 197
Plan assets at market value,
primarily common stocks and
fixed income securities 153 440 136 495
Plan assets in excess of
projected benefit obligation (14 120) (11 298)
Add:
Unrecognized cumulative net gain
from past experience different
from that assumed 14 927 10 623
Unamortized transition asset, being
amortized over 14 years
beginning January 1, 1987 4 951 5 668
Less unrecognized prior service
cost due to plan amendments 3 218 3 512
Pension cost liability $2 540 $1 481
</TABLE>
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 December 31, 1993, 1992, and 1991,
the discount rates used were 7.25%, 7.75%, and 8%, and
the rates of increase in future compensation levels were
4.75%, 5.25%, and 5.5%, respectively. The expected long-
term rate of return on assets was 9% in each of the years
1993, 1992, and 1991.
F-48
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 the employee and covered dependents
during the years the employee renders 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 and were $1,790,000 and $1,564,000 in 1992 and
1991, respectively.
SFAS No. 106 postretirement cost in 1993, a portion of
which (about 35%) was charged to plant construction,
included the following components:
(Thousands of Dollars)
Service cost - benefits earned $ 383
Interest cost on accumulated postretirement
benefit obligation 3 042
Actual return on plan assets (7)
Amortization of unrecognized transition
obligation 1 986
Other net amortization and deferral 7
SFAS No. 106 postretirement cost 5 411
Regulatory deferral (846)
Net postretirement cost $4 565
The benefits earned to date and funded status of the
Company's share of the System plan at December 31,
1993, using a measurement date of September 30 were
as follows:
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $35 189
Fully eligible employees 7 741
Other employees 14 635
Total obligation 57 565
Plan assets at market value in short-term
investment fund 1 375
Accumulated postretirement benefit obligation
in excess of plan assets 56 190
Less:
Unrecognized cumulative net loss from past
experience different from that assumed 15 695
Unrecognized transition obligation, being
amortized over 20 years beginning
January 1, 1993 37 995
Postretirement benefit liability at
September 30, 1993 2 500
Fourth quarter 1993 contributions and
benefit payments 1 132
Postretirement benefit liability at
December 31, 1993 $1 368
F-49
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 the standard.
In determining the APBO at January 1 and December
31, 1993, the discount rates used were 8% and 7.25%, the
rates of increase in future compensation levels were 5.5%
and 4.75%, respectively. For measurement purposes, a
health care trend rate of 14% for 1993, declining 1% each
year thereafter to 7% in the year 2000 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, 1993, by $4.0 million and the
aggregate of the service and interest cost components
of net periodic postretirement benefit cost for 1993 by
$.3 million.
Recovery of SFAS No. 106 costs has been authorized
for retail customers in Maryland effective in February
1993 and for the FERC wholesale customers effective in
September 1993. Regulatory action has been taken by the
Virginia regulatory commission which provides support
that substantial recovery is probable. Recovery has been
requested in rate cases filed in Virginia and West Virginia
for which final commission decisions are expected in
1994. The Company has recorded regulatory assets at
December 31, 1993, of $.8 million relating to those
regulatory jurisdictions where full recovery of SFAS No.
106 level of expenses has not yet been granted recovery in
rates, with the result that adoption of SFAS No. 106 has
had no effect on net income.
Note G - 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,
4,000,000 shares in September 1992, and 1,250,000 shares
in September 1991. Other paid-in capital decreased
$2,000 in 1992 as a result of preferred stock transactions.
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.
F-50
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, commencing in 1992, 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 estimated fair value of this
series of preferred stock at December 31, 1993 and 1992,
was $28,566,000 and $28,944,000, respectively, based on
quoted market prices. The call price declines in future
years. In August 1993, the Company redeemed the
remaining 4,046 outstanding shares of Series B, 4.70%
preferred stock.
Note H - Long-Term Debt:
Maturities for long-term debt for the next five years
are: 1994, $16,000,000; 1995, none; 1996, $18,700,000;
1997, $800,000; and 1998, $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.
In 1993, the Company sold $45 million of 7-3/4%
30-year first mortgage bonds and $75 million of 5-7/8%
7-year first mortgage bonds to refund a $25 million
8-5/8% issue due in 2007, a $15 million 8-5/8% issue due
in 2003, a $20 million 8-3/8% issue due in 2001, a $15
million 7-5/8% issue due in 1999, a $12 million 7-1/2%
issue due in 2002, and a $25 million 7% issue due in 1998.
The Company also issued $8.6 million of 5.95% 20-year
Pollution Control Revenue Notes to Monongalia County,
West Virginia to refund an $8.6 million 9.5% issue due
in 2013.
The estimated fair value of long-term debt at December
31, 1993 and 1992, was $566,070,000 and $538,211,000,
respectively, based on actual market prices or market
prices of similar issues.
Note I - 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, 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
F-51
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 1993 or 1992. The Company had outstanding at the
end of 1993 and 1992, $4.6 million and $38 million,
respectively, of notes receivable from affiliates in the
money pool.
Note J - Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its
construction program, for which expenditures are
estimated to be $136 million for 1994 and $106 million for
1995. 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 laws, regulations, and
uncertainties with respect to air and water quality, land
use, and other 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 expenditures through the year 2000 will
include substantial amounts for compliance with Phase I
and Phase II of the CAAA. The Company is estimating
expenditures of approximately $350 million, which includes
$153 million expended through 1993, depending on the
strategy eventually selected for complying with Phase II.
Construction estimates for 1994 and 1995 include $40
million and $10 million, respectively, for the program of
complying with the CAAA.
In complying with the CAAA, the Company will face
uncertainties, including regulatory administrative
interpretations and contingencies, such as potential
cost overruns, equipment performance, and cost recovery
in rates.
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 $75 million
revolving credit agreement of AGC, which in 1993 was
used by AGC solely as support for its indebtedness for
commercial paper outstanding.
F-52
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
West Penn Power Company
In our opinion, the 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, 1993 and 1992, and the results of its operations and its
cash flows for each of the three years in the period ended December 31, 1993,
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 income taxes and postretirement
benefits other than pensions in 1993.
PRICE WATERHOUSE
PRICE WATERHOUSE
New York, New York
February 3, 1994
F-53
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED STATEMENT
OF INCOME
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
Electric Operating Revenues:
<S> <C> <C> <C>
Residential $ 358 900 $ 321 871 $ 316 685
Commercial 194 773 177 697 172 924
Industrial 309 847 293 910 274 896
Nonaffiliated utilities 152 541 204 743 223 225
Other, including affiliates 68 916 78 620 83 073
Total Operating Revenues 1 084 977 1 076 841 1 070 803
Operating Expenses:
Operation:
Fuel 256 664 268 395 279 121
Purchased power and exchanges, net 235 772 264 208 262 539
Deferred power costs, net (Note A) 979 (1 527) (5 595)
Other 131 854 116 913 113 357
Maintenance 96 706 93 067 87 717
Depreciation 80 872 73 469 70 334
Taxes other than income taxes 89 249 87 300 80 630
Federal and state income taxes (Note B) 51 529 44 078 47 846
Total Operating Expenses 943 625 945 903 935 949
Operating Income 141 352 130 938 134 854
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A) 5 077 5 010 1 875
Other income, net 12 728 14 534 15 077
Total Other Income and Deductions 17 805 19 544 16 952
Income Before Interest Charges 159 157 150 482 151 806
Interest Charges:
Interest on long-term debt 58 857 53 768 51 129
Other interest 1 728 1 824 848
Allowance for borrowed funds used during
construction (Note A) (3 489) (3 266) (1 349)
Total Interest Charges 57 096 52 326 50 628
Consolidated Net Income $102 061 $ 98 156 $101 178
See accompanying notes to consolidated financial statements.
</TABLE>
F-54
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED STATEMENT
OF RETAINED EARNINGS
Year Ended December 31
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Balance at January 1 $400 515 $392 331 $376 191
Add:
Consolidated net income 102 061 98 156 101 178
502 576 490 487 477 369
Deduct:
Dividends on capital stock of the Company:
Preferred stock 8 206 7 331 7 136
Common stock 82 082 82 641 77 902
Total Deductions 90 288 89 972 85 038
Balance at December 31 (Note C) $412 288 $400 515 $392 331
See accompanying notes to consolidated financial statements.
</TABLE>
F-55
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Consolidated net income $102 061 $ 98 156 $101 178
Depreciation 80 872 73 469 70 334
Deferred investment credit and
income taxes, net (10 115) 809 482
Deferred power costs, net 979 (1 527) (5 595)
Unconsolidated subsidiaries' dividends
in excess of earnings 3 311 4 287 4 799
Allowance for other than borrowed funds used
during construction (5 077) (5 010) (1 875)
Changes in certain current assets and liabilities:
Accounts receivable, net (5 947) 8 799 (8 940)
Materials and supplies 26 889 (15 593) 3 893
Accounts payable 3 196 3 877 10 220
Taxes accrued 9 198 1 875 1 208
Interest accrued (5 146) 3 534 3 861
Other, net 8 878 (8 989) 7 693
209 099 163 687 187 258
Cash Flows from Investing:
Construction expenditures (251 017) (204 409) (134 443)
Allowance for other than borrowed
funds used during construction 5 077 5 010 1 875
(245 940) (199 399) (132 568)
Cash Flows from Financing:
Sale of common stock 100 000 35 000
Sale of preferred stock 39 450
Issuance of long-term debt 268 766 181 843 167 505
Retirement of long-term debt (251 414) (158 500)
Deposit with trustee for redemption
of long-term debt 68 354 (68 354)
Short-term debt, net (74 600)
Notes receivable from affiliates (4 000) (20 900)
Dividends on capital stock:
Preferred stock (8 206) (7 331) (7 136)
Common stock (82 082) (82 641) (77 902)
23 064 20 275 (25 487)
Net Change in Cash and
Temporary Cash Investments (Note A) (13 777) (15 437) 29 203
Cash and Temporary Cash Investments
at January 1 14 342 29 779 576
Cash and Temporary Cash Investments
at December 31 $ 565 $ 14 342 $ 29 779
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $ 61 329 $ 48 135 $ 47 168
Income taxes 55 111 45 868 51 766
See accompanying notes to consolidated financial statements.
</TABLE>
F-56
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED BALANCE SHEET
DECEMBER 31
1993 1992
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $283,779,000 and
<S> <C> <C>
$170,844,000 under construction $2 803 811 $2 581 641
Accumulated depreciation (962 623) (904 906)
1 841 188 1 676 735
Investments and Other Assets:
Allegheny Generating Company - common stock
at equity (Note D) 102 830 105 988
Other 1 537 2 032
104 367 108 020
Current Assets:
Cash and temporary cash investments (Note A) 565 14 342
Accounts receivable:
Electric service, net of $1,126,000 and
$1,129,000 uncollectible allowance 94 570 90 278
Affiliated and other 22 372 20 717
Notes receivable from affiliates (Note I) 24 900 20 900
Materials and supplies - at average cost:
Operating and construction 36 030 36 417
Fuel 32 892 59 394
Prepaid and other 17 954 22 349
229 283 264 397
Deferred Charges:
Regulatory assets (Note B) 331 755 2 934
Unamortized loss on reacquired debt 11 645 6 710
Other 26 525 24 331
369 925 33 975
Total $2 544 763 $2 083 127
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Note C) $ 893 969 $ 782 341
Preferred stock (not subject to
mandatory redemption) 149 708 149 708
Long-term debt 782 369 759 005
1 826 046 1 691 054
Current Liabilities:
Accounts payable 105 493 104 096
Accounts payable to affiliates 9 451 7 652
Taxes accrued:
Federal and state income 11 533 4 291
Other 22 823 20 867
Interest accrued 13 855 19 001
Other 20 954 20 028
184 109 175 935
Deferred Credits and Other Liabilities:
Unamortized investment credit 55 524 58 116
Deferred income taxes 424 000 146 282
Regulatory liabilities (Note B) 40 834
Other 14 250 11 740
534 608 216 138
Commitments and Contingencies (Note J)
Total $2 544 763 $2 083 127
See accompanying notes to consolidated financial statements.
</TABLE>
F-57
<TABLE>
<CAPTION>
West Penn
CONSOLIDATED STATEMENT OF CAPITALIZATION
DECEMBER 31
1993 1992 1993 1992
(Thousands of Dollars) (Capitalization Ratios)
Common Stock of the Company:
Common stock-no par value, authorized 28,902,923
shares, outstanding 22,361,586 shares (issued
5,000,000 shares in 1993 and 1,750,000 shares
<S> <C> <C> <C> <C>
in 1991) $425 994 $325 994
Other paid-in capital (Note G) 55 687 55 832
Retained earnings (Note C) 412 288 400 515
Total 893 969 782 341 49.0% 46.3%
</TABLE>
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 G):
<TABLE>
<CAPTION>
December 31, 1993
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
<S> <C> <C> <C> <C> <C> <C> <C>
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 $8,215,847) 149 708 149 708 8.2 8.8
</TABLE>
<TABLE>
<CAPTION>
Long-Term Debt (Note H):
First
Mortage
Bonds
Of the Date of Date Due
Company Issue Redeemable Date
<S> <C> <C> <C> <C> <C> <C> <C>
4-7/8% U 1965 1995 1995 27 000 27 000
7% V 1967 1997 25 000
5-1/2% JJ 1993 1998 1998 102 000
7-1/8% W 1968 1998 52 000
7-7/8% X 1969 1999 25 000
8-1/8% Z 1971 2001 40 000
7-5/8% AA 1972 2002 35 000
6-3/8% KK 1993 2003 2003 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
Interest Rate
Secured notes due 1998-2023 4.95%-9.375% 187 640 169 600
Unsecured notes due 2000-2007 6.10% 14 435 14 435
Unamortized debt discount and premium, net (7 061) (5 898)
Total (annual interest requirements $55,566,368) 784 014 762 137
Less amount on deposit with trustee 1 645 3 132
782 369 759 005 42.8 44.9
Total Capitalization $1 826 046 $1 691 054 100.0% 100.0%
See accompanying notes to consolidated financial statements.
