<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1996
<TABLE>
<CAPTION>
Registrant; I.R.S. Employer
Commission State of Incorporation; Identification
File Number Address; and Telephone Number Number
<S> <C> <C>
1-267 ALLEGHENY POWER SYSTEM, INC. 13-5531602
(A Maryland Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400
1-5164 MONONGAHELA POWER COMPANY 13-5229392
(An Ohio Corporation)
1310 Fairmont Avenue
Fairmont, West Virginia 26554
Telephone (304) 366-3000
1-3376-2 THE POTOMAC EDISON COMPANY 13-5323955
(A Maryland and Virginia
Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400
1-255-2 WEST PENN POWER COMPANY 13-5480882
(A Pennsylvania Corporation)
800 Cabin Hill Drive
Greensburg, Pennsylvania 15601
Telephone (412) 837-3000
0-14688 ALLEGHENY GENERATING COMPANY 13-3079675
(A Virginia Corporation)
10435 Downsville Pike
Hagerstown, Maryland 21740-1766
Telephone (301) 790-3400
</TABLE>
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) have been subject to such filing
requirements for the past 90 days. Yes X No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrants' knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. [X]
<PAGE>
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
Name of each exchange
Registrant Title of each class on which registered
<S> <C> <C>
Allegheny Power System, Inc. Common Stock, New York Stock Exchange
$1.25 par value Chicago Stock Exchange
Pacific Stock Exchange
Amsterdam Stock Exchange
Monongahela Power Company Cumulative Preferred
Stock,
$100 par value;
4.40% American Stock Exchange
4.50%, Series C American Stock Exchange
8% Quarterly Income Debt
Securities, Junior
Subordinated Deferrable
Interest Debentures,
Series A New York Stock Exchange
The Potomac Edison Company Cumulative Preferred
Stock,
$100 par value:
3.60% Philadelphia Stock Exchange
Inc.
$5.88, Series C Philadelphia Stock Exchange
Inc.
8% Quarterly Income Debt
Securities, Junior
Subordinated Deferrable
Interest Debentures,
Series A New York Stock Exchange
West Penn Power Company Cumulative Preferred
Stock,
$100 par value:
4-1/2% New York Stock Exchange
8% Quarterly Income Debt
Securities, Junior
Subordinated Deferrable
Interest Debentures,
Series A New York Stock Exchange
</TABLE>
Securities registered pursuant to Section 12(g) of the Act:
Allegheny Generating Company Common Stock
$1.00 par value None
<PAGE>
<TABLE>
<CAPTION>
Aggregate market value Number of shares
of voting stock (common stock) of common stock
held by nonaffiliates of of the registrants
the registrants at outstanding at
March 6, 1997 March 6, 1997
<S> <C> <C>
Allegheny Power System, Inc. $3,731,360,014 121,840,327
($1.25 par value)
Monongahela Power Company None. (a) 5,891,000
($50 par value)
The Potomac Edison Company None. (a) 22,385,000
(no par value)
West Penn Power Company None. (a) 24,361,586
(no par value)
Allegheny Generating Company None. (b) 1,000
($1.00 par value)
</TABLE>
(a) All such common stock is held by Allegheny Power System, Inc., the
parent Company.
(b) All such common stock is held by its parents, Monongahela Power Company,
The Potomac Edison Company, and West Penn Power Company.
<PAGE>
<TABLE>
<CAPTION>
CONTENTS
PART I: Page
<S> <C> <C>
ITEM 1. Business 1
Competition 4
Restructuring 8
Sales 9
Electric Facilities 15
Allegheny Power Map 18
Research and Development 20
Capital Requirements and Financing 21
Fuel Supply 25
Rate Matters 26
Environmental Matters 27
Air Standards 27
Water Standards 30
Hazardous and Solid Wastes 31
Regulation 32
ITEM 2. Properties 34
ITEM 3. Legal Proceedings 34
ITEM 4. Submission of Matters to a Vote of Security
Holders 38
Executive Officers of the Registrants 39
PART II:
ITEM 5. Market for the Registrants' Common Equity
and Related Stockholder Matters 41
ITEM 6. Selected Financial Data 42
ITEM 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations 43
ITEM 8. Financial Statements and Supplementary Data 44
ITEM 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 51
<PAGE>
CONTENTS (Cont'd)
Page
PART III:
ITEM 10. Directors and Executive Officers of the Registrants 51
ITEM 11. Executive Compensation 52
ITEM 12. Security Ownership of Certain Beneficial Owners
and Management 56
ITEM 13. Certain Relationships and Related Transactions 57
PART IV:
ITEM 14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K 58
</TABLE>
<PAGE>
THIS COMBINED FORM 10-K IS SEPARATELY FILED BY ALLEGHENY POWER SYSTEM,
INC., MONONGAHELA POWER COMPANY, THE POTOMAC EDISON COMPANY, WEST PENN
POWER COMPANY, AND ALLEGHENY GENERATING COMPANY. INFORMATION CONTAINED
HEREIN RELATING TO ANY INDIVIDUAL REGISTRANT IS FILED BY SUCH REGISTRANT
ON ITS OWN BEHALF. EACH REGISTRANT MAKES NO REPRESENTATION AS TO
INFORMATION RELATING TO THE OTHER REGISTRANTS.
PART I
ITEM 1. BUSINESS
Allegheny Power System, Inc. (APS), incorporated in Maryland in
1925, is an electric utility holding company which owns directly and
indirectly various regulated subsidiaries (collectively, Allegheny
Power), and a nonutility subsidiary, AYP Capital, Inc. (AYP Capital).
APS derives substantially all of its income from the electric utility
operations of its direct and indirect subsidiaries, Monongahela Power
Company (Monongahela), The Potomac Edison Company (Potomac Edison), West
Penn Power Company (West Penn), and Allegheny Generating Company (AGC)
(collectively, the Subsidiaries). The properties of the Subsidiaries
are located in Maryland, Ohio, Pennsylvania, Virginia, and West
Virginia, are interconnected, and are operated as a single integrated
electric utility system (System), which is interconnected with all
neighboring utility systems. The three electric utility operating
subsidiaries are Monongahela, Potomac Edison, and West Penn
(collectively, the Operating Subsidiaries). APS has no employees. Its
officers are employed by Allegheny Power Service Corporation (APSC), a
wholly owned subsidiary of APS. On December 31, 1996, Allegheny Power
had approximately 5,100 employees. In 1996 APS, APSC and the Operating
Subsidiaries began doing business under the common business name
"Allegheny Power." In June 1996, the corporate headquarters of
Allegheny Power moved from New York City to Washington County, Maryland.
The move situated Allegheny Power's headquarters in the service
territory of the 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 350,100 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, 1996, Monongahela had 1,534
employees. Most employees have been or will be transferred to APSC in
1997 as part of the final phase of a restructuring of operations which
began in 1996. Monongahela's service area has navigable waterways and
substantial deposits of bituminous coal, glass sand, natural gas, rock
salt, and other natural resources. Its service area's principal
industries produce coal, chemicals, iron and steel, fabricated products,
wood products, and glass. There are two municipal electric distribution
systems and two rural electric cooperative associations in its service
area. Except for one of the cooperatives, they purchase all of their
power from Monongahela.
<PAGE> - 2 -
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 375,400 customers in a service area of about 7,300 square miles
with a population of about 782,000. The six largest communities served
have populations ranging from 11,900 to 40,100. On December 31, 1996,
Potomac Edison had 790 employees. Most employees have been or will be
transferred to APSC in 1997 as part of the final phase of a
restructuring of operations which began in 1996. Potomac Edison's
service area's principal industries produce aluminum, cement, fabricated
products, rubber products, sand, stone, and gravel. There are four
municipal electric distribution systems in its service area, all of
which purchase power from Potomac Edison, and six rural electric
cooperatives, one of which purchases power from Potomac Edison.
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 662,900
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, 1996, West
Penn had 1,625 employees. Most employees have been or will be
transferred to APSC in 1997 as part of the final phase of a
restructuring of operations which began in 1996. West Penn's service
area has navigable waterways and substantial deposits of bituminous
coal, limestone, and other natural resources. Its service area's
principal industries produce steel, coal, fabricated products, and
glass. There are three municipal electric distribution systems in its
service area, all of which purchase their power requirements from West
Penn, and five rural electric cooperative associations, located partly
within the area, all of which purchase virtually their power through a
pool supplied by West Penn and other nonaffiliated utilities.
AGC, organized in 1981 under the laws of Virginia, is jointly
owned by the Operating Subsidiaries as follows: Monongahela, 27%;
Potomac Edison, 28%; and West Penn, 45%. AGC has no employees, and its
only asset is a 40% undivided interest in the Bath County (Virginia)
pumped-storage hydroelectric station, which was placed in commercial
operation in December 1985, and its connecting transmission facilities.
AGC's 840-megawatt (MW) share of capacity of the station is sold to its
three parents. The remaining 60% interest in the Bath County Station is
owned by Virginia Electric and Power Company (Virginia Power).
APSC, incorporated in Maryland in 1963, is a wholly owned
subsidiary of APS which provides various technical, engineering,
accounting, administrative, purchasing, computing, managerial,
operational, and legal services to the Subsidiaries and to AYP Capital and its
subsidiaries at cost. On December 31, 1996, APSC had 1,171 employees. This
number will increase in 1997, as employees formerly employed by the Operating
Subsidiaries are transferred to APSC as part of a restructuring of operations.
(See ITEM I. RESTRUCTURING for a further discussion of the restructuring.)
<PAGE> - 3 -
AYP Capital, incorporated in Delaware in 1994, is a wholly owned
nonutility subsidiary of APS which was formed in an effort to meet the
challenges of the new competitive environment in the industry. AYP
Capital has two wholly owned subsidiaries, AYP Energy, Inc. (AYP Energy)
and Allegheny Communications Connect, Inc., (ACC) both Delaware
corporations. AYP Energy is an exempt wholesale generator and a power
marketer. AYP Energy owns a 50% interest (276 MW) in Unit No. 1 of the
Fort Martin Power Station which it purchased in 1996 for approximately
$170 million. ACC is an exempt telecommunications company. AYP Capital
is also part owner of APS Cogenex, a limited liability company formed
with EUA Cogenex. APS Cogenex ceased its marketing activities in 1996
and is concluding existing projects. (See ITEM 1. COMPETITION for a
further description of AYP Capital and its subsidiaries' activities.)
AYP Capital and its subsidiaries have no employees. However, as of
December 31, 1996, 16 APSC employees were dedicated to AYP Capital and
its subsidiaries' activities on a full-time basis. Other APSC employees
provide services to AYP Capital as required. AYP Capital reimburses
APSC for the use of its employees. APS' total investment in AYP Capital
as of December 31, 1996, was $27.8 million. APS is currently committed
to invest up to an additional $6.9 million in AYP Capital to fund AYP
Capital's investment in two limited partnerships.
Allegheny Power has in the past and may in the future experience
some of the more significant problems and challenges common to electric
utilities in general. These include the effect on Allegheny Power of:
legislation and proposals to restructure and to deregulate portions of
the industry and to increase competition; the potential adverse effect
of increased competition on revenues and earnings; increases in
operating and other expenses; difficulties in obtaining adequate and
timely rate relief (particularly as ratemaking methodologies change as
the industry moves toward increased competition and exposure to market
forces); and restrictions on construction and operation of facilities
due to regulatory requirements and environmental and health
considerations. These include the requirements of the Clean Air Act
Amendments of 1990 (CAAA), which among other things, require a
substantial annual reduction in emissions of sulfur dioxides (SO2) and
nitrogen oxides (NOx), and other state and federal Clean Air
initiatives.
Further concerns of the industry include possible restrictions
on carbon dioxide and NOx emissions, uncertainties in demand due to
economic conditions, energy conservation, market competition, weather,
and interruptions in fuel supply. The move to a more competitive
environment will present a new set of opportunities and problems,
including determining the appropriate industry structure, determining
recovery of stranded costs (those costs imposed or incurred under a
regulatory structure that would not be recoverable in a competitive
environment), retaining existing customers and acquiring new customers,
and in general changing the way electric utilities do business.
<PAGE> - 4 -
COMPETITION
Competitive forces within the electric utility industry
continued to increase in 1996. In Pennsylvania, Allegheny Power's
largest service territory, legislation enacted in 1996 moved that state
toward retail competition for electric utility customers. The
legislation will phase-in competition over three years by offering
retail choice to one-third of each electric utility's customers each
year starting in 1999. Difficult questions including stranded cost
recovery, responsibility for service and service reliability, the
obligation to serve, recovery of environmental and other social costs,
tax implications, and the effect of competition on all classes of
customers are being investigated in Maryland, Ohio, Virginia and West
Virginia, as well as at the federal level. Federal legislation to
restructure the industry was introduced by several members of Congress
in 1996 and has been reintroduced in 1997. In response to the
competitive environment that has been evolving, Allegheny Power has
developed, and is continuing to develop, a number of strategies to
retain and continue to serve its existing customers and to expand its
customer base.
On December 3, 1996, Pennsylvania enacted a new chapter to the
Public Utility Code to restructure its electric utility industry in
order to create retail access to a competitive market for the generation
of electricity. The legislation reflects many of the recommendations
made in a July 1996 Pennsylvania Public Utility Commission (PUC) order
which resulted from the PUC's investigation into electric power
competition. The legislation became effective on January 1, 1997 and
includes the following major provisions:
All electric utilities in Pennsylvania are required to
file, beginning on April 1, 1997, and in no event later than
September 30, 1997, a restructuring plan to implement direct
access to a competitive market for electric generation. The
plan must include unbundled rates for generation, juris-
dictional transmission, distribution and other services; a
proposed mechanism for recovery of stranded costs; a proposed
universal service and energy conservation cost recovery
mechanism; procedures for ensuring direct access to all
licensed energy suppliers; a discussion of the proposed plan's
effects on utility employees; and revised tariffs and rates
implementing the foregoing.
Retail customer choice will be phased in as follows: up
to 33% of all customer load on January 1, 1999; up to 66% of
all customer load in all customer classes on January 1, 2000;
and 100% of all customer load by January 1, 2001. The PUC
can delay this schedule by two six-month periods, if necessary.
Electric distribution companies will continue to be the
suppliers of last resort. The PUC will ensure that adequate
generation reserves exist to maintain reliable electric
<PAGE> - 5 -
service. A utility's transmission and distribution system
must continue to meet established national industry standards
for installation, maintenance, and safety.
Retail rates will be capped for at least 4-1/2 years for
transmission and distribution charges and for as long as 9
years for generation charges. A utility may be exempted from
the caps only under very specific circumstances, e.g.,
nonutility generation contracts, changes in laws or regula-
tions, required upgrades or repairs to the transmission
system, increases in fuel prices or purchased power prices,
nuclear power plant decommissioning costs, or taxes.
Pennsylvania utilities are permitted to recover
PUC-approved transition or stranded costs over several years;
however, the utilities are required to mitigate these costs
to the extent practicable. The recovery of these costs is not
to result in cost shifting among customers. Financing of such
costs through securitization is also permitted.
All generation suppliers must demonstrate financial and
technical fitness and must be licensed by the PUC.
Cooperatives and municipalities may participate in retail
competition but are not subject to the provisions of the
legislation unless they elect to serve customers outside their
franchised territories.
State tax revenues paid by utilities and generation
suppliers are to remain at their current level to protect
against any state revenue loss from restructuring.
The PUC will monitor electricity markets for anti-
competitive or discriminatory conduct, and will consider the
effect of mergers and acquisitions on these markets.
Allegheny Power is currently evaluating the new legislation to
formulate its plan to implement direct retail customer access to a
competitive generation services market. Allegheny Power cannot predict
what the ultimate effect will be of this legislation. As required by
the legislation, West Penn will file its restructuring plan on June 1,
1997. In addition, in 1997 West Penn will implement a Retail Customer
Choice Pilot Program for up to 5% of the peak load of its customers.
This will result in customers with as much as 165 MW of Allegheny
Power's Pennsylvania retail load being eligible to choose an alternate
supplier of generation. Allegheny Power, on the other hand, anticipates
the opportunity to offer capacity and/or energy to a similar portion of
the load of the other Pennsylvania utilities.
As a result of the Pennsylvania competition legislation, West
Penn's rates, including its energy cost rates, have been capped
effective January 1, 1997. The legislation did not eliminate the energy
<PAGE> - 6 -
cost tracking procedure and left to Pennsylvania PUC discretion the
method of future rate adjustments for energy costs.
On December 12, 1996, the Public Service Commission of West
Virginia issued an order initiating a general investigation for the
purpose of seeking comments and information regarding the restructuring
of the regulated electric utility industry, establishment of competition
in power supply markets, and establishment of retail wheeling and intra-
state open access of jurisdictional power distribution systems. Public
hearings are scheduled to begin on April 1, 1997.
In September 1995, the Virginia State Corporation Commission
(SCC) began an investigation to review its policy regarding
restructuring of and competition in the electric industry. On November
12, 1996, the SCC ordered further investigation into restructuring of
the industry, requiring the three largest electric utilities in
Virginia, including Potomac Edison, to file competition information by
March 31, 1997.
On October 9, 1996, the Maryland Public Service Commission
issued an order directing its Staff to evaluate the current state of the
electric industry and to submit a report to the Commission by May 31,
1997. The four major Maryland electric utilities, including Potomac
Edison, are to present unbundled cost studies and model retail service
tariffs, among other things, by August 1, 1997.
The Public Utilities Commission of Ohio (Ohio PUC) has initiated
informal roundtable discussions on issues concerning competition in the
electric utility industry and promoting increased competitive options
for Ohio businesses. The meetings have resulted in sets of guidelines
on interruptible rates and conjunctive service pilot programs which have
been adopted by the Ohio PUC.
On average, the Operating Subsidiaries' rates compare favorably
with those of potential alternate suppliers who use cost-based pricing.
However, the Operating Subsidiaries face increased competition from
utilities with excess generation that may be willing to sell at prices
lower than the sum of their actual fixed and variable costs or from
marketers acting as resellers of the same low-priced generation. At the
same time, the Operating Subsidiaries have experienced increased costs
due to compliance with the CAAA and purchases from PURPA projects. (See
page 14 for a discussion of PURPA projects, and ITEM 3. LEGAL
PROCEEDINGS for a description of litigation and regulatory proceedings
concerning PURPA capacity.)
Fully meeting challenges in the emerging competitive environment
will be difficult for Allegheny Power unless certain outmoded and anti-
competitive laws, specifically the Public Utility Holding Company Act of
1935 (PUHCA) and Section 210 of the Public Utility Regulatory Policies
Act of 1978 (PURPA), are repealed or significantly revised.
<PAGE> - 7 -
Allegheny Power, along with the other electric public utility
holding companies under PUHCA, advocates repeal of PUHCA. PUHCA
prevents or significantly disadvantages regulated holding companies from
diversifying into utility-related or nonutility businesses within or
outside their service territories, except under limited circumstances.
Exempt companies as well as other competitors, on the other hand, can
diversify into other types of businesses with generally no greater
limitations than any other domestic company. In the past, legislation
has been introduced in Congress to repeal PUHCA and grant utility
oversight responsibility to the Federal Energy Regulatory Commission
(FERC). The Securities and Exchange Commission (SEC) has also
recommended repeal of PUHCA. If the problems with PUHCA are not
resolved through legislation, restructuring of Allegheny Power to reduce
or eliminate the effect of PUHCA on its operations is an alternative.
Allegheny Power continues to advocate repeal of PURPA and in
1996 worked with other utilities seeking PURPA repeal or reform of
Section 210 on the grounds that it is obsolete, anticompetitive, and it
results in utility customers paying above-market prices for power. (See
ITEM 3. LEGAL PROCEEDINGS for information concerning PURPA-related
litigation.)
Allegheny Power joined with seven other electric utilities in
1996 to form the Partnership for Customer Choice whose purpose is to
seek enactment of federal legislation to bring choice to electric
customers no later than the year 2000. The legislation sought would
deregulate the generation of electric power, creating a free market for
electricity.
To help meet the challenges of the new competitive environment,
AYP Capital was formed in 1994. Its purpose is to pursue and develop
new opportunities in unregulated markets and to strengthen the long-term
competitiveness and profitability of Allegheny Power. During 1996 AYP
Capital made several investments in funds which were established in
1995. They include an investment in EnviroTech Investment Fund I, L.P.
(EnviroTech), a limited partnership formed to invest in emerging
electrotechnologies that promote the efficient use of electricity and
improve the environment. AYP Capital has committed to invest up to $5
million in EnviroTech over ten years, beginning in 1995. They also
include an investment in the Latin American Energy and Electricity Fund
I, L.P. (FONDELEC), a limited partnership formed to invest in and
develop electric energy opportunities in Latin America. AYP Capital has
committed to invest up to $5 million in FONDELEC over eight years,
beginning in 1995. Through FONDELEC, AYP Capital has invested in
electric distribution companies in Peru and Argentina. Both EnviroTech
and FONDELEC may offer AYP Capital opportunities to identify investments
in which AYP Capital may coinvest, in excess of its capital commitment
in each limited partnership.
AYP Capital is also developing other energy-related service
businesses. AYP Capital offers engineering consulting services and
project management for transmission and distribution facilities. APS
<PAGE> - 8 -
Cogenex, a limited liability company formed jointly with EUA Cogenex to
offer certain energy-related services, ceased marketing activities in
1996 but will conclude existing projects.
AYP Energy, a wholly owned subsidiary of AYP Capital, moved into
the wholesale unregulated power generation market with its purchase of
Duquesne Light Company's (Duquesne) 50% interest in Unit No. 1 of the
Fort Martin Power Station. AYP Energy is an exempt wholesale generator
and a certified power marketer. AYP Energy is marketing the output of
its 50% interest in Unit No. 1 of Fort Martin, as well as engaging in
other power marketing activities. The operation of a merchant plant and
power marketing in the wholesale market is essentially participation in
a commodity market, which creates certain risk exposures. AYP Energy
expects to use exchange-traded and over-the-counter futures, options,
and swap contracts both to hedge its exposure to changes in electric
power prices, and for trading purposes. The risks to which AYP Energy
is exposed include underlying price volatility, credit risk and
variation in cash flows, among others. To manage these risks,
Allegheny Power has implemented risk management policies and procedures,
consistent with industry practice and its goals.
Allegheny Communications Connect (ACC) was formed in 1996 as an
exempt telecommunications company under PUHCA. ACC's purpose is to
develop unregulated opportunities in the deregulated communications
market.
In addition to utilizing AYP Capital and its subsidiaries,
management continues to explore methods of marketing and pricing
electric energy in new and competitive ways, such as bulk sales of each
type of service to nonaffiliates, innovative pricing to traditional
utility customers, and repackaging of services in nontraditional ways.
Management is also attempting to reduce costs to make Allegheny Power
more competitive.
RESTRUCTURING
In 1995, Allegheny Power announced its intention to undertake a
restructuring designed to consolidate and reengineer its operations to
better meet the competitive challenges of the changing electric utility
industry and remain the energy supplier of choice in the future for its
customers. In 1996, Allegheny Power essentially completed restructuring
of its operations. The benefits Allegheny Power has realized from
restructuring include increased efficiencies and synergies due to the
elimination of layers of management and the combination of previously
duplicated functions.
In general, the restructuring of Allegheny Power consolidated in
APSC certain functions which previously were either performed separately
by employees of each of the three Operating Subsidiaries, or by
employees of the three Operating Subsidiaries along with employees of
APSC. Allegheny Power and AYP Capital have been restructured into the
<PAGE> - 9 -
following revenue-generating business units: Operating Business Unit;
Retail Marketing Business Unit; Generation Business Unit; Transmission
Business Unit; and AYP Capital and its subsidiaries. Support business
units which provide services to these revenue-generating business units
have also been formed. The restructuring of Allegheny Power did not
involve the formation of any new legal entities, nor did it require the
writedown of any rate base assets. Moreover, no capital assets were
transferred within Allegheny Power in connection with the restructuring.
Most of the functions which were performed exclusively by the
Operating Subsidiaries have been restructured into the Operating
Business Unit and Retail Marketing Business Unit. Most of the functions
performed by the Bulk Power Supply section of APSC were restructured
into the distinct generating, transmission, and planning and compliance
business units. The support functions were restructured in order to
supply services to the above with greater efficiency.
Most employees who have left service as a result of
restructuring were offered a voluntary separation plan which included
continuation of salary and certain benefits for up to eighteen months,
job counseling and outplacement assistance, and in some cases an early
retirement enhancement was offered. Allegheny Power anticipates that
future reductions in force will occur due to normal attrition.
SALES
In 1996, consolidated kilowatt-hour (kWh) sales to regular
customers (retail and wholesale power) increased 1.9% from those of 1995
as a result of increases of 2.5%, 2.1%, and .6% in residential,
commercial, and industrial sales, respectively. The increased kWh sales
in 1996 reflect both growth in number of customers for all classes and
an increase in residential and commercial use. Consolidated revenues
from residential sales increased .5%. Consolidated revenues from
commercial and industrial sales decreased .2% and 2.25%, respectively,
primarily due to decreases in fuel and energy recovery revenues which
have little effect on net income. (See ITEM 1. RATE MATTERS and ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.)
Bulk power transaction revenues, primarily with nonaffiliated
utilities and power marketers, increased 30%. These revenues have
little effect on net income as most profit therefrom is passed through
to retail customers.
Allegheny Power's all-time peak load of 7500 MW occurred on
February 5, 1996. The peak load in 1995 was 7280 MW.
Consolidated regulated electric operating revenues for 1996 were
derived as follows: Pennsylvania, 44.9%; West Virginia, 27.9%; Maryland,
19.2%; Virginia, 6.0%; Ohio, 2.0% (residential, 40.1%; commercial,
21.2%; industrial, 32.3%; bulk power transactions, 3.2%; and other,
<PAGE> - 10 -
3.2%). The following percentages of such revenues were derived from
these industries: iron and steel, 6.8%; fabricated products, 1.8%;
chemicals, 3.5%; aluminum and other nonferrous metals, 3.4%; coal mines,
3.4%; cement, 2.5%; and all other industries, 11.0%.
During 1996, Monongahela's kWh sales to retail customers
decreased .4%. Residential and commercial sales increased .3% and 2.0%,
respectively, but industrial sales decreased 1.8%. Revenues from
residential, commercial and industrial customers decreased 1.4%, 2.3%,
and 5.4%, respectively, primarily due to a reduction in the fuel and
energy cost component. Revenues from bulk power transactions and sales
to affiliates increased 6.5%. Monongahela's revenues represented 24.0%
of Allegheny Power's total sales to regular customers. Monongahela's
all-time peak load of 1825 MW occurred on August 17, 1995.
Monongahela's electric operating revenues were derived as
follows: West Virginia, 92.9% and Ohio, 7.1% (residential, 32.6%;
commercial, 19.2%; industrial, 31.8%; bulk power transactions, 2.7%; and
other, 13.7%).
During 1996, Potomac Edison's kWh sales to retail customers
increased 3.1% as a result of increases of 5.1%, 3.4%, and 1.5% in
residential, commercial, and industrial sales, respectively. Revenues
from residential and commercial customers increased 2.3% and .9%,
respectively. Revenues from industrial customers decreased 2.0% due to
a reduction in the fuel and energy cost component. Revenues from bulk
power transactions and sales to affiliates increased 22.8%. Potomac
Edison's revenues represented 31.1% of Allegheny Power's total sales to
regular customers. Potomac Edison's all-time peak load of 2614 MW
occurred on January 17, 1997.
Potomac Edison's electric operating revenues were derived as
follows: Maryland, 62.0%; West Virginia 18.9% and Virginia, 19.1%;
(residential, 44.6%; commercial, 20.1%; industrial, 27.1%; bulk power
transactions, 3.4%; and other, 4.8%). Revenues from one industrial
customer, the Eastalco aluminum reduction plant near Frederick,
Maryland, amounted to $64 million (8.8% of total electric operating
revenues). Minimum annual charges to Eastalco under an electric service
agreement which continues through March 31, 2000, with automatic
extensions thereafter unless terminated on notice by either party, were
$20.3 million in 1996. This 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 1996, West Penn's kWh sales to retail customers increased
1.5% as a result of increases of 1.6%, 1.4% and 1.5% in residential,
commercial, and industrial sales, respectively. Revenues from
residential and commercial customers increased .2% and .2%,
respectively. Revenues from industrial customers decreased .5% due to a
reduction in the fuel and energy cost component. Revenues from bulk
power transactions and sales to affiliates increased 10.7%. West Penn's
revenues represented 44.9% of Allegheny Power's total sales to regular
<PAGE> - 11 -
customers. West Penn's all-time peak load of 3242 MW occurred on
February 5, 1996.
West Penn's electric operating revenues were derived as follows:
Pennsylvania, 100% (residential, 36.9%; commercial, 20.6%; industrial,
32.6%; bulk power transactions, 3.0%; and other, 6.9%).
In 1996, AYP Energy provided 109,229 MWH of energy to
nonaffiliated customers, including generation from the Fort Martin Unit
No. 1 acquisition amounting to 44,014 MWH. Unregulated operating
revenues in 1996 amounted to $.7 million.