</TABLE>
F-58
West Penn
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial statements.)
Note A - Summary of Significant
Accounting Policies:
The Company is a wholly-owned subsidiary of
Allegheny Power System, Inc. and is a part of the
Allegheny Power integrated electric utility system
(the System).
The Company is subject to regulation by the Securities
and Exchange Commission (SEC), by various state
bodies having jurisdiction, and by the Federal Energy
Regulatory Commission (FERC). Significant accounting
policies of the Company are summarized below.
CONSOLIDATION:
The consolidated financial statements include the
accounts of the Company and its wholly-owned
subsidiaries (the companies).
REVENUES:
Customers are billed on a cycle basis, and revenues,
including amounts resulting from the application of fuel
and energy cost adjustment clauses, are recorded when
billed.
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 funds when so
F-59
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 1993, 1992, and 1991 were 9.40%, 9.25%, and
9.46%, respectively.
DEPRECIATION AND MAINTENANCE:
Provisions for depreciation are determined generally
on a straight-line method based on estimated service lives
of depreciable properties and amounted to approximately
3.4%, 3.3%, and 3.2% of average depreciable property in
1993, 1992, and 1991, 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 that would be paid if
taxes were computed on the basis of financial accounting
income instead of taxable income are accounted for
substantially in accordance with the accounting
procedures followed for ratemaking purposes.
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 in
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.
F-60
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 Statement of Financial
Accounting Standards (SFAS) No. 106 (described below).
Medical benefits are self-insured; the life insurance plan is
paid through insurance premiums.
The Financial Accounting Standards Board (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. Pursuant to SFAS
No. 71, "Accounting for the Effects of Certain Types of
Regulation", regulatory deferrals of these benefit
expenses are recorded for those jurisdictions which reflect
as net expense the funding of pensions and cash payment
of other benefits in the ratemaking process.
TEMPORARY CASH INVESTMENTS:
For purposes of the Consolidated Statement of Cash
Flows, temporary cash investments with original
maturities of three months or less, generally in the form of
commercial paper, certificates of deposit, and repurchase
agreements, are considered to be the equivalent of cash.
The carrying amount of temporary cash investments
approximates the fair value because of the short-term
maturity of those instruments.
ACCOUNTING CHANGES:
Effective January 1, 1993, the Company adopted
SFAS No. 106, "Employers' Accounting for Post-
retirement Benefits Other Than Pensions". This statement
requires the costs of providing postretirement benefits,
such as medical and life insurance, to be accrued over the
applicable employees' service periods. 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 as further described in
Note B.
F-61
<TABLE>
<CAPTION>
Note B - Income Taxes:
Details of federal and state income tax provisions are:
1993 1992 1991
(Thousands of Dollars)
Income taxes-current:
<S> <C> <C> <C>
Federal $47 089 $37 965 $37 929
State 14 983 5 884 9 825
Total 62 072 43 849 47 754
Income taxes-deferred,
net of amortization:
Accelerated depreciation 1 581 1 005 2 451
Deferred power costs (410) 602 2 867
Tax interest capitalized (3 905) (2 012) (818)
Unbilled revenue (1 024) (4 053) 1 023
West Virginia pollution
control expenditures (2 255) 7 205 1 137
Other (1 509) 656 (3 019)
Total (7 522) 3 403 3 641
Investment credit
disallowed (2) (562)
Amortization of deferred
investment credit (2 592) (2 592) (2 597)
Total income taxes 51 958 44 658 48 236
Income taxes-charged to
other income (429) (580) (390)
Income taxes-charged to
operating income $51 529 $44 078 $47 846
</TABLE>
The total provision for income taxes is less than
the amount produced by applying the federal income
statutory tax rate to financial accounting income before
income taxes, as set forth below:
<TABLE>
<CAPTION>
1993 1992 1991
(Thousands of Dollars)
Financial accounting income
<S> <C> <C> <C>
before income taxes $153 590 $142 234 $149 024
Amount so produced $ 53 800 $ 48 400 $ 50 700
Increased (decreased) for:
Tax deductions for which
deferred tax was not provided:
Lower (excess) tax
depreciation 100 (200) (100)
Plant removal costs (900) (2 500) (2 100)
State income tax, net
of federal income tax
benefit 9 600 7 600 5 800
Amortization of deferred
investment credit (2 592) (2 592) (2 597)
Equity in earnings of
subsidiaries (4 300) (4 700) (4 900)
Adjustments of provisions
for prior years (600) 800 1 200
Other, net (3 579) (2 730) (157)
Total $51 529 $44 078 $47 846
</TABLE>
Federal income tax returns through 1989 have been
examined and substantially settled.
F-62
In adopting SFAS No. 109, the Company recognized a
significant increase in both deferred tax assets and
liabilities. At December 31, 1993, the deferred tax assets
and liabilities were comprised of the following:
(Thousands of Dollars)
Deferred tax assets:
Unamortized investment tax credit $40 455
Unbilled revenue 21 626
Tax interest capitalized 10 750
State tax loss carryback/carryforward 8 790
Contributions in aid of construction 4 588
Other 7 416
93 625
Deferred tax liabilities:
Book vs. tax plant basis differences, net 507 214
Other 8 437
515 651
Total net deferred tax liabilities 422 026
Add portion above included in current assets 1 974
Total long-term net deferred tax liabilities $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 for an amount equal to the $326 million
increase in deferred tax liabilities. Regulatory liabilities
were recorded in an amount equal to the $41 million
increase in deferred tax assets 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. Based on
the provisions in the standard for recording these
regulatory assets and liabilities on the balance sheet, there
was no effect on consolidated net income resulting from
adoption of the standard.
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, 1993, 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, an
unaffiliated 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
F-63
29, 1992, AGC's return on equity (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, with any resultant rate
decreases subject to refund from March 1, 1992 through
May 31, 1993. 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 have been
filed by all parties for consideration by the full
Commission. On January 28, 1994, the JCA filed a joint
complaint claiming that both the existing ROE of 11.53%
and the ALJ's recommended ROE of 10.83% are unjust
and unreasonable. This new complaint requests an ROE
of 8.53%, with rates subject to refund beginning
April 1, 1994.
Following is a summary of financial information
for AGC:
<TABLE>
<CAPTION>
December 31
1993 1992
(Thousands of Dollars)
Balance sheet information:
<S> <C> <C>
Property, plant, and equipment $696 529 $710 809
Current assets 11 063 4 722
Deferred charges 28 337 12 289
Total assets $735 929 $727 820
Total capitalization $505 708 $522 669
Current liabilities 21 891 6 631
Deferred credits 208 330 198 520
Total capitalization and liabilities $735 929 $727 820
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
1993 1992 1991
(Thousands of Dollars)
Income statement information:
<S> <C> <C> <C>
Electric operating revenues $90 606 $96 147 $100 505
Operation and maintenance
expense 6 609 6 094 6 774
Depreciation 16 899 16 827 16 778
Taxes other than
income taxes 5 347 5 236 4 563
Federal income taxes 13 262 14 702 15 455
Interest charges 21 635 22 585 24 030
Other income, net (328) (21) (24)
Net income $27 182 $30 724 $32 929
</TABLE>
The Company's share of the equity in earnings above
was $12.2 million, $13.8 million, and $14.8 million for
1993, 1992, and 1991, respectively, and was included in
other income, net, on the Consolidated Statement of
Income.
F-64
Note E - Pension Benefits:
The Company's share of net pension costs under the
System's pension plan, a portion of which (about 25%)
was charged to plant construction, included the following
components:
<TABLE>
<CAPTION>
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Service cost - benefits earned $ 4 606 $ 4 272 $ 3 858
Interest cost on projected
benefit obligation 13 773 13 312 12 855
Actual return on plan assets (31 224) (24 750) (34 064)
Net amortization and deferral 14 262 8 388 18 210
SFAS No. 87 pension cost 1 417 1 222 859
Regulatory deferral (1 309) (1 222) (859)
Net pension cost $ 108 $ - $ -
</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:
<TABLE>
<CAPTION>
1993 1992
(Thousands of Dollars)
Actuarial present value of
accumulated benefit obligation
earned to date (including
vested benefit of $151,394,000
<S> <C> <C>
and $139,185,000) $160 097 $146 707
Funded status:
Actuarial present value of
projected benefit obligation $199 414 $183 091
Plan assets at market value,
primarily common stocks and
fixed income securities 219 625 199 612
Plan assets in excess of
projected benefit obligation (20 211) (16 521)
Add:
Unrecognized cumulative net gain
from past experience different
from that assumed 17 586 11 776
Unamortized transition asset,
amortized over 14 years
beginning January 1, 1987 9 678 10 926
Less unrecognized prior service
cost due to plan
amendments 5 678 6 222
Pension cost liability (prepaid) $1 375 $ (41)
</TABLE>
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 December 31, 1993, 1992,
and 1991, the discount rates used were 7.25%, 7.75%, and
8%, and the rates of increase in future compensation
levels were 4.75%, 5.25%, and 5.5%, respectively. The
expected long-term rate of return on assets was 9% in each
of the years 1993, 1992, and 1991.
F-65
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 the employee and covered dependents
during the years the employee renders 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 and were $1,907,000 and $1,721,000 in 1992 and
1991, respectively.
SFAS No. 106 postretirement cost in 1993, a portion of
which (about 25%) was charged to plant construction,
included the following components:
(Thousands of Dollars)
Service cost - benefits earned $ 939
Interest cost on accumulated postretirement
benefit obligation 4 389
Actual return on plan assets (9)
Amortization of unrecognized transition obligation 2 817
Other net amortization and deferral 9
SFAS No. 106 postretirement cost 8 145
Regulatory deferral (1 963)
Net postretirement cost $6 182
The benefits earned to date and funded status of the
Company's share of the System plan at December 31,
1993, using a measurement date of September 30 were
as follows:
(Thousands of Dollars)
Accumulated postretirement benefit obligation:
Retirees $35 748
Fully eligible employees 9 030
Other employees 18 378
Total obligation 63 156
Plan assets at market value in short-term
investment fund 1 510
Accumulated postretirement benefit obligation
in excess of plan assets 61 646
Less:
Unrecognized cumulative net loss from past
experience different from that assumed 3 362
Unrecognized transition obligation, being amortized
over 20 years beginning January 1, 1993 53 746
Postretirement benefit liability at
September 30, 1993 4 538
Fourth quarter 1993 contributions and
benefit payments 1 960
Postretirement benefit liability at
December 31, 1993 $2 578
F-66
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 the standard.
In determining the APBO at January 1 and December
31, 1993, the discount rates used were 8% and 7.25%, and
the rates of increase in future compensation levels were
5.5% and 4.75%, respectively. For measurement purposes,
a health care trend rate of 14% for 1993, declining 1% each
year thereafter to 7% in the year 2000 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, 1993, by $4.3 million and the
aggregate of the service and interest cost components of
net periodic postretirement benefit cost for 1993 by
$.4 million.
Recovery of SFAS No. 106 costs has been authorized
for retail customers in Pennsylvania effective in May 1993
and for the FERC wholesale customers effective in June
1993. The Company has recorded regulatory assets at
December 31, 1993, of $2.0 million relating to SFAS No.
106 costs in Pennsylvania incurred prior to the May rate
order, with the result that adoption of SFAS No. 106 has
had no effect on consolidated net income. The Company
will seek to recover these costs in its next base rate case.
Note G - Stockholders' Equity:
COMMON STOCK AND OTHER PAID-IN CAPITAL:
The Company issued and sold common stock to its
parent, at $20 per share, 5,000,000 shares in October 1993,
and 1,750,000 shares in December 1991. 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.
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.
F-67
Note H - Long-Term Debt:
Maturities for long-term debt for the next five years
are: 1994, none; 1995, $27,000,000; 1996 and 1997, none;
and 1998, $103,500,000. Substantially all of the properties
of the Company are held subject to the lien securing its
first mortgage bonds. Some properties are also subject to
a second lien securing certain pollution control and solid
waste disposal notes. Certain first mortgage bond series
are not redeemable by certain refunding until dates
established in the respective supplemental indentures.
In 1993, the Company sold $102 million of 5-1/2%
5-year first mortgage bonds to refund a $25 million 7%
issue due in 1997, a $25 million 7-7/8% issue due in 1999,
and a $52 million 7-1/8% issue due in 1998, and sold $80
million of 6-3/8% 10-year first mortgage bonds to refund
a $35 million 7-5/8% issue due in 2002 and a $40 million
8-1/8% issue due in 2001. The Company also issued $7.75
million of 5.95% 20-year Pollution Control Revenue
Notes to refund a $7.75 million 9-3/8% issue due in 2013,
and issued $61.5 million of 10-year 4.95% Pollution
Control Revenue Notes to refund a $30 million 9-3/4%
series and a $31.5 million 9-1/2% series due in 2003.
The estimated fair value of long-term debt at December
31, 1993 and 1992, was $823,333,000 and $783,379,000,
respectively, based on actual market prices or market
prices of similar issues.
Note I - 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, 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. 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 1993 or 1992. The Company had outstanding at the
end of 1993 and 1992, $24.9 million and $20.9 million,
respectively, of notes receivable from affiliates in the
money pool.