In 1996, the Operating Subsidiaries provided approximately 1
billion kWh of energy to nonaffiliated companies and marketers from
generation facilities operated by the Subsidiaries. Revenues from those
sales of generation from the Operating Subsidiaries were approximately
$22.4 million.
The Operating Subsidiaries transmitted approximately 17.4
billion kWh to others located outside their service territories under
various forms of transmission service agreements. Revenues from those
sales of service approximated $52.4 million.
Sales of generation and transmission services to others vary
with the needs of those companies for capacity and/or economic
replacement power; the availability of generating facilities and excess
power, fuel, and regional transmission facilities; and the availability
and price of competitive sources of power. Although increases occurred
in sales of transmission services to others in 1996, sales of power
generated by the Operating Subsidiaries did not change appreciably
relative to 1995 primarily because of stagnant demand, increases in
Allegheny Power's native load, and increased number of and willingness
of other suppliers to make sales at lower prices. Decreases in sales by
Allegheny Power of power generated from rate base assets to
nonaffiliates and others are expected in 1997 and beyond. For 1996,
substantially all of the benefits of power and transmission service
sales to nonaffiliates by the Operating Subsidiaries were passed on to
retail customers and as a result have little effect on net income.
Pursuant to a peak diversity exchange arrangement with Virginia
Power, the Operating Subsidiaries annually supply Virginia Power with
200 MW during each June, July, and August and in return Virginia Power
supplies the Operating Subsidiaries with 200 MW during each December,
January, and February, at least through February 2000. 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. Negotiations are
currently under way to reach an agreement on an amount of diversity
exchange beyond February 2000. The total number of megawatt-hours (MWh)
to be delivered by each utility to the other over the term of the
arrangement is expected to be the same.
<PAGE> - 12 -
Pursuant to an exchange arrangement with Duquesne which will
continue through February 2000 and may be extended beyond that date, the
Operating Subsidiaries supply Duquesne with up to 200 MW for a specified
number of weeks, generally during each March, April, May, September,
October, and November. In return, Duquesne supplies the Operating
Subsidiaries with up to 100 MW, generally during each December, January,
and February. The total number of MWh to be delivered by each utility
to the other over the term of the arrangement is expected to be the
same.
Until March 16, 1996, West Penn supplied retail electric service
to the Borough of Tarentum (Tarentum) using in part distribution
facilities leased from Tarentum under a 30-year lease agreement which
terminated in 1996. In June 1993, Tarentum notified West Penn of its
intention to exercise its option to end the lease agreement and re-enter
the retail electric business. The termination of the lease agreement
and resulting transfer and sale by West Penn of electric facilities
installed by West Penn resulted in Tarentum becoming a municipal
customer which at present purchases electricity on a wholesale basis
from West Penn under a new 3-year contract. In 1996 Tarentum provided a
load of 6.5 MW and revenues of $1.1 million.
The Energy Policy Act of 1992 (EPACT) permits wholesale
generators, utility-owned and otherwise, and wholesale consumers to
request from owners of bulk power transmission facilities a commitment
to supply transmission services. Of particular significance to public
utilities, on April 24, 1996, the FERC issued its Orders 888 and 889.
These Orders will lead to a fundamental restructuring of the business of
transmitting wholesale electric power and could potentially influence
the future of retail electric sales as well. The FERC's stated
objective is to stimulate wholesale (sale for resale) generation service
competition among electric utilities and nonregulated electricity
generators while preventing anti-competitive or discriminatory
transmission practices. The Orders encourage wholesale competition by
requiring utilities that own transmission systems and are under the
FERC's jurisdiction to file nondiscriminatory, open access transmission
tariffs available to all wholesale buyers and sellers of electricity and
apply those open access tariffs to their own wholesale purchases and
sales of electricity. Utilities must allow their transmission
facilities to be used by sellers or buyers of wholesale power without
undue discrimination, as long as sufficient transmission capacity is
available to provide service without impairing reliability. When
existing facility capacity is insufficient, transmission system owners
are required to attempt to build additional facilities when customers
are willing to support the cost of those facilities.
To meet the objective of providing nondiscriminatory or
comparable wholesale transmission services, the Orders require that
utilities functionally unbundle transmission operations from wholesale
merchant functions. In addition, separate rates must be presented for
wholesale generation, transmission and ancillary services. Accordingly,
as of January 3, 1997, the FERC required separation of the transmission
<PAGE> - 13 -
operations and marketing functions from the wholesale generation
marketing function of public utilities. In response to both the process
leading up to the FERC's adoption of Orders 888 and 889, and the
continuing evolution of the wholesale power and transmission service
markets, Allegheny Power in 1996 established separate business units to
operate and manage its generation and transmission assets.
Effective July 9, 1996, the FERC required that wholesale
transmission services be purchased by a transmission owner under that
owner's filed open access tariffs whenever a generation affiliate of the
owner intends to make wholesale generation service sales to any party.
In addition, the Orders set standard terms which must be contained in
each transmission provider's open access tariffs. Effectively, the
tariffs contractually open the interconnected transmission network to
provide comparable transmission service for use by the transmission
owner, its affiliates and non-affiliates alike. Order 888 also states
that electric utilities should be able to collect stranded costs that
may result from restructuring of the wholesale electric industry. In
addition, the Order provides that it is up to each state to decide if
retail wheeling should be adopted and, if so, to address retail stranded
costs. In a separate notice, the FERC proposed the development of a
standardized, real-time electronic information network to provide all
potential users of a utility's transmission system equal access to
information regarding transmission capability and pricing and in Order
889 directed implementation of such a network. Although Allegheny Power
has taken appropriate steps to comply, it has also requested rehearing
of certain aspects of both Orders. Allegheny Power cannot predict what
action the FERC may take on this request.
Effective in 1995 and consistent with the intentions of the FERC
prior to its issuance of Orders 888 and 889, Allegheny Power submitted a
filing to the FERC of a set of two new transmission service tariffs
which qualified as open access filings. The FERC then accepted for
filing a Network Transmission Service Tariff and a Point-to-Point
Transmission Service Tariff under which the Operating Subsidiaries began
to sell comparable open access transmission services to eligible
wholesale customers as of December 1995. The tariffs were accepted by
the FERC, subject to modification pending the outcome of the proceeding.
The FERC set the tariffs for hearing during the summer of 1996. In the
interim, the Operating Subsidiaries sold transmission services under the
tariffs, subject to refund. Refunds, if any, are not expected to be
material. With that filing, the need for and applicability of the
Standard Transmission Service Tariff was eliminated for new service
transactions.
With the issuance of Orders 888 and 889, the FERC mandated that
most transmission owning entities (the major exclusion was tight power
pools) had to issue or reissue open access transmission service tariffs
which complied with the rules by July 9, 1996. Allegheny Power did so
and the immediate effect was that its 1995 open access tariff filings
became subsumed by the July filing of one all-encompassing tariff.
However, the rates terms and conditions previously set for hearing were
<PAGE> - 14 -
carried over to the new tariff. In January 1997, the tariffs were again
modified to strictly comply with current FERC orders on non-rate terms
and conditions. Allegheny Power still awaits an order on rates for the
open access tariff.
In addition, the Operating Subsidiaries have a Standard
Generation Service Schedule (SGS) tariff on file with and accepted by
the FERC under which the Operating Subsidiaries previously made
available bundled, nonfirm generation services with associated
transmission services to any customer who executed an agreement under
such tariff. Recently and in keeping with the unbundled service
prescription of the FERC Orders, the SGS tariff has been amended to
separate the provision of generation and transmission services.
Customers in search of delivered wholesale power service from Allegheny
Power now have to separately contract for generation and transmission
services under the SGS and the Open Access Tariffs.
Similarly, as of December 1996, Allegheny Power filed to
unbundle generation and transmission services sold under existing
coordination agreements with contiguous public utilities.
Specifically in Order 889, the FERC established that an Open
Access Same Time Information System (OASIS) and Standards of Conduct
must be adopted by each transmission provider to ensure the separation
of service directed by the functional unbundling of wholesale services
required by Order 888 and to assure that all buyers and sellers of
transmission services will have equal and timely access to the
information needed to transact business. Allegheny Power adopted and
filed Standards of Conduct and joined with other transmission service
providers in a collaborative effort to develop OASIS capability. OASIS
became operational for processing requests for transmission services as
of January 3, 1997; the Standards of Conduct were implemented on the
same day.
Allegheny Power founded and continues to participate in, along
with other utilities, an organization, General Agreement on Parallel
Paths (GAPP) whose primary purpose is to develop a mutually acceptable
method of resolving the inequities imposed on transmission network
owners by parallel power flows. Allegheny Power also participated in
the funding of and continued support of an organization known as the
"Alliance" whose four transmission-owning members intend, among other
things, to pursue a test of the GAPP methodology. To that end, a
request for such experimentation authorization was submitted by the
Alliance and two other GAPP members to the FERC in December 1996.
Allegheny Power cannot predict what action the FERC may take on this
request.
Under PURPA, certain municipalities, businesses and private
developers have installed, are installing or are proposing to install
generating facilities at various locations in or near the Operating
Subsidiaries' service areas with the intent of selling some or all of
the electric capacity and energy to the Operating Subsidiaries at rates
<PAGE> - 15 -
consistent with PURPA and ordered by appropriate state commissions. As
a result of PURPA, Allegheny Power is committed to 299 MW of on-line
PURPA capacity. Payments for PURPA capacity and energy in 1996 totaled
approximately $133 million at an average cost to Allegheny Power of 5.5
cents/kWh, as compared to Allegheny Power's own generating cost of about
3 cents/kWh. Allegheny Power projects an additional 180 MW of PURPA
capacity (Warrior Run) to come on-line in 1999. It is expected that the
Warrior Run project will result in substantial costs for Potomac
Edison's Maryland customers. Allegheny Power has attempted to negotiate
a buyout or restructuring of the existing contract with the Warrior Run
project developer to reduce the cost impact on customers. The
negotiations have been unsuccessful. (See ITEM 3. LEGAL PROCEEDINGS for
a description of litigation and regulatory proceedings in Pennsylvania
and West Virginia concerning other proposed PURPA projects.)
ELECTRIC FACILITIES
The following table shows Allegheny Power's December 31, 1996,
generating capacity, based on the maximum monthly normal seasonal
operating capacity of each unit. Allegheny Power's owned capacity
totaled 8070 MW, of which 7090 MW (88%) are coal-fired, 840 MW (10%) are
pumped-storage, 82 MW (1%) are oil-fired, and 58 MW (1%) are
hydroelectric. The term "pumped-storage" refers to the Bath County
station which stores energy for use principally during peak load hours
by pumping water from a lower to an upper reservoir, using the most
economic available electricity, generally during off-peak hours. During
the generating cycle, power is produced by water falling from the upper
to the lower reservoir through turbine generators.
The weighted average age of Allegheny Power's owned steam
stations shown on the following page, based on generating capacity at
December 31, 1996, was about 26.6 years. In 1996, their average heat
rate was 9,910 Btu's/kWh, and their availability factor was 86.0%.
<PAGE> - 16 -
<TABLE>
<CAPTION>
Allegheny Power Stations
Maximum Generating Capacity
(Megawatts) (a)
<S> <C> <C> <C> <C> <C> <C> <C>
Dates When
Station Monon- Potomac West Service
Station Units Total gahela Edison Penn Commenced (b)
Coal-fired (steam):
Albright 3 292 216 76 1952-4
Armstrong 2 352 352 1958-9
Fort Martin 2 831 249 304 278 1967-8
Harrison 3 1,920 480 629 811 1972-4
Hatfield's Ferry 3 1,660 456 332 872 1969-71
Mitchell 1 284 284 1963
Pleasants 2 1,252 313 376 563 1979-80
Rivesville 2 142 142 1943-51
R. Paul Smith 2 114 114 1947-58
Willow Island 2 243 243 1949-60
Oil-fired (steam): (a)
Mitchell 1 82 82 1948
Pumped-storage and Hydro:
Bath County 6 840 227(c) 235(c) 378(c) 1985
Lake Lynn(d) 4 52 52 1926
Potomac Edison (d) 21 6 6 Various
Total Allegheny Power Owned
Capacity 54 8,070 2,326 2,072 3,672
Nonutility Generation
Maximum Generating Capacity
(Megawatts) (e)
Contract
Project Monon- Potomac West Commencement
Project Total gahela Edison Penn Date
Coal-fired:
AES Beaver Valley 125 125 1987
Grant Town 80 80 1993
West Virginia University 50 50 1992
Hydro:
Allegheny Lock and Dam 5 6 6 1988
Allegheny Lock and Dam 6 7 7 1989
Hannibal Lock and Dam 31 31 1988
Total Nonutility Capacity 299 161 0(f) 138
Total Allegheny Power Owned and
PURPA Committed 8,369 2,487 2,072 3,810
Generating Capacity (a)
</TABLE>
<PAGE> - 17 -
(a) Excludes 207 MW of West Penn oil-fired capacity at Springdale Power
Station and 77 MW of the total MW at Mitchell Power Station, which were
placed on cold reserve status as of June 1, 1983. Current plans call
for the reactivation/repowering of these units in about five years. On
December 31, 1994, 82 MW of the total MW at Mitchell Power Station were
reactivated. Also excludes 276 MW of Unit No. 1 of Fort Martin merchant
plant capacity owned by AYP Energy which is not subject to price
regulation by any regulatory commission.
(b) Where more than one year is listed as a commencement date for a
particular source, the dates refer to the years in which operations
commenced for the different units at that source.
(c) Capacity entitlement through ownership of AGC, 27%, 28% and 45% by
Monongahela, Potomac Edison and West Penn, respectively.
(d) West Penn has a 30-year license for Lake Lynn, effective December 1994.
Potomac Edison's license for hydroelectric facilities Dam No. 4 and Dam
No. 5 will expire in 2003. Potomac Edison has received 30-year licenses,
effective January 1994, for the Shenandoah, Warren, Luray and Newport
projects. The FERC accepted Potomac Edison's surrender of the license
for the Harper's Ferry Dam No. 3 and issued an order effective October
1994.
(e) Nonutility generating capacity available through state utility commission
approved arrangements pursuant to PURPA.
(f) The 180-MW Warrior Run project has completed its financial closing, is
under construction, and is planned to begin providing capacity and energy
to Potomac Edison in 1999.
<PAGE> - 18 -
ALLEGHENY POWER MAP
The Allegheny Power Map (Map), which has been omitted, provides a
broad illustration of the names and approximate locations of Allegheny Power's
major generation and transmission facilities, both existing and under
construction, in a five-state region which includes portions of Pennsylvania,
Ohio, West Virginia, Maryland and Virginia. Additionally, Extra High Voltage
substations are displayed. By use of shading, the Map also provides a
general representation of the service areas of Monongahela (portions of West
Virginia and Ohio), Potomac Edison (portions of Maryland, Virginia and West
Virginia), and West Penn (portions of Pennsylvania).
Power Stations shown on the Map which appear within the Monongahela
service area are Willow Island, Pleasants, Harrison, Rivesville, Albright, and
Fort Martin. The single Power Station appearing within the Potomac Edison
service area is R. Paul Smith. The Bath County Power Station appears on the
map just south of the westernmost portion of Potomac Edison's service area
formed by the borders of Virginia and West Virginia. Power Stations appearing
within the West Penn service area are Armstrong, Mitchell, Hatfield's Ferry,
Springdale and Lake Lynn.
The Map also depicts transmission facilities which are (i) owned
solely by the Operating Subsidiaries; (ii) owned by the Operating Subsidiaries
in conjunction with other utilities; or (iii) owned solely by other utilities.
The transmission facilities portrayed range in capcity from 138kV to 765kV.
Additionally, interconnections with other utilities are displayed.
<PAGE> - 19 -
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, 1996:
Above Ground Transmission and
Distribution Lines (a) and Substations
<TABLE>
<CAPTION>
Portion of Total Transmission and
Representing Distribution
Total 500-Kilovolt (kV) Lines Substations(b)
<S> <C> <C> <C>
Monongahela 20,060 283 243
Potomac Edison 17,423 202 208
West Penn 22,850 273 520
AGC(c) 85 85 1
Total 60,418 843 972
</TABLE>
(a) Allegheny Power has a total of 6,083 miles of underground distribution
lines.
(b) The substations have an aggregate transformer capacity of 39,357,495
kilovoltamperes.
(c) Total Bath County transmission lines, of which AGC owns an undivided
40% interest and Virginia Power owns the remainder.
Allegheny Power has 11 extra-high-voltage (345-kV and above)
(EHV) and 29 lower-voltage interconnections with neighboring utility
systems. The interregional EHV transmission system, including System
facilities, historically has operated near reliability limits because of
frequent periods of heavy power flows, predominantly in a west-to-east
direction. In early 1996, use of the transmission system in aggregate
declined and the west-to-east power flows decreased to more comfortable
levels. However, beginning in the summer months of 1996, west-to-east
transfers increased and occasionally reached the critical levels
commonly seen earlier in the decade. If transfers and customer load
continue to increase, along with coincident parallel flows,
interregional EHV transmission facilities, including Allegheny Power
facilities, may again operate more frequently nearer to reliability
limits at which time restrictions on transfers may become necessary.
(SEE discussion concerning General Agreement on Parallel Paths and the
Alliance under ITEM I. SALES.)
Wholesale generators and other wholesale customers may now seek
from owners of bulk power transmission facilities a commitment to supply
transmission services. (See discussion under ITEM 1. SALES.) Such
demand on Allegheny Power's transmission facilities may add to heavy
power flows on Allegheny Power's facilities.
The Operating Subsidiaries have, since the early 1980's,
provided managed contractual access to Allegheny Power's transmission
facilities under various tariffs. As described earlier, for new
agreements starting in 1996, managed access will also be governed by the
<PAGE> - 20 -
provisions of the Allegheny Power open access tariffs recently filed
with the FERC.
RESEARCH AND DEVELOPMENT
The Operating Subsidiaries spent $7.7 million, $9.0 million, and
$7.7 million, in 1996, 1995, and 1994, respectively, for research
programs. Of these amounts, $5.5 million, $6.2 million, and $5.9
million were for Electric Power Research Institute (EPRI) dues in 1996,
1995, and 1994, respectively. EPRI is an industry-sponsored research
and development institution. The Operating Subsidiaries plan to spend
approximately $7.5 million for research in 1997, with EPRI dues
representing $5.7 million of that total.
In addition to EPRI support, in-house research conducted by
Allegheny Power concentrated on environmental protection, generating
unit performance, transmission system performance, future generating
technologies, delivery systems, customer-related research, clean power
technology focused on power quality and load management devices, and
techniques for customer and delivery equipment. All in-house research
is related to adapting both competitive and leading edge technology to
Allegheny Power's operations.
Research is also being directed to help address major issues
facing our industry, including electric and magnetic field (EMF)
assessment of employee exposure within the work environment, waste
disposal and discharges, greenhouse gases, renewable resources, fuel
cells, new combustion turbines and cogeneration technologies. A
constructed wetlands project at Allegheny Power's Springdale Power
Station significantly improved the water quality of the effluent from a
closed ash management facility. The project received the 1996
Industrial Excellence Award from the Pennsylvania Water Environment
Association. During 1996, Allegheny Power supported the federal
government's National EMF Research and Public Information Dissemination
Program, a project on biomechanisms with the Massachusetts Institute of
Technology, and an Edison Electric Institute (EEI) program to study
employee and public health effects, if any, of EMF. The financial
effect of these issues on Allegheny Power, if any, cannot be determined
at this time. In addition, there is continuing evaluation of technical
proposals from outside sources and monitoring of developments in
industry-related literature, law and litigation, general business and
environmental standards (ISO 9000 AND ISO 14000), and intellectual
property rights.
Because of the NOx control requirements of the CAAA, Allegheny
Power is participating in a collaborative effort coordinated by EPRI to
gain a greater understanding of the formation of ground level ozone and
how measures to control NOx and volatile organic compounds affect ozone
formation. The North American Research Strategy for Tropospheric Ozone-
Northeast is focused on this effort. Other research is directed at NOx
control technologies for power station compliance. Allegheny Power
<PAGE> - 21 -
continues to monitor and demonstrate technical solutions to greenhouse
gas reduction, sequestration, capture, and control.
As part of its response to Energy Policy Act of 1992 and the
subsequent Clinton Climate Action Plan, Allegheny Power, as part of an
EEI program, has agreed to participate in research initiatives which are
designed to reduce, sequester or control greenhouse gases. This program
is consistent with filings made with the Department of Energy (DOE) in
voluntary compliance with Section 1605(b) of EPACT.
Electric vehicle (EV) research in 1996 included participation in
the Ford Ecostar Demonstration Program, EV America and the Electric
Transportation Coalition, as well as the development of appropriate
wiring and building code standards to accommodate electric vehicles.
In 1996 research was also directed into communication systems to
develop and demonstrate a high speed advanced power line communication
system utilizing existing utility wires to service information and
automation needs of Allegheny Power's customers and to support system
requirements in retail wheeling.
Allegheny Power continues to pursue beneficial uses of coal
combustion by-products. In cooperation with the West Virginia Division
of Environmental Protection, a project is under way to investigate the
feasibility and cost-effectiveness of injecting fly ash from Allegheny
Power's power stations into abandoned underground mine sites in West
Virginia to reduce acid mine drainage and mine surface subsidence. The
project cost is being shared with EPRI as part of a Tailored
Collaboration Agreement. Also being investigated is the use of fly ash
as a construction material.
As part of customer research, a model home program is being
developed and adjustable speed drives for customer motor loads are being
used at a steel company and at an extrusion process plant. An effort in
which Allegheny Power participated through West Penn in 1996 is the
Pennsylvania Electric Energy Research Council (PEERC). PEERC was formed
in 1987 as a partnership of Pennsylvania-based electric utilities to
promote technological advancements related to the electric utility
industry.
In 1996 the Operating Subsidiaries made research grants to
regional colleges and universities to encourage the development of
technical resources related to current and future utility problems.
CAPITAL REQUIREMENTS AND FINANCING
Construction expenditures by the Subsidiaries in 1996 amounted
to $289 million and for 1997 and 1998 are expected to aggregate $322
million and $324 million, respectively. In 1996, these expenditures
included $3 million for compliance with the CAAA. The 1997 and 1998
estimated expenditures include $15 million and $42 million,
<PAGE> - 22 -
respectively, to cover the costs of compliance with the CAAA.
Expenditures to cover the costs of compliance with the CAAA were much
more significant in prior years and may be again in future years if
required for Phase II compliance.
Construction Expenditures
<TABLE>
<CAPTION>
1996 1997 1998
<S> <C> <C> <C>
Millions of Dollars
(Actual) (Estimated)
Monongahela
Generation Business Unit $ 30.3 $ 32.7 $ 47.4
Transmission Business Unit 4.5 8.6 9.8
Distribution Unit 37.8 41.8 33.4
Total* $ 72.6 $ 83.1 $ 90.6
Potomac Edison
Generation Business Unit $ 27.7 $ 24.0 $ 30.8
Transmission Business Unit 15.9 25.0 33.8
Distribution Unit 42.7 48.8 44.8
Total* $ 86.3 $ 97.8 $ 109.4
West Penn
Generation Business Unit $ 49.9 $ 59.1 $ 72.2
Transmission Business Unit 24.9 14.5 3.8
Distribution Unit 51.0 56.0 45.3
Other 4.8 10.8 2.1
Total* $ 130.6 $ 140.4 $ 123.4
AGC
Generation Business Unit $ 0.1 $ 1.0 $ .4
Total Capital Expenditures, Regulated $ 289.6 $ 322.3 $ 323.8
AYP Capital $ 180.2 $ 21.1 $ 20.7
Total Construction Expenditures $ 469.8** $ 343.4** $ 344.5**
</TABLE>
* Includes allowance for funds used during construction (AFUDC) for 1996,
1997 and 1998 of: Monongahela $0.7, $1.8 and $2.5; Potomac Edison $2.5,
$2.2 and $2.7; and West Penn $2.7, $3.4 and $4.5.
** Includes amounts for capital projects connected with the restructuring
of $22.4, $40.5 and $1.8 for 1996, 1997 and 1998, respectively.
These construction expenditures include major capital projects
at existing generating stations, upgrading distribution lines and
substations, and the strengthening of the transmission and
<PAGE> - 23 -
subtransmission systems. They also include $22.4 million, $40.5 million
and $1.8 million in 1996, 1997 and 1998, respectively, for new systems
resulting from the restructuring effort.
On a collective basis for the Subsidiaries, expenditures for
1996, 1997, and 1998 include $43 million, $37 million, and $59 million,
respectively, for construction of environmental control technology.
Outages for construction, CAAA compliance work, and other environmental
work is, and will continue to be, coordinated with planned outages.
Allegheny Power continues to study ways to reduce and meet
existing customer demand and future increases in customer demand,
including demand-side management programs, new and efficient electric
technologies, construction of various types and sizes of generating
units, increasing the efficiency and availability of Allegheny Power
generating facilities, reducing internal electrical use and transmission
and distribution losses, and, acquisition of energy and capacity from
third-party suppliers.
Potomac Edison is engaged in implementing state commission
ordered demand-side management programs. (See ITEM 1. REGULATION for a
further discussion of these programs.)
Current forecasts, which reflect demand-side management efforts
and other considerations and assume normal weather conditions, project
average annual winter and summer peak load growth rates of 1.35% and
1.49%, respectively, in the period 1997-2007. It is anticipated that
the reactivation of Mitchell No. 2 Unit, the repowering of Springdale
No. 8 Unit, peak diversity exchange arrangements (described under ITEM
1. SALES), demand-side management and conservation programs, and
mandated PURPA capacity will be sufficient for Allegheny Power's needs
until the year 2000 and beyond. The advent of retail competition may
have a significant effect on load growth.
In connection with its construction and demand-side management
programs, Allegheny Power must make estimates of the availability and
cost of capital as well as the future demands of its customers that are
necessarily subject to regional, national, and international
developments, changing business conditions, and other factors. The
construction of facilities and their cost are affected by laws and
regulations, lead times in manufacturing, availability of labor,
materials and supplies, inflation, interest rates, and licensing, rate,
environmental, and other proceedings before regulatory authorities.
Decisions regarding construction of facilities must now also take into
account retail competition. As a result, future plans of Allegheny
Power are subject to continuing review and substantial change.
The Subsidiaries have financed their construction programs
through internally generated funds, first mortgage bonds, debentures,
medium-term notes, subordinated debt and preferred stock issues,
pollution control and solid waste disposal notes, installment loans,
long-term lease arrangements, equity investments by APS (or, in the case
<PAGE> - 24 -
of AGC, by the Operating Subsidiaries), and, where necessary, interim
short-term debt. The future ability of the Subsidiaries to finance
their construction programs by these means depends on many factors,
including creditworthiness, rate levels sufficient to provide internally
generated funds and adequate revenues to produce a satisfactory return
on the common equity portion of the Subsidiaries' capital structures 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.
AYP Energy financed its $170 million acquisition of 276 MW of
Fort Martin Unit No. 1 from Duquesne with a combination of $25 million
of equity from APS and $160 million of 5-year debt financing provided by
a syndicate of banks. Funds in excess of the purchase price will be
used to fund operations. AYP Energy's obligation under the Credit
Agreement is supported by APS. The debt is priced at a floating rate.
Prior to closing the transaction, AYP Energy entered into a $160 million
forward swap to hedge against fluctuations in interest rates during the
5-year period.
In 1996, APS sold 1,139,518 shares of its common stock for $33.8
million through its Dividend Reinvestment and Stock Purchase Plan and
its Employee Stock Ownership and Savings Plan.
During 1996, the rate for West Penn's 400,000 shares of market
auction preferred stock, par value $100 per share, reset approximately
every 90 days at 4.185%, 4.04%, 4.245%, and 4.018%. The rate set at
auction on January 14, 1997 was 4.008%.
At December 31, 1996, short-term debt was outstanding in the
following amounts: APS $84.4 million, Monongahela $31.1 million,
Potomac Edison $7.5 million, and West Penn $33.4 million. At December
31, 1996, AGC had $20.0 million of commercial paper outstanding.
The Subsidiaries' ratios of earnings to fixed charges for the
year ended December 31, 1996, were as follows: Monongahela, 3.44;
Potomac Edison, 3.25; West Penn, 2.88; and AGC, 3.48.
Allegheny Power's consolidated capitalization ratios as of
December 31, 1996, were: common equity, 45.8%; preferred stock, 3.6%;
and long-term debt, 50.6%, including Quarterly Income Debt Securities
(QUIDS) (3.3%). Allegheny Power's long-term objective is to maintain
the common equity portion above 46%.
During 1997, Monongahela plans to issue $45 million of new debt
for general corporate purposes, including its construction program.
Potomac Edison and West Penn currently anticipate meeting their capital
requirements through a combination of internally generated funds, cash
on hand, and short-term borrowing as necessary. However, West Penn may
issue debt securities pursuant to the securitization provisions of the
<PAGE> - 25 -
Pennsylvania legislation of December 3, 1996. APS plans to continue
selling common stock through its Dividend Reinvestment and Stock
Purchase Plan and Employee Stock Ownership and Savings Plan.
FUEL SUPPLY
Allegheny Power-operated stations burned approximately 16.4
million tons of coal in 1996. Of that amount, 86% was either cleaned
(5.0 million tons) or used in stations equipped with scrubbers (9.1
million tons). The use of desulfurization equipment and the cleaning
and blending of coal make burning local higher-sulfur coal practical.
In 1996, about 99% of the coal received at Allegheny Power-operated
stations came from mines in West Virginia, Pennsylvania, Maryland, and
Ohio. Allegheny Power does not mine or clean any coal. All raw, clean,
or washed coal is purchased from various suppliers as necessary to meet
station requirements.
Long-term arrangements, subject to price change, are in effect
to provide for approximately 14.8 million tons of coal in 1997. The
Operating Subsidiaries will depend on short-term arrangements and spot
purchases for their remaining requirements. Through the year 1999, the
total coal requirements of present Allegheny Power-operated stations are
expected to be met with coal acquired under existing contracts or from
known suppliers.
For each of the years 1992 through 1995, the average cost per
ton of coal burned was $36.31, $36.19, $35.88, and $32.68, respectively.
For the year 1996, the cost per ton decreased to $32.25.
Long-term arrangements, subject to price change, are in effect
and will provide for the lime requirements of scrubbers at Allegheny
Power's scrubbed stations.
In addition to using ash in various power plant applications
such as scrubber by-product stabilization at Harrison and Mitchell Power
Stations, the Operating Subsidiaries continue their efforts to market
coal combustion by-products for beneficial uses and thereby reduce
landfill requirements. (See ITEM 1. RESEARCH AND DEVELOPMENT.) In
1996, the Operating Subsidiaries received approximately $919,000 from
the sale of 131,000 tons of fly ash and 168,000 tons of bottom ash for
various uses, including cement replacement, mine grouting, oil well
grouting, soil extenders, and anti-skid material.
The Operating Subsidiaries own coal reserves estimated to
contain about 125 million tons of higher sulfur coal recoverable by deep
mining. There are no present plans to mine these reserves and, in view
of economic conditions now prevailing in the coal market, the Operating
Subsidiaries plan to hold the reserves as a long-term resource.
<PAGE> - 26 -
RATE MATTERS
On October 29, 1996 the Virginia State Corporation Commission
(SCC) approved an agreement filed by Potomac Edison and staff of the SCC
that reduced rates effective November 1, 1996, by $1.2 million (1%) on
an annual basis. The agreement was the result of an Annual
Informational Filing required by the SCC.
AGC's rates are set by a formula filed with and previously
accepted by the FERC. The only component which changes is the return on
equity (ROE). Pursuant to a settlement agreement filed April 4, 1996,
with the FERC, AGC's ROE was set at 11% for 1996 and will continue until
the time any affected party seeks renegotiation of the ROE. Notice of
such intent to seek a revision in ROE must be filed during a notice
period each year between November 1 and November 15. No requests for
change were filed during the 1996 notice period. Therefore, AGC's ROE
will remain at 11% for 1997.
Currently all state regulatory jurisdictions and the FERC
utilize special procedures to recognize changes in fuel and other energy
costs in rates on a more current basis than other costs. These
procedures, generally referred to as energy recovery or fuel clauses,
use an expedited proceeding schedule, and require the companies to use a
tracking procedure to compare revenues received for energy costs with
actual energy costs incurred. Differences are deferred until the next
proceeding when energy rates are adjusted to return or recover previous
overrecoveries or underrecoveries, respectively. Because of this
procedure, changes in fuel and other energy costs have had little effect
on net income.
The Pennsylvania competition legislation capped West Penn's
rates, including its energy cost rates, effective January 1, 1997.
Since the new legislation left the method of future rate adjustments for
energy costs to Pennsylvania PUC discretion, West Penn on February 28,
1997 filed a Petition with the Pennsylvania PUC to roll the energy cost
rates into its base rates. Upon receipt of an order of approval, West
Penn would then assume the risks of increases in the costs of fuel and
purchased power and any declines in bulk power transaction sales.
However, West Penn would also retain the benefits of decreases in such
costs and increases in such sales. West Penn would accomplish this
result by discontinuance of deferred fuel accounting.
On May 23, 1996, the Pennsylvania PUC approved a settlement
authorizing West Penn to recover all of the costs ($31 million)
associated with termination of a power supply contract with the
Shannopin PURPA project. This contract was negotiated under the
requirements of PURPA. The majority of cost recovery ($24 million) was
accomplished by reducing West Penn's overrecovered fuel balance.
Effective July 9, 1996, West Penn's energy cost rates were decreased by
$5.1 million annually. The remaining Shannopin costs ($7 million) were
to be recovered in 1997 and 1998, but, pursuant to the rate caps enacted
<PAGE> - 27 -
by the new Pennsylvania competition legislation, will be recovered
through other means.
On June 25, 1996, the Public Service Commission of West Virginia
approved stipulated agreements in the annual Expanded Net Energy Cost
proceedings under which Monongahela and Potomac Edison customers will
receive annual decreases in their energy rates of $19.5 million and $5.3
million, respectively. Included for both companies was a small increase
in base rates to cover additional costs for CAAA-related investments and
operating expenses. The new rates became effective July 1, 1996.
Annual audit reports on fuel-related items for Monongahela were
filed with the Ohio Public Utilities Commission on October 11, 1996. A
fuel rate change was effective February 1, 1997, and reflected a slight
decrease.
By order dated June 20, 1996, the Maryland Public Service
Commission accepted a stipulation and agreement that approved a decrease
in fuel rates to Potomac Edison's Maryland customers of $6.8 million
annually. This decrease resulted from fuel costs declining by more than
5% when measured by a commission formula.
A Virginia SCC order dated March 6, 1996, approved an annual
increase in fuel rates to Potomac Edison's Virginia customers of
$315,000 effective March 7, 1996. This increase resulted from the SCC's
annual fuel cost review. On February 14, 1997, Potomac Edison requested
the Virginia SCC to permit it to continue to charge its currently
authorized fuel rates until further order of the commission.
ENVIRONMENTAL MATTERS
The operations of the Allegheny Power-operated stations are
subject to regulation as to air and water quality, hazardous and solid
waste disposal, and other environmental matters by various federal,
state, and local authorities.
Meeting known environmental standards is estimated to cost the
Subsidiaries about $189 million in capital expenditures over the next
three years. Additional legislation or regulatory control requirements,
if enacted, may require modifying, supplementing, or replacing equipment
at existing stations at substantial additional cost.
Air Standards
Allegheny Power currently meets applicable standards as to
particulates and opacity at the power stations through high-efficiency
electrostatic precipitators, cleaned coal, flue-gas conditioning, and,
at times, reduction of output. From time to time minor excursions of
opacity, normal to fossil fuel operations, are experienced and are
accommodated by the regulatory process.
<PAGE> - 28 -
Allegheny Power meets current emission standards as to SO2 by
the use of scrubbers, the burning of low-sulfur coal, the purchase of
cleaned coal to lower the sulfur content, and the blending of low-sulfur
with higher sulfur coal.
The CAAA, among other things, require an annual reduction in
total utility emissions within the United States of 10 million tons of
SO2 and two million tons of NOx from 1980 emission levels, to be
completed in two phases, Phase I and Phase II. Five coal-fired
Allegheny Power plants are affected in Phase I and the remaining plants
and units reactivated in the future will be affected in Phase II.
Installation of scrubbers at the Harrison Power Station was the strategy
undertaken by Allegheny Power to meet the required SO2 emission
reductions for Phase I (1995-1999). Continuing studies will determine
the compliance strategy for Phase II (2000 and beyond). Studies to
evaluate cost-effective options to comply with Phase II SO2 limits,
including those which may be available from the use of Allegheny Power's
banked emission allowances and from the emission allowance trading
market, are continuing. It is expected that burner modifications at
most of the Allegheny Power-operated stations will satisfy the NOx
emission reduction requirements for the acid rain (Title IV) provisions
of the CAAA. Additional post-combustion controls may be mandated in
Maryland, Pennsylvania, and West Virginia for ozone nonattainment (Title
I) reasons. Continuous emission monitoring equipment has been installed
on all Phase I and Phase II units.
In an effort to introduce market forces into pollution control,
the CAAA created SO2 emission allowances. An allowance is defined as an
authorization to emit one ton of SO2 into the atmosphere. Subject to
regulatory limitations, allowances (including bonus and extension
allowances) may be sold or banked for future use or sale. Allegheny
Power received, through an industry allowance pooling agreement, a total
of approximately 554,000 bonus and extension allowances during Phase I.
These allowances are in addition to the CAAA Table A allowances of
approximately 356,000 per year during the Phase I years. Ownership of
these allowances permits Allegheny Power to operate in compliance with
Phase I, as well as to postpone a decision on its compliance strategy
for Phase II. As part of its compliance strategy, Allegheny Power
continues to study the allowance market to determine whether sales or
purchases of allowances or participation in certain derivative or
hedging allowance transactions are appropriate.
Pursuant to an option in the CAAA and in order to avoid the
potential for more stringent NOx limits in Phase II, Allegheny Power
chose to treat five Phase II, Group 1 boilers (tangential- and wall-
fired) as Phase-I-affected units (Substitution Units) for calendar year
1996. Additionally, three of the four Phase II, Group 2 boilers (top-
and cyclone-fired) were also made Substitution Units for 1996. The
status of all Substitution Units is evaluated on an annual basis to
ascertain the financial benefits of retaining these units as Phase-1-
affected units. As a result of being Phase-I-affected, these
Substitution Units will also be required to comply with the Phase I SO2
<PAGE> - 29 -
limits for each year that they are accorded substitution status by
Allegheny Power. Phase I NOx and SO2 compliance for these units should
not require additional capital or operating expenditures.
Title I of the CAAA established an ozone transport region (OTR)
consisting of the District of Columbia, the northern part of Virginia
and 11 northeast states including Maryland and Pennsylvania. On October
11, 1995, Pennsylvania petitioned the Environmental Protection Agency
(EPA) to remove western Pennsylvania from the OTR. The EPA has denied
the request. Sources within the OTR will be required to reduce NOx
emissions, a precursor of ozone, to a level conducive to attainment of
the ozone National Ambient Air Quality Standards (NAAQS). The
installation of reasonably available control technology (RACT) (overfire
air equipment and/or low NOx burners) at all Pennsylvania and Maryland
stations has been completed. The installation of RACT satisfies both
Title I and Title IV NOx reduction requirements.
Title I of the CAAA also established an Ozone Transport
Commission (OTC), which has determined that Allegheny Power will be
required to make additional NOx reductions beyond RACT in order for the
OTR to meet the ozone NAAQS. Under terms of a Memorandum of
Understanding (MOU) among the OTR states, Allegheny Power-operated
stations located in Maryland and Pennsylvania will be required to reduce
NOx emissions by approximately 55% from the 1990 baseline emissions,
with a compliance date of May 1999. Further reductions of 75% from the
1990 baseline may be required by May 2003, unless the results of
modeling studies, due to be completed by 1998, indicate otherwise. If
Allegheny Power has to make reductions of 75%, it could be very
expensive and would depend upon the installation of post-combustion
control technologies. Both Maryland and Pennsylvania must promulgate
regulations to implement the terms of the MOU.
During 1995, the Environmental Council of States (ECOS) and the
EPA established the Ozone Transport Assessment Group (OTAG) to develop
recommendations for the regional control of NOx and Volatile Organic
Compounds (VOCs) in 37 states east of and bordering the west bank of the
Mississippi River plus Texas. OTAG is similar to the OTC in purpose and
organization and could lead to additional NOx controls on certain
Allegheny Power-operated stations in West Virginia. There is no
assurance that NOx control for non-OTR states will be limited to RACT.
What occurs in the non-OTR states could also affect whether Allegheny
Power-operated stations in Maryland and Pennsylvania would need post-
RACT controls. OTAG plans to issue recommendations by late spring 1997.
The EPA is required by law to regularly review the NAAQS for
criteria pollutants. Recent court orders due to litigation by the
American Lung Association have expedited these reviews. The EPA in 1996
concluded not to revise the SO2 and NOx standards. Revisions to
particulate matter and ozone standards were proposed by the EPA in 1996
and will likely be finalized in 1997. The impact on Allegheny Power of
any revision to these standards is unknown at this time but could be
substantial if the 1996 recommendations become requirements.
<PAGE> - 30 -
In 1989, the West Virginia Air Pollution Control Commission
approved the construction of a third-party cogeneration facility in the
vicinity of Rivesville, West Virginia. Emissions impact modeling for
that facility raised concerns about the compliance of Monongahela's
Rivesville Station with ambient standards for SO2. Pursuant to a
consent order, Monongahela agreed to collect on-site meteorological data
and conduct additional dispersion modeling in order to demonstrate
compliance. The modeling study and a compliance strategy recommending
construction of a new "good engineering practices" (GEP) stack were
submitted to the West Virginia Department of Environmental Protection
(WVDEP) in June 1993. Costs associated with the GEP stack are
approximately $20 million. Monongahela is awaiting action by the WVDEP.
Under an EPA-approved consent order with Pennsylvania, West Penn
completed construction of a GEP stack at the Armstrong Power Station in
1982 at a cost of over $13 million with the expectation that EPA's
reclassification of Armstrong County to "attainment status" under NAAQS
for SO2 would follow. As a result of the 1985 revision of its stack
height rules, EPA refused to reclassify the area to attainment status.
Subsequently, West Penn filed an appeal with the U.S. Court of Appeals
for the Third Circuit for review of that decision as well as a petition
for reconsideration with EPA. In 1988, the Court dismissed West Penn's
appeal stating it could not decide the case while West Penn's request
for reconsideration before EPA was pending. West Penn cannot predict
the outcome of this proceeding.
Water Standards
Under the National Pollutant Discharge Elimination System
(NPDES), permits for all of Allegheny Power's stations and disposal
sites are in place. However, NPDES permit renewals for several West
Virginia and Pennsylvania disposal sites contain what Allegheny Power
believes are overly stringent discharge limitations. Allegheny Power is
working cooperatively with the states to develop alternate water quality
criteria which will result in less stringent permit limits. If this
effort is unsuccessful, installation of wastewater treatment facilities
may become necessary. The cost of such facilities, if required, cannot
be predicted at this time.
The stormwater permitting program required under the 1987
Amendments to the Clean Water Act required implementation in two phases.
In Phase I, the EPA and state agencies implemented stormwater runoff
regulations for controlling discharges from industrial and municipal
sources as well as construction sites. Stormwater discharges have been
identified and included in NPDES permit renewals, but controls have not
yet been required. Since the current round of permit renewals began in
1993, monitoring requirements have been imposed, with pollution
reduction plans and additional control of some discharges anticipated.
In April 1995, EPA promulgated the Phase II stormwater rule
which established a two-tiered application process for discharges
<PAGE> - 31 -
composed entirely of stormwater. Under the rule, sources determined to
be significant contributors to water quality problems will be required
to apply for a discharge permit within 180 days of receiving notice.
The remaining sources are required to apply for permits within six years
of the rule's effective date or August 2, 2001, under yet-to-be proposed
application requirements.
Pursuant to the National Groundwater Protection Strategy, West
Virginia adopted a Groundwater Protection Act in 1991. This law
established a statewide antidegradation policy which could require
Allegheny Power to undertake reconstruction of existing landfills and
surface impoundments as well as groundwater remediation, and may affect
herbicide use for right-of-way maintenance in West Virginia.
Groundwater protection standards were approved and implemented in 1993
(based on EPA drinking water criteria) which established compliance
limits. Pursuant to the groundwater protection standards variance
provision, on October 26, 1994, Allegheny Power jointly filed with
American Electric Power Company (AEP) and Virginia Power, a Notice of
Intent (NOI) to request class or source variances from the groundwater
standards for steam electric operating facilities in West Virginia.
Additionally, each of the companies filed individual NOIs. Technical
and socio-economic justification to support the variance requests are
being developed and the costs shared through EPRI by all participants,
including Allegheny Power. While the justification for the variance
requests is being developed, Allegheny Power is protected from any
enforcement action. Because variance requests must ultimately be
approved by the West Virginia legislature, it is not possible to predict
the outcome.
The Pennsylvania Land Recycling Act, adopted in 1996, allows for
the development and application of site-specific, risk-based groundwater
cleanup standards to both abandoned and active industrial sites. The
intent is to encourage the reuse of abandoned but contaminated
industrial sites and to allow for continual operation of industrial
sites whose operation began before groundwater protection statutes were
in place -- as long as it can be demonstrated by the owner/operator that
there is little or no risk to human health or the environment. A
similar statute has passed in West Virginia and implementing regulations
are being drafted in both states. It is anticipated that the final rules
should provide for reasonable and cost-effective groundwater cleanup of
Allegheny Power facilities should it become necessary and will encourage
economic development in Allegheny Power's service territories in
Pennsylvania and West Virginia.
Hazardous and Solid Wastes
Pursuant to the Resource Conservation and Recovery Act of 1976
(RCRA) and the Hazardous and Solid Waste Management Amendments of 1984,
EPA regulates the disposal of hazardous and solid waste materials.
Maryland, Ohio, Pennsylvania, Virginia, and West Virginia have also
<PAGE> - 32 -
enacted hazardous and solid waste management regulations that are as
stringent as or more stringent than the corresponding EPA regulations.
Allegheny Power is in a continual process of either permitting
new or re-permitting existing disposal capacity to meet future disposal
needs. All disposal areas are currently operating in compliance with
their permits.
Significant costs were incurred during 1995 and 1996 for
expansion of existing coal combustion by-product (CCB) disposal sites
due to requirements for installation of liners on new sites and
assessment of groundwater effects through routine groundwater monitoring
and specific hydrogeological studies. Existing sites may not meet the
current regulatory criteria and groundwater remediation may be required
at some of Allegheny Power's facilities.
Allegheny Power continues to actively pursue, with PADEP and
WVDEP encouragement, ash utilization projects such as deep mine
injection for subsidence and water quality improvement, structural fills
for highway and building construction, and soil enhancement for surface
mine reclamation. A work group comprised of a number of state agencies
and utility company representatives has been proposed and will be formed
by PADEP to encourage beneficial use of CCBs. A similar work group is
operating in West Virginia with Allegheny Power support and
participation.
Potomac Edison received a notice from the Maryland Department of
the Environment (MDE) in 1990 regarding a remediation ordered under
Maryland law at a facility previously owned by Potomac Edison. The MDE
has identified Potomac Edison as a potentially responsible party under
Maryland law. Remediation is being implemented by the current owner of
the facility which is located in Frederick. It is not anticipated that
Potomac Edison's share of remediation costs, if any, will be
substantial.
The Operating Subsidiaries are also among a group of potentially
responsible parties under the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended (CERCLA), for the
Jack's Creek/Sitkin Smelting Superfund Site and the Butler Tunnel
Superfund Site in Pennsylvania. (See ITEM 3. LEGAL PROCEEDINGS for a
description of these Superfund cases.)
REGULATION
Allegheny Power and AYP Capital are subject to the broad
jurisdiction of the SEC under PUHCA. APS, as a Maryland corporation, is
also subject to the jurisdiction of the Maryland PSC as to certain of
its activities. The Subsidiaries are regulated as to substantially all
of their operations by regulatory commissions in the states in which
they operate and also by the DOE. The Subsidiaries and AYP Energy are
<PAGE> - 33 -
regulated by the FERC. In addition, they are subject to numerous other
city, county, state, and federal laws, regulations, and rules.
In June 1995, the SEC published its report which recommended
changes to PUHCA, including a recommendation to Congress to repeal the
entire act. Bills were introduced in the last Congress to repeal PUHCA,
but did not pass. Similar bills will likely be introduced in the 105th
Congress. However, Allegheny Power cannot predict what changes, if any,
will be made to PUHCA as a result of these activities.
The FERC issued Orders 888 and 889 on April 24, 1996. (See ITEM
1. SALES for a discussion of these Orders.)
Section 111 of EPACT requires state utility commissions to
institute proceedings to investigate and determine the feasibility of
adopting proposed federal standards regarding three regulatory policy
issues related to integrated resource planning, rate recovery methods
for investments in demand-side management programs, and rates to
encourage investments in cost-effective energy efficiency improvements
to generation, transmission, and distribution facilities. Maryland,
Pennsylvania, Ohio, Virginia, and West Virginia declined to adopt the
federal standards, concluding that existing state regulations adequately
address the issues.
Although regulatory agencies in Ohio and West Virginia have
considered competitive bidding rules for long-term purchase of capacity
and energy by electric utilities, neither has yet imposed such a
requirement.
As part of its investigation into market competition and
regulatory policies, the Maryland PSC, in an Order issued August 18,
1995, declared that all new capacity needs in the state will be subject
to competitive bidding unless a utility can demonstrate why a particular
capacity need should not be bid. (See ITEM 1. COMPETITION for more
information on Maryland and other state utility commission
investigations into competition.)
Virginia has not mandated competitive bidding for capacity
additions.
On December 30, 1995, the Pennsylvania PUC issued its
regulations regarding future competitive bidding for purchase of
capacity and energy. The regulations specify the rules an electric
utility must follow to competitively bid the long-term purchase of
capacity and energy.
In August 1994, the Pennsylvania PUC instituted a proposed
rulemaking relating to Pennsylvania PUC review of siting and
construction of electric transmission lines. In connection with the
proposed rulemaking, the Pennsylvania PUC propounded a list of
questions, including questions regarding electric and magnetic fields.
<PAGE> - 34 -
In December 1994, West Penn filed responses to the questions. West Penn
cannot predict the outcome of this proposed rulemaking.
During 1996, Potomac Edison continued its participation in the
Collaborative Process for demand-side management in Maryland. Rebates
paid in the various programs totaled $394,000 and the savings in future
generation requirements was 746 kW. The surcharge for recovery of
demand-side management was revised based on a September 1996 Maryland
PSC order. The surcharge for commercial and small and intermediate
industrial customers was set at approximately 6% of revenue while the
surcharge for large industrial and residential customers was
approximately 1% of revenue.
In 1996, the Operating Subsidiaries continued to take part in
and fund various programs to assist low income customers, customers with
special needs, and/or customers experiencing temporary financial
hardship.
ITEM 2. PROPERTIES
Substantially all of the properties of the Operating
Subsidiaries are held subject to the lien of the indenture securing each
Operating Subsidiary's first mortgage bonds and, in many cases, subject
to certain reservations, minor encumbrances, and title defects which do
not materially interfere with their use. Some properties are also
subject to a second lien securing certain solid waste disposal and
pollution control notes. The indenture under which AGC's unsecured
debentures and medium-term notes are issued prohibits AGC, with certain
limited exceptions, from incurring or permitting liens to exist on any
of its properties or assets unless the debentures and medium-term notes
are contemporaneously secured equally and ratably with all other
indebtedness secured by such lien. Transmission and distribution lines,
in substantial part, some substations and switching stations, and some
ancillary facilities at power stations are on lands of others, in some
cases by sufferance, but in most instances pursuant to leases,
easements, rights-of-way, permits or other arrangements, many of which
have not been recorded and some of which are not evidenced by formal
grants. In some cases no examination of titles has been made as to
lands on which transmission and distribution lines and substations are
located. Each of the Operating Subsidiaries possesses the power of
eminent domain with respect to its public utility operations. (See also
ITEM 1. BUSINESS and ALLEGHENY POWER MAP.)
ITEM 3. LEGAL PROCEEDINGS
Pursuant to PURPA, in 1987, West Penn entered into separate
Electric Energy Purchase Agreements (EEPAs) with developers of three
PURPA projects: Milesburg (43 MW), Burgettstown (80 MW), and Shannopin
(80 MW). The EEPAs provided for the purchase of each project's power
<PAGE> - 35 -
over 30 years or more at rates generally approximating West Penn's
estimated avoided cost at the time the EEPAs were negotiated. Each EEPA
was subject to prior Pennsylvania PUC approval. In 1987 and 1988, West
Penn filed a separate petition with the Pennsylvania PUC for approval of
each EEPA. Thereafter the Pennsylvania PUC issued orders that
significantly modified the EEPAs. Since that time, all three EEPAs, as
modified, have been, in varying degrees, the subject of complex and
continuing regulatory and judicial proceedings.
West Penn and the developers of the Shannopin project reached an
agreement on January 25, 1996, which provided that West Penn would buy
out the Shannopin EEPA and terminate the project and all pending
litigation associated with the Shannopin project for a price of $31
million. The buyout agreement was approved by the Pennsylvania PUC on
May 28, 1996, and provided for full pass through of the buyout price to
West Penn's customers through the energy cost rate by no later than
March 31, 1999. Because the buyout agreement includes full pass-through
of the buyout price to customers, it will not have a material effect on
West Penn's net income.
On February 27, 1995, the Milesburg developers filed with the
Pennsylvania PUC a Petition for Recalculation of capacity cost to be
paid to the project in accordance with the July 1990 order of the
Commonwealth Court. These matters have since been stayed at the request
of Milesburg and West Penn for the purpose of pursuing settlement
discussions.
The Burgettstown EEPA, as modified by Pennsylvania PUC orders,
automatically terminated in accordance with its terms, as the financing
closing had not occurred by May 8, 1995, and Burgettstown did not
request a further extension.
On May 2, 1995, Washington Power, the developer of
Burgettstown, filed a complaint against West Penn, APS and APSC in the
United States District Court for the Western District of Pennsylvania
asserting claims of treble damages for monopolization and attempts to
monopolize in violation of the federal antitrust laws, unfair
competition, breach of contract, intentional interference with contract
and interference with prospective business relations. This complaint
was later amended to add a count alleging wrongful use of civil
proceedings. On April 1, 1996, Champion Processing, Inc., North Branch
Energy, Inc., and Air Products and Chemicals, Inc., claiming involvement
or potential involvement in the Burgettstown project, filed a similar
complaint alleging anti-trust violations, unfair competition and
intentional interference with a contract. The complaints have been
consolidated. West Penn, APS and APSC cannot predict the outcome of
this litigation.
In October 1993, South River Power Partners, L.P. (South River)
filed a complaint against West Penn with the Pennsylvania PUC. The
complaint sought to require West Penn to purchase 240 MW of power from a
proposed coal-fired PURPA project to be built in Fayette County,
<PAGE> - 36 -
Pennsylvania. West Penn opposed this complaint as the power was not
needed and the price proposed by South River was in excess of avoided
cost. The Pennsylvania Consumer Advocate, the Small Business Advocate,
the Pennsylvania PUC Trial Staff and various industrial customers
intervened in opposition to the complaint. On October 7, 1996, the PUC
dismissed the complaint on the basis that the developers had failed to
demonstrate that they had "a defined and viable" Qualifying Facility
(QF) project. The developers appealed to the Commonwealth Court. That
appeal is pending. West Penn cannot predict the outcome of this
proceeding.
On September 7, 1995, MidAtlantic Energy (MidAtlantic) sued
Monongahela, Potomac Edison, and APS in state court in Marshall County,
West Virginia for failure to comply with PURPA regulations in refusing
to purchase capacity and energy from a proposed PURPA project and
interference with MidAtlantic's contract with the Babcock and Wilcox
Company (B and W), among other things. This suit followed an
unsuccessful complaint proceeding by MidAtlantic requesting the West
Virginia PSC order Monongahela and Potomac Edison to purchase capacity
and energy from the project. The MidAtlantic suit also named B and W as
a defendant. MidAtlantic seeks compensatory and punitive damages.
Monongahela, Potomac Edison and APS filed an answer and B and W filed an
answer and counterclaim. Monongahela, Potomac Edison and APS cannot
predict the outcome of this litigation.
On August 24, 1995, American Bituminous Power Partners, L.P.
(ABPP), owner and operator of the Grant Town project, an operating 80 MW
waste coal PURPA project located in Marion County, West Virginia, filed
a Petition to Reopen and for Emergency Interim Relief with the West
Virginia PSC to modify its power purchase contract with Monongahela.
The modifications would have increased the price of project energy. The
West Virginia PSC dismissed the petition on March 29, 1996. On August
13, 1996, ABPP filed a request for arbitration alleging that the energy
rate payable under the purchase power contract had been improperly
calculated. The first phase of the arbitration proceeding is scheduled
for March 1997. Monongahela cannot predict the outcome of this
proceeding.
As of January 16, 1997, Monongahela has been named as a
defendant along with multiple other defendants in a total of 6,700
pending asbestos cases involving one or more plaintiffs. Potomac Edison
and West Penn have been named as defendants along with multiple other
defendants in approximately one-half of those cases. Because these
cases are filed in a "shot-gun" format whereby multiple plaintiffs file
claims against multiple defendants in the same case, it is presently
impossible to determine the actual number of cases in which plaintiffs
make claims against the Operating Subsidiaries. However, based upon
past experience and available data, it is estimated that about one-third
of the total number of cases filed actually involve claims against any
or all of the Operating Subsidiaries. All complaints allege that the
plaintiffs sustained unspecified injuries resulting from claimed
exposure to asbestos in various generating plants and other industrial
<PAGE> - 37 -
facilities operated by the various defendants, although all plaintiffs
do not claim exposure at facilities operated by all defendants. With
very few exceptions, plaintiffs claiming exposure at stations operated
by the Operating Subsidiaries were employed by third-party contractors,
not the Operating Subsidiaries. Three plaintiffs are known to be either
present or former employees of Monongahela. Each plaintiff generally
seeks compensatory and punitive damages against all defendants in
amounts of up to $1 million and $3 million, respectively; in those cases
which include a spousal claim for loss of consortium, damages are
generally sought against all defendants in an amount of up to an
additional $1 million. A total of 94 cases have been previously settled
and/or dismissed as against Monongahela for an amount substantially less
than the anticipated cost of defense. While the Operating Subsidiaries
believe that all of the cases are without merit, they cannot predict the
outcome nor are they able to determine whether additional cases will be
filed.