F-68
Note J - Commitments and Contingencies:
CONSTRUCTION PROGRAM:
The Company has entered into commitments for its
construction program, for which expenditures are
estimated to be $258 million for 1994 and $208 million for
1995. 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 laws, regulations, and
uncertainties with respect to air and water quality, land
use, and other 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 expenditures through the year 2000 will
include substantial amounts for compliance with Phase I
and Phase II of the CAAA. The Company is estimating
expenditures of approximately $700 million, which
includes $207 million expended through 1993, depending
on the strategy eventually selected for complying with
Phase II. Construction estimates for 1994 and 1995
include $82 million and $33 million, respectively, for the
program of complying with the CAAA.
In complying with the CAAA, the Company will face
uncertainties, including regulatory administrative
interpretations and contingencies, such as potential cost
overruns, equipment performance, and cost recovery
in rates.
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 $75 million
revolving credit agreement of AGC, which in 1993 was
used by AGC solely as support for its indebtedness for
commercial paper outstanding.
F-69
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, 1993 and 1992, and the results of its operations
and its cash flows for each of the three years in the period ended December
31, 1993, 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
PRICE WATERHOUSE
New York, New York
February 3, 1994
<TABLE>
<CAPTION>
F-70
AGC
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Electric Operating Revenues $90 606 $96 147 $100 505
Operating Expenses:
Operation and maintenance expense 6 609 6 094 6 774
Depreciation 16 899 16 827 16 778
Taxes other than income taxes 5 347 5 236 4 563
Federal income taxes (Note B) 13 262 14 702 15 455
Total Operating Expenses 42 117 42 859 43 570
Operating Income 48 489 53 288 56 935
Other Income and Deductions 328 21 24
Income Before Interest Charges 48 817 53 309 56 959
Interest Charges:
Interest on long-term debt 21 185 22 285 23 953
Other interest 450 300 77
Total Interest Charges 21 635 22 585 24 030
Net Income $27 182 $30 724 $32 929
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-71
AGC
Year Ended December 31
1993 1992 1991
(Thousands of Dollars)
STATEMENT OF RETAINED EARNINGS
<S> <C> <C> <C>
Balance at January 1 $25 530 $34 593 $44 664
Add:
Net income 27 182 30 724 32 929
52 712 65 317 77 593
Deduct:
Dividends on common stock 34 200 39 787 43 000
Balance at December 31 $18 512 $25 530 $34 593
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-72
AGC
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1993 1992 1991
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income $27 182 $30 724 $32 929
Depreciation 16 899 16 827 16 778
Deferred investment credit and
income taxes, net 5 321 6 437 6 591
Changes in certain current assets
and liabilities:
Accounts receivable, net (6 118) (11) (280)
Materials and supplies (163) 131 (203)
Accounts payable 6 (242) 96
Taxes accrued (153) (766) 309
Interest accrued 632 361 206
Other, net 4 851 1 853 259
48 457 55 314 56 685
Cash Flows from Investing:
Construction expenditures (2 739) (3 251) (1 391)
Cash Flows from Financing:
Issuance of long-term debt 198 075 2 364 35 423
Retirement of long-term debt (209 598) (14 842) (47 664)
Cash dividends on common stock (34 200) (39 787) (43 000)
(45 723) (52 265) (55 241)
Net Change in Cash (5) (202) 53
Cash at January 1 20 222 169
Cash at December 31 $ 15 $20 $222
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized) $21 109 $22 062 $14 816
Income taxes 8 220 9 027 8 552
See accompanying notes to financial statements.
</TABLE>
<TABLE>
<CAPTION>
F-73
AGC
BALANCE SHEET DECEMBER 31
1993 1992
(Thousands of Dollars)
ASSETS
Property, Plant, and Equipment:
At original cost, including $2,212,000 and
<S> <C> <C>
$426,000 under construction $824 904 $825 493
Accumulated depreciation (128 375) (114 684)
696 529 710 809
Current Assets:
Cash 15 20
Accounts receivable, principally from parents 8 615 2 497
Materials and supplies - at average cost 2 191 2 028
Other 242 177
11 063 4 722
Deferred Charges:
Regulatory assets (Note B) 4 489
Unamortized loss on reacquired debt 11 374
Other 12 474 12 289
28 337 12 289
Total $735 929 $727 820
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 18 512 25 530
228 512 235 530
Long-term debt (Note C) 277 196 287 139
505 708 522 669
Current Liabilities:
Long-term debt due within one year (Note C) 10 000
Accounts payable 11 5
Interest accrued 5 100 4 468
Taxes accrued 249 402
Other 6 531 1 756
21 891 6 631
Deferred Credits:
Unamortized investment credit 53 613 54 930
Deferred income taxes 125 848 143 590
Regulatory liabilities (Note B) 28 869
208 330 198 520
Total $735 929 $727 820
See accompanying notes to financial statements.
</TABLE>
F-74
AGC
NOTES TO FINANCIAL STATEMENTS
(These notes are an integral part of the financial statements.)
Note A - Summary of Significant
Accounting Policies:
The Company was incorporated in Virginia in 1981. Its
common stock is owned by Monongahela Power
Company - 27%, The Potomac Edison Company - 28%,
and West Penn Power Company - 45% (the Parents). The
Parents are wholly-owned subsidiaries of Allegheny
Power System, Inc. and are a part of the Allegheny Power
integrated electric utility system. The Company is subject
to 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
1993, 1992, and 1991. 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 that would be paid if
taxes were computed on the basis of financial accounting
income instead of taxable income are deferred.
Prior to 1987, provisions for federal income tax were
reduced by investment credits, and amounts equivalent to
such credits were charged to income with concurrent
credits to a deferred account, balances in which are being
amortized over estimated service lives of the related
properties.
F-75
ACCOUNTING CHANGE:
Effective January 1, 1993, the Company adopted
Statement of Financial Accounting Standards (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>
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Current income taxes payable $ 8 112 $ 8 276 $ 8 875
Deferred income taxes-
accelerated depreciation 6 637 7 758 7 678
Investment credit adjustment 1 257
Amortization of deferred
investment credit (1 316) (1 322) (1 344)
Total income taxes 13 433 14 713 15 466
Income taxes-charged to other income (171) (11) (11)
Income taxes-charged to
operating income $13 262 $14 702 $15 455
</TABLE>
In 1993, the total provision for income taxes
($13,262,000) was less than the amount produced by
applying the federal income tax statutory rate to financial
accounting income before income taxes ($14,155,000),
due primarily to amortization of deferred investment
credit ($1,316,000).
Federal income tax returns through 1989 have been
examined and substantially settled.
The Company adopted SFAS No. 109 as of January 1,
1993, and in doing so recognized a significant increase in
both deferred tax assets and liabilities. At December 31,
1993, the deferred tax assets and liabilities were comprised
of the following:
(Thousands of Dollars)
Deferred tax assets
Unamortized investment tax credit $ 28 869
Deferred tax liabilities
Book vs. tax plant basis differences, net 154 565
Other 152
154 717
Total net deferred tax liabilities $125 848
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
for an amount equal to the $4 million increase in deferred
tax liabilities. Regulatory liabilities were recorded in an
amount equal to the $29 million increase in deferred tax
assets 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. Based on the provisions in the
standard for recording these regulatory assets and
liabilities on the balance sheet, there was no effect on net
income resulting from adoption of the standard.
Note C - Long-Term Debt:
The Company had long-term debt outstanding
as follows:
<TABLE>
<CAPTION>
Interest December 31
Rate - % 1993 1992
(Thousands of Dollars)
<S> <C> <C> <C>
Debentures redeemed in 1993 $200 000
Debentures due:
September 1, 2003 5.625 $ 50 000
September 1, 2023 6.875 100 000
Commercial paper 3.53* 21 362
Medium-term notes
due 1994-1998 5.75-7.93 87 975 37 975
Notes payable to affiliates 2.85* 29 500 50 870
Unamortized debt discount (1 641) (1 706)
Total $287 196 $287 139
Less current maturities 10 000
Total $277 196 $287 139
*Weighted average interest rate at December 31, 1993.
</TABLE>
F-77
The Company has a revolving credit agreement with a
group of seven banks which provides for loans of up to
$75 million at any one time outstanding through 1997.
Each bank has the option to discontinue its loans after
1997 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, the
Company and its affiliates in 1992 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. 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: 1994, 10,000,000; 1995, $1,000,000; 1996, $6,375,000;
1997, $61,462,000; and 1998, $60,000,000.
The estimated fair value of debentures and medium-
term notes at December 31, 1993 and 1992, was
$233,445,000 and $249,850,000 respectively, based on
actual market prices or market prices of similar issues.
The carrying amount of commercial paper and notes
payable to affiliates approximates their fair value because
of the short maturity of those instruments.
<TABLE>
<CAPTION>
S-1 SCHEDULE V
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Property, Plant, and Equipment
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
<S> <C> <C> <C> <C> <C>
Intangible $ 2 882 134 $ 277 214 $ 3 159 348
Production 3 247 733 253 140 198 379 $22 063 495 $ (623 782) 3 365 244 355
Transmission 790 522 060 31 094 531 2 466 380 131 399 819 281 610
Distribution 1 909 584 425 132 456 219 20 636 190 (528 038) 2 020 876 416
General 220 527 927 14 776 992 2 089 925 126 331 233 341 325
Held for future use 83 815 420 384 968 386 436 6 625 83 820 577
Construction work in progress 412 058 186 227 235 080 (373 663) 638 919 603
Acquisition adjustments 213 320 (140 818) 72 502
Purchase of plant 351 000 351 000
Total electric 6 667 336 725 546 774 383 47 642 426 (1 401 946) 7 165 066 736
Other 12 550 009 36 517 108 807 (697 321) 11 780 398
Total $6 679 886 734 $546 810 900 $47 751 233 $ (2 099 267) $7 176 847 134
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-2 SCHEDULE V
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Property, Plant, and Equipment
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
<S> <C> <C> <C> <C> <C>
Intangible $ 2 892 923 $ (10 788) $ (1) $ 2 882 134
Production 3 171 306 225 88 188 348 $11 530 530 (230 790) 3 247 733 253
Transmission 775 135 181 15 295 174 1 416 116 1 507 821 790 522 060
Distribution 1 794 343 847 136 265 845 19 257 698 (1 767 569) 1 909 584 425
General 206 931 859 16 493 301 2 616 841 (280 392) 220 527 927
Held for future use 82 876 825 1 649 579 434 723 (276 261) 83 815 420
Construction work in progress 208 334 621 203 873 991 (150 426) 412 058 186
Acquisition adjustments 354 133 (140 813) 213 320
Sale of plant (72 525) 72 525
Total electric 6 242 103 089 461 755 450 35 255 908 (1 265 906) 6 667 336 725
Other 13 613 556 30 191 405 674 (688 064) 12 550 009
Total $6 255 716 645 $461 785 641 $35 661 582 $ (1 953 970) $6 679 886 734
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-3 SCHEDULE V
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Property, Plant, and Equipment
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
<S> <C> <C> <C> <C> <C>
Intangible $ 2 470 291 $ 422 632 $ 2 892 923
Production 3 138 565 976 38 527 834 $ 5 326 920 $ (460 665) 3 171 306 225
Transmission 739 862 237 37 469 789 2 127 005 (69 840) 775 135 181
Distribution 1 689 558 088 124 971 098 19 691 279 (494 060) 1 794 343 847
General 186 377 966 25 697 188 5 401 538 258 243 206 931 859
Held for future use 91 743 285 20 612 17 391 (8 869 681) 82 876 825
Construction work in progress 123 625 949 89 379 421 (4 670 749) 208 334 621
Acquisition adjustments 494 946 (140 813) 354 133
Sale of plant (72 525) (72 525)
Total electric 5 972 698 738 316 488 574 32 564 133 (14 520 090) 6 242 103 089
Other 13 480 362 817 653 140 711 (543 748) 13 613 556
Total $5 986 179 100 $317 306 227 $32 704 844 $(15 063 838) $6 255 716 645
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-4 SCHEDULE VI
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Accumulated Depreciation
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Other Balance at
beginning charged to costs changes end of
Description of period and expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $1 298 701 254 $117 170 656 $22 442 665 $(13 453 665) $1 379 976 034
Transmission 262 327 984 21 691 150 2 466 380 (907 888) 280 644 866
Distribution 628 455 319 61 265 709 20 444 063 (994 001) 668 282 964
General 49 448 491 10 172 953 2 089 925 1 133 554 58 665 073
Amortization of limited-
term investments 9 071 2 427 11 498
Total electric 2 238 942 119 210 302 895 47 442 579 (14 222 000) 2 387 580 435
Other 1 013 699 179 211 56 209 40 918 1 177 619
Total $2 239 955 818 $210 482 106 $47 498 788 $(14 181 082) (A)$2 388 758 054
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $(27 158 991)
Salvage 10 262 279
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 1 533 749
Accrued depreciation on properties acquired 16 220
Miscellaneous 1 165 661
$(14 181 082)
</TABLE>
<TABLE>
<CAPTION>
S-5 SCHEDULE VI
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Accumulated Depreciation
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Other Balance at
beginning charged to costs changes end of
Description of period and expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $1 216 976 754 $108 697 116 $11 925 721 $(15 046 895) $1 298 701 254
Transmission 241 466 941 21 574 921 1 415 152 701 274 262 327 984
Distribution 592 524 959 58 033 581 19 234 537 (2 868 684) 628 455 319
General 41 527 560 9 334 640 2 649 883 1 236 174 49 448 491
Amortization of limited-
term investments 6 645 2 426 9 071
Total electric 2 092 502 859 197 642 684 35 225 293 (15 978 131) 2 238 942 119
Other 1 220 120 185 120 405 242 13 701 1 013 699
Total $2 093 722 979 $197 827 804 $35 630 535 $(15 964 430) (A)$2 239 955 818
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $(25 804 895)
Salvage 6 907 157
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 1 657 034
Accrued depreciation on properties acquired 49 764
Miscellaneous 1 226 510
$(15 964 430)
</TABLE>
<TABLE>
<CAPTION>
S-6 SCHEDULE VI
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Accumulated Depreciation
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Other Balance at
beginning charged to costs changes end of
Description of period and expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $1 127 577 153 $105 116 893 $ 5 337 827 $(10 379 465) $1 216 976 754
Transmission 222 671 443 20 432 585 2 104 627 467 540 241 466 941
Distribution 557 957 525 55 584 719 19 686 549 (1 330 736) 592 524 959
General 36 708 910 8 517 413 5 385 021 1 686 258 41 527 560
Amortization of limited-
term investments 6 521 124 6 645
Total electric 1 944 921 552 189 651 734 32 514 024 (9 556 403) 2 092 502 859
Other 1 149 534 152 546 274 020 192 060 1 220 120
Total $1 946 071 086 $189 804 280 $32 788 044 $ (9 364 343) (A)$2 093 722 979
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $(20 438 037)
Salvage 7 566 716
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 1 616 431
Accrued depreciation on properties acquired 28 578
Miscellaneous 1 861 969
$ (9 364 343)
</TABLE>
<TABLE>
<CAPTION>
S-7 SCHEDULE VIII
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1993, 1992, and 1991
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, 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
Year ended December 31, 1991 $ 3,488,950 $ 4,590,000 $ 2,659,468 $ 6,994,148 $ 3,744,270
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<TABLE>
<CAPTION>
S-8 SCHEDULE IX
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Short-Term Borrowings
For Years Ended December 31, 1993, 1992, and 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Weighted Maximum Average Weighted
average amount amount average
Category of aggregate Balance at interest rate outstanding outstanding interest rate
short-term borrowings end of year at end of year during the year during the year during the year
(A) (B) (C)
1993
<S> <C> <C> <C> <C> <C>
Notes payable (D) $ 75 825 000 3.45% $ 80 450 000 $ 25 597 252 3.19%
Commercial paper (E) 54 811 289 3.31% 54 811 289 21 566 894 3.24%
Commercial paper - AGC (F) 21 361 630 3.53% 42 365 409 17 450 789 3.18%
Total $151 997 919
1992
Notes payable (D) $ 11 205 000 3.60% $ 55 065 000 $ 16 788 068 3.79%
Commercial paper (E) - - 62 314 460 31 957 617 3.93%
Commercial paper - AGC (F) - - 61 059 403 25 949 661 4.17%
Total $ 11 205 000
1991
Notes payable (D) $ 18 240 000 5.13% $ 18 240 000 $ 4 843 603 5.99%
Commercial paper (E) 55 949 958 5.08% 106 467 086 50 813 011 6.26%
Commercial paper - AGC (F) 65 712 494 4.65% 109 553 714 97 212 434 6.10%
Total $139 902 452
</TABLE>
(A) The maximum amount outstanding at any month end during the year.