On January 27, 1995, Allegheny Power filed a declaratory
judgment action in the Court of Common Pleas of Westmoreland County,
Pennsylvania against its historic comprehensive general liability (CGL)
insurers. This suit seeks a declaration that the CGL insurers have a
duty to defend and indemnify the Operating Subsidiaries in the asbestos
cases, as well as in certain environmental actions. To date, two
insurers have settled. However, the final outcome of this proceeding
cannot be predicted.
On December 13, 1995, APSC, Monongahela, and Potomac Edison
filed a civil complaint in the Court of Common Pleas of Westmoreland
County, Pennsylvania against Industrial Risk Insurers (IRI) seeking
damages in excess of $5 million for breach of an insurance contract
covering physical damage to property at Unit No. 1 of Fort Martin Power
Station. This case was settled in 1996.
On March 4, 1994, the Operating Subsidiaries received notice
that the EPA had identified them as potentially responsible parties
(PRPs) under the Comprehensive Environmental Response, Compensation and
Liability Act of 1980, as amended, with respect to the Jack's
Creek/Sitkin Smelting Superfund Site (Site). There are approximately
875 other PRPs involved. A Remedial Investigation/Feasibility Study
(RI/FS) prepared by the EPA indicates remedial alternatives which range
as high as $113 million, to be shared by all responsible parties. A PRP
Group has been formed and has submitted an addendum to the RI/FS which
proposes a substantially less expensive cleanup remedy. A final
determination has not been made for the Operating Subsidiaries' share of
the remediation costs based on the amount of materials sent to the site.
However, at this time it is estimated that the impact to the Operating
Subsidiaries will not be material.
Potomac Edison received a questionnaire on October 1, 1996 from
the EPA concerning a release or threat of release of hazardous
substances, pollutants, or contaminants into the environment at the
Butler Tunnel Site located in Luzerne County, Pennsylvania. Potomac
<PAGE> - 38 -
Edison notified the EPA that it has no records or recollection of any
business relations with the site or any of the companies identified in
the questionnaire. It is not possible to determine at this time what
impact, if any, this matter may have on Potomac Edison.
After protracted litigation concerning the Operating
Subsidiaries' application for a license to build a 1,000-MW energy-
storage facility near Davis, West Virginia, in 1988 the U.S. District
Court reversed the U.S. Army Corps of Engineers' (Corps) denial of a
dredge and fill permit on the grounds that, among other things, the
Operating Subsidiaries were denied an opportunity to review and comment
upon written materials and other communications used by the Corps in
reaching its decision. As a result, the Court remanded the matter to
the Corps for further proceedings. This remand order has been appealed
and negotiations are ongoing to settle this matter. The Operating
Subsidiaries cannot predict the outcome of this proceeding.
In 1979, National Steel Corporation (National Steel) filed suit
against APS and certain Subsidiaries in the Circuit Court of Hancock
County, West Virginia, alleging damages of approximately $7.9 million as
a result of an order issued by the West Virginia PSC requiring
curtailment of National Steel's use of electric power during the United
Mine Workers' strike of 1977-8. A jury verdict in favor of APS and the
Subsidiaries was rendered in June 1991. National Steel has filed a
motion for a new trial, which is still pending before the Circuit Court
of Hancock County. APS and the Subsidiaries believe the motion is
without merit; however, they cannot predict the outcome of this case.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
APS, Monongahela, Potomac Edison, West Penn and AGC did not
submit any matters to a vote of shareholders during the fourth quarter
of 1996.
<PAGE> - 39 -
Executive Officers of the Registrants
The names of the executive officers of each company, their ages as of December
31, 1996, the positions they hold, or held during 1996, and their business
experience during the past five years appears below:
<TABLE>
<CAPTION>
Position (a) and Period of Service
<S> <C> <C> <C> <C> <C> <C> <C>
Name Age APS APSC MP PE WP AGC
Charles S. Ault 58 V.P.
(1990- )
Eileen M. Beck 55 Secretary Secretary Secretary Secretary Secretary Secretary
(1988- ) (1988- ) (1995- ) (1996- ) (1996- ) (1982- )
Previously, Previously, Previously, Previously, Previously,
Asst. Treas. Asst. Treas. Asst. Treas. Asst. Sec. Asst. Sec.
(1979-95) (1979-95) (1981-95) (1988-95) (1988-95)
Asst. Sec.
(1988-94)
Klaus Bergman(b) 65 Chairman Chairman Chrm.& CEO Chrm.& CEO Chrm.& CEO Pres. & CEO
(1994- ) (1994-6/96) (1985-6/96) (1985-6/96) (1985-6/96) (1985-6/96)
CEO CEO Dir.(1985- ) Dir.(1985 ) Dir.(1985- ) Dir.(1982-6/96
(1985-6/96) (1985-6/96)
& Dir.(1985- ) & Dir.(1985- )
Previously, Previously,
Pres. Pres.
(1985-94) (1985-94)
Marvin W. Bomar(c) 56 V.P.
(9/95-96)
Nancy L. Campbell 57 V.P. V.P. Treasurer Treasurer Treasurer Treas. (1988- )
(1994- ) (1993- ) (1995- ) (1996- ) (1996- ) & Asst. Sec.
& Treas. & Treas. & Asst. Sec. (1988-96)
(1988- ) (1988- ) (1988-96)
Previously,
Asst. Treas.
(1988-95)
C. Vernon Estel, Jr. 41 V.P.
(4/96- )
Richard J. Gagliardi 46 V.P. V.P. Asst. Sec. Asst. Treas.
(1991- ) (1990- ) (1990-96) (1982-96)
Thomas K. Henderson 56 V.P. V.P. V.P. V.P. V.P. Dir.
(1997- ) (1996- ) (1995- ) (1995- ) (1985- ) (8/96- )
Previously,
Asst. V.P.
(9/95-12/95)
Kenneth M. Jones 59 V.P. & V.P. Dir. & V.P.
Controller (1991- ) (1991- )
(1991- ) Previously,
Controller
(1976-95)
Thomas J. Kloc 44 Controller Controller Controller Controller Controller
(1995- ) (1996- ) (1988- ) (1995- ) (1988- )
</TABLE>
(a) All officers and directors are elected annually.
(b) Retired as CEO effective June 1, 1996, and as Chairman to be
effective May 8, 1997.
(c) Retired effective July 1, 1996.
<PAGE> - 40 -
<TABLE>
<CAPTION>
Executive Officers of the Registrants, cont'd.
The names of the executive officers of each company, their ages, the positions
they hold and their business experience during the past five years appears below:
Position (a) and Period of Service
Name Age APS APSC MP PE WP AGC
<S> <C> <C> <C> <C> <C> <C> <C>
James D. Latimer 58 V.P. V.P. V.P.
(1995- ) (1995- ) (1995- )
Previously,
Executive V.P.
(6/94-12/95)
V.P.
(1988-6/94)
Michael P. Morrell(b) 48 Sr. V.P. Sr. V.P. Dir. & VP Dir. & VP Dir. & VP Dir. & V.P.
(5/96- ) (5/96- ) (12/96- ) (12/96- ) (12/96- ) (8/96- )
Alan J. Noia 49 CEO Chairman Chairman Chairman Chairman Chairman,
(6/96- ) & CEO & CEO & CEO & CEO Pres. & CEO
Pres.& Dir. (6/96- ) (6/96- ) (6/96- ) (6/96- ) (6/96- )
(1994- ) Pres.& Dir. Dir. Dir. Dir. Dir. & V.P.
COO (1994- ) (1994- ) (1990- ) (1994- ) (1994- 6/96)
(1994-6/96) COO Previously,
(1994-6/96) Pres.
(1990-94)
Karl V. Pfirrmann 48 V.P. V.P. V.P. V.P.
(1995-5/96) (5/96- ) (5/96- ) (5/96- )
Jay S. Pifer 59 Senior V.P. Senior V.P. Pres. & Dir. Pres. & Dir. Pres.
(1996- ) (1995- ) (1995- ) (1995- ) (1990- )
& Dir.
(1992- )
Richard A. Roschli(c) 62 V.P.
(1994-96)
Previously,
Asst. V.P.
(5/94-6/94);
Div. Mgr.
(1988-1994)
Victoria V. Schaff(d) 52 V.P. V.P.
(1/97- ) (1996- )
Peter J. Skrgic 55 Senior V.P. Senior V.P. V.P. V.P. V.P. Dir. & V.P.
(1994- ) (1994- ) (1996- ) (1990- ) (1996- ) (1989- )
Previously, Previously, & Dir. & Dir.
V.P. V.P. (1990- ) (1990- )
(1989-94) (1989-94)
Robert R. Winter 53 V.P. V.P. V.P.
(1987- ) (1995- ) (1995- )
</TABLE>
(a) All officers and directors are elected annually.
(b) Prior to joining Allegheny Power, Mr. Morrell was a V.P. - Regulatory and
Public Affairs, Jersey Central Power & Light Company (JCP&L) (8/94-4/96);
V.P. - Materials, Services and Regulatory Affairs, JCP&L, (1/93-8/94);
and V.P. and Treasurer, GPU, Inc. and Subsidiaries (2/86-1/93).
(c) Retired effective July 1, 1996.
(d) Prior to joining Allegheny Power, Ms. Schaff was a Federal Affairs
Representative with the Union Electric Company (4/88-12/95).
<PAGE> - 41 -
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, 1996, there were 58,677 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>
<S> <C> <C> <C> <C> <C> <C>
1996 1995
Dividend High Low Dividend High Low
1st Quarter 42 cents $30-7/8 $28 41 cents $24-3/8 $21-1/2
2nd Quarter 42 cents $31-1/16 $28-1/2 41 cents $25-1/8 $22-3/4
3rd Quarter 42 cents $31 $29 41 cents $26 $22-7/8
4th Quarter 43 cents $31-1/8 $28-7/8 42 cents $29-1/4 $25-1/2
</TABLE>
The high and low prices through March 6, 1997 were $30-3/4 and $30-
1/2. The last reported sale on that date was at $30-5/8.
Monongahela, Potomac Edison, and West Penn. The information
required by this Item is not applicable as all the common stock of the
Operating Subsidiaries is held by APS.
AGC. The information required by this Item is not applicable as
all the common stock of AGC is held by Monongahela, Potomac Edison, and
West Penn.
<PAGE> - 42 -
ITEM 6. SELECTED FINANCIAL DATA
Page No.
APS D-1
Monongahela D-3
Potomac Edison D-5
West Penn D-7
AGC D-9
<PAGE> D-1
<TABLE>
<CAPTION>
Allegheny Power System
Consolidated Statistics
Year ended December 31
<S> <C> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991 1986
Summary of Operations (Millions of Dollars)
Operating revenues(a) $2,327.6 $2,315.2 $2,184.6 $2,050.6 $1,962.6 $1,948.6 $1,585.9
Operation expense(a) 1,013.0 1,024.9 1,017.8 927.5 907.9 918.6 633.9
Maintenance 243.3 249.5 241.9 231.2 210.9 204.2 164.5
Restructuring charges and asset write-offs 103.9 23.4 9.2
Depreciation 263.2 256.3 223.9 210.4 197.8 189.7 150.9
Taxes other than income 185.4 184.7 183.1 178.8 174.6 167.5 116.6
Taxes on income 128.0 154.2 125.9 128.1 115.4 119.1 169.4
Allowance for funds used during construction (5.9) (8.2) (19.6) (21.5) (17.5) (7.9) (5.2)
Interest charges and preferred dividends 191.1 196.9 184.1 180.3 171.3 165.0 154.8
Other income and deductions (4.4) (6.2) (1.5) (1.3) (1.6) (2.7)
Consolidated income before cumulative
effect of accounting change $ 210.0 $ 239.7 $ 219.8 $ 215.8 $ 203.5 $ 194.0 $ 203.7
Cumulative effect of accounting change,
net(b) 43.4
Consolidated net income $ 210.0 $ 239.7 $ 263.2 $ 215.8 $ 203.5 $ 194.0 $ 203.7
Common Stock Data(c)
Shares outstanding (Thousands) 121,840 120,701 119,293 117,664 113,899 108,451 101,736
Average shares outstanding (Thousands) 121,141 119,864 118,272 114,937 111,226 107,548 100,998
Earnings per average share:
Consolidated income before cumulative
effect of accounting change $1.73 $2.00 $1.86 $1.88 $1.83 $1.80 $2.01
Cumulative effect of accounting change(b) .37
Consolidated net income $1.73 $2.00 $2.23 $1.88 $1.83 $1.80 $2.01
Dividends paid per share $1.69 $1.65 $1.64 $1.63 $1.605 $1.585 $1.43
Dividend payout ratio(d) 97.5% 82.5% 88.3% 86.9% 88.3% 87.8% 70.9%
Shareholders 58,677 63,280 66,818 63,396 63,918 62,095 73,365
Market price range per share:
High 31 1/8 29 1/4 26 1/2 28 7/16 24 3/8 23 1/4 26 15/16
Low 28 21 1/2 19 3/4 23 7/16 20 3/4 17 7/16 15 13/16
Book value per share $17.80 $17.65 $17.26 $16.62 $16.05 $15.54 $13.47
Return on average common equity(d) 9.69% 11.35% 10.96% 11.40% 11.45% 11.59% 15.30%
Capitalization Data (Millions of Dollars)
Common stock $2,169.1 $2,129.9 $2,059.3 $1,955.8 $1,827.8 $1,685.6 $1,370.5
Preferred stock:
Not subject to mandatory redemption 170.1 170.1 300.1 250.1 250.1 235.1 235.1
Subject to mandatory redemption 25.2 26.4 28.0 29.3 30.8
Long-term debt and QUIDS 2,397.1 2,273.2 2,178.5 2,008.1 1,951.6 1,747.6 1,584.1
Total capitalization $4,736.3 $4,573.2 $4,563.1 $4,240.4 $4,057.5 $3,697.6 $3,220.5
Capitalization ratios:
Common stock 45.8% 46.6% 45.1% 46.1% 45.0% 45.6% 42.5%
Preferred stock:
Not subject to mandatory redemption 3.6 3.7 6.6 5.9 6.2 6.3 7.3
Subject to mandatory redemption .6 .6 .7 .8 1.0
Long-term debt and QUIDS 50.6 49.7 47.7 47.4 48.1 47.3 49.2
Total Assets (Millions of Dollars) $6,618.5 $6,447.3 $6,362.2 $5,949.2 $5,039.3 $4,855.0 $4,199.9
Property Data (Millions of Dollars)
Gross property $8,206.2 $7,812.7 $7,586.8 $7,176.9 $6,679.9 $6,255.7 $5,092.4
Accumulated depreciation (2,910.0) (2,700.1) (2,529.4) (2,388.8) (2,240.0) (2,093.7) (1,404.6)
Net property $5,296.2 $5,112.6 $5,057.4 $4,788.1 $4,439.9 $4,162.0 $3,687.8
Gross additions during year-utility $ 289.5 $ 319.1 $ 508.3 $ 574.0 $ 487.6 $ 337.7 $ 197.6
-nonutility $ 178.5
Ratio of provisions for depreciation to
depreciable property 3.47% 3.50% 3.32% 3.37% 3.31% 3.28% 3.16%
<PAGE> D-2
Allegheny Power System
Consolidated Statistics (continued)
Year ended December 31
1996 1995 1994 1993 1992 1991 1986
Revenues (Millions of Dollars)
Residential $ 932.2 $ 927.0 $ 863.7 $ 818.4 $ 734.9 $ 708.3 $ 568.8
Commercial 492.7 493.7 459.3 430.2 391.9 375.4 295.7
Industrial 752.9 770.2 728.0 673.4 637.7 600.2 528.6
Wholesale and other(a) 74.3 66.1 65.8 60.3 60.0 58.7 47.9
Bulk power transactions, net(a) 75.5 58.2 67.8 68.3 138.1 206.0 144.9
Total revenues $2,327.6 $2,315.2 $2,184.6 $2,050.6 $1,962.6 $1,948.6 $1,585.9
Sales-GWh
Residential 13,328 13,003 12,630 12,514 11,746 11,755 9,839
Commercial 8,132 7,963 7,607 7,440 7,071 7,003 5,701
Industrial 18,568 18,457 17,708 16,967 16,910 16,430 14,725
Wholesale and other 1,456 1,304 1,275 1,240 1,186 1,146 994
Bulk power transactions, net(a) 18,477 15,093 10,491 13,009 18,590 19,762 10,162
Total sales 59,961 55,820 49,711 51,170 55,503 56,096 41,421
Output-GWh
Steam generation 40,067 39,174 38,959 38,247 40,373 42,307 37,175
Hydro and pumped-storage generation 1,348 1,234 1,390 1,233 1,204 1,654 953
Pumped-storage input (1,405) (1,390) (1,564) (1,385) (1,340) (1,907) (975)
Purchased power and exchanges, net(a) 22,920 19,607 13,541 15,866 18,116 16,872 6,671
Losses and system uses (2,969) (2,805) (2,615) (2,791) (2,850) (2,830) (2,403)
Total sales as above 59,961 55,820 49,711 51,170 55,503 56,096 41,421
Energy Supply
Generating capability-MW
System-owned 8,070 8,070 8,070 7,991 7,991 7,992 7,971
Nonutility contracts(e) 299 299 299 292 212 162
Maximum hour peak-MW 7,500 7,280 7,153 6,678 6,530 6,238 5,674
Load factor 67.5% 68.3% 66.8% 70.0% 69.3% 71.7% 67.8%
Heat rate-Btu's per kWh 9,910 9,970 9,927 10,020 9,910 9,956 10,023
Fuel costs-cents per million Btu's 129.22 130.20 141.50 142.12 141.93 143.19 146.25
Customers (Thousands)
Residential 1,213.7 1,204.4 1,189.7 1,176.6 1,161.5 1,146.6 1,067.8
Commercial 148.5 146.0 143.0 140.1 137.4 134.7 118.6
Industrial 25.0 24.6 24.2 23.8 23.6 23.1 21.0
Other 1.3 1.3 1.3 1.2 1.2 1.3 1.2
Total customers 1,388.5 1,376.3 1,358.2 1,341.7 1,323.7 1,305.7 1,208.6
Average Annual Use-kWh per customer
Residential-Allegheny Power 11,042 10,865 10,682 10,715 10,181 10,316 9,285
Residential-National 9,897(f) 9,583 9,378 9,394 8,949 9,280 8,627
All retail service-Allegheny Power 29,085 28,908 28,205 27,800 27,259 27,205 25,325
Average Rate-cents per kWh
Residential-Allegheny Power 6.99 7.13 6.84 6.54 6.26 6.03 5.78
Residential-National 8.80(f) 8.87 8.83 8.73 8.63 8.46 7.78
All retail service-Allegheny Power 5.46 5.58 5.43 5.23 4.96 4.80 4.62
</TABLE>
(a) Prior period amounts have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
(b) To record unbilled revenues, net of income taxes.
(c) Reflects a two-for-one common stock split effective November 4, 1993.
(d) Excludes the cumulative effect of the accounting change in 1994 and includes
the effect of restructuring in 1995 and 1996.
(e) Capability available through contractual arrangements with nonutility
generators.
(f) Preliminary.
<PAGE> D-3
<TABLE>
<CAPTION>
Monongahela Power Company
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991
Electric operating revenues:
Residential.......................... $206,033 $209,065 $190,861 $185,141 $169,589 $163,757
Commercial........................... 121,631 124,457 116,201 110,762 102,709 97,849
Industrial........................... 200,970 212,427 202,181 187,669 186,442 177,688
Wholesale and other, including
affiliates (a)..................... 86,474 84,193 90,351 71,573 49,403 42,133
Bulk power transactions, net (a)..... 17,363 13,338 16,853 18,136 38,319 60,383
Total............................ 632,471 643,480 616,447 573,281 546,462 541,810
Operation expense (a).................. 310,480 330,740 330,909 295,464 286,501 281,652
Maintenance............................ 74,735 73,041 69,389 67,770 62,909 64,035
Restructuring charges and asset
write-offs........................... 24,299 5,493
Depreciation........................... 55,490 57,864 57,952 56,056 53,865 51,903
Taxes other than income................ 40,418 38,551 40,404 34,076 33,207 35,378
Taxes on income........................ 34,496 41,834 30,650 33,612 27,919 31,173
Allowance for funds used
during construction.................. (672) (1,393) (2,946) (5,780) (3,908) (1,341)
Interest charges....................... 38,604 39,872 38,156 37,588 36,013 33,494
Other income, net...................... (6,831) (9,235) (8,003) (7,203) (8,388) (8,573)
Income before cumulative effect
of accounting change................. 61,452 66,713 59,936 61,698 58,344 54,089
Cumulative effect of accounting
change, net (b)...................... 7,945
Net income............................. $ 61,452 $ 66,713 $ 67,881 $ 61,698 $ 58,344 $ 54,089
Return on average common equity (c).... 11.00% 11.92% 10.66% 11.83% 11.96% 11.43%
</TABLE>
(a) Prior period amounts have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
(b) To record unbilled revenues, net of income taxes.
(c) Excludes the cumulative effect of the accounting change in 1994 and includes
the effect of restructuring in 1995 and 1996.
<PAGE> D-4
<TABLE>
<CAPTION>
Monongahela Power Company
FINANCIAL AND OPERATING STATISTICS
<S> <C> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.............................. $1,879,622 $1,821,613 $1,763,533 $1,684,322 $1,567,252 $1,458,643
Accumulated depreciation........... (790,649) (747,013) (701,271) (664,947) (628,595) (590,311)
Net.............................. $1,088,973 $1,074,600 $1,062,262 $1,019,375 $ 938,657 $ 868,332
GROSS ADDITIONS TO PROPERTY
(Thousands).......................... $ 72,577 $ 75,458 $ 103,975 $ 140,748 $ 126,422 $ 84,515
TOTAL ASSETS at Dec. 31
(Thousands).......................... $1,486,755 $1,480,591 $1,476,483 $1,407,453 $1,166,410 $1,091,287
CAPITALIZATION at Dec. 31:
Amount (Thousands):
Common stock....................... $ 512,212 $ 505,752 $ 495,693 $ 483,030 $ 475,628 $ 428,855
Preferred stock.................... 74,000 74,000 114,000 64,000 64,000 69,000
Long-term debt and QUIDS........... 474,841 489,995 470,131 460,129 444,506 372,618
$1,061,053 $1,069,747 $1,079,824 $1,007,159 $ 984,134 $ 870,473
Ratios:
Common stock....................... 48.3% 47.3% 45.9% 48.0% 48.3% 49.3%
Preferred stock.................... 7.0 6.9 10.6 6.3 6.5 7.9
Long-term debt and QUIDS........... 44.7 45.8 43.5 45.7 45.2 42.8
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31:
Company-owned...................... 2,326,300 2,326,300 2,326,300 2,325,300 2,325,300 2,325,300
Nonutility contracts (a)........... 161,000 161,000 161,000 159,000 79,000 29,000
KILOWATT-HOURS (Thousands):
Sales:
Residential........................ 2,815,414 2,807,135 2,674,664 2,689,830 2,527,247 2,581,628
Commercial......................... 2,007,116 1,967,473 1,846,791 1,825,127 1,742,469 1,744,881
Industrial......................... 5,024,257 5,114,126 4,942,388 4,656,921 4,872,126 4,905,715
Wholesale and other, including
affiliates....................... 1,836,920 1,734,537 1,925,450 1,565,561 824,393 584,677
Bulk power transactions, net (b)... 4,414,993 3,602,342 2,563,159 3,276,663 4,826,248 5,305,025
Total sales...................... 16,098,700 15,225,613 13,952,452 14,014,102 14,792,483 15,121,926
Output:
Steam generation................... 10,678,491 10,620,003 10,743,934 10,194,794 10,593,059 11,512,714
Pumped-storage generation.......... 263,640 257,284 290,586 263,329 260,155 375,500
Pumped-storage input............... (337,451) (330,915) (373,116) (337,737) (332,989) (475,898)
Purchased power and exchanges,
net (b).......................... 6,258,286 5,400,860 3,964,049 4,575,864 4,953,479 4,397,049
Losses and system uses............. (764,266) (721,619) (673,001) (682,148) (681,221) (687,439)
Total sales as above............. 16,098,700 15,225,613 13,952,452 14,014,102 14,792,483 15,121,926
CUSTOMERS at Dec. 31:
Residential.......................... 305,579 303,568 300,465 297,865 294,595 291,578
Commercial........................... 36,323 35,793 35,268 34,626 34,005 33,484
Industrial........................... 8,019 8,085 8,029 8,014 8,005 7,994
Other................................ 182 170 171 170 172 172
Total customers.................... 350,103 347,616 343,933 340,675 336,777 333,228
RESIDENTIAL SERVICE:
Average use-
kWh per customer................... 9,256 9,306 8,957 9,093 8,636 8,905
Average revenue-
dollars per customer............... 677.37 693.11 639.16 625.87 579.51 564.87
Average rate-
cents per kWh...................... 7.32 7.45 7.14 6.88 6.71 6.34
</TABLE>
(a) Capability available through contractual arrangements with nonutility
generators.
(b) Prior period amounts have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
<PAGE> D-5
The Potomac Edison Company
<TABLE>
<CAPTION>
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991
Electric operating revenues:
Residential.......................... $324,120 $316,714 $296,090 $274,358 $243,413 $227,851
Commercial........................... 146,432 145,096 135,937 124,667 111,506 104,642
Industrial........................... 196,813 200,890 195,089 175,902 157,304 147,654
Wholesale and other, including
affiliates (a)..................... 34,901 28,592 24,178 28,744 29,480 27,690
Bulk power transactions, net (a)..... 24,494 19,377 21,607 21,008 41,580 62,223
Total............................ 726,760 710,669 672,901 624,679 583,283 570,060
Operation expense (a).................. 373,133 374,731 362,167 325,239 310,335 319,472
Maintenance............................ 62,248 60,052 58,624 64,376 53,141 49,766
Restructuring charges and asset
write-offs........................... 26,094 6,847
Depreciation........................... 71,254 68,826 59,989 56,449 53,446 50,578
Taxes other than income................ 45,809 47,629 46,740 46,813 45,791 43,937
Taxes on income........................ 34,132 36,936 33,126 30,086 28,422 24,194
Allowance for funds used
during construction.................. (2,491) (1,752) (5,874) (7,134) (5,368) (3,366)
Interest charges....................... 50,197 51,179 46,456 43,802 39,392 36,831
Other income, net...................... (11,791) (12,044) (10,310) (8,419) (9,352) (9,593)
Income before cumulative effect
of accounting change................. 78,175 78,265 81,983 73,467 67,476 58,241
Cumulative effect of accounting
change, net (b)...................... 16,471
Net income............................. $ 78,175 $ 78,265 $ 98,454 $ 73,467 $ 67,476 $ 58,241
Return on average common equity (c).... 11.42% 11.34% 11.86% 11.63% 11.85% 11.04%
</TABLE>
(a) Prior period amounts have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
(b) To record unbilled revenues, net of income taxes.
(c) Excludes the cumulative effect of the accounting change in 1994 and includes
the effect of restructuring in 1995 and 1996.