(B) Computed by multiplying the principal amounts of short-term debt by the
days outstanding, and dividing the sum of the products by
the number of days in the year.
(C) Computed by dividing total interest accrued for the year by the average
principal amount outstanding for the year.
(D) Unsecured promissory notes issued under informal credit arrangements
with various banks with terms of 270 days or less.
(E) Unsecured bearer promissory notes sold to dealers at a discount with a
term of 270 days or less.
(F) Classified as long-term debt by Allegheny Generating Company (AGC).
<TABLE>
<CAPTION>
S-9 SCHEDULE X
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Supplementary Income Statement Information
The principal taxes charged directly to operating expenses were:
1993 1992 1991
(Thousands of Dollars)
Federal (Unemployment, old
<S> <C> <C> <C>
age benefits, and environmental) $ 16 674 $ 15 428 $ 14 438
State and local:
Gross receipts 112 811 111 993 112 524
Property 35 218 33 565 29 587
Capital stock or franchise 11 431 11 608 9 445
Miscellaneous 2 654 1 984 1 461
Total $178 788 $174 578 $167 455
</TABLE>
Charges for maintenance and depreciation other than amounts shown in the
consolidated statement of income were not material.
<TABLE>
<CAPTION>
S-10 SCHEDULE V
MONONGAHELA POWER COMPANY
Property, Plant, and Equipment
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 22 781 $ 22 781
<S> <C> <C> <C> <C> <C>
Production 675 077 723 $ 47 309 309 $ 6 545 244 715 841 788
Transmission 228 495 826 5 260 144 430 170 $ (34 259) 233 291 541
Distribution 520 924 116 33 211 083 7 487 342 (215 472) 546 432 385
General 42 311 896 902 192 512 660 (24 876) 42 676 552
Held for future use 379 235 379 235
Construction work in progress 99 177 360 45 511 236 (68 059) 144 620 537
Total electric 1 566 388 937 132 193 964 14 975 416 (342 666) 1 683 264 819
Other 862 522 3 458 57 904 249 731 1 057 807
Total $1 567 251 459 $132 197 422 $15 033 320 $ (92 935) $1 684 322 626
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-11 SCHEDULE V
MONONGAHELA POWER COMPANY
Property, Plant, and Equipment
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
<S> <C> <C> <C> <C> <C>
Intangible $ 11 269 $ 11 513 $ (1) $ 22 781
Production 656 737 232 21 363 654 $ 3 023 163 675 077 723
Transmission 222 514 953 6 349 420 195 127 (173 420) 228 495 826
Distribution 488 514 551 38 632 293 6 329 945 107 217 520 924 116
General 41 118 464 2 426 672 1 210 667 (22 573) 42 311 896
Held for future use 462 544 (83 309) 379 235
Construction work in progress 48 565 134 50 599 498 12 728 99 177 360
Total electric 1 457 924 147 119 383 050 10 758 902 (159 358) 1 566 388 937
Other 718 780 5 771 149 513 862 522
Total $1 458 642 927 $119 383 050 $10 764 673 $ (9 845) $1 567 251 459
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-12 SCHEDULE V
MONONGAHELA POWER COMPANY
Property, Plant, and Equipment
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 11 269 $ 11 269
<S> <C> <C> <C> <C> <C>
Production 648 761 023 $ 9 269 227 $ 1 293 018 656 737 232
Transmission 219 143 307 3 573 091 201 029 $ (416) 222 514 953
Distribution 460 912 842 34 323 925 6 720 293 (1 923) 488 514 551
General 38 575 686 3 276 033 712 048 (21 207) 41 118 464
Held for future use 607 561 (145 017) 462 544
Construction work in progress 21 320 881 29 011 691 (1 767 438) 48 565 134
Total electric 1 389 332 569 79 453 967 8 926 388 (1 936 001) 1 457 924 147
Other 573 875 16 160 19 335 148 080 718 780
Total $1 389 906 444 $ 79 470 127 $ 8 945 723 $ (1 787 921) $1 458 642 927
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-13 SCHEDULE VI
MONONGAHELA POWER COMPANY
Accumulated Depreciation
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Other Balance at
beginning charged to costs changes end of
Description of period and expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C>
Production $ 350 945 870 $ 27 434 969 $ 6 541 129 $ (4 059 388) $ 367 780 322
Transmission 89 160 507 6 494 390 430 170 (259 280) 94 965 447
Distribution 182 324 348 20 617 872 7 317 336 (953 756) 194 671 128
General 6 061 011 1 506 298 512 660 293 141 7 347 790
Amortization of limited-
term investments 9 071 2 427 11 498
Total electric 628 500 807 56 055 956 14 801 295 (4 979 283) 664 776 185
Other 94 304 4 296 7 735 80 071 170 936
Total $ 628 595 111 $ 56 060 252 $14 809 030 $ (4 899 212) (A)$ 664 947 121
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $ (8 550 639)
Salvage 3 467 747
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 176 040
Accrued depreciation on properties acquired 7 640
$ (4 899 212)
</TABLE>
<TABLE>
<CAPTION>
S-14 SCHEDULE VI
MONONGAHELA POWER COMPANY
Accumulated Depreciation
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Other Balance at
beginning charged to costs changes end of
Description of period and expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 330 861 806 $ 26 476 555 $ 3 023 163 $ (3 369 328) $ 350 945 870
Transmission 82 525 689 6 372 265 195 127 457 680 89 160 507
Distribution 171 103 255 19 647 182 6 307 664 (2 118 425) 182 324 348
General 5 713 628 1 366 155 1 208 512 189 740 6 061 011
Amortization of limited-
term investments 6 645 2 426 9 071
Total electric 590 211 023 53 864 583 10 734 466 (4 840 333) 628 500 807
Other 99 471 171 5 338 94 304
Total $ 590 310 494 $ 53 864 754 $10 739 804 $ (4 840 333) (A)$ 628 595 111
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $ (7 038 905)
Salvage 2 001 927
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 169 223
Accrued depreciation on properties acquired 27 422
$ (4 840 333)
</TABLE>
<TABLE>
<CAPTION>
S-15 SCHEDULE VI
MONONGAHELA POWER COMPANY
Accumulated Depreciation
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Additions
Balance at charged to Other Balance at
beginning costs and changes end of
Description of period expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 307 657 807 $ 25 847 058 $ 1 293 017 $ (1 350 042) $ 330 861 806
Transmission 76 762 167 6 238 834 201 030 (274 282) 82 525 689
Distribution 160 738 070 18 469 010 6 695 151 (1 408 674) 171 103 255
General 4 848 484 1 348 283 689 048 205 909 5 713 628
Amortization of limited-
term investments 6 521 124 6 645
Total electric 550 013 049 51 903 309 8 878 246 (2 827 089) 590 211 023
Other 91 404 1 362 152 644 159 349 99 471
Total $ 550 104 453 $ 51 904 671 $ 9 030 890 $ (2 667 740) (A)$ 590 310 494
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $ (5 044 644)
Salvage 2 196 280
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 167 239
Accrued depreciation on properties acquired 13 385
$ (2 667 740)
</TABLE>
<TABLE>
<CAPTION>
S-16 SCHEDULE VIII
MONONGAHELA POWER COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1993, 1992, and 1991
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, 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
Year ended December 31, 1991 $ 993,751 $ 1,020,000 $ 827,818 $ 1,761,070 $ 1,080,499
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<TABLE>
<CAPTION>
S-17 SCHEDULE IX
MONONGAHELA POWER COMPANY
Short-Term Borrowings
For Years Ended December 31, 1993, 1992, and 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Weighted Maximum Average Weighted
average amount amount average
Category of aggregate Balance at interest rate outstanding outstanding interest rate
short-term borrowings end of year at end of year during the year during the year during the year
(A) (B) (C)
1993
<S> <C> <C> <C> <C> <C> <C> <C>
Notes payable (D) $ 63 100 000 3.45% $ 63 100 000 $ 10 626 882 3.20%
Commercial paper (E) - - 24 072 849 3 466 796 3.19%
Money pool (F) - - 40 100 000 8 226 890 3.01%
Total $ 63 100 000
1992
Notes payable (D) $ - - $ 39 000 000 $ 6 512 896 3.98%
Commercial paper (E) - - 41 843 532 14 444 695 4.22%
Money pool (F) 8 030 000 2.60% 8 030 000 108 497 3.31%
Total $ 8 030 000
1991
Notes payable (D) $ 18 240 000 5.13% $ 18 240 000 $ 4 217 301 5.87%
Commercial paper (E) 34 877 179 5.24% 44 807 760 28 426 519 5.94%
Total $ 53 117 179
(A) The maximum amount outstanding at any month end during the year.
(B) Computed by multiplying the principal amounts of short-term debt by the
days outstanding, and dividing the sum of the products by the number
of days in the year.
(C) Computed by dividing total interest accrued for the year by the average
principal amount outstanding for the year.
(D) Unsecured promissory notes issued under informal credit
arrangements with various banks with terms of 270 days or less.
(E) Unsecured bearer promissory notes sold to dealers at a discount
with a term of 270 days or less.
(F) Internal arrangement for borrowing funds on a short-term basis.
</TABLE>
<TABLE>
<CAPTION>
S-18 SCHEDULE X
MONONGAHELA POWER COMPANY
Supplementary Income Statement Information
The principal taxes charged directly to operating expenses were:
1993 1992 1991
(Thousands of Dollars)
Federal (Unemployment, old
<S> <C> <C> <C>
age benefits, and environmental) $ 3 438 $ 3 389 $ 3 103
State and local:
Gross receipts 19 716 19 965 22 763
Property 9 949 9 363 8 981
Capital stock or franchise 266 283 260
Miscellaneous 707 207 271
Total $ 34 076 $ 33 207 $ 35 378
</TABLE>
Charges for maintenance and depreciation other than amounts shown in the
statement of income were not material.
<TABLE>
<CAPTION>
S-19 SCHEDULE V
THE POTOMAC EDISON COMPANY
Property, Plant, and Equipment
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 216 140 $ 9 585 $ 225 725
<S> <C> <C> <C> <C> <C>
Production 623 747 513 41 717 535 $ 5 994 897 $ (286 046) 659 184 105
Transmission 251 069 515 7 966 882 1 223 047 270 316 258 083 666
Distribution 614 935 665 49 903 533 4 672 795 (270 316) 659 896 087
General 62 512 389 5 167 354 324 099 286 045 67 641 689
Held for future use 1 163 814 1 163 814
Construction work in progress 141 611 023 66 752 512 (55 317) 208 308 218
Total electric 1 695 256 059 171 517 401 12 214 838 (55 318) 1 854 503 304
Other 3 456 099 124 3 456 223
Total $1 698 712 158 $171 517 525 $12 214 838 $ (55 318) $1 857 959 527
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-20 SCHEDULE V
THE POTOMAC EDISON COMPANY
Property, Plant, and Equipment
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 216 140 $ 216 140
<S> <C> <C> <C> <C> <C>
Production 606 706 010 $ 19 949 591 $ 2 991 922 $ 83 834 623 747 513
Transmission 243 834 680 5 881 536 341 068 1 694 367 251 069 515
Distribution 574 122 967 46 316 308 3 740 762 (1 762 848) 614 935 665
General 54 653 160 8 071 491 122 029 (90 233) 62 512 389
Held for future use 1 372 303 (208 489) 1 163 814
Construction work in progress 73 415 534 68 259 109 (63 620) 141 611 023
Sale of plant (72 525) 72 525
Total electric 1 554 248 269 148 478 035 7 195 781 (274 464) 1 695 256 059
Other 3 446 207 9 892 3 456 099
Total $1 557 694 476 $148 487 927 $ 7 195 781 $ (274 464) $1 698 712 158
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-21 SCHEDULE V
THE POTOMAC EDISON COMPANY
Property, Plant, and Equipment
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 124 449 $ 91 691 $ 216 140
<S> <C> <C> <C> <C> <C>
Production 597 125 026 11 102 817 $ 1 526 755 $ 4 922 606 706 010
Transmission 217 637 199 27 063 792 762 238 (104 073) 243 834 680
Distribution 532 452 408 45 741 801 3 787 543 (283 699) 574 122 967
General 47 865 842 7 824 186 1 132 679 95 811 54 653 160
Held for future use 1 467 117 (94 814) 1 372 303
Construction work
in progress 54 153 082 21 258 282 (1 995 830) 73 415 534
Sale of plant (72 525) (72 525)
Total electric 1 450 825 123 113 082 569 7 209 215 (2 450 208) 1 554 248 269
Other 3 424 600 27 883 (6 276) 3 446 207
Total $1 454 249 723 $113 110 452 $ 7 209 215 $ (2 456 484) $1 557 694 476
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-22 SCHEDULE VI
THE POTOMAC EDISON COMPANY
Accumulated Depreciation
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Additions
Balance at charged to Other Balance at
beginning costs and changes end of
Description of period expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 295 555 144 $ 26 085 922 $ 5 990 782 $ (3 524 286) $ 312 125 998
Transmission 69 218 963 7 463 926 1 223 047 164 645 75 624 487
Distribution 213 888 741 20 503 689 4 650 674 (469 360) 229 272 396
General 12 595 474 2 395 553 324 099 453 293 15 120 221
Total electric 591 258 322 56 449 090 12 188 602 (3 375 708) 632 143 102
Other 120 080 5 104 125 184
Total $ 591 378 402 $ 56 454 194 $12 188 602 $ (3 375 708) (A)$ 632 268 286
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $ (7 915 385)
Salvage 4 037 353
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 494 083
Accrued depreciation on properties acquired 6 565
Miscellaneous 1 676
$ (3 375 708)
</TABLE>
<TABLE>
<CAPTION>
S-23 SCHEDULE VI
THE POTOMAC EDISON COMPANY
Accumulated Depreciation
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Additions
Balance at charged to Other Balance at
beginning costs and changes end of
Description of period expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 276 275 509 $ 24 431 324 $ 2 987 588 $ (2 164 101) $ 295 555 144
Transmission 62 003 043 7 066 445 340 104 489 579 69 218 963
Distribution 197 816 016 19 872 487 3 739 881 (59 881) 213 888 741
General 10 658 188 2 076 212 122 029 (16 897) 12 595 474
Total electric 546 752 756 53 446 468 7 189 602 (1 751 300) 591 258 322
Other 114 763 5 317 120 080
Total $ 546 867 519 $ 53 451 785 $ 7 189 602 $ (1 751 300) (A)$ 591 378 402
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $ (4 996 767)
Salvage 2 797 107
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 477 551
Accrued depreciation on properties acquired 12 152
Miscellaneous (41 343)
$ (1 751 300)
</TABLE>
<TABLE>
<CAPTION>
S-24 SCHEDULE VI
THE POTOMAC EDISON COMPANY
Accumulated Depreciation
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Additions
Balance at charged to Other Balance at
beginning costs and changes end of
Description of period expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 256 123 157 $ 22 796 808 $ 1 526 755 $ (1 117 701) $ 276 275 509
Transmission 56 919 227 5 879 200 739 859 (55 525) 62 003 043
Distribution 181 629 535 19 921 440 3 807 955 72 996 197 816 016
General 9 386 779 1 980 457 1 132 679 423 631 10 658 188
Total electric 504 058 698 50 577 905 7 207 248 (676 599) 546 752 756
Other 109 446 5 317 114 763
Total $ 504 168 144 $ 50 583 222 $ 7 207 248 $ (676 599) (A)$ 546 867 519
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $ (3 510 174)
Salvage 2 492 031
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 398 267
Accrued depreciation on properties acquired 910
Miscellaneous (57 633)
$ (676 599)
</TABLE>
<TABLE>
<CAPTION>
S-25 SCHEDULE VIII
THE POTOMAC EDISON COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1993, 1992, and 1991
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, 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
Year ended December 31, 1991 $ 1,176,266 $ 1,280,000 $ 746,717 $ 1,988,421 $ 1,214,562
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<TABLE>
<CAPTION>
S-26 SCHEDULE IX
THE POTOMAC EDISON COMPANY
Short-Term Borrowings
For Years Ended December 31, 1993, 1992, and 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Weighted Maximum Average Weighted
average amount amount average
Category of aggregate Balance at interest rate outstanding outstanding interest rate
short-term borrowings end of year at end of year during the year during the year during the year
(A) (B) (C)
1993
<S> <C> <C> <C> <C> <C> <C>
Notes payable (D) $ - - $ 19 950 000 $ 1 111 507 3.24%
Commercial paper (E) - - - 36 155 2.97%
Total $ -
1992
Notes payable (D) $ - - $ 19 900 000 $ 2 923 169 3.57%
Commercial paper (E) - - - 286 692 3.45%
Money pool (F) - - - 356 382 3.69%
Total $ -
1991
Notes payable (D) $ - - $ - $ 1 096 6.30%
Commercial paper (E) - - 42 540 182 12 747 687 6.11%
Total $ -
</TABLE>
(A) The maximum amount outstanding at any month end during the year.
(B) Computed by multiplying the principal amounts of short-term debt by
the days outstanding, and dividing the sum of the products by the
number of days in the year.
(C) Computed by dividing total interest accrued for the year by the
average principal amount outstanding for the year.
(D) Unsecured promissory notes issued under informal credit arrangements
with various banks with terms of 270 days or less.
(E) Unsecured bearer promissory notes sold to dealers at a discount with
a term of 270 days or less.
(F) Internal arrangement for borrowing funds on a short-term basis.
<TABLE>
<CAPTION>
S-27 SCHEDULE X
THE POTOMAC EDISON COMPANY
Supplementary Income Statement Information
The principal taxes charged directly to operating expenses were:
1993 1992 1991
(Thousands of Dollars)
Federal (Unemployment, old
<S> <C> <C> <C>
age benefits, and environmental) $ 3 233 $ 3 292 $ 3 129
State and local:
Gross receipts 27 512 27 473 27 277
Property 11 597 10 789 10 242
Capital stock or franchise 2 628 2 293 2 123
Miscellaneous 1 843 1 944 1 166
Total $ 46 813 $ 45 791 $ 43 937
Charges for maintenance and depreciation other than amounts shown in the
statement of income were not material.
</TABLE>
<TABLE>
<CAPTION>
S-28 SCHEDULE V
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Property, Plant, and Equipment
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 2 629 591 $ 267 629 $ 2 897 220
<S> <C> <C> <C> <C> <C>
Production 1 170 698 541 50 662 495 $ 6 622 167 $ (337 736) 1 214 401 133
Transmission 266 941 700 17 834 700 813 163 (104 658) 283 858 579
Distribution 773 724 644 49 341 603 8 476 053 (42 250) 814 547 944
General 112 874 322 8 646 570 1 176 810 (134 839) 120 209 243
Held for future use 78 254 630 384 968 386 436 6 625 78 259 787
Construction work in progress 170 844 043 113 185 489 (250 286) 283 779 246
Acquisition adjustments 213 320 (140 818) 72 502
Purchase of plant 351 000 351 000
Total electric 2 576 180 791 240 674 454 17 474 629 (1 003 962) 2 798 376 654
Other 5 460 789 48 475 21 858 5 434 172
Total $2 581 641 580 $240 674 454 $17 523 104 $ (982 104) $2 803 810 826
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-29 SCHEDULE V
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Property, Plant, and Equipment
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 2 651 892 $ (22 301) $ 2 629 591
<S> <C> <C> <C> <C> <C>
Production 1 133 631 133 42 831 004 $ 5 448 972 $ (314 624) 1 170 698 541
Transmission 264 771 218 3 063 529 879 921 (13 126) 266 941 700
Distribution 731 706 329 51 317 244 9 186 991 (111 938) 773 724 644
General 108 439 081 5 873 012 1 270 185 (167 586) 112 874 322
Held for future use 77 024 237 1 649 579 434 723 15 537 78 254 630
Construction work in progress 85 003 206 85 940 371 (99 534) 170 844 043
Acquisition adjustments 354 133 (140 813) 213 320
Total electric 2 403 581 229 190 652 438 17 220 792 (832 084) 2 576 180 791
Other 5 422 654 5 720 43 855 5 460 789
Total $2 409 003 883 $190 652 438 $17 226 512 $ (788 229) $2 581 641 580
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-30 SCHEDULE V
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Property, Plant, and Equipment
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
(A)
Electric Plant:
In Service -
Intangible $ 2 334 573 $ 317 319 $ 2 651 892
<S> <C> <C> <C> <C> <C>
Production 1 118 165 497 18 054 457 $ 2 123 234 $ (465 587) 1 133 631 133
Transmission 259 736 956 6 163 351 1 163 738 34 649 264 771 218
Distribution 696 192 838 44 905 372 9 183 443 (208 438) 731 706 329
General 97 305 838 14 467 425 3 517 821 183 639 108 439 081
Held for future use 85 650 866 20 612 17 391 (8 629 850) 77 024 237
Construction work in progress 47 217 299 38 693 389 (907 482) 85 003 206
Acquisition adjustments 494 946 (140 813) 354 133
Total electric 2 307 098 813 122 621 925 16 005 627 (10 133 882) 2 403 581 229
Other 5 327 374 21 017 116 297 5 422 654
Total $2 312 426 187 $122 621 925 $16 026 644 $(10 017 585) $2 409 003 883
(A) Transfers between classifications and miscellaneous.
</TABLE>
<TABLE>
<CAPTION>
S-31 SCHEDULE VI
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Accumulated Depreciation
For Year Ended December 31, 1993
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Additions Other Balance at
beginning charged to costs changes end of
Description of period and expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 545 670 765 $ 48 160 172 $ 7 009 113 $ (5 635 481) $ 581 186 343
Transmission 95 934 831 6 472 846 813 163 (800 884) 100 793 630
Distribution 232 242 230 20 144 148 8 476 053 429 115 244 339 440
General 30 650 801 6 122 057 1 176 810 370 101 35 966 149
Total electric 904 498 627 80 899 223 17 475 139 (5 637 149) 962 285 562
Other 407 147 17 420 48 474 (39 153) 336 940
Total $ 904 905 774 $ 80 916 643 $17 523 613 $ (5 676 302) (A)$ 962 622 502
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $(10 342 707)
Salvage 2 636 779
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 863 626
Accrued depreciation on properties acquired 2 015
Miscellaneous 1 163 985
$ (5 676 302)
</TABLE>
<TABLE>
<CAPTION>
S-32 SCHEDULE VI
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Accumulated Depreciation
For Year Ended December 31, 1992
Col. A Col. B Col. C Col. D Col. E Col. F
Additions
Balance at charged to Other Balance at
beginning costs and changes end of
Description of period expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C>
Production $ 518 684 616 $ 42 359 679 $ 5 848 497 $ (9 525 033) $ 545 670 765
Transmission 90 177 601 6 883 136 879 921 (245 985) 95 934 831
Distribution 223 605 688 18 513 912 9 186 992 (690 378) 232 242 230
General 25 156 515 5 747 751 1 305 382 1 051 917 30 650 801
Total electric 857 624 420 73 504 478 17 220 792 (9 409 479) 904 498 627
Other 374 766 24 400 5 720 13 701 407 147
Total $ 857 999 186 $ 73 528 878 $17 226 512 $ (9 395 778) (A)$ 904 905 774
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $(13 759 719)
Salvage 2 075 638
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 1 010 260
Accrued depreciation on properties acquired 10 190
Miscellaneous 1 267 853
$ (9 395 778)
</TABLE>
<TABLE>
<CAPTION>
S-33 SCHEDULE VI
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Accumulated Depreciation
For Year Ended December 31, 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Additions
Balance at charged to Other Balance at
beginning costs and changes end of
Description of period expenses Retirements add (deduct) period
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 487 695 353 $ 41 079 883 $ 2 134 142 $ (7 956 478) $ 518 684 616
Transmission 83 469 736 7 070 529 1 163 738 801 074 90 177 601
Distribution 215 589 920 17 194 269 9 183 443 4 942 223 605 688
General 22 580 680 5 048 125 3 524 304 1 052 014 25 156 515
Total electric 809 335 689 70 392 806 16 005 627 (6 098 448) 857 624 420
Other 338 672 24 400 21 017 32 711 374 766
Total $ 809 674 361 $ 70 417 206 $16 026 644 $ (6 065 737) (A)$ 857 999 186
</TABLE>
<TABLE>
<S> <C>
(A) Cost of removal $(11 822 254)
Salvage 2 771 707
Provisions for depreciation of motor vehicles - charged to
transportation expense clearing account 1 050 925
Accrued depreciation on properties acquired 14 283
Miscellaneous 1 919 602
$ (6 065 737)
</TABLE>
<TABLE>
<CAPTION>
S-34 SCHEDULE VIII
WEST PENN POWER COMPANY AND SUBSIDARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1993, 1992, and 1991
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, 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
Year ended December 31, 1991 $ 1,318,933 $ 2,290,000 $ 1,084,933 $ 3,244,657 $ 1,449,209
(A) Recoveries.