<PAGE> D-6
<TABLE>
<CAPTION>
The Potomac Edison Company
FINANCIAL AND OPERATING STATISTICS
<S> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.................................. $2,124,956 $2,050,835 $1,978,396 $1,857,961 $1,698,711 $1,557,695
Accumulated depreciation............... (791,257) (729,653) (673,853) (632,269) (591,378) (546,867)
Net.................................. $1,333,699 $1,321,182 $1,304,543 $1,225,692 $1,107,333 $1,010,828
GROSS ADDITIONS TO PROPERTY
(Thousands).............................. $ 86,256 $ 92,240 $ 142,826 $ 179,433 $ 153,485 $ 116,589
TOTAL ASSETS at Dec. 31
(Thousands).............................. $1,677,886 $1,654,444 $1,629,535 $1,519,763 $1,355,385 $1,256,712
CAPITALIZATION at Dec. 31:
Amount (Thousands):
Common stock........................... $ 678,116 $ 667,242 $ 658,146 $ 626,467 $ 567,826 $ 480,931
Preferred stock:
Not subject to mandatory redemption.. 16,378 16,378 36,378 36,378 36,378 56,378
Subject to mandatory redemption...... 25,200 26,400 28,005 29,280
Long-term debt and QUIDS............... 628,431 628,854 604,749 517,910 511,801 453,584
$1,322,925 $1,312,474 $1,324,473 $1,207,155 $1,144,010 $1,020,173
Ratios:
Common stock........................... 51.3% 50.8% 49.7% 51.9% 49.6% 47.1%
Preferred stock:
Not subject to mandatory redemption.. 1.2 1.3 2.7 3.0 3.2 5.5
Subject to mandatory redemption...... 1.9 2.2 2.5 2.9
Long-term debt and QUIDS............... 47.5 47.9 45.7 42.9 44.7 44.5
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31 2,072,292 2,072,292 2,072,292 2,076,592 2,076,592 2,077,192
KILOWATT-HOURS (Thousands):
Sales:
Residential............................ 4,599,758 4,377,416 4,214,997 4,144,958 3,822,387 3,753,884
Commercial............................. 2,288,229 2,213,052 2,136,081 2,091,930 1,954,025 1,912,848
Industrial............................. 5,567,088 5,485,220 5,339,737 5,194,909 4,979,219 4,881,835
Wholesale and other, including
affiliates........................... 771,792 656,539 653,614 649,636 616,711 615,604
Bulk power transactions, net (a)....... 5,933,720 4,913,120 3,363,171 4,037,167 5,632,220 6,116,141
Total sales.......................... 19,160,587 17,645,347 15,707,600 16,118,600 17,004,562 17,280,312
Output:
Steam generation....................... 10,762,678 10,410,118 10,464,607 10,103,411 10,713,987 11,192,300
Hydro and pumped-storage generation.... 401,998 395,315 426,550 368,834 351,035 502,302
Pumped-storage input................... (455,142) (452,151) (506,213) (433,885) (407,393) (593,879)
Purchased power and exchanges, net (a). 9,257,431 8,058,312 6,065,083 6,868,168 7,175,251 6,984,666
Losses and system uses................. (806,378) (766,247) (742,427) (787,928) (828,318) (805,077)
Total sales as above................. 19,160,587 17,645,347 15,707,600 16,118,600 17,004,562 17,280,312
CUSTOMERS at Dec. 31:
Residential.............................. 327,344 321,813 315,309 309,096 302,559 295,564
Commercial............................... 42,670 41,759 40,927 40,173 39,236 38,522
Industrial............................... 4,887 4,733 4,595 4,509 4,435 4,283
Other.................................... 571 543 524 510 510 501
Total customers........................ 375,472 368,848 361,355 354,288 346,740 338,870
RESIDENTIAL SERVICE:
Average use-
kWh per customer....................... 14,179 13,729 13,506 13,562 12,766 12,822
Average revenue-
dollars per customer................... 999.10 993.35 948.76 897.70 812.96 778.25
Average rate-
cents per kWh.......................... 7.05 7.24 7.02 6.62 6.37 6.07
</TABLE>
(a) Prior period amounts have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
<PAGE> D-7
West Penn Power Company
and Subsidiaries
<TABLE>
<CAPTION>
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991
Electric operating revenues:
Residential.......................... $ 402,083 $ 401,186 $ 376,776 $ 358,900 $ 321,871 $ 316,685
Commercial........................... 224,663 224,144 207,165 194,773 177,697 172,924
Industrial........................... 355,120 356,937 330,739 309,847 293,910 274,896
Wholesale and other, including
affiliates (a)..................... 74,328 73,388 67,320 67,806 71,168 76,716
Bulk power transactions, net (a)..... 32,930 25,438 29,337 29,172 58,231 83,324
Total.............................. 1,089,124 1,081,093 1,011,337 960,498 922,877 924,545
Operation expense (a).................. 531,522 523,279 531,059 500,790 494,025 503,164
Maintenance............................ 104,211 114,489 111,841 96,706 93,067 87,717
Restructuring charges and asset
write-offs........................... 53,343 11,099 8,919
Depreciation........................... 119,066 112,334 88,935 80,872 73,469 70,334
Taxes other than income................ 90,132 89,694 87,224 89,249 87,300 80,630
Taxes on income........................ 47,455 61,745 46,645 51,529 44,078 47,846
Allowance for funds used
during construction.................. (2,723) (5,041) (10,777) (8,566) (8,276) (3,224)
Interest charges....................... 71,072 67,902 60,274 60,585 55,592 51,977
Other income, net...................... (13,439) (12,287) (13,798) (12,728) (14,534) (15,077)
Consolidated income before cumulative
effect of accounting change.......... 88,485 117,879 101,015 102,061 98,156 101,178
Cumulative effect of accounting
change, net (b)...................... 19,031
Consolidated net income................ $ 88,485 $ 117,879 $ 120,046 $ 102,061 $ 98,156 $ 101,178
Return on average common equity (c).... 8.72% 11.46% 9.94% 11.49% 11.53% 12.66%
</TABLE>
(a) Prior period amounts have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
(b) To record unbilled revenues, net of income taxes.
(c) Excludes the cumulative effect of the accounting change in 1994 and includes
the effect of restructuring in 1995 and 1996.
<PAGE> D-8
West Penn Power Company
and Subsidiaries
<TABLE>
<CAPTION>
FINANCIAL AND OPERATING STATISTICS
<S> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.................................. $3,182,208 $3,097,522 $3,013,777 $2,803,811 $2,581,641 $2,409,005
Accumulated depreciation............... (1,152,383) (1,063,399) (1,009,565) (962,623) (904,906) (857,999)
Net.................................. $2,029,825 $2,034,123 $2,004,212 $1,841,188 $1,676,735 $1,551,006
GROSS ADDITIONS TO PROPERTY
(Thousands).............................. $ 130,606 $ 149,122 $ 260,366 $ 251,017 $ 204,409 $ 134,443
TOTAL ASSETS at Dec. 31
(Thousands).............................. $2,699,737 $2,771,164 $2,731,858 $2,544,763 $2,083,127 $2,006,309
CAPITALIZATION at Dec. 31:
Amount (Thousands):
Common stock........................... $ 962,752 $ 973,188 $ 955,482 $ 893,969 $ 782,341 $ 774,707
Preferred stock........................ 79,708 79,708 149,708 149,708 149,708 109,708
Long-term debt and QUIDS............... 905,243 904,669 836,426 782,369 759,005 621,906
$1,947,703 $1,957,565 $1,941,616 $1,826,046 $1,691,054 $1,506,321
Ratios:
Common stock........................... 49.4% 49.7% 49.2% 49.0% 46.3% 51.4%
Preferred stock........................ 4.1 4.1 7.7 8.2 8.8 7.3
Long-term debt and QUIDS............... 46.5 46.2 43.1 42.8 44.9 41.3
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
GENERATING CAPABILITY--
kW at Dec. 31:
Company-owned.......................... 3,671,408 3,671,408 3,671,408 3,589,408 3,589,408 3,589,408
Nonutility contracts (a)............... 138,000 138,000 138,000 133,000 133,000 133,000
KILOWATT-HOURS (Thousands):
Sales:
Residential............................ 5,913,412 5,818,838 5,740,028 5,679,746 5,396,533 5,419,150
Commercial............................. 3,835,831 3,782,250 3,624,117 3,522,566 3,374,355 3,345,255
Industrial............................. 7,974,265 7,857,689 7,426,267 7,114,765 7,058,895 6,643,238
Wholesale and other, including
affiliates........................... 1,659,834 1,621,745 1,530,853 1,821,189 2,247,844 2,485,366
Bulk power transactions, net (b)....... 8,020,181 6,576,819 4,564,743 5,695,515 8,131,268 8,340,989
Total sales.......................... 27,403,523 25,657,341 22,886,008 23,833,781 26,208,895 26,233,998
Output:
Steam generation....................... 18,578,677 18,143,822 17,750,267 17,949,335 19,066,445 19,602,129
Hydro and pumped-storage generation.... 682,747 581,353 673,195 600,497 592,895 775,798
Pumped-storage input................... (612,877) (606,953) (684,715) (613,290) (599,729) (836,700)
Purchased power and exchanges, net (b). 10,150,319 8,856,122 6,347,394 7,218,469 8,490,110 8,030,357
Losses and system uses................. (1,395,343) (1,317,003) (1,200,133) (1,321,230) (1,340,826) (1,337,586)
Total sales as above................. 27,403,523 25,657,341 22,886,008 23,833,781 26,208,895 26,233,998
CUSTOMERS at Dec. 31:
Residential.............................. 580,816 578,983 573,963 569,601 564,300 559,444
Commercial............................... 69,457 68,500 66,842 65,337 64,212 62,674
Industrial............................... 12,051 11,801 11,563 11,218 11,138 10,826
Other.................................... 607 598 586 576 569 692
Total customers........................ 662,931 659,882 652,954 646,732 640,219 633,636
RESIDENTIAL SERVICE:
Average use-
kWh per customer....................... 10,223 10,096 10,041 10,025 9,608 9,733
Average revenue-
dollars per customer................... 695.08 696.06 659.07 633.48 573.07 568.76
Average rate-
cents per kWh.......................... 6.80 6.89 6.56 6.32 5.96 5.84
</TABLE>
(a) Capability available through contractual arrangements with nonutility
generators.
(b) Prior period amounts have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
<PAGE> D-9
<TABLE>
<CAPTION>
Allegheny Generating Company
STATISTICS
SUMMARY OF OPERATIONS
Year ended December 31
(Thousands of Dollars)
<S> <C> <C> <C> <C> <C> <C>
1996 1995 1994 1993 1992 1991
Electric operating revenues............ $ 83,402 $ 86,970 $ 91,022 $ 90,606 $ 96,147 $100,505
Operation and maintenance expense...... 5,165 5,740 6,695 6,609 6,094 6,774
Depreciation........................... 17,160 17,018 16,852 16,899 16,827 16,778
Taxes other than income taxes.......... 4,801 5,091 5,223 5,347 5,236 4,563
Federal income taxes................... 13,297 13,552 14,737 13,262 14,702 15,455
Interest charges....................... 16,193 18,361 17,809 21,635 22,585 24,030
Other income, net...................... (3) (16) (11) (328) (21) (24)
Net Income........................... $ 26,789 $ 27,224 $ 29,717 $ 27,182 $ 30,724 $ 32,929
Return on average common equity........ 12.58% 12.46% 13.14% 11.72% 12.79% 13.09%
PROPERTY, PLANT, AND EQUIPMENT
at Dec. 31 (Thousands):
Gross.............................. $837,050 $836,894* $824,714 $824,904 $825,493 $822,332
Accumulated depreciation........... (176,178) (159,037) (143,965) (128,375) (114,684) (97,915)
Net.............................. $660,872 $677,857 $680,749 $696,529 $710,809 $724,417
GROSS ADDITIONS TO PROPERTY
(Thousands).......................... $ 178 $ 14,165* $ 1,065 $ 2,729 $ 3,251 $ 1,391
TOTAL ASSETS
at Dec. 31 (Thousands)............... $692,408 $710,287 $714,236 $735,929 $727,820 $742,223
CAPITALIZATION at Dec. 31:
Amount (in thousands):
Common stock....................... $202,955 $214,153 $222,729 $228,512 $235,530 $244,593
Long-term debt..................... 228,634 249,709 267,165 277,196 287,139 299,502
$431,589 $463,862 $489,894 $505,708 $522,669 $544,095
Ratios:
Common stock....................... 47.0% 46.2% 45.5% 45.2% 45.1% 45.0%
Long-term debt..................... 53.0 53.8 54.5 54.8 54.9 55.0
100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
KILOWATT-HOURS (Thousands):
Pumping energy supplied by parents... 1,405,470 1,390,019 1,564,044 1,384,912 1,340,111 1,906,477
Pumped-storage generation............ 1,098,278 1,081,112 1,218,446 1,079,985 1,047,015 1,504,310
</TABLE>
*Reflects a balance sheet reclassification of $12 million from deferred charges
to plant for a prior tax payment.
<PAGE> - 43 -
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Page No.
APS M- 1
Monongahela M-12
Potomac Edison M-20
West Penn M-28
AGC M-38
<PAGE> M-1
Allegheny Power System
Management's Discussion and Analysis of Financial Condition
and Results of Operations
Review of Operations
Earnings
Earnings for 1996, 1995, and 1994, and the after tax restructuring charges,
asset write-offs, and cumulative effect of accounting change included in
each period are:
<TABLE>
<CAPTION>
Consolidated Net Income Per Share
<S> <C> <C> <C> <C> <C> <C>
(Millions of Dollars Except 1996 1995 1994 1996 1995 1994
for Per Share Data)
Consolidated Net Income as Reported $210 $240 $263 $1.73 $2.00 $2.23
Restructuring Charges & Asset Write-
offs (Note B) 63 14 5 .52 .12 .05
Cumulative Effect of Accounting
Change (NoteA) (43) (.37)
Consolidated Net Income Adjusted $273 $254 $225 $2.25 $2.12 $1.91
The increases in 1996 and 1995 adjusted consolidated net income were
due primarily to increases in kilowatt-hour (Kwh) sales and, in 1995, also
to increased revenues from retail rate increases.
In 1996, the Company and its subsidiaries essentially completed
their restructuring initiatives undertaken in 1995 to consolidate and
reengineer operations to meet the competitive challenges of the changing
electric utility industry. Although restructuring initiatives have been
essentially completed, review of operations will be a continuing
process. During 1996, restructuring activities included consolidation of
operating divisions, customer services, and other functions. By
reorganizing and eliminating certain processes and condolidating common
decentralized functions, the Company and its subsidiaries reduced
employment by about 1,000 employees since October 1994. These reductions
were accomplished through a voluntary separation plan, attrition, and
layoffs. Due to efficiencies created by the restructuring process, a
reduction in the rate of growth in operating and maintenance costs is
expected. The costs associated with the restructuring program will be
recovered through future cost savings. Restructuring activities are
described further in Note B to the Consolidated Financial Statements.
Competitive forces within the electric utility industry were
heightened in 1996 with the enactment of the Pennsylvania Electric
Generation Customer Choice and Competition Act and issuance of the
Federal Energy Regulatory Commission (FERC) Orders 888 and 889. The
Company continues to advocate true competition in the electric utility
industry and is proactive in its efforts to promote deregulation. See
Competition in Core Business on page M-8 for a further discussion of
competitive issues in the electric utility industry.
<PAGE> M-2
Sales and Revenues
Kwh sales to and revenues from residential, commercial, and industrial
customers are shown on page D-2. Such Kwh sales increased 2% and 4% in
1996 and 1995, respectively. The changes in revenues from sales to
residential, commercial, and industrial customers resulted from the
following:
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <C>
Changes from Prior Year
(Millions of Dollars) 1996 1995
Increased Kwh sales $27.2 $ 56.2
Fuel and energy cost adjustment clauses* (40.3) (2.8)
Rate changes:
Pennsylvania 50.2
Maryland 17.7
West Virginia 19.3
Ohio 5.6 .5
5.6 87.7
Other (5.5) (1.2)
Net Change in Retail Revenues $(13.0) $139.9
</TABLE>
*Changes in revenues from fuel and energy cost adjustment clauses have
little effect on consolidated net income. See "Rate Caps" under
Competition in Core Business on page M-10 for information regarding a
potential change in the fuel and energy cost adjustment clause (Energy
Cost Rate or ECR) in Pennsylvania.
The increase in Kwh sales in 1996 was attributable to increases in
each of the residential, commercial, and industrial customer classes.
Residential Kwh sales increased 3% in both 1996 and 1995. These
increases, which are more weather sensitive than commercial and
industrial sales, were due primarily to increased customer usage and
continued growth in the number of customers. The Company measures the
effect of weather conditions on its utility sales by using degree days,
which reflect the differences between the average daily actual
temperature and the baseline temperature of 65 degrees. In 1996, heating
degree days in the relatively colder January-through-April period were
about 10% greater than the corresponding 1995 period. This increase was
somewhat offset by milder weather during the remainder of the year. In
1995, increased sales resulted from extremely hot summer weather and
cooler-than-normal winter weather.
The 2% increase in commercial sales in 1996 and the 5% increase in
1995 reflect growth in the number of customers, and, in 1995, also
reflects increased customer usage. Industrial sales increased 1% and 4%
in 1996 and 1995, respectively. Excluding the decrease in the fuel and
energy cost component of industrial sales, revenues from sales to
industrial customers also increased over 1% in 1996. The increase in Kwh
sales reflects a trend of economic growth in the service territory and
the efforts of the newly formed Retail Marketing Business Unit. With the
increased potential for retail competition and in light of the
Pennsylvania legislation (see Competition in Core Business on M-8), this
function has been expanded to increase efforts to retain and acquire
customers and to expand into other markets.
<PAGE> M-3
Increases resulting from rate changes were minimal for 1996, as
the base rate increases effective in 1994 have been fully reflected in
both the 1996 and 1995 periods. As a result of the Pennsylvania
competition legislation, West Penn Power's (West Penn) rates have been
capped effective January 1, 1997. This is more fully described on page
M-9.
The increase in wholesale and other revenues in 1996 resulted
primarily from load additions to the wholesale customers' systems
(cooperatives and municipalities who own their own distribution systems
and who buy all or part of their bulk power needs from the subsidiaries
under regulation by the FERC). Competition in the wholesale market for
electricity was enhanced by the Energy Policy Act of 1992 (EPACT), which
permits wholesale generators, utility-owned and otherwise, and wholesale
customers to request from owners of bulk power transmission facilities a
commitment to supply transmission services. An agreement in principle
was reached with one customer in 1996, representing $3 million in annual
wholesale revenues, for a new five-year contract effective in 1997. With
this new contract, all of the wholesale customers have signed contracts
to remain as customers for periods ranging from two to six years. Kwh
deliveries to and revenues from bulk power transactions consist of the
following items:
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C>
1996 1995 1994
Kwh deliveries (Billions):
From transmission services 17.5 14.6 9.4
From sale of
subsidiaries' generation 1.0 .5 1.1
Total 18.5 15.1 10.5
Revenues (Millions):
From transmission services $52.9 $45.2 $38.8
From sale of
subsidiaries' generation 22.6 13.0 29.0
Total $75.5 $58.2 $67.8
</TABLE>
The final rules on open transmission access, issued by the FERC in
early 1996, require utilities to offer to others transmission service
that is comparable to service they provide to themselves. Increased
transmission services in 1996 resulted primarily from increased activity
from power marketers who have agreed to take service under the new open
access tariffs filed by the subsidiaries in accordance with these rules.
Deliveries from the sale of subsidiaries' generation in 1995 decreased
because of growth in Kwh sales to retail customers, which reduced the
amount available for sale, and because of continuing price competition.
About 95% of the aggregate benefits from bulk power transactions are
passed on to retail customers through fuel cost adjustment clauses and
have little effect on consolidated net income. See page M-10 for
information regarding the potential change in the ECR for Pennsylvania.
Operating Expenses
The 1% increase in fuel expenses in 1996 was due to a 2% increase
in Kwh generated, offset in part by lower average coal prices. The 7%
decrease in fuel expenses in 1995 was primarily the result of
renegotiations of long-term fuel contracts which reduced fuel prices
<PAGE> M-4
effective in January 1995. Fuel expenses for the regulated subsidiaries
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 their fuel expenses have little effect on
consolidated net income. See page M-10 for information regarding the
potential change in the ECR for Pennsylvania.
"Purchased Power and Exchanges, Net" represents power purchases
from and exchanges with other utilities and purchases from qualified
facilities under the Public Utility Regulatory Policies Act of 1978
(PURPA) and consists of the following items:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
(Millions of Dollars) 1996 1995 1994
Purchased power:
From PURPA generation $132.7 $129.3 $134.0
Other 48.4 49.0 40.4
Total purchased power 181.1 178.3 174.4
Power exchanges, net 3.3 (.2) ( .6)
Purchased power and
exchanges, net $184.4 $178.1 $173.8
</TABLE>
The decrease in purchase costs from PURPA generation in 1995 was
due primarily to a contractual reduction in the energy rate effective in
June 1995 for the Grant Town PURPA project. In 1996, West Penn and the
developers of a proposed Shannopin PURPA project reached an agreement to
terminate the project at a buyout price of $31 million. The Pennsylvania
Public Utility Commission (PUC) has authorized full recovery of the
buyout price, of which $24 million was recovered by reducing West Penn's
over-recovered fuel balance. The remaining $7 million was to be
recovered in 1997 and 1998, but, pursuant to the recent Pennsylvania
rate caps enacted by the new Pennsylvania Electric Generation Customer
Choice and Competition Act, will be recovered through other means. The
buyout will save West Penn's customers approximately $665 million over
the next 30 years by eliminating the need to buy the uneconomic power.
A PURPA power station project in The Potomac Edison Company's
(Potomac Edison) Maryland jurisdiction is scheduled to commence
generation in 1999. Because of the high cost of this energy, Potomac
Edison has attempted to negotiate a buyout or restructure the existing
contract to reduce the cost to customers. To date, the negotiations have
been unsuccessful. This project will significantly increase the cost of
power purchases.
None of the subsidiaries' purchased power contracts is capitalized
since there are no minimum payment requirements absent associated Kwh
generation. The cost of power purchased, including power from PURPA
generation, is mostly recovered from customers currently through the
regular fuel and energy cost recovery procedures with the result that
changes in such costs have little effect on consolidated net income. See
page M-10 for information regarding the potential change in the ECR for
Pennsylvania.
<PAGE> M-5
The increase in other operation expense in 1996 resulted primarily
from increased allowances for uncollectible accounts ($4 million) and
the write-off of deferred Clean Air Act Amendments of 1990 (CAAA)
compliance costs ($4 million). For 1997 and thereafter, operations
expense is expected to reflect the benefits of savings related to the
restructuring activities. Allowances for uncollectible accounts
increased 40% in 1996 due to an increase in aged accounts receivable
caused primarily by regulations in Pennsylvania which severely restrict
curtailment of service to non-paying customers.
Maintenance expenses represent costs incurred to maintain the
power stations, the transmission and distribution (T&D) system, and
general plant, and reflect routine maintenance of equipment and rights-
of-way as well as planned major repairs and unplanned expenditures,
primarily from forced outages at the power stations and periodic storm
damage on the T&D system. Variations in maintenance expense result
primarily from unplanned events and planned major projects, which vary
in timing and magnitude, depending upon the length of time equipment has
been in service without a major overhaul and the amount of work found
necessary when the equipment is dismantled.
Restructuring charges and asset write-offs resulted primarily from
the completion of restructuring initiatives undertaken in 1995 and the
write-off of previously accumulated costs related to a proposed
transmission line. See Note B to the Consolidated Financial Statements
for additional information.
Depreciation expense increases resulted primarily from additions
to electric plant. The subsidiaries began depreciating the Harrison
scrubbers in mid-November 1994, amounting to $32 million annually.
Future depreciation expense increases for utility operations are
expected to be less than historical increases because of reduced levels
of planned capital expenditures.
The increase in taxes other than income in 1996 was due to higher
property taxes and, in 1995, reflects increases in gross receipts taxes
resulting from higher revenues from retail customers. The net decrease
in federal and state income taxes in 1996 resulted primarily from a
decrease in income before taxes ($23 million), which was primarily
related to restructuring charges recorded in 1996. The net increase of
$28 million in federal and state income taxes in 1995 resulted primarily
from an increase in income before taxes ($20 million) and an increase in
reversals of prior year depreciation benefits for which deferred taxes
were not then provided ($6 million). Note C to the Consolidated
Financial Statements provides a further analysis of income tax expenses.
The combined decreases in allowances for funds used during
construction in 1996 and 1995 were $2 million and $11 million,
respectively, and reflect decreases in capital expenditures due to
substantial completion of the program to comply with Phase I of the
CAAA.
<PAGE> M-6
The decrease in other income, net, of $2 million in 1996 was due
primarily to a write-off of a deferred return on West Virginia
expenditures related to the CAAA and increased interest income in 1995
associated with the 1995 refinancings. The increase in other income,
net, of $5 million in 1995 was due primarily to income from demand-side
management programs. During 1996, Potomac Edison continued its
participation in the collaborative process for demand-side management in
Maryland. Program costs, including lost revenues and rebates, are
deferred as a regulatory asset and are being recovered through an energy
conservation surcharge over a seven-year period.
Dividends on preferred stock decreased $6 million and $5 million
in 1996 and 1995, respectively, due primarily to the redemption of
preferred stock issues refinanced with the June 1995 issuance of $155.5
million of Quarterly Income Debt Securities (QUIDS). The increase in
interest on long-term debt associated with the QUIDS was offset in 1996
by decreased interest on first mortgage bonds due primarily to
refinancings to lower rate securities in 1995. Other interest expense
reflects changes in the levels of short-term debt maintained by the
companies throughout the year, as well as the associated interest rates.
Environmental and Other Issues
In the normal course of business, the subsidiaries are subject to
various contingencies and uncertainties relating to their operations and
construction programs, including cost recovery in the regulatory
process, laws, regulations and uncertainties related to environmental
matters, and legal actions. Contingencies and uncertainties related to
the restructuring of the electric utility industry and the recently
passed Pennsylvania restructuring legislation are discussed in
Competition in Core Business on page M-8.
The significant costs of complying with Phase I of the CAAA have
essentially been incurred and are being recovered currently from
customers in rates. Studies to evaluate cost-effective options to comply
with Phase II SO2 limits, including those which may be available from
the use of the Company's banked emission allowances and from the
emission allowance trading market, are continuing. It is expected that
burner modifications, which have been completed at most of the System's
stations, will satisfy the NOx emission reduction requirements for the
acid rain (Title IV) provisions of the CAAA. Additional post-combustion
controls may be mandated in Maryland, Pennsylvania, and West Virginia
for ozone nonattainment (Title I) reasons.
The subsidiaries previously reported that the Environmental
Protection Agency had identified them and approximately 875 others as
potentially responsible parties in a Superfund site subject to cleanup.
A final determination has not been made for the subsidiaries' share of
the remediation costs based on the amount of materials sent to the site.
The subsidiaries have also been named as defendants along with multiple
other defendants in pending asbestos cases involving one or more
plaintiffs. The subsidiaries believe that provisions for liabilities and
<PAGE> M-7
insurance recoveries are such that final resolution of these claims will
not have a material effect on their financial position.
Financial Condition and Requirements
Liquidity and Capital Requirements
To meet the System companies' need for cash for operating
expenses, the payment of interest and dividends, retirement of debt and
certain preferred stocks, and for their construction programs, the
companies have used internally generated funds and external financings,
such as the sale of common and preferred stock, debt instruments,
installment loans, and lease arrangements. The timing and amount of
external financings depend primarily upon economic and financial market
conditions, the companies' cash needs, and capitalization ratio
objectives. The availability and cost of external financing depend upon
the financial health of the companies seeking those funds.
Construction expenditures of the regulated subsidiaries in 1996 were
$289 million and, for 1997 and 1998, are estimated at $322 million and
$324 million, respectively. The 1997 and 1998 estimated expenditures
include $37 million and $59 million, respectively, for construction of
environmental control technology. Expenditures in the future to cover
the costs of compliance with Phase II of the CAAA may be significant
depending on the method chosen to meet the requirements. Based on
current forecasts and considering the reactivation and repowering of
capacity in cold reserve, peak diversity exchange arrangements, demand-
side management and conservation programs, and mandated PURPA capacity,
it is anticipated that generating capacity will be sufficient to meet
the Company's needs until the year 2000 or beyond. It is the Company's
goal to constrain future base capital spending, with the exception of
mandated environmental expenditures, to the approximate level of
depreciation currently in rates. The regulated subsidiaries also have
additional capital requirements for debt maturities (see Note J to the
Consolidated Financial Statements). The Company will have additional
capital requirements in the future related to nonutility investments of
AYP Capital, which are described under Nonutility Business on page M-11.
Internal Cash Flows
Internal generation of cash, consisting of cash flows from
operations reduced by dividends, was $386 million in 1996 compared with
$281 million in 1995. Current rate levels and reduced levels of capital
expenditures permitted the regulated subsidiaries to finance their
entire capital expenditure program in 1996 and approximately 88% in 1995
through internal cash generation. It is expected that internal
generation of cash over the next several years will continue to finance
the majority of utility capital expenditures. See page M-11 for a
description of future nonutility investments. Dividends paid on common
stock in 1996 increased to $1.69 per share compared with $1.65 in 1995.
<PAGE> M-8
The dividend payout ratio, excluding the restructuring charges and asset
write-offs in 1996 and 1995, decreased in 1996. It is expected that the
payout ratio will continue to decline in future years.
As capital-intensive electric utilities, the regulated
subsidiaries are affected by the rate of inflation. The inflation rate
over the past several years has been relatively low and has not
materially affected their financial position. However, since utility
revenues are currently based on rate regulation that generally only
recognizes historical costs, cash flows based on recovery of historical
plant may not be adequate to replace plant in future years.
The increase in current liabilities for restructuring activities
is related primarily to payout provisions under employee severance
packages. Materials and supplies continued to provide a source of cash
in 1996, primarily related to lower contracted fuel prices and to
maintaining optimum levels of inventories.
Financing
During 1996, the Company issued 1,139,518 shares of common stock
under its Dividend Reinvestment and Stock Purchase Plan (DRISP) and
Employee Stock Ownership and Savings Plan (ESOSP) for $33.8 million. The
Company plans to continue to issue DRISP/ESOSP shares in the future.