(B) Uncollectible accounts charged off.
</TABLE>
<TABLE>
<CAPTION>
S-35 SCHEDULE IX
WEST PENN POWER COMPANY AND SUBSIDARY COMPANIES
Short-Term Borrowings
For Years Ended December 31, 1993, 1992, and 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Weighted Maximum Average Weighted
average amount amount average
Category of aggregate Balance at interest rate outstanding outstanding interest rate
short-term borrowings end of year at end of year during the year during the year during the year
(A) (B) (C)
1993
<S> <C> <C> <C> <C> <C> <C>
Notes payable (D) $ - - $ 44 500 000 $ 9 081 151 3.18%
Money pool (F) - - 8 750 000 1 166 000 3.01%
Total $ -
1992
Notes payable (D) $ - - $ 28 255 000 $ 6 697 877 3.69%
Commercial paper (E) - - 19 972 719 1 360 973 4.04%
Money pool (F) - - 33 580 000 8 102 796 3.42%
Total $ -
1991
Notes payable (D) $ - - $ 1 000 000 $ 625 205 6.80%
Commercial paper (E) - - 71 189 328 9 523 338 7.43%
Total $ -
(A) The maximum amount outstanding at any month end during the year.
(B) Computed by multiplying the principal amounts of short-term debt
by the days outstanding, and dividing the sum of the
products by the number of days in the year.
(C) Computed by dividing total interest accrued for the year by the average
principal amount outstanding for the year.
(D) Unsecured promissory notes issued under informal credit arrangements
with various banks with terms of 270 days or less.
(E) Unsecured bearer promissory notes sold to dealers at a discount with a
term of 270 days or less.
(F) Internal arrangement for borrowing funds on a short-term basis.
</TABLE>
<TABLE>
<CAPTION>
S-36 SCHEDULE X
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Supplementary Income Statement Information
The principal taxes charged directly to operating expenses were:
1993 1992 1991
(Thousands of Dollars)
Federal (Unemployment, old
<S> <C> <C> <C>
age benefits, and environmental) $ 6 903 $ 5 758 $ 5 388
State and local:
Gross receipts 63 771 62 632 60 474
Property 10 175 10 162 7 865
Capital stock or franchise 8 534 9 053 7 041
Miscellaneous (134) (305) (138)
Total $ 89 249 $ 87 300 $ 80 630
Charges for maintenance and depreciation other than amounts shown in the
consolidated statement of income were not material.
</TABLE>
<TABLE>
<CAPTION>
S-37 SCHEDULE V
ALLEGHENY GENERATING COMPANY
Property, Plant, and Equipment
For Years Ended December 31, 1993, 1992, and 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Balance at Other Balance at
beginning Additions changes end of
Classification of period at cost Retirements add (deduct) period
1993
Electric Plant:
Intangible $ 13 622 $ 13 622
<S> <C> <C> <C> <C> <C>
Production 778 209 476 $ 509 040 $ 2 901 187 775 817 329
Transmission 44 015 019 32 805 44 047 824
General 2 829 320 60 876 76 356 2 813 840
Construction work in progress 425 760 1 785 843 2 211 603
Total $ 825 493 197 $ 2 388 564 $ 2 977 543 $ 0 $ 824 904 218
1992
Electric Plant:
Intangible $ 13 622 $ 13 622
Production 774 231 850 $ 4 044 099 $ 66 473 778 209 476
Transmission 44 014 330 689 44 015 019
General 2 721 154 122 126 13 960 2 829 320
Construction work in progress 1 350 747 (924 987) 425 760
Total $ 822 331 703 $ 3 241 927 $ 80 433 $ 0 $ 825 493 197
1991
Electric Plant:
Intangible $ 13 622 $ 13 622
Production $ 774 514 430 101 333 $ 383 913 774 231 850
Transmission 43 344 775 669 555 44 014 330
General 2 630 600 129 544 38 990 2 721 154
Construction work in progress 934 688 416 059 1 350 747
Total $ 821 424 493 $ 1 330 113 $ 422 903 $ 0 $ 822 331 703
</TABLE>
<TABLE>
<CAPTION>
S-38 SCHEDULE VI
ALLEGHENY GENERATING COMPANY
Accumulated Depreciation
For Years Ended December 31, 1993, 1992, and 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Additions
Balance at charged to Other Balance at
beginning costs and changes end of
Description of period expenses Retirements add (deduct) period
1993
Electric Plant:
<S> <C> <C> <C> <C> <C>
Production $ 106 529 475 $ 15 489 593 $ 2 901 187 $ (234 510) $ 118 883 371
Transmission 8 013 683 1 259 988 (12 369) 9 261 302
General 141 205 149 045 76 356 17 019 230 913
Total $ 114 684 363 $ 16 898 626 $ 2 977 543 $ (229 860) (A)$ 128 375 586
1992
Electric Plant:
Production $ 91 154 823 $ 15 429 558 $ 66 473 $ 11 567 $ 106 529 475
Transmission 6 760 608 1 253 075 8 013 683
General (771) 144 522 13 960 11 414 141 205
Total $ 97 914 660 $ 16 827 155 $ 80 433 $ 22 981 (A)$ 114 684 363
1991
Electric Plant:
Production $ 76 100 836 $ 15 393 144 $ 383 913 $ 44 756 $ 91 154 823
Transmission 5 520 313 1 244 022 (3 727) 6 760 608
General (107 033) 140 548 38 990 4 704 (771)
Total $ 81 514 116 $ 16 777 714 $ 422 903 $ 45 733 (A)$ 97 914 660
</TABLE>
<TABLE>
1993 1992 1991
<S> <C> <C> <C>
(A) Cost of removal $ (350 260) $ (9 504) $ (60 965)
Salvage 120 400 32 485 106 698
$ (229 860) $ 22 981 $ 45 733
</TABLE>
<TABLE>
<CAPTION>
S-39 SCHEDULE IX
ALLEGHENY GENERATING COMPANY
Short-Term Borrowings
For Years Ended December 31, 1993, 1992, and 1991
Col. A Col. B Col. C Col. D Col. E Col. F
Weighted Maximum Average Weighted
average amount amount average
Category of aggregate Balance at interest rate outstanding outstanding interest rate
short-term borrowings end of year at end of year during the year during the year during the year
(A) (B) (C)
1993
<S> <C> <C> <C> <C> <C>
Commercial paper (D) $ 21 361 630 3.53% $ 42 365 409 $ 17 450 789 3.18%
Money pool (E) 29 500 000 2.85% 55 230 000 27 558 595 3.01%
Total $ 50 861 630
1992
Commercial paper (D) $ - - $ 61 059 403 $ 25 949 661 4.17%
Money pool (E) 50 870 000 2.60% 59 180 000 28 462 475 3.28%
Total $ 50 870 000
1991
Commercial paper (D) $ 65 712 494 4.65% $ 109 553 714 $ 97 212 434 6.10%
Total $ 65 712 494
(A) The maximum amount outstanding at any month end during the year.
(B) Computed by multiplying the principal amounts of short-term debt by
the days outstanding, and dividing the sum of the
products by the number of days in the year.
(C) Computed by dividing total interest accrued for the year by the average
principal amount outstanding for the year.
(D) Unsecured bearer promissory notes sold to dealers at a discount with a
term of 270 days or less. Classified as long-term debt.
(E) Internal arrangement for borrowing funds on a short-term basis.
Classified as long-term debt.
</TABLE>
<TABLE>
<CAPTION>
S-40 SCHEDULE X
ALLEGHENY GENERATING COMPANY
Supplementary Income Statement Information
The principal taxes charged directly to operating expenses were:
1993 1992 1991
(Thousands of Dollars)
<S> <C> <C> <C>
Federal (Environmental) $ 40 $ 62 $ 55
State and local:
Gross receipts 1 812 1 923 2 010
Property 3 497 3 251 2 498
Total $ 5 349 $ 5 236 $ 4 563
</TABLE>
<PAGE>
- 43 -
<TABLE>
<CAPTION>
Supplementary Data
Quarterly Financial Data
(Thousands of Dollars)
Electric
Operating Operating Net Earnings
Quarter ended Revenues Income Income Per Share
APS
<S> <C> <C> <C> <C>
March 1992 $622 614 $105 292 $67 300 $.62
June 1992 555 800 79 816 42 498 .39
September 1992 551 993 82 635 44 320 .39
December 1992 576 251 88 321 49 429 .44
March 1993 614 678 107 524 67 609 .59
June 1993 552 380 83 292 44 358 .39
September 1993 583 311 94 119 54 527 .48
December 1993 581 157 89 704 49 262 .42
Monongahela
March 1992 $163 557 $ 21 384 $15 981
June 1992 145 122 15 195 9 756
September 1992 159 061 21 536 14 748
December 1992 164 223 23 946 17 859
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 1992 $191 082 $ 31 571 $25 306
June 1992 165 415 21 479 15 293
September 1992 160 661 19 482 13 089
December 1992 170 729 19 616 13 788
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 1992 $291 956 $ 39 264 $31 367
June 1992 265 975 30 614 22 813
September 1992 253 829 28 829 21 202
December 1992 265 081 32 231 22 774
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 1992 $ 24 384 $ 13 628 $ 7 900
June 1992 24 024 13 364 7 695
September 1992 23 970 13 281 7 603
December 1992 23 769 13 015 7 526
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>
- 44 -
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
For APS and the Subsidiaries, none.
<PAGE>
- 45 -
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
APS, Monongahela, Potomac Edison, West Penn, and AGC. Reference is made to
the Executive Officers of the Registrants in Part I of this report.
The names, ages, and the business experience during the past five years of
the directors of the System companies are set forth below:
<TABLE>
<CAPTION>
Business Experience during Director since date shown of
Name the Past Five Years Age APS MP PE WP AGC
<S> <C> <C> <C> <C> <C> <C>
Eleanor Baum See below (a) 53 1988 1988 1988 1988
William L. Bennett See below (b) 44 1991 1991 1991 1991
Klaus Bergman System employee (1) 62 1985 1985 1985 1979 1982
Stanley I. Garnett, II System employee (1) 50 1990 1990 1990 1990
Benjamin H. Hayes System employee (1) 59 1992
Kenneth M. Jones System employee (1) 56 1991
Phillip E. Lint See below (c) 64 1989 1989 1989 1989
Edward H. Malone See below (d) 69 1985 1985 1985 1985
Frank A. Metz, Jr. See below (e) 59 1984 1984 1984 1984
Clarence F. Michalis See below (f) 71 1973 1973 1973 1973
Alan J. Noia System employee (1) 46 1987
Jay S. Pifer System employee (1) 56 1992
Steven H. Rice See below (g) 50 1986 1986 1986 1986
Gunnar E. Sarsten See below (h) 57 1992 1992 1992 1992
Peter L. Shea See below (i) 61 1993 1993 1993 1993
Peter J. Skrgic System employee (1) 52 1990 1990 1990 1989
</TABLE>
(1) See Executive Officers of the Registrants in Part I of this report for
further details.
(a) Eleanor Baum. Dean of the Albert Nerken School of Engineering of
The Cooper Union for the Advancement of Science and Art.
Director of United States Trust Company, Commissioner of the Engineering
Manpower Commission, and a fellow of the Institute of Electrical and
Electronic Engineers and the Society of Women Engineers. Ms. Baum
filed one late report on Form 4 concerning one purchase transaction in 1993.
(b) William L. Bennett. Co-Chairman, Director and Chief Executive Officer of
Noel Group, Inc. Formerly, General partner, Discovery Funds,
a venture capital affiliate of Rockefeller & Company, Inc. Chairman of
the Board of TDX Corporation. Director of Forschner Group, Inc., Global
Natural Resources Inc., Lincoln Snacks Company, Simmons
Outdoor Corporation and VISX, Inc.
(c) Phillip E. Lint. Retired. Formerly, partner, Price Waterhouse.
(d) 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,
Mattel, Inc., and Corporate Property Investors, a real estate investment
trust.
(e) 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.
(f) 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.
(g) Steven H. Rice. Business consultant and attorney-at-law. Formerly,
President and Chief Operating Officer and Director of The Seamen's Bank
for Savings. Director and member of the Investment and Audit Committees
of Royal Group, Inc. (The Royal Insurance Companies). Director and
Vice Chairman of the Board of The Stamford (CT) Federal Savings Bank.
(h) Gunnar E. Sarsten. President and Chief Operating Officer of Morrison
Knudsen Corporation. Formerly, President and Chief Executive Officer
of United Engineers & Constructors International, Inc., a subsidiary
of the Raytheon Company, and Deputy Chairman of the Third District Federal
Reserve Bank in Philadelphia.
(i) Peter L. Shea. Managing director of Hydrocarbon Energy, Inc., a privately
owned oil and gas development drilling and production company.
<PAGE>
- 46 -
ITEM 11. EXECUTIVE COMPENSATION
During 1993, and for 1992 and 1991, 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
$100,000 was as follows:
<TABLE>
<CAPTION>
Summary Compensation Tables
APS
Annual Compensation (a)
Other All
Name Annual Other
and Compen- Compen-
Principal sation sation
Position Year Salary($) Bonus($)(b) ($)(c) ($)(d)
<S> <C> <C> <C> <C> <C>
Klaus Bergman, 1993 460,008 80,000 46,889
Chief Executive 1992 445,008 80,000 13,529(e)
Officer and 1991 425,004 70,000 6,037
President (f)
Stanley I. Garnett, II 1993 206,004 35,000 24,006
Vice President (f) 1992 195,600 35,000 7,939(e)
1991 180,600 29,000 5,752
Peter J. Skrgic, 1993 185,004 31,000 (g) 18,678
Vice President (f) 1992 175,008 29,000 (g) 8,325(e)
1991 161,004 27,000 (g) 5,696
Nancy H. Gormley, 1993 162,504 28,000 15,446
Vice President (f) 1992 150,000 26,000 8,159(e)
1991 137,508 (h) 4,755
Kenneth M. Jones, 1993 155,004 27,000 17,423(i) 12,879
Vice President (f) 1992 147,504 23,000 17,457(i) 9,359(e)
1991 135,629 (h) 5,304
</TABLE>
(a) APS has no paid employees. All salaries and bonuses are paid by APSC.
(b) Bonus amounts are determined and paid in April of the year in which the
figure appears and are based upon performance in the prior year.
(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 for both the Executive
Life Insurance and Secured Benefit Plans (based upon the premium, future valued
to retirement, using the policy internal rate of return minus the
corporation's premium payment), as well as the premium paid for the basic
Group Life Insurance program plan and the contribution for the 401(k) plan. For
1993, 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 $42,392 and $4,497;
Mr. Garnett $19,509 and $4,497; Mr. Skrgic $14,181 and $4,497; Ms. Gormley
$11,152 and $4,294; and Mr. Jones $8,382 and $4,497, respectively.
(e) These amounts as previously reported did not include the following amounts
representing the dollar value of the benefit to the executive officer of the
remainder of the premium paid on the Executive Life Insurance Plan: Mr.
Bergman $786; Mr. Garnett $210; Mr. Skrgic $218; Ms. Gormley $232; and
Mr. Jones $519.
(f) See Executive Officers of the Registrants for other positions held.
(g) Although less than 10% of total annual salary and bonus, Mr. Skrgic received
a $15,000 housing allowance in 1993, 1992 and 1991.
(h) The incentive plan was not in effect for these officers in 1991.
(i) Includes $15,000 housing allowance for both 1993 and 1992 and miscellaneous
other items totaling $2,423 and $2,457 for 1993 and 1992, respectively.
<PAGE>
- 47 -
<TABLE>
<CAPTION>
Summary Compensation Tables
MONONGAHELA
Annual Compensation
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($)(a) ($)(b)
<S> <C> <C> <C> <C>
Klaus Bergman, 1993
Chief Executive 1992
Officer (c) 1991
Benjamin H. Hayes, 1993 189,996 30,000 19,668
President 1992 180,000 27,000 11,114(d)
1991 156,250 27,000 5,151
Thomas A. Barlow, 1993 119,496 16,000 12,777
Vice President 1992 113,247 15,000 7,145(d)
1991 105,999 (e) 4,197
Robert R. Winter, 1993 119,502 17,000 19,529
Vice President 1992 112,002 15,000 6,332(d)
1991 103,998 (e) 4,120
Richard E. Myers, 1993 110,121 10,000 17,246
Comptroller 1992 104,581 10,000 7,486(d)
1991 98,000 (e) 3,882
(a) Bonus amounts are determined and paid in April of the year in which
the figure appears and are based upon performance in the prior year.
(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 for both
the Executive Life Insurance and Secured
Benefit Plans (based upon the premium, future valued to
retirement, using the policy internal rate of return minus the
corporation's premium payment), as well
as the premium paid for the basic Group Life Insurance program
plan and the contribution for the 401(k) plan. For 1993,
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. Hayes $15,171 and $4,497; Mr.
Barlow $9,194 and $3,583; Mr. Winter $15,946 and $3,583; and
Mr. Myers $13,944 and $3,302, respectively.
(c) The total compensation Messrs. Bergman, Garnett, Skrgic, Jones
and Ms. Gormley received for services in all capacities to APS,
APSC and the Subsidiaries is set
forth in the Summary Compensation Table for APS.
(d) These amounts as previously reported did not include the
following amounts representing the dollar value of the benefit
to the executive officer of the
remainder of the premium paid on the Executive Life Insurance
Plan: Mr. Hayes $381; Mr. Barlow $494; Mr. Winter $147; and Mr.
Myers $215.
(e) The incentive plan was not in effect for these officers in 1991.
</TABLE>
<PAGE>
- 48 -
<TABLE>
<CAPTION>
Summary Compensation Tables
POTOMAC EDISON
Annual Compensation
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($)(a) ($)(b)
<S> <C> <C> <C> <C>
Klaus Bergman, 1993
Chief Executive 1992
Officer (c) 1991
Alan J. Noia, 1993 212,500 38,000 20,107
President 1992 200,000 38,000 7,975(d)
1991 185,833 35,000 6,990
Robert B. Murdock, 1993 135,000 19,000 12,936
Vice President 1992 128,914 18,000 8,853(d)
1991 122,501 (e) 5,831
James D. Latimer, 1993 119,996 15,000 12,971
Vice President 1992 111,666 15,000 7,625(d)
1991 103,255 (e) 4,969
Thomas J. Kloc, 1993 112,500 10,000 11,204
Comptroller 1992 107,004 9,000 5,366(d)
1991 100,500 (e) 4,839
(a) Bonus amounts are determined and paid in April of the year in which the figure
appears and are based upon performance in the prior year.
(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 for both the Executive Life Insurance and Secured
Benefit Plans (based upon the premium, future valued to retirement, using the
policy internal rate of return minus the corporation's premium payment), as well
as the premium paid for the basic Group Life Insurance program plan and the
contribution for the 401(k) plan. For 1993, 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. Noia $15,610 and $4,497; Mr.
Murdock $9,081 and $3,855; Mr. Latimer $9,371 and $3,600; and Mr. Kloc $7,829 and
$3,375, respectively.
(c) The total compensation Messrs. Bergman, Garnett, Skrgic, Jones and Ms. Gormley
received for services in all capacities to APS, APSC and the Subsidiaries is set
forth in the Summary Compensation Table for APS.
(d) These amounts as previously reported did not include the following amounts
representing the dollar value of the benefit to the executive officer of the
remainder of the premium paid on the Executive Life Insurance Plan: Mr. Noia
$186; Mr. Murdock $310; Mr. Latimer $211; and Mr. Kloc $99.
(e) The incentive plan was not in effect for these officers in 1991.
</TABLE>
<PAGE>
- 49 -
<TABLE>
<CAPTION>
Summary Compensation Tables
WEST PENN
Annual Compensation
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($)(a) ($)(b)
<S> <C> <C> <C> <C>
Klaus Bergman, 1993
Chief Executive 1992
Officer (c) 1991
Jay S. Pifer, 1993 175,500 28,000 18,093
President 1992 156,495 26,000 9,870(d)
1991 133,754 (e) 4,854
Thomas K. Henderson, 1993 124,004 17,000 17,570
Vice President 1992 117,838 15,000 6,887(d)
1991 110,924 (e) 4,335
Charles S. Ault, 1993 114,419 15,000 12,673
Vice President 1992 107,129 14,000 6,764(d)
1991 99,335 (e) 5,266
Charles V. Burkley, 1993 112,996 10,000 10,544
Comptroller 1992 106,913 10,000 6,748(d)
1991 96,706 (e) 3,780
(a) Bonus amounts are determined and paid in April of the year in which the figure
appears and are based upon performance in the prior year.
(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 for both the Executive Life Insurance and Secured
Benefit Plans (based upon the premium, future valued to retirement, using the
policy internal rate of return minus the corporation's premium payment), as well
as the premium paid for the basic Group Life Insurance program plan and the
contribution for the 401(k) plan. For 1993, 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. Pifer $13,596 and $4,497; Mr.
Henderson $13,850 and $3,720; Mr. Ault $9,240 and $3,433; and Mr. Burkley $7,154
and $3,390, respectively.
(c) The total compensation Messrs. Bergman, Garnett, Skrgic, Jones and Ms. Gormley
received for services in all capacities to APS, APSC and the Subsidiaries is set
forth in the Summary Compensation Table for APS.
(d) These amounts as previously reported did not include the following amounts
representing the dollar value of the benefit to the executive officer of the
remainder of the premium paid on the Executive Life Insurance Plan: Mr. Pifer
$270; Mr. Henderson $174; Mr. Ault $191; and Mr. Burkley $280.
(e) The incentive plan was not in effect for these officers in 1991.
</TABLE>
<PAGE>
- 50 -
Summary Compensation Tables
AGC
Annual Compensation (a)
Name All Other
and Compen-
Principal sation
Position Year Salary($) Bonus($) ($)
(a) AGC has no paid employees.
<PAGE>
- 51 -
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE
Estimated
Name and Capacities Annual Benefits
Company in Which Served on Retirement (a)
APS (b)
Klaus Bergman, President* $235,270
and Chief Executive
Officer (c)
Stanley I. Garnett, II, 112,320
Vice President, Finance (c)
Peter J. Skrgic, 126,000
Vice President (c)
Kenneth M. Jones, 90,004
Vice President and
Comptroller (c)
Nancy H. Gormley, 78,404
Vice President (c)
Monongahela
Klaus Bergman, $
Chief Executive Officer (c)(d)
Benjamin H. Hayes, 113,364
President
Thomas A. Barlow, 70,788
Vice President
Robert R. Winter, 67,896
Vice President
Richard E. Myers, 67,200
Comptroller
* Elected Chairman of the Board effective January 1, 1994.
<PAGE>
- 52 -
Estimated
Name and Capacities Annual Benefits
Company in Which Served on Retirement (a)
Potomac Edison
Klaus Bergman, $
Chief Executive Officer (c)(d)
Alan J. Noia, 133,200
President
Robert B. Murdock, 80,677
Vice President
James D. Latimer, 75,298
Vice President
Thomas J. Kloc, 68,591
Comptroller
West Penn
Klaus Bergman, $
Chief Executive Officer (c)(d)
Jay S. Pifer, 111,463
President
Thomas K. Henderson, 73,127
Vice President
Charles S. Ault, 71,100
Vice President
Charles V. Burkley, 66,442
Comptroller
Allegheny
Generating Company
No paid employees.
<PAGE>
- 53 -
(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, 1993 the maximum amount of any employee's compensation
that may be used in these computations is $235,840. The maximum
amount will be reduced to $150,000 effective July 1, 1994 as a result of
The Omnibus Budget Reconciliation Act of 1993. 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. 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 1993, 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 of five 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, 1993 the maximum amount of any
employee's
compensation that may be used in these computations is $235,840. Effective
January 1, 1994, the amount was reduced to $150,000 as a result of The Omnibus
Budget Reconciliation Act of 1993. 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) The total estimated annual benefits on retirement payable to Mr. Bergman for
services in all capacities to APS, APSC and the Subsidiaries is set forth in
the table for APS.
Compensation of Directors
In 1993, 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.
<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 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 14, 1994. 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 other than the one shareholder shown below.
Executive Shares of
Officer or APS Percent
Name Director of Common Stock of Class
<S> <S> <C> <C>
Charles S. Ault WP 4,072 Less than .01%
Thomas A. Barlow MP 6,725 "
Eleanor Baum APS,MP,PE,WP 2,000 "
William L. Bennett APS,MP,PE,WP 2,362 "
Klaus Bergman APS,MP,PE,WP,AGC 9,519 "
Charles V. Burkley WP 2,134 "
Stanley I. Garnett, II APS,MP,PE,WP,AGC 3,940 "
Nancy H. Gormley APS, MP 5,001 "
Benjamin H. Hayes MP 5,082 "
Thomas K. Henderson WP 3,444 "
Kenneth M. Jones APS,AGC 3,996 "
Thomas J. Kloc PE,AGC 2,823 "
James D. Latimer PE 4,765 "
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 1,795 "
Clarence F. Michalis APS,MP,PE,WP 1,000 "
Robert B. Murdock PE 7,571 "
Richard E. Myers MP 3,899 "
Alan J. Noia PE 10,235 "
Jay S. Pifer WP 7,087 "
Steven H. Rice APS,MP,PE,WP 2,030 "
Gunnar E. Sarsten APS,MP,PE,WP 5,000 "
Peter L. Shea APS,MP,PE,WP 900 "
Peter J. Skrgic APS,MP,PE,WP,AGC 5,026 "
Robert R. Winter MP 2,997 "
Franklin Resources, Inc. 6,393,300 5.4%
777 Mariners Island Blvd.
San Mateo, CA 94404
All directors and executive officers
of APS as a group (17 persons) 53,030 Less than .06%
All directors and executive officers
of MP as a group (17 persons) 58,200 "
All directors and executive officers
of PE as a group (17 persons) 65,830 "
All directors and executive officers
of WP as a group (17 persons) 54,433 "
All directors and executive officers
of AGC as a group (6 persons) 27,354 "
All of the shares of common stock of Monongahela (5,891,000), Potomac Edison (22,385,000), and West Penn
(22,361,586) 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>
- 55 -
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 42.
(b) APS filed a report on Form 8-K on November 5, 1993 concerning the
two-for-one stock split. No other reports on Form 8-K were filed by
System companies during the quarter ended December 31, 1993.
(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>
Graphics Appendix
Page
System Map . . . . . . . . . . . . . . . . . . . . . . . 10
<PAGE>
- 56 -
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, President and
Chief Executive Officer)
Date: February 3, 1994
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 2/3/94
of the Board,
KLAUS BERGMAN President, Chief
(Klaus Bergman) Executive Officer,
and Director
(ii) Principal Financial Officer:
STANLEY I. GARNETT, II Vice President, 2/3/94
(Stanley I. Garnett, II) Finance
(iii) Principal Accounting Officer:
KENNETH M. JONES Vice President 2/3/94
(Kenneth M. Jones) and Comptroller
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Clarence F. Michalis
*Klaus Bergman *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Edward H. Malone *Peter L. Shea
*By: NANCY H. GORMLEY 2/3/94
(Nancy H. Gormley)
<PAGE>
- 57 -
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: BENJAMIN H. HAYES
(Benjamin H. Hayes,
President)
Date: February 3, 1994
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 2/3/94
of the Board,
KLAUS BERGMAN President, Chief
(Klaus Bergman) Executive Officer,
and Director
(ii) Principal Financial Officer:
CHARLES S. MULLETT Secretary and 2/3/94
(Charles S. Mullett) Treasurer
(iii) Principal Accounting Officer:
RICHARD E. MYERS Comptroller 2/3/94
(Richard E. Myers)
(iv) A Majority of the Directors:
*Eleanor Baum *Edward H. Malone
*William L. Bennett *Frank A. Metz, Jr.