Short-term debt is used to meet temporary cash needs until the timing is
considered appropriate to issue long-term securities. Short-term debt
decreased $44 million to $156 million in 1996. At December 31, 1996,
unused lines of credit with banks were $325 million.
During 1997, Monongahela Power Company anticipates issuing $45
million of new debt for general corporate purposes, including its
construction program. The other subsidiaries anticipate they will be
able to meet their 1997 cash needs through internal cash generation. See
page M-11 for information on financing requirements for nonutility
investments.
Competition in Core Business
All states in the System's service territory have initiated
inquiries or investigations into retail competition and electric utility
restructuring, with Pennsylvania enacting legislation in December 1996.
Pennsylvania, which accounts for 45% of retail revenues for the Company,
became only the fourth state in the country to legislate retail electric
competition. The transition to competition in Pennsylvania will be
phased in over the periods described below. The legislation includes the
following major provisions:
All electric utilities in Pennsylvania must file
a restructuring plan by September 30, 1997, to implement
direct access to a competitive market for electric
generation. The plan must include unbundled rates for
<PAGE> M-9
generation, jurisdictional transmission, distribution and
other services, a proposed mechanism for recovery of
stranded costs, and a proposed universal service and energy
conservation cost recovery mechanism. West Penn is scheduled
to make its filing on or about June 1, 1997.
Retail customer choice will be phased in
beginning with one-third of retail customers in the year
1999, another one-third in 2000, and the remaining customers
in 2001.
Retail rates will be capped for at least 4-1/2
years for transmission and distribution charges and for as
long as 9 years for generation charges. A utility may be
exempted from the caps only under very specific
circumstances as determined by the Pennsylvania PUC.
Pennsylvania utilities are permitted to recover
PUC-approved transition or stranded costs over several
years; however, the utilities are required to mitigate these
costs to the extent practicable.
The Company is currently evaluating the new legislation to
formulate its plan to implement direct access to a competitive market.
As required in the legislation, in 1997 West Penn and other Pennsylvania
electric utilities are required to implement Retail Customer Choice
Pilot Programs for up to 5% of the peak load of their customers. This
will result in customers with as much as 165 MW of West Penn's retail
load being eligible to choose an alternate supplier of generation. The
Company's subsidiaries on the other hand anticipate the opportunity to
offer capacity and/or energy to customers of other Pennsylvania
utilities' pilot programs. The Company cannot predict the ultimate
effect of this legislation, but the issues being evaluated include:
Stranded Cost Recovery - Stranded costs can generally be described as
mandated costs (such as regulatory assets and obligations under PURPA
contracts) and costs of generation that could be recovered in a
regulated environment but cannot be recovered in a competitive
environment because they are in excess of market. The Pennsylvania
legislation permits recovery of both types from customers through a
competitive transition charge (CTC), with the provision that utilities
have an obligation to mitigate stranded costs to the extent practicable.
Over the CTC recovery period, which can be up to nine years, all
Pennsylvania utilities are permitted a CTC charge to recover costs in
excess of market. Because West Penn has no high-cost nuclear power
stations, its CTC charge for costs in excess of market, if any, may be
significantly less than the other utilities. West Penn is concerned that
it may be placed at a significant competitive disadvantage in the first
several phase-in years because other utilities with excess capacity may
be willing to sell energy at marginal cost rates, lower than West Penn's
full-cost rates, until the excess capacity is used. Under this
possibility, West Penn would have stranded costs in the early years.
<PAGE> M-10
West Penn's restructuring plan filing on or about June 1, 1997, will
address this issue.
Applicability of SFAS No. 71 - In accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
regulated subsidiaries' financial statements reflect assets and
liabilities based on current cost-based ratemaking regulation. Once the
Pennsylvania transition to full retail competition is completed, West
Penn may not meet the criteria for applying SFAS No. 71 to its
generation operations and assets. In that event, any remaining related
regulatory assets and liabilities, if any, would be written off, and any
related long-lived fixed and intangible assets would need to be
evaluated for impairment under the provisions of SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of." Because of the provisions in the new
legislation related to stranded cost recovery, West Penn does not
believe any such write-offs or charges should be required.
Rate Caps - As a result of the Pennsylvania legislation, West Penn's
rates, including its energy cost rates, have been capped effective
January 1, 1997. The legislation did not eliminate the ECR tracking
procedure and left to PUC discretion the method of future rate
adjustments for energy costs. In 1997, West Penn is reviewing its option
to file a Petition with the PUC to roll the energy cost rates into its
base rates. Upon receipt of a PUC order to that effect, which is
expected if a Petition is filed, West Penn would then assume the risks
of increases in the costs of fuel and purchased power and any declines
in bulk power transaction sales. However, West Penn would also retain
the benefits of decreases in such costs and increases in such sales.
West Penn would accomplish this result by discontinuance of deferred
fuel accounting.
Initiatives on comprehensive retail competition at the federal
government level are also being undertaken. The Company believes that a
federal framework of legislation to speed customer choice and provide a
uniform framework for rules is necessary because of differences among
the states. The Company supports deregulation of all generation,
regulation of transmission by the FERC, and regulation of distribution
by the states. The Company joined with seven other electric utilities in
1996 to form the Partnership for Customer Choice whose purpose is to
seek enactment of federal legislation to bring choice to electric
customers no later than the year 2000. The legislation sought would
deregulate the generation of electric power, creating a free market for
electricity.
The Company is also advocating federal legislation to repeal
Section 210 of PURPA and the Public Utility Holding Company Act of 1935
(PUHCA). Both of these laws severely impede the Company's ability to
compete on equal terms with both utility and nonutility electric
providers who are not subject to their requirements.
<PAGE> M-11
Nonutility Business
AYP Capital, the System's nonutility subsidiary, has continued to
broaden its operations to strengthen the long-term competitiveness and
profitability of the Company. In 1996, this included the formation of
two wholly owned subsidiaries, AYP Energy, Inc. (AYP Energy) and
Allegheny Communications Connect, Inc. (ACC).
AYP Energy is an exempt wholesale generator and power marketer. In
October 1996, AYP Energy purchased Duquesne Light Company's 50% interest
(276 MW) in Unit No. 1 of the Fort Martin Power Station for about $170
million. The remainder of the station is owned by the Company's
regulated subsidiaries. AYP Energy incurs depreciation expense and other
operating expenses related to Fort Martin. AYP Energy is marketing the
output from its share of the station, as well as engaging in other power
marketing activities. The operation of a merchant plant and power
marketing in the wholesale market is essentially participation in a
commodity market, which creates certain risk exposure. AYP Energy
expects to use exchange-traded and over-the-counter futures, options,
and swap contracts both to hedge its exposure to changes in electric
power prices and for trading purposes. The risks to which AYP Energy is
exposed include underlying price volatility, credit risk, and variations
in cash flows, among others. The Company is in the process of
implementing risk management policies and procedures consistent with
industry practices and Company goals.
AYP Energy financed its October 1996 acquisition of the 50%
interest of Fort Martin Power Station Unit No. 1 with a combination of
$25 million of equity contribution from the Company and $160 million of
five-year debt financing provided by a syndicate of banks. AYP Energy's
obligation under the Credit Agreement is supported by the Company. The
debt is priced at a floating rate. AYP Energy entered into a $160
million forward swap to hedge against fluctuations in interest rates
during the five-year period. The swap converted the floating rate to an
annual fixed rate of 6.78% for the five-year period. Throughout the
five-year period, the floating rate may be above or below the fixed rate
but is only relevant in the event of termination prior
to maturity.
ACC was formed in 1996 as an exempt telecommunications company
under PUHCA. ACC's purpose is to develop unregulated opportunities in
the deregulated communications market.
AYP Capital has also committed to invest up to an additional $7
million in two limited partnerships, Envirotech Investment Fund I, L.P.,
formed to invest in emerging electrotechnologies that promote the
efficient use of electricity and improve the environment, and the Latin
American Energy and Electricity Fund I, L.P., formed to invest in and
develop electric energy opportunities in Latin America. AYP Capital will
continue to evaluate investment opportunities with potentially
significant additional capital investments in the future.
AYP Capital is also developing other energy-related service
businesses and offering engineering consulting services and project
management for transmission and distribution facilities. The Company
believes that the diversification provided by AYP Capital will
ultimately enhance earnings growth.
<PAGE> M-12
Monongahela Power Company
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income for 1996, 1995, and 1994, and the after tax restructuring
charges, asset write-offs, and cumulative effect of accounting changes
included in each period are:
<TABLE>
<CAPTION>
Net Income
<S> <C> <C> <C>
(Millions of Dollars) 1996 1995 1994
Net Income as Reported................... $61 $67 $68
Restructuring Charges &
Asset Write-offs (Note B).............. 15 3
Cumulative Effect of
Accounting Change (Note A)............. (8)
Net Income Adjusted...................... $76 $70 $60
</TABLE>
The increases in 1996 and 1995 adjusted net income were due primarily to
increased revenues from previously reported retail rate increases, and
in 1995 also from increased kilowatt-hour (kWh) sales.
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). In 1996, the System, including the Company, essentially
completed its restructuring initiatives undertaken in 1995 to
consolidate and reengineer operations to meet the competitive challenges
of the changing electric utility industry. Although restructuring
initiatives have been essentially completed, review of operations will
be a continuing process. During 1996, restructuring activities included
consolidation of operating divisions, customer services, and other
functions. By reorganizing and eliminating certain processes and
consolidating common decentralized functions, the System reduced
employment by about 1,000 employees since October 1994. These
reductions were accomplished through a voluntary separation plan,
attrition, and layoffs. Due to efficiencies created by the
restructuring process, a reduction in the rate of growth in operating
and maintenance costs is expected. The costs associated with the
restructuring program will be recovered through future cost savings.
<PAGE> M-13
Restructuring activities are described further in Note B to the
Financial Statements.
Competitive forces within the electric utility industry were heightened
in 1996 with the issuance of the Federal Energy Regulatory Commission
(FERC) Orders 888 and 889. The Company continues to advocate true
competition in the electric utility industry and is proactive in its
efforts to promote deregulation. See Competition in Core Business on
page M-19 for a further discussion of competitive issues in the electric
utility industry.
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 decreased .4% in
1996 and increased 4.5% in 1995. The changes in revenues from sales to
residential, commercial, and industrial customers resulted from the
following:
<TABLE>
<CAPTION>
Changes
from Prior Year
(Millions of Dollars) 1996 1995
<C> <C> <C>
(Decreased) increased kWh sales.................. $ (.7) $21.6
Fuel and energy cost adjustment clauses*......... (22.0) (3.1)
Rate changes:
West Virginia.................................. 17.1
Ohio........................................... 5.6 .5
5.6 17.6
Other............................................ (.2) .6
Net Change in Retail Revenues.................. $(17.3) $36.7
</TABLE>
*Changes in revenues from fuel and energy cost adjustment clauses have
little effect on net income.
Residential kWh sales increased .3% and 5% in 1996 and 1995,
respectively. These increases were due primarily to continued growth in
the number of customers, and in 1995 also due to increased customer
usage. In 1996, residential usage decreased because of mild weather in
comparison to the 1995 extremely hot summer weather and cooler-than-
normal winter weather.
The 2% increase in commercial kWh sales in 1996 and the 7% increase in
1995 reflect growth in the number of customers and increased customer
usage. Industrial kWh sales decreased 2% in 1996 due primarily to
decreased sales to chemical customers and increased 3% in 1995. With
the increased potential for retail competition (see Competition in Core
Business on page M-19), the efforts of the newly formed Retail Marketing
Business Unit have been expanded to increase efforts to retain and
acquire customers and to expand into other markets.
<PAGE> M-14
The rate increase in Ohio became effective on November 9, 1995 and
included recovery of the remaining carrying charges on investment,
depreciation, and all operating costs required to comply with Phase I of
the Clean Air Act Amendments of 1990 (CAAA), and other increasing levels
of expenses. There were no increases from rate changes in West
Virginia, as the base rate increase effective in 1994 has been fully
reflected in both the 1996 and 1995 periods.
The increase in wholesale and other revenues in 1996 resulted primarily
from increases in sales of capacity to affiliated companies. The
decrease in other revenues in 1995 resulted primarily from a decrease in
sales of energy and spinning reserve to affiliated companies, offset in
part by increased revenues from wholesale customers (cooperatives and
municipalities who own their own distribution systems and who buy all or
part of their bulk power needs from the Company under regulation by the
FERC). Competition in the wholesale market for electricity was enhanced
by the Energy Policy Act of 1992 (EPACT), which permits wholesale
generators, utility-owned and otherwise, and wholesale customers to
request from owners of bulk power transmission facilities a commitment
to supply transmission services. In 1994, a rate case for wholesale
customers was completed with the result that such customers agreed to
negotiated rate increases and signed five-year contracts to remain as
the Company's customers.
KWh deliveries to and revenues from bulk power transactions consist of
the following items:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
KWh deliveries (Billions):
From transmission services............. 4.2 3.5 2.3
From sale of Company generation........ .2 .1 .3
Total................................ 4.4 3.6 2.6
Revenues (Millions):
From transmission services............. $12.6 $10.6 $ 9.2
From sale of Company generation........ 4.8 2.7 7.7
Total................................ $17.4 $13.3 $16.9
</TABLE>
The final rules on open transmission access, issued by the FERC in early
1996, require utilities to offer to others transmission service that is
comparable to service they provide to themselves. Increased
transmission services in 1996 resulted primarily from increased activity
from power marketers who have agreed to take service under the new open
access tariffs filed by the Company in accordance with these rules.
Deliveries from the sale of Company generation in 1995 decreased because
of growth in kWh sales to retail customers, which reduced the amount
available for sale, and because of continuing price competition. About
90% of the aggregate benefits from bulk power transactions are passed on
to retail customers through fuel cost adjustment clauses and have little
effect on net income.
<PAGE> M-15
Operating Expenses
The 1% decrease in fuel expenses in 1996 was primarily due to lower
average coal prices. The 9% decrease in fuel expenses in 1995 was
primarily the result of renegotiations of long-term fuel contracts which
reduced fuel prices effective in January 1995. 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 purchases from qualified
facilities under the Public Utility Regulatory Policies Act of 1978
(PURPA), capacity charges paid to Allegheny Generating Company (AGC), an
affiliate partially owned by the Company, and other transactions with
affiliates made pursuant to a power supply agreement whereby each
company uses the most economical generation available in the System at
any given time, and consists of the following items:
<TABLE>
<CAPTION>
(Millions of Dollars) 1996 1995 1994
<S> <C> <C> <C> <C>
Nonaffiliated transactions:
Purchased power:
From PURPA generation................ $ 69.1 $64.6 $68.3
Other................................ 11.3 11.7 9.5
Power exchanges, net................... .9 .1 (.2)
Affiliated transactions:
AGC capacity charges................... 20.2 20.6 20.1
Energy and spinning reserve charges.... .1 .4 .5
Purchased power and exchanges, net... $101.6 $97.4 $98.2
</TABLE>
The decrease in purchase costs from PURPA generation in 1995 was due
primarily to a contractual reduction in the energy rate effective in
June 1995 for the Grant Town PURPA project. None of the Company's
purchased power contracts is capitalized since there are no minimum
payment requirements absent associated kWh generation. The cost of
power purchased, including power from PURPA generation and affiliated
transactions, is mostly recovered from customers currently through the
regular fuel and energy cost recovery procedures with the result that
changes in such costs have little effect on net income.
The decrease in other operation expense in 1996 resulted primarily from
decreases in salaries and wages and employee benefits. For 1997 and
thereafter, operations expense is expected to reflect the benefits of
savings related to the restructuring activities.
<PAGE> M-16
Maintenance expenses represent costs incurred to maintain the power
stations, the transmission and distribution (T&D) system, and general
plant, and reflect routine maintenance of equipment and rights-of-way as
well as planned major repairs and unplanned expenditures, primarily from
forced outages at the power stations and periodic storm damage on the
T&D system. Variations in maintenance expense result primarily from
unplanned events and planned major projects, which vary in timing and
magnitude, depending upon the length of time equipment has been in
service without a major overhaul and the amount of work found necessary
when the equipment is dismantled.
Restructuring charges and asset write-offs resulted primarily from the
completion of restructuring initiatives undertaken in 1995. See Note B
to the Financial Statements for additional information.
The depreciation expense decrease in 1996 was the net result of a
reduction in depreciation rates of $5.3 million, effective in January
1996, offset by additions to electric plant of $3 million. The Company
began depreciating the Harrison scrubbers in mid-November 1994,
amounting to approximately $8 million annually. Future depreciation
expense increases are expected to be less than historical increases
because of reduced levels of planned capital expenditures.
The increase in taxes other than income in 1996 was due to higher
property taxes and a prior period adjustment in West Virginia Business
and Occupation (B&O) Taxes. The decrease in 1995 was primarily due to a
decrease in West Virginia B&O Taxes resulting from an amendment in the
B&O tax law effective June 1995, which changed the basis for this tax
from generation to generating capacity. The net decrease in federal and
state income taxes in 1996 resulted primarily from a decrease in income
before taxes ($4 million), which was primarily related to restructuring
charges recorded in 1996, and changes in the provisions for prior years
($2 million). The net increase of $11 million in federal and state
income taxes in 1995 resulted from an increase in income before taxes
($7 million) and changes in the provisions for prior years ($4 million).
Note C to the Financial Statements provides a further analysis of income
tax expenses.
The combined decreases in allowances for funds used during construction
in 1996 and 1995 were about $1 million and $2 million, respectively, and
reflect decreases in capital expenditures due to substantial completion
of the program to comply with Phase I of the CAAA.
The decrease in other income, net, of $2 million in 1996 was due
primarily to a write-off of a deferred return on West Virginia
expenditures related to the CAAA and increased interest income in 1995
associated with the 1995 refinancings. The increase in other income,
net, of $1 million in 1995 reflects an increase in the deferral of
carrying charges on CAAA expenditures in Ohio until the base rate
increase became effective in November 1995, proceeds from the sale of
timber, and interest income on a tax refund.
<PAGE> M-17
The increase in interest on long-term debt associated with the June 1995
issuance of $40 million of Quarterly Income Debt Securities (QUIDS) was
offset in 1996 by decreased interest on first mortgage bonds due
primarily to refinancings to lower rate securities in 1995. Other
interest expense reflects changes in the levels of short-term debt
maintained by the Company throughout the year, as well as the associated
interest rates.
Environmental and Other Issues
In the normal course of business, the Company is subject to various
contingencies and uncertainties relating to its operations and
construction programs, including cost recovery in the regulatory
process, laws, regulations and uncertainties related to environmental
matters, and legal actions. Contingencies and uncertainties related to
the restructuring of the electric utility industry are discussed in
Competition in Core Business on page M-19.
The significant costs of complying with Phase I of the CAAA have
essentially been incurred and are being recovered currently from
customers in rates. Studies to evaluate cost-effective options to
comply with Phase II SO2 limits, including those which may be available
from the use of the Company's banked emission allowances and from the
emission allowance trading market, are continuing. It is expected that
burner modifications, which have been completed at most of the System's
stations, will satisfy the NOX emission reduction requirements for the
acid rain (Title IV) provisions of the CAAA. Additional post-combustion
controls may be mandated in Maryland, Pennsylvania, and West Virginia
for ozone nonattainment (Title I) reasons.
The Company previously reported that the Environmental Protection Agency
had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup. A final determination has not been made for the Company's
share of the remediation costs based on the amount of materials sent to
the site.
The Company has also been named as a defendant along with multiple other
affiliated and nonaffiliated defendants in pending asbestos cases
involving one or more plaintiffs. The Company believes that provisions
for liabilities and insurance recoveries are such that final resolution
of these claims will not have a material effect on its financial
position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash for operating expenses, the payment
of interest and dividends, retirement of debt and certain preferred
<PAGE> M-18
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the sale of
common and preferred stock, debt instruments, installment loans, and
lease arrangements. The timing and amount of external financings depend
primarily upon economic and financial market conditions, the Company's
cash needs, and capitalization ratio objectives. The availability and
cost of external financing depend upon the financial health of the
companies seeking those funds.
Construction expenditures in 1996 were $73 million and, for 1997 and
1998, are estimated at $83 million and $91 million, respectively. The
1997 and 1998 estimated expenditures include $13 million and $18
million, respectively, for construction of environmental control
technology. Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant depending on the method
chosen to meet the requirements. Based on current forecasts and
considering an affiliate's reactivation and repowering of capacity in
cold reserve, peak diversity exchange arrangements, and a power supply
agreement with affiliates, it is anticipated that generating capacity
will be sufficient to meet the Company's needs until the year 2000 or
beyond. It is the Company's goal to constrain future base capital
spending, with the exception of mandated environmental expenditures, to
the approximate level of depreciation currently in rates. The Company
also has additional capital requirements for debt maturities (see Note J
to the Financial Statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $92 million in 1996 compared with $93 million
in 1995. Current rate levels and reduced levels of capital expenditures
permitted the Company to finance its entire capital expenditure program
in 1996 and 1995 through internal cash generation. It is expected that
internal generation of cash over the next several years will continue to
finance the majority of capital expenditures.
As a capital-intensive electric utility, the Company is affected by the
rate of inflation. The inflation rate over the past several years has
been relatively low and has not materially affected the Company's
financial position. However, since utility revenues are currently based
on rate regulation that generally only recognizes historical costs, cash
flows based on recovery of historical plant may not be adequate to
replace plant in future years.
The increase in current liabilities for restructuring activities is
related primarily to payout provisions under employee severance
packages. Materials and supplies continued to provide a source of cash
in 1996, primarily related to lower contracted fuel prices and to
maintaining optimum levels of inventories.
<PAGE> M-19
Financing
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 $1
million to $31 million in 1996. At December 31, 1996, the Company had
Securities and Exchange Commission authorization to issue up to $100
million of short-term debt. The Company and its regulated affiliates
use an internal money pool as a facility to accommodate intercompany
short-term borrowing needs, to the extent that certain of the companies
have funds available. During 1997, the Company anticipates issuing $45
million of new debt for general corporate purposes, including its
construction program.
COMPETITION IN CORE BUSINESS
All states in the System's service territory have initiated inquiries or
investigations into retail competition and electric utility
restructuring, with Pennsylvania enacting legislation in December 1996.
In December 1996, the Public Service Commission of West Virginia issued
an order initiating a general investigation for the purpose of seeking
comments and information regarding the restructuring of the regulated
electric utility industry, establishment of competition in power supply
markets, and establishment of retail wheeling and intra-state open
access of jurisdictional power distribution systems. Public hearings
are scheduled to begin on April 1, 1997.
The Public Utilities Commission of Ohio (Ohio PUC) has initiated
informal roundtable discussions on issues concerning competition in the
electric utility industry and promoting increased competitive options
for Ohio businesses. The meetings have resulted in sets of guidelines
on interruptible rates which have been adopted by the Ohio PUC and
guidelines on conjunctive service which are now pending before the Ohio
PUC.
Initiatives on comprehensive retail competition at the federal
government level are also being undertaken. The Company believes that a
federal framework of legislation to speed customer choice and provide a
uniform framework for rules is necessary because of differences among
the states. The System, including the Company, supports deregulation of
all generation, regulation of transmission by the FERC, and regulation
of distribution by the states. The System, including the Company,
joined with seven other electric utilities in 1996 to form the
Partnership for Customer Choice whose purpose is to seek enactment of
federal legislation to bring choice to electric customers no later than
the year 2000. The legislation sought would deregulate the generation
of electric power, creating a free market for electricity.
The System is also advocating federal legislation to repeal Section 210
of PURPA and the Public Utility Holding Company Act of 1935. Both of
these laws severely impede the Company's ability to compete on equal
terms with both utility and nonutility electric providers who are not
subject to their requirements.
<PAGE> M-20
The Potomac Edison Company
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Net Income
Net income for 1996, 1995, and 1994, and the after tax restructuring
charges, asset write-offs, and cumulative effect of accounting change
included in each period are:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
Net Income
(Millions of Dollars) 1996 1995 1994
Net Income as Reported..................... $78 $78 $98
Restructuring Charges &
Asset Write-Offs (Note B)................ 16 4
Cumulative Effect of
Accounting Change (Note A)............... (16)
Net Income Adjusted........................ $94 $82 $82
</TABLE>
The increase in 1996 adjusted net income was due primarily to increases
in kilowatt-hour (kWh) sales.
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). In 1996, the System, including the Company, essentially
completed its restructuring initiatives undertaken in 1995 to
consolidate and reengineer operations to meet the competitive challenges
of the changing electric utility industry. Although restructuring
initiatives have been essentially completed, review of operations will
be a continuing process. During 1996, restructuring activities included
consolidation of operating divisions, customer services, and other
functions. By reorganizing and eliminating certain processes and
consolidating common decentralized functions, the System reduced
employment by about 1,000 employees since October 1994. These
reductions were accomplished through a voluntary separation plan,
attrition, and layoffs. Due to efficiencies created by the
restructuring process, a reduction in the rate of growth in operating
and maintenance costs is expected. The costs associated with the
restructuring program will be recovered through future cost savings.
Restructuring activities are described further in Note B to the
Financial Statements.
<PAGE> M-21
Competitive forces within the electric utility industry were heightened
in 1996 with the issuance of the Federal Energy Regulatory Commission
(FERC) Orders 888 and 889. The Company continues to advocate true
competition in the electric utility industry and is proactive in its
efforts to promote deregulation. See Competition in Core Business on
page M-27 for a further discussion of competitive issues in the electric
utility industry.
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 3.1%
and 3.3% in 1996 and 1995, respectively. The changes in revenues from
sales to residential, commercial, and industrial customers resulted from
the following:
<TABLE>
<CAPTION>
Changes
from Prior Year
<S> <C> <C>
(Millions of Dollars) 1996 1995
Increased kWh sales.............................. $17.7 $17.3
Fuel and energy cost adjustment clauses*......... (10.5) 3.2
Rate changes:
Maryland....................................... 17.7
West Virginia.................................. 2.2
19.9
Other............................................ (2.5) (4.8)
Net Change in Retail Revenues.................. $ 4.7 $35.6
</TABLE>
*Changes in revenues from fuel and energy cost adjustment clauses have
little effect on net income.
The increase in kWh sales in 1996 was attributable to increases in each
of the residential, commercial, and industrial customer classes.
Residential kWh sales increased 5% in 1996 and 4% in 1995. These
increases, which are more weather sensitive than commercial and
industrial sales, were due primarily to increased customer usage and
continued growth in the number of customers. The Company measures the
effect of weather conditions on its utility sales by using degree days,
which reflect the differences between the average daily actual
temperature and the baseline temperature of 65 degrees. In 1996,
heating degree days in the relatively colder January-through-April
period were about 12% greater than the corresponding 1995 period. This
increase was somewhat offset by milder weather during the remainder of
the year. In 1995, increased sales resulted from extremely hot summer
weather and cooler-than-normal winter weather.
The 3% increase in commercial kWh sales in 1996 and the 4% increase in
1995 reflect growth in the number of customers and increased customer
usage. Industrial kWh sales increased 1% and 3% in 1996 and 1995,
respectively. Excluding the decrease in the fuel and energy cost
component of industrial sales, revenues from sales to industrial
<PAGE> M-22
customers also increased over 1% in 1996. The increase in kWh sales
reflects a trend of economic growth in the service territory and the
efforts of the newly formed Retail Marketing Business Unit. With the
increased potential for retail competition (see Competition in Core
Business on page M-27), this function has been expanded to increase
efforts to retain and acquire customers and to expand into other
markets.
Base rate increases effective in 1994 have been fully reflected in both
the 1996 and 1995 periods.
The increase in wholesale and other revenues in 1996 resulted primarily
from load additions to the wholesale customers' systems (cooperatives
and municipalities who own their own distribution systems and who buy
all or part of their bulk power needs from the Company under regulation
by the FERC). Competition in the wholesale market for electricity was
enhanced by the Energy Policy Act of 1992 (EPACT), which permits
wholesale generators, utility-owned and otherwise, and wholesale
customers to request from owners of bulk power transmission facilities a
commitment to supply transmission services. An agreement in principle
was reached with one customer in 1996, representing $3 million in annual
wholesale revenues, for a new five-year contract effective in 1997.
With this new contract, all of the wholesale customers have signed
contracts to remain as the Company's customers for two to five years.
The increase in wholesale and other revenues in 1995 resulted primarily
from provisions recorded for rate refunds in 1994 and increased revenues
from wholesale customers.
KWh deliveries to and revenues from bulk power transactions consist of
the following items:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
1996 1995 1994
KWh deliveries (Billions):
From transmission services............ 5.6 4.7 3.1
From sale of Company generation....... .3 .2 .3
Total............................... 5.9 4.9 3.4
Revenues (Millions):
From transmission services............ $16.9 $14.8 $12.7
From sale of Company generation....... 7.6 4.6 8.9
Total............................... $24.5 $19.4 $21.6
</TABLE>
The final rules on open transmission access, issued by the FERC in early
1996, require utilities to offer to others transmission service that is
comparable to service they provide to themselves. Increased
transmission services in 1996 resulted primarily from increased activity
from power marketers who have agreed to take service under the new open
access tariffs filed by the Company in accordance with these rules.
Deliveries from the sale of Company generation in 1995 decreased because
of growth in kWh sales to retail customers, which reduced the amount
available for sale, and because of continuing price competition. About
95% of the aggregate benefits from bulk power transactions are passed on
<PAGE> M-23
to retail customers through fuel cost adjustment clauses and have little
effect on net income.
Operating Expenses
The 2% increase in fuel expenses in 1996 was due to a 3% increase in kWh
generated, offset in part by lower average coal prices. The 7% decrease
in fuel expenses in 1995 was primarily the result of renegotiations of
long-term fuel contracts which reduced fuel prices effective in January
1995. Fuel expenses are primarily subject to deferred power cost
accounting procedures, as described in Note A to the financial
statements, with the result that changes in fuel expenses have little
effect on net income.
"Purchased power and exchanges, net" represents power purchases from and
exchanges with nonaffiliated utilities, capacity charges paid to
Allegheny Generating Company (AGC), an affiliate partially owned by the
Company, and other transactions with affiliates made pursuant to a power supply
agreement whereby each company uses the most economical generation
available in the System at any given time, and consists of the following
items:
<TABLE>
<CAPTION>
<S> <C> <C> <C>
(Millions of Dollars) 1996 1995 1994
Nonaffiliated transactions:
Purchased power........................ $ 14.8 $ 15.6 $ 12.7
Power exchanges, net................... 1.7 (.2) (.2)
Affiliated transactions:
AGC capacity charges................... 26.9 28.1 29.4
Other affiliated capacity charges...... 47.7 44.0 36.1
Energy and spinning reserve charges.... 49.9 49.8 52.7
Purchased power and exchanges, net... $141.0 $137.3 $130.7
</TABLE>
A Public Utility Regulatory Policies Act of 1978 (PURPA) power station
project in the Company's Maryland jurisdiction is scheduled to commence
generation in 1999. Because of the high cost of this energy, the
Company has attempted to negotiate a buyout or restructure the existing
contract to reduce the cost to customers. To date, the negotiations
have been unsuccessful. This project will significantly increase the
costs of power purchases.
The cost of power purchased from nonaffiliates for use by the Company,
AGC capacity charges in West Virginia, and affiliated energy and
spinning reserve charges are mostly recovered from customers currently
through the regular fuel and energy cost recovery procedures with the
result that changes in such costs have little effect on net income.
Maintenance expenses represent costs incurred to maintain the power
stations, the transmission and distribution (T&D) system, and general
<PAGE> M-24
plant, and reflect routine maintenance of equipment and rights-of-way as
well as planned major repairs and unplanned expenditures, primarily from
forced outages at the power stations and periodic storm damage on the
T&D system. Variations in maintenance expense result primarily from
unplanned events and planned major projects, which vary in timing and
magnitude, depending upon the length of time equipment has been in
service without a major overhaul and the amount of work found necessary
when the equipment is dismantled.
Restructuring charges and asset write-offs resulted primarily from the
completion of restructuring initiatives undertaken in 1995. See Note B
to the Financial Statements for additional information.
Depreciation expense increases resulted primarily from additions to
electric plant. The Company began depreciating the Harrison scrubbers
in mid-November 1994, amounting to approximately $10 million annually.
Future depreciation expense increases are expected to be less than
historical increases because of reduced levels of planned capital
expenditures.
The decrease in taxes other than income in 1996 was primarily due to a
decrease in West Virginia Business and Occupation Taxes (B&O) resulting
from an amendment in the B&O tax law effective June 1995, which changed
the basis for this tax from generation to generating capacity. The net
decrease of $3 million in federal and state income taxes in 1996
resulted primarily from changes in the provisions for prior years ($1
million), a decrease in income before taxes ($1 million) which was
primarily related to restructuring charges recorded in 1996, and plant
removal tax deductions for which deferred taxes were not provided ($1
million). The net increase of $4 million in federal and state income
taxes in 1995 resulted primarily from an increase in reversals of prior
year depreciation benefits for which deferred taxes were not then
provided. Note C to the Financial Statements provides a further
analysis of income tax expenses.
The combined increase in allowances for funds used during construction
(AFUDC) in 1996 of $.7 million is the result of a correction to reduce
previously accrued AFUDC by $1.4 million in 1995. The combined decrease
in AFUDC in 1995 reflects a decrease in capital expenditures due to
substantial completion of the program to comply with Phase I of the
Clean Air Act Amendments of 1990 (CAAA).
The increase in other income, net, of $2 million in 1995 was due
primarily to income from demand-side management programs. During 1996,
the Company continued its participation in the collaborative process for
demand-side management in Maryland. Program costs, including lost
revenues and rebates, are deferred as a regulatory asset and are being
recovered through an energy conservation surcharge over a seven-year
period.
The increase in interest on long-term debt associated with the June 1995
issuance of $45.5 million of Quarterly Income Debt Securities (QUIDS)
was offset in 1996 by decreased interest on first mortgage bonds due
<PAGE> M-25
primarily to refinancings to lower rate securities in 1995. Other
interest expense reflects changes in the levels of short-term debt
maintained by the Company throughout the year, as well as the associated
interest rates.
Environmental and Other Issues
In the normal course of business, the Company is subject to various
contingencies and uncertainties relating to its operations and
construction programs, including cost recovery in the regulatory
process, laws, regulations and uncertainties related to environmental
matters, and legal actions. Contingencies and uncertainties related to
the restructuring of the electric utility industry are discussed in
Competition in Core Business on page M-27.
The significant costs of complying with Phase I of the CAAA have
essentially been incurred and are being recovered currently from
customers in rates. Studies to evaluate cost-effective options to
comply with Phase II SO2 limits, including those which may be available
from the use of the Company's banked emission allowances and from the
emission allowance trading market, are continuing. It is expected that
burner modifications, which have been completed at most of the System's
stations, will satisfy the NOx emission reduction requirements for the
acid rain (Title IV) provisions of the CAAA. Additional post-combustion
controls may be mandated in Maryland, Pennsylvania, and West Virginia
for ozone nonattainment (Title I) reasons.
The Company previously reported that the Environmental Protection Agency
had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup. A final determination has not been made for the Company's
share of the remediation costs based on the amount of materials sent to
the site. The Company has also been named as a defendant along with
multiple other affiliated and nonaffiliated defendants in pending
asbestos cases involving one or more plaintiffs. The Company believes
that provisions for liabilities and insurance recoveries are such that
final resolution of these claims will not have a material effect on its
financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash for operating expenses, the payment
of interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the sale of
common and preferred stock, debt instruments, installment loans, and
lease arrangements. The timing and amount of external financings depend
primarily upon economic and financial market conditions, the Company's
<PAGE> M-26
cash needs, and capitalization ratio objectives. The availability and
cost of external financing depend upon the financial health of the
companies seeking those funds.
Construction expenditures in 1996 were $86 million and, for 1997 and
1998, are estimated at $98 million and $109 million, respectively. The
1997 and 1998 estimated expenditures include $7 million and $11 million,
respectively, for construction of environmental control technology.
Expenditures in the future to cover the costs of compliance with Phase
II of the CAAA may be significant depending on the method chosen to meet
the requirements. Based on current forecasts and considering an
affiliate's reactivation and repowering of capacity in cold reserve,
peak diversity exchange arrangements, a power supply agreement with
affiliates, and mandated PURPA capacity, it is anticipated that
generating capacity will be sufficient to meet the Company's needs until
the year 2000 or beyond. It is the Company's goal to constrain future
base capital spending, with the exception of mandated environmental
expenditures, to the approximate level of depreciation currently in
rates. The Company also has additional capital requirements for debt
maturities (see Note I to the Financial Statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $116 million in 1996 compared with $85 million
in 1995. Current rate levels and reduced levels of capital expenditures
permitted the Company to finance its entire capital expenditure program
in 1996 and approximately 92% in 1995 through internal cash generation.
It is expected that internal generation of cash over the next several years
will continue to finance the majority of capital expenditures.
As a capital-intensive electric utility, the Company is affected by the
rate of inflation. The inflation rate over the past several years has
been relatively low and has not materially affected the Company's
financial position. However, since utility revenues are currently based
on rate regulation that generally only recognizes historical costs, cash
flows based on recovery of historical plant may not be adequate to
replace plant in future years.
The increase in current liabilities for restructuring activities is
related primarily to payout provisions under employee severance
packages. Materials and supplies continued to provide a source of cash
in 1996, primarily related to lower contracted fuel prices and to
maintaining optimum levels of inventories.
Financings
Short-term debt is used to meet temporary cash needs until the timing is
considered appropriate to issue long-term securities. Short-term debt
decreased $14 million to $7 million in 1996. At December 31, 1996, the
Company had Securities and Exchange Commission authorization to issue up
to $115 million of short-term debt. The Company and its regulated
<PAGE> M-27
affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of
the companies have funds available. The Company anticipates that it
will be able to meet its 1997 cash needs through internal cash
generation.
COMPETITION IN CORE BUSINESS
All states in the Company's service territory have initiated inquiries
or investigations into retail competition and electric utility
restructuring, with Pennsylvania enacting legislation in December 1996.
In December 1996, the Public Service Commission of West Virginia issued
an order initiating a general investigation for the purpose of seeking
comments and information regarding the restructuring of the regulated
electric utility industry, establishment of competition in power supply
markets, and establishment of retail wheeling and intra-state open
access of jurisdictional power systems. Public hearings are scheduled
to begin on April 1, 1997.
In September 1995, the Virginia State Corporation Commission (SCC) began
an investigation to review its policy regarding restructuring of and
competition in the electric industry. In November 1996, the SCC ordered
further investigation into restructuring of the industry, requiring the
three largest electric utilities in Virginia, including the Company, to
file competition information by March 31, 1997.
On October 9, 1996, the Maryland Public Service Commission issued an
order directing its Staff to evaluate the current state of the electric
industry and to submit a report to the Commission by May 31, 1997. The
four major Maryland electric utilities, including the Company, are to present
unbundled cost studies and model service tariffs, among other things, by
August 1, 1997.
Initiatives on comprehensive retail competition at the federal
government level are also being undertaken. The Company believes that a
federal framework of legislation to speed customer choice and provide a
uniform framework for rules is necessary because of differences among
the states. The System, including the Company, supports deregulation of
all generation, regulation of transmission by the FERC, and regulation
of distribution by the states. The System, including the Company,
joined with seven other electric utilities in 1996 to form the
Partnership for Customer Choice whose purpose is to seek enactment of
federal legislation to bring choice to electric customers no later than
the year 2000. The legislation sought would deregulate the generation
of electric power, creating a free market for electricity.
The System is also advocating federal legislation to repeal Section 210
of PURPA and the Public Utility Holding Company Act of 1935. Both of
these laws severely impede the Company's ability to compete on equal
terms with both utility and nonutility electric providers who are not
subject to their requirements.
<PAGE> M-28
West Penn Power Company
and Subsidiaries
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
REVIEW OF OPERATIONS
Consolidated Net Income
Consolidated net income for 1996, 1995, and 1994, and the after tax
restructuring charges, asset write-offs, and cumulative effect of
accounting change included in each period are:
<TABLE>
<CAPTION>
Consolidated Net Income
<S> <C> <C> <C>
(Millions of Dollars) 1996 1995 1994
Consolidated Net Income as Reported.......... $ 88 $118 $120
Restructuring Charges &
Asset Write-Offs (Note B).................. 31 7 5
Cumulative Effect of
Accounting Change (Note A)................. (19)
Consolidated Net Income Adjusted............. $119 $125 $106
</TABLE>
The decrease in 1996 adjusted consolidated net income was due primarily
to higher depreciation expense, increased charge-offs for uncollectible
accounts, and the write-off of deferred Clean Air Amendments of 1990
(CAAA) compliance costs. The increase in 1995 adjusted consolidated net
income resulted primarily from additional retail revenues due to
increased kilowatt-hour (kWh) sales and retail rate increases.
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). In 1996, the System, including the Company, essentially
completed its restructuring initiatives undertaken in 1995 to
consolidate and reengineer operations to meet the competitive challenges
of the changing electric utility industry. Although restructuring
initiatives have been essentially completed, review of operations will
be a continuing process. During 1996, restructuring activities included
consolidation of operating divisions, customer services, and other
functions. By reorganizing and eliminating certain processes and
consolidating common decentralized functions, the System reduced
employment by about 1,000 employees since October 1994. These
reductions were accomplished through a voluntary separation plan,
<PAGE> M-29
attrition, and layoffs. Due to efficiencies created by the
restructuring process, a reduction in the rate of growth in operating
and maintenance costs is expected. The costs associated with the
restructuring program will be recovered through future cost savings.
Restructuring activities are described further in Note B to the
Consolidated Financial Statements.
Competitive forces within the electric utility industry were heightened
in 1996 with the enactment of the Pennsylvania Electric Generation
Customer Choice and Competition Act and issuance of the Federal Energy
Regulatory Commission (FERC) Orders 888 and 889. The Company continues
to advocate true competition in the electric utility industry and is
proactive in its efforts to promote deregulation. See Competition in
Core Business on page M-35 for a further discussion of competitive
issues in the electric utility industry.
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 2% and
4% in 1996 and 1995, respectively. The changes in revenues from sales
to residential, commercial, and industrial customers resulted from the
following:
<TABLE>
<CAPTION>
Changes
<S> <C> <C>
from Prior Year
(Millions of Dollars) 1996 1995
Increased kWh sales.............................. $10.2 $17.3
Rate changes..................................... 50.2
Fuel and energy cost adjustment clauses*......... (7.7) (2.9)
Other............................................ (2.9) 3.0
Net Change in Retail Revenues.................. $ (.4) $67.6
</TABLE>
*Changes in revenues from fuel and energy cost adjustment clauses have
little effect on consolidated net income. See "Rate Caps" under
Competition in Core Business on page M-35 for information regarding a
potential change in the fuel and energy cost adjustment clause (Energy
Cost Rate or ECR) in Pennsylvania.
The increase in kWh sales in 1996 was attributable to increases in each
of the residential, commercial, and industrial customer classes.
Residential kWh sales increased 2% in 1996 and 1% in 1995. These
increases, which are more weather sensitive than commercial and
industrial sales, were due primarily to increased customer usage and
continued growth in the number of customers. The Company measures the
effect of weather conditions on its utility sales by using degree days,
which reflect the differences between the average daily actual
temperature and the baseline temperature of 65 degrees. In 1996,
heating degree days in the relatively colder January- through-April
period were about 8% greater than the corresponding 1995 period. This
increase was somewhat offset by milder weather during the remainder of
<PAGE> M-30
the year. In 1995, increased sales resulted from extremely hot summer
weather and cooler-than-normal winter weather.
The 1% increase in commercial kWh sales in 1996 and the 4% increase in
1995 reflect growth in the number of customers, and, in 1995, also
reflects increased customer usage. Industrial kWh sales increased 1%
and 6% in 1996 and 1995, respectively. Excluding the decrease in the
fuel and energy cost component of industrial sales, revenues from sales
to industrial customers also increased over 1% in 1996. The increase in
kWh sales reflects a trend of economic growth in the service territory
and the efforts of the newly formed Retail Marketing Business Unit.
With the increased potential for retail competition and in light of the
Pennsylvania legislation (see Competition in Core Business on page M-35),
this function has been expanded to increase efforts to retain and acquire
customers and to expand into other markets.
There were no increases resulting from rate changes in 1996, as the base
rate increases effective in 1994 have been fully reflected in both the
1996 and 1995 periods. As a result of the Pennsylvania competition
legislation, the Company's rates have been capped effective January 1,
1997. This is more fully described on page M-35.
The increase in wholesale and other revenues in 1995 resulted primarily
from an increase in sales of capacity, energy, and spinning reserve to
affiliated companies. About $19 million of wholesale and other revenues
in 1996 were derived from wholesale customers (cooperatives and
municipalities who own their own distribution systems and who buy all or
part of their bulk power needs from the Company under regulation by the
FERC). Competition in the wholesale market for electricity was enhanced
by the Energy Policy Act of 1992 (EPACT), which permits wholesale
generators, utility-owned and otherwise, and wholesale customers to
request from owners of bulk power transmission facilities a commitment
to supply transmission services. In 1994, a rate case for wholesale
customers was completed with the result that such customers agreed to
negotiated rate increases and signed seven-year contracts to remain as
the Company's customers. Also, effective April 1997, a new wholesale
customer (formerly a retail customer) signed a five-year contract to
become a Company customer.
KWh deliveries to and revenues from bulk power transactions consist of
the following items:
<TABLE>
<CAPTION>
1996 1995 1994
<S> <C> <C> <C>
KWh deliveries (Billions):
From transmission services.............. 7.6 6.4 4.1
From sale of Company generation......... .4 .2 .5
Total................................. 8.0 6.6 4.6
Revenues (Millions):
From transmission services.............. $22.9 $19.7 $17.0
From sale of Company generation......... 10.0 5.7 12.3
Total................................. $32.9 $25.4 $29.3
</TABLE>
<PAGE> M-31
The final rules on open transmission access, issued by the FERC in early
1996, require utilities to offer to others transmission service that is
comparable to service they provide to themselves. Increased
transmission services in 1996 resulted primarily from increased activity
from power marketers who have agreed to take service under the new open
access tariffs filed by the Company in accordance with these rules.
Deliveries from the sale of Company generation in 1995 decreased because
of growth in kWh sales to retail customers, which reduced the amount
available for sale, and because of continuing price competition. Most
of the aggregate benefits from bulk power transactions are passed on to
retail customers through fuel cost adjustment clauses and have little
effect on consolidated net income. See page M-37 for information
regarding the potential change in the ECR for Pennsylvania.
Operating Expenses
The 1% increase in fuel expenses in 1996 was due to a 2% increase in kWh
generated, offset in part by lower average coal prices. The 6% decrease
in fuel expenses in 1995 was primarily the result of renegotiations of
long-term fuel contracts which reduced fuel prices effective in January
1995.
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. See page M-37 for information
regarding the potential change in the ECR for Pennsylvania.
"Purchased power and exchanges, net" represents power purchases from and
exchanges with nonaffiliated utilities and purchases from qualified
facilities under the Public Utility Regulatory Policies Act of 1978
(PURPA), capacity charges paid to Allegheny Generating Company (AGC), an
affiliate partially owned by the Company, and other transactions with
affiliates made pursuant to a power supply agreement whereby each
company uses the most economical generation available in the System at
any given time, and consists of the following items:
<TABLE>
<CAPTION>
(Millions of Dollars) 1996 1995 1994
<S> <C> <C> <C> <C>
Nonaffiliated transactions:
Purchased power:
From PURPA generation................ $ 63.6 $ 64.7 $ 65.7
Other................................ 22.3 21.8 18.3
Power exchanges, net................... .7 (.1) (.2)
Affiliated transactions:
AGC capacity charges................... 36.3 37.8 37.2
Energy and spinning reserve charges.... 4.0 5.3 9.3
Purchased power and exchanges, net... $126.9 $129.5 $130.3
</TABLE>
In 1996, the Company and the developers of a proposed Shannopin PURPA
project reached an agreement to terminate the project at a buyout price
of $31 million. The Pennsylvania Public Utility Commission (PUC) has
<PAGE> M-32
authorized full recovery of the buyout price, of which $24 million was
recovered by reducing the Company's over-recovered fuel balance. The
remaining $7 million was to be recovered in 1997 and 1998, but, pursuant
to the recent Pennsylvania rate caps enacted by the new Pennsylvania
Electric Generation Customer Choice and Competition Act, will be
recovered through other means. The buyout will save the Company's
customers approximately $665 million over the next 30 years by
eliminating the need to buy the uneconomic power.
None of the Company's purchased power contracts is capitalized since
there are no minimum payment requirements absent associated kWh
generation. The cost of power purchased, including power from PURPA
generation and affiliated transactions, is mostly recovered from
customers currently through the regular fuel and energy cost recovery
procedures with the result that changes in such costs have little effect
on consolidated net income. See page M-37 for information regarding the
potential change in the ECR in Pennsylvania.
The increase in other operation expense in 1996 resulted primarily from
increased allowances for uncollectible accounts ($3 million) and the
write-off of deferred CAAA compliance costs ($2 million). For 1997 and
thereafter, operations expense is expected to reflect the benefits of
savings related to the restructuring activities. Allowances for
uncollectible accounts increased 60% in 1996 due to an increase in aged
accounts receivable caused primarily by regulations in Pennsylvania
which severely restrict curtailment of service to non-paying customers.
Maintenance expenses represent costs incurred to maintain the power
stations, the transmission and distribution (T&D) system, and general
plant, and reflect routine maintenance of equipment and rights-of-way as
well as planned major repairs and unplanned expenditures, primarily from
forced outages at the power stations and periodic storm damage on the
T&D system. Variations in maintenance expense result primarily from
unplanned events and planned major projects, which vary in timing and
magnitude, depending upon the length of time equipment has been in
service without a major overhaul and the amount of work found necessary
when the equipment is dismantled.
Restructuring charges and asset write-offs resulted primarily from the
completion of restructuring initiatives undertaken in 1995 and the
write-off of previously accumulated costs related to a proposed
transmission line. See Note B to the Consolidated Financial Statements
for additional information.
Depreciation expense increases resulted primarily from additions to
electric plant. The Company began depreciating the Harrison scrubbers
in mid-November 1994, amounting to approximately $14 million annually.
Future depreciation expense increases are expected to be less than
historical increases because of reduced levels of planned capital
expenditures.
The increase in taxes other than income in 1996 was due to higher
property taxes and, in 1995, reflects increases in gross receipts taxes
<PAGE> M-33
resulting from higher revenues from retail customers. The net decrease
in federal and state income taxes in 1996 resulted primarily from a
decrease in income before taxes ($18 million), which was primarily
related to restructuring charges recorded in 1996. The net increase of
$15 million in federal and state income taxes in 1995 resulted primarily
from an increase in income before taxes. Note C to the Consolidated
Financial Statements provides a further analysis of income tax expenses.
The combined decreases in allowances for funds used during construction
in 1996 and 1995 were $2 million and $6 million, respectively, and
reflect decreases in capital expenditures due to substantial completion
of the program to comply with Phase I of the CAAA.
The increase in interest on long-term debt associated with the June 1995
issuance of $70 million of Quarterly Income Debt Securities (QUIDS) was
offset in 1996 by decreased interest on first mortgage bonds due
primarily to refinancings to lower rate securities in 1995 and the
redemption of $27 million of first mortgage bonds in 1995. Other
interest expense reflects changes in the levels of short-term debt
maintained by the Company throughout the year, as well as the associated
interest rates. The increase in other interest expense in 1996 resulted
primarily from interest on overcollections on the fuel cost portion of
customer billings.
Environmental and Other Issues
In the normal course of business, the Company is subject to various
contingencies and uncertainties relating to its operations and
construction programs, including cost recovery in the regulatory
process, laws, regulations and uncertainties related to environmental
matters, and legal actions. Contingencies and uncertainties related to
the restructuring of the electric utility industry and the recently
passed Pennsylvania restructuring legislation are discussed in
Competition in Core Business on page M-35.
The significant costs of complying with Phase I of the CAAA have
essentially been incurred and are being recovered currently from
customers in rates. Studies to evaluate cost-effective options to
comply with Phase II SO2 limits, including those which may be available
from the use of the Company's banked emission allowances and from the
emission allowance trading market, are continuing. It is expected that
burner modifications, which have been completed at most of the System's
stations, will satisfy the NOx emission reduction requirements for the
acid rain (Title IV) provisions of the CAAA. Additional post-combustion
controls may be mandated in Maryland, Pennsylvania, and West Virginia
for ozone nonattainment (Title I) reasons.
The Company previously reported that the Environmental Protection Agency
had identified the Company and its affiliates and approximately 875
others as potentially responsible parties in a Superfund site subject to
cleanup. A final determination has not been made for the Company's
<PAGE> M-34
share of the remediation costs based on the amount of materials sent to
the site. The Company has also been named as a defendant along with
multiple other affiliated and nonaffiliated defendants in pending
asbestos cases involving one or more plaintiffs. The Company believes
that provisions for liabilities and insurance recoveries are such that
final resolution of these claims will not have a material effect on its
financial position.
FINANCIAL CONDITION AND REQUIREMENTS
Liquidity and Capital Requirements
To meet the Company's need for cash for operating expenses, the payment
of interest and dividends, retirement of debt and certain preferred
stocks, and for its construction program, the Company has used
internally generated funds and external financings, such as the sale of
common and preferred stock, debt instruments, installment loans, and
lease arrangements. The timing and amount of external financings depend
primarily upon economic and financial market conditions, the Company's
cash needs, and capitalization ratio objectives. The availability and
cost of external financing depend upon the financial health of the
companies seeking those funds.
Construction expenditures in 1996 were $131 million and, for 1997 and
1998, are estimated at $140 million and $123 million, respectively. The
1997 and 1998 estimated expenditures include $17 million and $29
million, respectively, for construction of environmental control
technology. Expenditures in the future to cover the costs of compliance
with Phase II of the CAAA may be significant depending on the method
chosen to meet the requirements. Based on current forecasts and
considering the reactivation and repowering of capacity in cold reserve,
peak diversity exchange arrangements, and a power supply agreement with
affiliates, it is anticipated that generating capacity will be
sufficient to meet the Company's needs until the year 2000 or beyond.
It is the Company's goal to constrain future base capital spending, with
the exception of mandated environmental expenditures, to the approximate
level of depreciation currently in rates. The Company also has
additional capital requirements for debt maturities (see Note J to the
Consolidated Financial Statements).
Internal Cash Flows
Internal generation of cash, consisting of cash flows from operations
reduced by dividends, was $173 million in 1996 compared with $110
million in 1995. Current rate levels and reduced levels of capital
expenditures permitted the Company to finance its entire capital
expenditure program in 1996 and approximately 74% in 1995 through
internal cash generation. It is expected that internal generation of
cash over the next several years will continue to finance the majority
of capital expenditures.
<PAGE> M-35
As a capital-intensive electric utility, the Company is affected by the
rate of inflation. The inflation rate over the past several years has
been relatively low and has not materially affected the Company's
financial position. However, since utility revenues are currently based
on rate regulation that generally only recognizes historical costs, cash
flows based on recovery of historical plant may not be adequate to
replace plant in future years.
The increase in current liabilities for restructuring activities is
related primarily to payout provisions under employee severance
packages. Materials and supplies continued to provide a source of cash
in 1996, primarily related to lower contracted fuel prices and to
maintaining optimum levels of inventories.
Financing
Short-term debt is used to meet temporary cash needs until the timing is
considered appropriate to issue long-term securities. Short-term debt
decreased $37 million to $33 million in 1996. At December 31, 1996, the
Company had Securities and Exchange Commission authorization to issue up
to $170 million of short-term debt. The Company and its regulated
affiliates use an internal money pool as a facility to accommodate
intercompany short-term borrowing needs, to the extent that certain of
the companies have funds available. The Company anticipates that it
will be able to meet its 1997 cash needs through internal cash
generation.
COMPETITION IN CORE BUSINESS
In December 1996, Pennsylvania became only the fourth state in the
country to enact legislation on retail competition and electric utility
restructuring. The transition to competition in Pennsylvania will be
phased in over the periods described below. The legislation includes
the following major provisions:
All electric utilities in Pennsylvania must file a
restructuring plan by September 30, 1997, to implement
direct access to a competitive market for electric
generation. The plan must include unbundled rates for
generation, jurisdictional transmission, distribution and
other services, a proposed mechanism for recovery of
stranded costs, and a proposed universal service and energy
conservation cost recovery mechanism. The Company is
scheduled to make its filing on or about June 1, 1997.
Retail customer choice will be phased in beginning with one-
third of retail customers in the year 1999, another one-
third in 2000, and the remaining customers in 2001.
Retail rates will be capped for at least 4-1/2 years for
transmission and distribution charges and for as long as 9
years for generation charges. A utility may be exempted
<PAGE> M-36
from the caps only under very specific circumstances as
determined by the PUC.
Pennsylvania utilities are permitted to recover PUC-approved
transition or stranded costs over several years; however,
the utilities are required to mitigate these costs to the
extent practicable.
The Company is currently evaluating the new legislation to formulate its
plan to implement direct access to a competitive market. As required in
the legislation, in 1997 the Company and other Pennsylvania electric
utilities are required to implement Retail Customer Choice Pilot
Programs for up to 5% of the peak load of their customers. This will
result in customers with as much as 165 MW of the Company's retail load
being eligible to choose an alternate supplier of generation. The
Company on the other hand anticipates the opportunity to offer capacity
and/or energy to customers of other Pennsylvania utilities' pilot
programs. The Company cannot predict the ultimate effect of this
legislation, but the issues being evaluated include:
Stranded Cost Recovery - Stranded costs can generally be described as
mandated costs (such as regulatory assets and obligations under PURPA
contracts) and fixed costs of generating facilities in excess of market
value. The Pennsylvania legislation permits recovery of both types from
customers through a competitive transition charge (CTC), with the
provision that utilities have an obligation to mitigate stranded costs
to the extent practicable. Over the nine-year CTC recovery period, all
Pennsylvania utilities are permitted a CTC charge to recover fixed costs
in excess of market. Because the Company has no high cost nuclear power
stations, its CTC charge for fixed costs in excess of market, if any,
will be significantly less than the other utilities. The Company is
concerned that it may be placed at a significant competitive
disadvantage in the first several phase-in years because other utilities
with excess capacity may be willing to sell energy at marginal cost
rates, lower than the Company's full-cost rates, until the excess
capacity is used. Under this possibility, the Company would have
stranded fixed costs in the early years. The Company's restructuring
plan filing on or about June 1, 1997, will address this issue.