*Klaus Bergman *Clarence F. Michalis
*Stanley I. Garnett, II *Steven H. Rice
*Benjamin H. Hayes *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Peter J. Skrgic
*By: NANCY H. GORMLEY 2/3/94
(Nancy H. Gormley)
<PAGE>
- 58 -
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: ALAN J. NOIA
(Alan J. Noia, President)
Date: February 3, 1994
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 2/3/94
of the Board,
KLAUS BERGMAN President, Chief
(Klaus Bergman) Executive Officer,
and Director
(ii) Principal Financial Officer:
DALE F. ZIMMERMAN Secretary and 2/3/94
(Dale F. Zimmerman) Treasurer
(iii) Principal Accounting Officer:
THOMAS J. KLOC Comptroller 2/3/94
(THOMAS J. KLOC)
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Clarence F. Michalis
*Klaus Bergman *Alan J. Noia
*Stanley I. Garnett, II *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Edward H. Malone *Peter L. Shea
*Peter J. Skrgic
*By: NANCY H. GORMLEY 2/3/94
(Nancy H. Gormley)
<PAGE>
- 59 -
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 3, 1994
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 2/3/94
of the Board,
KLAUS BERGMAN President, Chief
(Klaus Bergman) Executive Officer,
and Director
(ii) Principal Financial Officer:
KENNETH D. MOWL Secretary and 2/3/94
(Kenneth D. Mowl) Treasurer
(iii) Principal Accounting Officer:
CHARLES V. BURKLEY Comptroller 2/3/94
(Charles V. Burkley)
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Clarence F. Michalis
*Klaus Bergman *Jay S. Pifer
*Stanley I. Garnett, II *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Edward H. Malone *Peter L. Shea
*Peter J. Skrgic
*By: NANCY H. GORMLEY 2/3/94
(Nancy H. Gormley)
<PAGE>
- 60 -
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 3, 1994
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 2/3/94
of the Board,
KLAUS BERGMAN President, Chief
(Klaus Bergman) Executive Officer,
and Director
(ii) Principal Financial Officer:
NANCY L. CAMPBELL Treasurer and 2/3/94
(Nancy L. Campbell Assistant Secretary
(iii) Principal Accounting Officer:
THOMAS J. KLOC Comptroller 2/3/94
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Klaus Bergman
*Kenneth M. Jones
*Stanley I. Garnett, II
*Peter J. Skrgic
*By: NANCY H. GORMLEY 2/3/94
(Nancy H. Gormley)
<PAGE>
- 61 -
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 (No. 33-36716) 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 (No. 33-51303); of our reports
dated February 3, 1994 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
PRICE WATERHOUSE
New York, New York
March 11, 1994
<PAGE>
- 62 -
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, 1993 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 3, 1994
ELEANOR BAUM FRANK A. METZ, JR.
(Eleanor Baum) (Frank A. Metz, Jr.)
WILLIAM L. BENNETT CLARENCE F. MICHALIS
(William L. Bennett) (Clarence F. Michalis)
KLAUS BERGMAN STEVEN H. RICE
(Klaus Bergman) (Steven H. Rice)
PHILLIP E. LINT GUNNAR E. SARSTEN
(Phillip E. Lint) (Gunnar E. Sarsten)
EDWARD H. MALONE PETER L. SHEA
(Edward H. Malone) (Peter L. Shea)
<PAGE>
- 63 -
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned director of
The Potomac Edison Company, a Maryland and Virginia corporation, does
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, 1993
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 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 3, 1994
ALAN J. NOIA
(Alan J. Noia)
<PAGE>
- 64 -
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned director of
West Penn Power Company, a Pennsylvania corporation, does 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, 1993 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 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 3, 1994
JAY S. PIFER
(Jay S. Pifer)
<PAGE>
- 65 -
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned director of
Monongahela Power Company, an Ohio corporation, does 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, 1993 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 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 3, 1994
BENJAMIN H. HAYES
(Benjamin H. Hayes)
<PAGE>
- 66 -
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, 1993 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 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 3, 1994
KLAUS BERGMAN
(Klaus Bergman)
KENNETH M. JONES
(Kenneth M. Jones)
PETER J. SKRGIC
(Peter J. Skrgic)
<PAGE>
- 67 -
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned director of
Monongahela Power Company, an Ohio corporation, The Potomac Edison
Company, a Maryland and Virginia corporation, and West Penn Power
Company, a Pennsylvania corporation, does 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, 1993 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 3, 1994
PETER J. SKRGIC
(Peter J. Skrgic)
<PAGE>
E-1
EXHIBIT INDEX
(Rule 601(a))
Allegheny Power System, Inc.
Incorporation
Documents by Reference
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
11 Statement re computation of per share earnings:
Clearly determinable from the financial statements
contained in Item 8.
21 Subsidiaries of APS:
Name of Company State of Organization
Allegheny Generating Company (a) Virginia
Allegheny Power Service Corporation Maryland
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 61 herein.
24 Powers of Attorney See pages 62-67
herein.
<PAGE>
Exhibit 10.1
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
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.
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
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
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
-- 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.
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.
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.
Exhibit 10.4
ALLEGHENY POWER SYSTEM
SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN
(Effective July 1, 1990)
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.
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 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.
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
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.
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
(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.
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
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
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.
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:
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.
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)
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 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.
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.
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 as
set 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.
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.
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.
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>
E-2
Monongahela Power Company
Incorporation
Documents by Reference
3.1 Charter of the Company,
as amended Form S-3, 33-51301, exh.
4(a)
3.2 Code of Regulations, Form 10-Q of the Company
as amended (1-268-2), September
1993, exh. (a)(3)
4 Indenture, dated as S 2-5819, exh. 7(f)
of August 1, 1945, S 2-8782, exh. 7(f) (1)
and certain S 2-8881, exh. 7(b)
Supplemental S 2-9355, exh.4(h) (1)
Indentures of the S 2-9979, exh. 4(h)(1)
Company defining S 2-10548, exh. 4(b)
rights of security S 2-14763, exh. 2(b) (i)
holders.* 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.
12 Computation of ratio of earnings
to fixed charges
21 Subsidiaries: Monongahela Power Company has a
27% equity ownership in Allegheny Generating
Company, incorporated in Virginia; and a 25%
equity ownership in Allegheny Pittsburgh Coal
Company, incorporated in Pennsylvania.
23 Consent of Independent Accountants See page 61
herein.
24 Powers of Attorney See pages 62-67
herein.
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS
TO FIXED CHARGES
For Year Ended December 31, 1993
(Dollar Amounts in Thousands)
Monongahela The Potomac West Penn Allegheny
Power Edison Power Generating
Company Company Company Company
Earnings:
<S> <C> <C> <C> <C>
Net Income $ 61,698 $ 73,467 $102,061 $ 27,182
Fixed charges
(see below) 38,260 44,501 61,845 21,635
Income taxes 33,662 30,630 51,958 13,433
Total earnings $133,620 $148,598 $215,864 $ 62,250
Fixed Charges:
Interest on long-
term debt $ 35,555 $ 42,695 $ 58,857 $ 21,185
Other
interest 2,033 1,107 1,728 450
Estimated interest
component of
rentals 672 699 1,260 ---
Total fixed
charges $ 38,260 $ 44,501 $ 61,845 $ 21,635
Ratio of Earnings to
Fixed Charges: 3.49 3.34 3.49 2.88
</TABLE>
<PAGE>
E-3
The Potomac Edison Company
Incorporation
Documents by Reference
3.1 Charter of the Company, Form 10-Q of the Company
as amended (1-3376-2), September 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 (1-
Indentures of the 33-76-2) dated June 14, 1989,
Company defining rights June 25, 1990, August 21,
Company defining rights 1991, December 11, 1991,
of security holders* December 15, 1992, February
17, 1993 and March 30, 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.
12 Computation of ratio of earnings
to fixed charges
21 Subsidiaries: The Potomac Edison Company has a 28% equity
ownership in Allegheny Generating Company, incorporated in
Virginia and a 25% equity ownership in Allegheny Pittsburgh
Coal Company, incorporated in Pennsylvania.
23 Consent of Independent See page 61 herein.
Accountants
24 Powers of Attorney See pages 62-67 herein.
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS
TO FIXED CHARGES
For Year Ended December 31, 1993
(Dollar Amounts in Thousands)
Monongahela The Potomac West Penn Allegheny
Power Edison Power Generating
Company Company Company Company
Earnings:
<S> <C> <C> <C> <C>
Net Income $ 61,698 $ 73,467 $102,061 $ 27,182
Fixed charges
(see below) 38,260 44,501 61,845 21,635
Income taxes 33,662 30,630 51,958 13,433
Total earnings $133,620 $148,598 $215,864 $ 62,250
Fixed Charges:
Interest on long-
term debt $ 35,555 $ 42,695 $ 58,857 $ 21,185
Other
interest 2,033 1,107 1,728 450
Estimated interest
component of
rentals 672 699 1,260 ---
Total fixed
charges $ 38,260 $ 44,501 $ 61,845 $ 21,635
Ratio of Earnings to
Fixed Charges: 3.49 3.34 3.49 2.88
</TABLE>
<PAGE>
E-4
West Penn Power Company
Incorporation
Documents by Reference
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.
12 Computation of ratio of earnings
to fixed charges
21 Subsidiaries: West Penn Power Company has a 45% equity
ownership in Allegheny Generating Company, incorporated in
Virginia; a 50% equity ownership in Allegheny Pittsburgh
Coal Company, incorporated in Pennsylvania; and a 100%
equity ownership in West Virginia Power and Transmission
Company, incorporated in West Virginia, which owns a 100%
equity ownership in West Penn West Virginia Water Power
Company, incorporated in Pennsylvania.
23 Consent of Independent See page 61 herein.
Accountants
24 Powers of Attorney See pages 62-67 herein.
<PAGE>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS
TO FIXED CHARGES
For Year Ended December 31, 1993
(Dollar Amounts in Thousands)
Monongahela The Potomac West Penn Allegheny
Power Edison Power Generating
Company Company Company Company
Earnings:
<S> <C> <C> <C> <C>
Net Income $ 61,698 $ 73,467 $102,061 $ 27,182
Fixed charges
(see below) 38,260 44,501 61,845 21,635
Income taxes 33,662 30,630 51,958 13,433
Total earnings $133,620 $148,598 $215,864 $ 62,250
Fixed Charges:
Interest on long-
term debt $ 35,555 $ 42,695 $ 58,857 $ 21,185
Other
interest 2,033 1,107 1,728 450
Estimated interest
component of
rentals 672 699 1,260 ---
Total fixed
charges $ 38,260 $ 44,501 $ 61,845 $ 21,635
Ratio of Earnings to
Fixed Charges: 3.49 3.34 3.49 2.88
</TABLE>
<PAGE>
E-5
Allegheny Generating Company
Documents
3.1(a) Charter of the Company, as amended*
3.1(b) Certificate of Amendment to Charter, effective July 14,
1989.**
3.2 By-laws of the Company, as amended*
4 Indenture, dated as of December 1, 1986, and Supplemental
Indenture, dated as of December 15, 1988, of the Company
defining rights of security holders.***
10.1 APS Power Agreement-Bath County Pumped Storage Project,
as amended, dated as of August 14, 1981, among
Monongahela Power Company, West Penn Power Company, and
The Potomac Edison Company and Allegheny Generating
Company.*
10.2 Operating Agreement, dated as of June 17, 1981, among
Virginia Electric and Power Company, Allegheny Generating
Company, Monongahela Power Company, West Penn Power
Company and The Potomac Edison Company.*
10.3 Equity Agreement, dated June 17, 1981, between and among
Allegheny Generating Company, Monongahela Power Company,
West Penn Power Company and The Potomac Edison Company.*
10.4 United States of America Before The Federal Energy
Regulatory Commission, Allegheny Generating Company,
Docket No. ER84-504-000, Settlement Agreement effective
October 1, 1985.*
12 Computation of ratio of earnings
to fixed charges
23 Consent of Independent See page 61 herein.
Accountants
24 Powers of Attorney See pages 62-67 herein.
* 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>
<TABLE>
<CAPTION>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS
TO FIXED CHARGES
For Year Ended December 31, 1993
(Dollar Amounts in Thousands)
Monongahela The Potomac West Penn Allegheny
Power Edison Power Generating
Company Company Company Company
Earnings:
<S> <C> <C> <C> <C>
Net Income $ 61,698 $ 73,467 $102,061 $ 27,182
Fixed charges
(see below) 38,260 44,501 61,845 21,635
Income taxes 33,662 30,630 51,958 13,433
Total earnings $133,620 $148,598 $215,864 $ 62,250
Fixed Charges:
Interest on long-
term debt $ 35,555 $ 42,695 $ 58,857 $ 21,185
Other
interest 2,033 1,107 1,728 450
Estimated interest
component of
rentals 672 699 1,260 ---
Total fixed
charges $ 38,260 $ 44,501 $ 61,845 $ 21,635
Ratio of Earnings to
Fixed Charges: 3.49 3.34 3.49 2.88
</TABLE>