Applicability of SFAS No. 71 - In accordance with SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation," the
Company's financial statements reflect assets and liabilities based on
current cost-based ratemaking regulation. Once the Pennsylvania
transition to full retail competition is completed, the Company may not
meet the criteria for applying SFAS No. 71 to its generation operations
and assets. In that event, any remaining related regulatory assets and
liabilities, if any, would be written off, and any related long-lived
fixed and intangible assets would need to be evaluated for impairment
under the provisions of SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to be Disposed Of." Because
of the provisions in the new legislation related to stranded cost
<PAGE> M-37
recovery, the Company does not believe any such write-offs or charges
should be required.
Rate Caps - As a result of the Pennsylvania legislation, the Company's
rates, including its energy cost rates, have been capped effective
January 1, 1997. The legislation did not eliminate the ECR tracking
procedure and left to PUC discretion the method of future rate
adjustments for energy costs. In 1997, the Company is reviewing its
option to file a Petition with the PUC to roll the energy cost rates
into its base rates. Upon receipt of a PUC order to that effect, which
is expected if a Petition is filed, the Company would then assume the
risks of increases in the costs of fuel and purchased power and any
declines in bulk power transaction sales. However, the Company would
also retain the benefits of decreases in such costs and increases in
such sales. The Company would accomplish this result by discontinuance
of deferred fuel accounting.
Initiatives on comprehensive retail competition at the federal
government level are also being undertaken. The Company believes that a
federal framework of legislation to speed customer choice and provide a
uniform framework for rules is necessary because of differences among
the states. The System, including the Company, supports deregulation of
all generation, regulation of transmission by the FERC, and regulation
of distribution by the states. The System, including the Company,
joined with seven other electric utilities in 1996 to form the
Partnership for Customer Choice whose purpose is to seek enactment of
federal legislation to bring choice to electrical customers no later
than the year 2000. The legislation sought would deregulate the
generation of electric power, creating a free market for electricity.
The System is also advocating federal legislation to repeal Section 210
of PURPA and the Public Utility Holding Company Act of 1935. Both of
these laws severely impede the Company's ability to compete on equal
terms with both utility and nonutility electric providers who are not
subject to their requirements.
<PAGE> M-38
Allegheny Generating Company
MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Review of Operations
As described under Liquidity and Capital Requirements, revenues are
determined under a cost of service formula rate schedule. Therefore, if
all other factors remain equal, revenues are expected to decrease each
year due to a normal continuing reduction in the Company's net
investment in the Bath County station and its connecting transmission
facilities upon which the return on investment is determined. The net
investment (primarily net plant less deferred income taxes) decreases to
the extent that provisions for depreciation and deferred income taxes
exceed net plant additions. Revenues for 1996 and 1995 decreased due to
a reduction in net investment and reduced operating expenses and,
additionally for 1996, due to the decrease in the Company's return on
equity (ROE) from 11.2% to 11% described below.
The decrease in operating expenses in 1995 resulted from a decrease in
federal income taxes due to a decrease in income before taxes ($1.2
million) combined with a decrease in operation and maintenance expense
($1.0 million).
The decrease in interest on long-term debt in 1996 was primarily the
result of a decrease in the average amount of long-term debt
outstanding. The increase in other interest in 1995 was due to cash
needs for refunds mandated in rate case proceedings (see Liquidity and
Capital Requirements).
Liquidity and Capital Requirements
The Company's only operating assets are an undivided 40% interest in the
Bath County (Virginia) pumped-storage hydroelectric station and its
connecting transmission facilities. The Company has no plans for
construction of any other major facilities.
Pursuant to an agreement, the Parents buy all of the Company's capacity
in the station priced under a "cost of service formula" wholesale rate
schedule approved by the FERC. Under this arrangement, the Company
recovers in revenues all of its operation and maintenance expenses,
depreciation, taxes, and a return on its investment.
The Company's rates are set by a formula filed with and previously
accepted by the FERC. The only component which changes is the ROE.
Through February 29, 1992, the Company's ROE was adjusted annually
pursuant to a settlement agreement approved by the Federal Energy
Regulatory Commission (FERC). In December 1991, the Company filed for a
continuation of the existing ROE of 11.53% and other parties (the
Consumer Advocate Division of the Public Service Commission of West
Virginia, Maryland People's Counsel, and Pennsylvania Office of Consumer
<PAGE> M-39
Advocate, filed to reduce the ROE. A settlement agreement was filed
with the FERC on January 12, 1995, which reduced the Company's ROE from
11.53% to 11.13% for the period from March 1, 1992 through December 31,
1994, and increased the Company's ROE to 11.2% for the period from
January 1, 1995 through December 31, 1995. This settlement was approved
by the FERC on March 23, 1995. Refunds were made by the Company of
revenues collected between March 1, 1992 and March 23, 1995 in excess of
these levels. On December 21, 1995, the Company submitted a negotiated
settlement to the FERC to address the Company's ROE effective after
1995. Interested parties representing less than 2% of the Company's
eventual revenues filed exceptions. Under the terms of the settlement,
the Company's ROE for 1996 would be 11%. For 1997 and 1998 the ROE
would be set by a formula based upon the yields of 10-year constant
maturity U.S. Treasury securities. However, the change in ROE from the
previous year's value cannot exceed 50 basis points. On February 20,
1996, the FERC instituted an investigation of the proposed rate.
Subsequently, the parties who filed exceptions removed their exceptions
and accepted the settlement agreement providing for a 1996 return on
equity of 11% and an ROE adjustment mechanism for future years.
Pursuant to a settlement agreement filed April 4, 1996, with the FERC,
the Company's ROE was set at 11% for 1996 and will continue at that rate
until the time any affected party seeks renegotiation of the ROE.
Notice of such intent to seek a revision in ROE must be filed during a
notice period each year between November 1 and November 15. No requests
for change were filed during the 1996 notice period. Therefore, the
Company's ROE will remain at 11% for 1997.
Through a filing completed on October 31, 1994, the Company sought FERC
approval to add a prior tax payment of approximately $12 million to rate
base which will produce about $1.4 million in additional annual
revenues. The FERC accepted the Company's filing and ordered the
increase to become effective June 1, 1995.
In July 1996, the Company filed a request with the Securities and
Exchange Commission (SEC) for authority to pay common dividends from
time to time through December 31, 2001, out of capital to the extent
permitted under applicable corporation law and any applicable financing
agreements which restrict distributions to shareholders. Due to the
nature of being a single asset company with declining capital needs, the
Company systematically reduces capitalization each year as its asset
depreciates. This has resulted in the payment of dividends in excess of
current earnings and the reduction of retained earnings. The Company's
goal is to retire debt and pay dividends in amounts necessary to
maintain a 45% common equity position. The payment of dividends out of
capital surplus will not be detrimental to the financial integrity or
working capital of either the Company or its parents, nor will it
adversely affect the protections due debt security holders. On
September 19, 1996, the SEC approved the Company's request to pay common
dividends out of capital.
An internal money pool accommodates intercompany short-term borrowing
needs to the extent that certain of the Company's regulated affiliates
have funds available.
<PAGE> - 44 -
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Financial Statements
<TABLE>
<CAPTION>
Index
Monon- Potomac West
APS gahela Edison Penn AGC
<S> <C> <C> <C> <C> <C>
Report of Independent Accountants F-1 F-19 F-32 F-48 F-67
Statement of Income for
the three years ended
December 31, 1996 F-2 F-20 F-33 F-49 F-68
Statement of Retained Earnings
for the three years ended
December 31, 1996 - F-20 F-33 F-49 F-68
Statement of Cash Flows for
the three years ended
December 31, 1996 F-3 F-21 F-34 F-50 F-69
Balance Sheet at December 31,
1996 and 1995 F-4 F-22 F-35 F-51 F-70
Statement of Capitalization at
December 31, 1996 and 1995 F-5 F-23 F-36 F-52 -
Statement of Common Equity for
the three years ended
December 31, 1996 F-6 - - - -
Notes to financial statements F-7 F-24 F-37 F-53 F-70
Financial Statement Schedules -
Schedules - for the three years
ended December 31, 1996 45 45 45 45 45
II Valuation and qualifying
accounts S-1 S-2 S-3 S-4 -
</TABLE>
All other schedules are omitted because they are not applicable or the required
information is shown in the Financial Statements or Notes thereto.
<PAGE> F-1
Allegheny Power System
Report of Independent Accountants
To the Board of Directors and the Shareholders
of Allegheny Power System, Inc.
In our opinion, the accompanying consolidated balance sheet, consolidated
statements of capitalization and of common equity and the related consolidated
statements of income and of cash flows present fairly, in all material respects,
the financial position of Allegheny Power System, Inc. and its subsidiaries
at December 31, 1996 and 1995, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 1996,
in conformity with generally accepted accounting principles. These financial
statements are the responsibility of the Company's management; our
responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform
the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining,
on a test basis, evidence supporting the amounts and disclosures in the
financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for the
opinion expressed above. As discussed in Note A to the consolidated financial
statements, the Company changed its method of accounting for revenue
recognition in 1994.
Price Waterhouse LLP
New York, New York
February 5, 1997
<PAGE> F-2
Consolidated Statement of Income
Year ended December 31
<TABLE>
<CAPTION>
<S> <C> <C> <C> <C> <C> <C>
(Thousands of Dollars Except for Per Share Data) 1996 1995 1994
Electric Operating Revenues:
Residential $ 932,235 $ 926,966 $ 863,725
Commercial 492,726 493,696 459,303
Industrial 752,905 770,251 728,009
Wholesale and other (Note A) 74,260 66,147 65,795
Bulk power transactions, net (Note A) 75,523 58,151 67,797
Total Operating Revenues 2,327,649 2,315,211 2,184,629
Operating Expenses:
Operation:
Fuel 513,210 508,533 547,241
Purchased power and exchanges, net (Note A) 184,357 178,103 173,825
Deferred power costs, net (Note A) 15,621 47,796 11,805
Other 299,817 290,501 285,007
Maintenance 243,314 249,477 241,913
Restructuring charges and asset write-offs (Note B) 103,865 23,440 9,178
Depreciation 263,246 256,316 223,883
Taxes other than income taxes 185,373 184,729 183,060
Federal and state income taxes (Note C) 127,992 154,203 125,913
Total Operating Expenses 1,936,795 1,893,098 1,801,825
Operating Income 390,854 422,113 382,804
Other Income and Deductions:
Allowance for other than borrowed funds used during
construction (Note A) 3,157 4,473 11,966
Other income, net 4,370 6,224 1,509
Total Other Income and Deductions 7,527 10,697 13,475
Income Before Interest Charges and Preferred Dividends 398,381 432,810 396,279
Interest Charges and Preferred Dividends:
Interest on long-term debt 166,387 167,199 153,668
Other interest 15,398 14,417 10,394
Allowance for borrowed funds used during construction
(Note A) (2,731) (3,713) (7,630)
Dividends on preferred stock of subsidiaries 9,280 15,215 20,096
Total Interest Charges and Preferred Dividends 188,334 193,118 176,528
Consolidated Income Before Cumulative Effect of
Accounting Change 210,047 239,692 219,751
Cumulative Effect of Accounting Change,
net (Note A) 43,446
Consolidated Net Income $ 210,047 $ 239,692 $ 263,197
Common Stock Shares Outstanding (average) 121,141,446 119,863,753 118,272,373
Earnings Per Average Share:
Consolidated income before cumulative
effect of accounting change $1.73 $2.00 $1.86
Cumulative effect of accounting change, net (Note A) .37
Consolidated net income $1.73 $2.00 $2.23
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-3
Consolidated Statement of Cash Flows
Year ended December 31
<TABLE>
<CAPTION>
<S> <C> <C> <C>
(Thousands of Dollars) 1996 1995 1994
Cash Flows from Operations:
Consolidated net income $210,047 $239,692 $263,197
Depreciation 263,246 256,316 223,883
Deferred investment credit and income taxes, net 20,887 27,019 25,684
Deferred power costs, net 15,621 47,796 11,805
Allowance for other than borrowed funds used
during construction (3,157) (4,473) (11,966)
Restructuring liability (Note B) 55,544 14,435
Cumulative effect of accounting change before
income taxes (Note A) (72,333)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative
effect of accounting change (Note A) 19,570 (63,370) 9,666
Materials and supplies 15,507 20,358 (20,519)
Accounts payable 1,739 (45,387) 3,119
Taxes accrued (181) 3,060 (5,792)
Interest accrued 878 (2,326) 3,452
Other, net (8,780) (14,685) 9,957
590,921 478,435 440,153
Cash Flows from Investing:
Utility construction expenditures (289,454) (319,050) (508,254)
Nonutility investments (180,245) (1,076)
Allowance for other than borrowed funds used
during construction 3,157 4,473 11,966
(466,542) (315,653) (496,288)
Cash Flows from Financing:
Sale of common stock 33,847 34,514 34,709
Sale of preferred stock 49,635
Retirement of preferred stock (162,171) (1,190)
Issuance of long-term debt and QUIDS 160,000 482,856 197,098
Retirement of long-term debt (54,143) (392,715) (26,000)
Short-term debt, net (43,988) 73,600 (3,818)
Cash dividends on common stock (204,720) (197,764) (193,951)
(109,004) (161,680) 56,483
Net Change in Cash and Temporary Cash
Investments (Note A) 15,375 1,102 348
Cash and Temporary Cash Investments at January 1 3,867 2,765 2,417
Cash and Temporary Cash Investments at December 31 $ 19,242 $ 3,867 $ 2,765
Supplemental Cash Flow Information
Cash paid during the year for:
Interest (net of amount capitalized) $169,200 $178,239 $148,016
Income taxes 132,037 126,386 122,343
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-4
<TABLE>
<CAPTION>
Consolidated Balance Sheet
As of December 31
<S> <C> <C>
(Thousands of Dollars) 1996 1995
Assets
Property, Plant, and Equipment:
At original cost, including $202,259,000 and $147,467,000
under construction $8,206,213 $7,812,670
Accumulated depreciation (2,910,022) (2,700,077)
5,296,191 5,112,593
Investments and Other Assets:
Subsidiaries consolidated-excess of cost over book equity at
acquisition (Note A) 15,077 15,077
Benefit plans' investments (Note A) 63,197 47,545
Other 4,359 2,981
82,633 65,603
Current Assets:
Cash and temporary cash investments (Note I) 19,242 3,867
Accounts receivable:
Electric service, net of $15,052,000 and $13,047,000
uncollectible allowance (Note A) 280,154 305,988
Other 22,188 15,924
Materials and supplies-at average cost:
Operating and construction 82,057 86,421
Fuel 60,755 71,898
Prepaid taxes 62,110 45,404
Deferred income taxes 39,428 28,655
Other 16,324 13,164
582,258 571,321
Deferred Charges:
Regulatory assets (Note H) 565,185 602,360
Unamortized loss on reacquired debt 53,403 57,255
Other 38,840 38,183
657,428 697,798
Total $6,618,510 $6,447,315
Capitalization and Liabilities
Capitalization:
Common stock, other paid-in capital, and
retained earnings (Note D) $2,169,091 $2,129,917
Preferred stock (Note J) 170,086 170,086
Long-term debt and QUIDS (Note J) 2,397,149 2,273,226
4,736,326 4,573,229
Current Liabilities:
Short-term debt (Note K) 156,430 200,418
Long-term debt due within one year (Note J) 26,900 43,575
Accounts payable 147,161 145,422
Taxes accrued:
Federal and state income 7,173 15,599
Other 62,361 54,116
Interest accrued 40,630 39,752
Deferred power costs (Note A) 22,845 26,735
Restructuring liability (Note B) 56,101 14,435
Other 57,436 56,477
577,037 596,529
Deferred Credits and Other Liabilities:
Unamortized investment credit 141,519 149,759
Deferred income taxes 1,000,023 985,804
Regulatory liabilities (Note H) 93,216 97,970
Other 70,389 44,024
1,305,147 1,277,557
Commitments and Contingencies (Note L)
Total $6,618,510 $6,447,315
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-5
<TABLE>
<CAPTION>
Consolidated Statement of Capitalization
As of December 31
<S> <C> <C> <C> <C>
(Thousands of Dollars) (Capitalization Ratios)
1996 1995 1996 1995
Common Stock:
Common stock of Allegheny Power System, Inc.-
$1.25 par value per share, 260,000,000
shares authorized, outstanding 121,840,327
and 120,700,809 shares $ 152,300 $ 150,876
Other paid-in capital 1,028,124 995,701
Retained earnings (Note D) 988,667 983,340
Total 2,169,091 2,129,917 45.8% 46.6%
Preferred Stock of Subsidiaries-cumulative,
par value
$100 per share, authorized 9,975,688
shares (Note J):
December 31, 1996
Shares Regular Call Price
Series Outstanding Per Share
3.60% - 4.80% 650,861 $103.75 to $110.00 65,086 65,086
$5.88 - $7.73 650,000 $102.85 to $102.86 65,000 65,000
Auction
4.02% - 4.25% 400,000 $100.00 40,000 40,000
Total (annual dividend requirments $9,213,669) 170,086 170,086 3.6% 3.7%
Long-Term Debt and QUIDS of Subsidiaries (Note J):
First mortgage bonds: December 31, 1996
Maturity Interest Rate-%
1996 - 2000 5 1/2 - 6 1/2 257,000 293,000
2002 - 2004 6 3/8 - 7 7/8 175,000 175,000
2006 - 2007 7 1/4 - 8 120,000 120,000
2021 - 2025 7 5/8 - 8 7/8 925,000 925,000
Debentures due
2003 - 2023 5 5/8 - 6 7/8 150,000 150,000
Quarterly Income Debt
Securities due 2025 8.00 155,457 155,457
Secured notes due
1998 - 2024 4.95 - 6.875 368,300 368,300
Unsecured notes due
1996 - 2012 6.10 - 6.40 26,295 27,495
Installment purchase
obligations due 1998 6.875 19,100 19,100
Commercial paper 7.00 19,992 30,561
Medium-term notes due
1996 - 2001 5.75 - 7.93 230,600 76,975
Unamortized debt discount and premium, net (22,695) (24,087)
Total (annual interest requirements $175,450,447) 2,424,049 2,316,801
Less current maturities (26,900) (43,575)
Total 2,397,149 2,273,226 50.6% 49.7%
Total Capitalization $4,736,326 $4,573,229 100.0% 100.0%
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-6
Consolidated Statement of Common Equity
Year ended December 31
<TABLE>
<CAPTION>
(Thousands of Dollars)
Other Retained Total
Shares Common Paid-In Earnings Common
Outstanding Stock Capital (Note D) Equity
<S> <C> <C> <C> <C> <C> <C>
Balance at January 1, 1994 117,663,582 $147,079 $ 931,063 $877,673 $ 1,955,815
Add:
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
Purchase Plan and Employee Stock
Ownership and Savings Plan 1,629,372 2,037 32,988 35,025
Consolidated net income 263,197 263,197
Deduct:
Dividends on common stock of the
Company (cash) 193,951 193,951
Expenses related to common stock 316 316
Expenses related to subsidiary
companies' preferred stock transactions 466 466
Balance at December 31, 1994 119,292,954 $149,116 $ 963,269 $946,919 $2,059,304
Add:
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
Purchase Plan and Employee Stock
Ownership and Savings Plan 1,407,855 1,760 32,754 34,514
Consolidated net income 239,692 239,692
Deduct:
Dividends on common stock of the
Company (cash) 197,764 197,764
Expenses related to subsidiary
companies' preferred stock transactions 322 5,507 5,829
Balance at December 31, 1995 120,700,809 $150,876 $ 995,701 $983,340 $2,129,917
Add:
Sale of common stock, net of expenses:
Dividend Reinvestment and Stock
Purchase Plan and Employee Stock
Ownership and Savings Plan 1,139,518 1,424 32,423 33,847
Consolidated net income 210,047 210,047
Deduct:
Dividends on common stock of the
Company (cash) 204,720 204,720
Balance at December 31, 1996 121,840,327 $152,300 $1,028,124 $988,667 $2,169,091
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-7
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial
statements.)
Note A: Summary of Significant Accounting Policies
Allegheny Power System, Inc. (the Company) is an electric utility
holding company that derives substantially all of its income from the
electric utility operations of its regulated subsidiaries, Monongahela
Power Company, The Potomac Edison Company, and West Penn Power Company.
These subsidiaries jointly own Allegheny Generating Company (AGC), which
owns and sells to its parents 840 megawatts (MW) of pumped-storage
generating capacity. The principal markets for the System's electric
sales are in the states of Pennsylvania, West Virginia, Maryland,
Virginia, and Ohio. In 1996, revenues from 50 of its largest electric
utility customers provided approximately 20% of the System's retail
revenues. The Company also has a wholly owned nonutility subsidiary, AYP
Capital, Inc. (AYP Capital), formed in 1994, which is involved primarily
in energy-related services, development of wholesale nonutility power
generation, and other energy-related businesses.
The Company and its subsidiaries are subject to regulation by the
Securities and Exchange Commission (SEC), including the Public Utility
Holding Company Act of 1935. The regulated subsidiaries are subject to
regulation by various state bodies having jurisdiction and by the
Federal Energy Regulatory Commission (FERC). Significant accounting
policies of the Company and its subsidiaries are summarized below.
Consolidation
The Company owns all of the outstanding common stock of its
subsidiaries. The consolidated financial statements include the accounts
of the Company and all subsidiary companies after elimination of
intercompany transactions.
Use of Estimates
The preparation of financial statements in conformity with
generally accepted accounting principles requires management to make
estimates that affect the reported amounts of assets, liabilities,
revenues, expenses, and disclosures of contingencies during the
reporting period, which in the normal course of business are
subsequently adjusted to actual results.
Revenues
Revenues, including amounts resulting from the application of fuel
and energy cost adjustment clauses, are recognized in the same period in
which the related electric services are provided to customers, by
recording an estimate for unbilled revenues for services provided from
the meter reading date to the end of the accounting period. Revenues
from nonregulated activities are recorded in the period earned.
<PAGE> F-8
Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other utilities, including transmission services,
are deferred until they are either recovered from or credited to
customers under fuel and energy cost recovery procedures.
Property, Plant, and Equipment
Utility property, plant, and equipment are stated at original
cost, less contributions in aid of construction, except for capital
leases, which are recorded at present value. Cost includes direct labor
and material, allowance for funds used during construction (AFUDC) on
utility property for which construction work in progress is not included
in rate base, and such indirect costs as administration, maintenance,
and depreciation of transportation and construction equipment, and
postretirement benefits, taxes, and other fringe benefits related to
employees engaged in construction.
The cost of depreciable utility property units retired, plus
removal costs less salvage, are charged to accumulated depreciation.
Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is
defined in applicable regulatory systems of accounts as including "the
net cost for the period of construction of borrowed funds used for
construction purposes and a reasonable rate on other funds when so
used." AFUDC is recognized by the regulated subsidiaries as a cost of
utility property, plant, and equipment with offsetting credits to other
income and interest charges. Rates used by the subsidiaries for
computing AFUDC in 1996, 1995, and 1994 averaged 8.41%, 8.73%, and
9.00%, respectively. AFUDC is not included in the cost of such
construction when the cost of financing the construction is being
recovered through rates.
Depreciation and Maintenance
Provisions for utility depreciation are determined generally on a
straight-line method based on estimated service lives of depreciable
properties and amounted to approximately 3.5% of average depreciable
property in 1996 and 1995 and 3.3% in 1994. The cost of maintenance and
of certain replacements of property, plant, and equipment is charged
principally to operating expenses.
Nonutility Property
Nonutility property is stated at cost and is depreciated by the
straight-line method over its estimated useful life.
Investments
The investment in subsidiaries consolidated represents the excess
of acquisition cost over book equity (goodwill) prior to 1966. Goodwill
is not being amortized because, in management's opinion, there has been
no reduction in its value.
<PAGE> F-9
Benefit plans' investments primarily represent the estimated cash
surrender values of purchased life insurance on qualifying management
employees under executive life insurance, and supplemental executive
retirement plans. Payment of future premiums will fully fund these
benefits.
Temporary Cash Investments
For purposes of the consolidated statement of cash flows,
temporary cash investments with original maturities of three months or
less, generally in the form of commercial paper, certificates of
deposit, and repurchase agreements, are considered to be the equivalent
of cash.
Regulatory Deferrals
In accordance with the Financial Accounting Standards Board's
Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting
for the Effects of Certain Types of Regulation," the Company's
consolidated financial statements reflect assets and liabilities based
on current cost-based ratemaking regulation.
Income Taxes
Financial accounting income before income taxes differs from
taxable income principally because certain income and deductions for tax
purposes are recorded in the financial income statement in another
period. For the regulated subsidiaries, differences between income tax
expense computed on the basis of financial accounting income and taxes
payable based on taxable income are accounted for substantially in
accordance with the accounting procedures followed for ratemaking
purposes. Deferred tax assets and liabilities represent the tax effect
of temporary differences between the financial statement and tax basis
of assets and liabilities computed utilizing the most current tax rates.
Provisions for federal income tax were reduced in previous years
by investment credits, and amounts equivalent to such credits were
charged to income with concurrent credits to a deferred account. These
balances are being amortized over the estimated service lives of the
related properties.
Postretirement Benefits
The subsidiaries have a noncontributory, defined benefit pension
plan covering substantially all employees, including officers. Benefits
are based on the employee's years of service and compensation. The
funding policy is to contribute annually at least the minimum amount
required under the Employee Retirement Income Security Act and not more
than can be deducted for federal income tax purposes.
The subsidiaries also provide partially contributory medical and
life insurance plans for eligible retirees and dependents. Medical
benefits, which comprise the largest component of the plans, are based
upon an age and years-of-service vesting schedule and other plan
provisions. The funding plan for these costs is to contribute the
maximum amount that can be deducted for federal income tax purposes.
Funding of these benefits is made primarily into Voluntary Employee
<PAGE> F-10
Beneficiary Association trust funds. Medical benefits are self-insured;
the life insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification
Effective in 1996, the regulated subsidiaries changed their method
of reporting certain bulk power transmission transactions with
nonaffiliated utilities and reclassified prior years' bulk power and
other revenues and operation expenses to achieve a consistent
presentation. In prior years, some use of the subsidiaries' transmission
system was recorded as purchased power from selling utilities and as
sales of power to buying utilities. The benefit to the subsidiaries was
the difference between the two. Because of new FERC requirements, the
subsidiaries predominantly do not "buy" and "sell" such energy, but
rather a transmission fee is charged.
Under the new reporting method, all such transactions are recorded
on a net revenue basis. The effect of the reclassifications was to
reduce amounts previously reported for bulk power transactions revenues
and operation expenses by $333 million and $267 million for 1995 and
1994, respectively, with no change in operating income or consolidated
net income.
Accounting Change
Effective January 1, 1994, the regulated subsidiaries changed
their revenue recognition method to include the accrual of estimated
unbilled revenues for electric services. The cumulative effect of this
accounting change for years prior to 1994, which is shown separately in
the consolidated statement of income for 1994, resulted in a benefit of
$43.4 million (after related income taxes of $28.9 million), or $.37 per
share of common stock. The effect of the change on 1994 consolidated
income before the cumulative effect of accounting change is not
material.
Note B: Restructuring Charges and Asset Write-Offs
In 1996, the Company and its subsidiaries essentially completed
their restructuring initiatives undertaken in 1995, simplifying the
management structure and streamlining operations. During 1996,
restructuring activities included consolidating operating divisions,
customer services, and other functions. By reorganizing and eliminating
certain processes and consolidating common decentralized functions, the
Company and its subsidiaries have reduced employment by about 1,000
employees since October 1994. These reductions were accomplished through
a voluntary separation plan, attrition, and layoffs.
In 1996 and 1995, the subsidiaries recorded restructuring charges
of $93.1 million ($56.2 million after tax) and $16.0 million ($9.6
million after tax) in operating expenses, including all restructuring
charges associated with the reorganization, which is essentially
complete. These charges reflect liabilities and payments for severance,
employee termination costs, and other restructuring costs. The
restructuring liability consists of:
<PAGE> F-11
<TABLE>
<CAPTION>
<S> <C> <C>
(Thousands of Dollars) 1996 1995
Restructuring liability (before tax):
Balance at the beginning of period $14,435
Accruals 93,103 $15,994
Less payments (37,559) (1,559)
Balance at end of period $69,979* $14,435
* Includes $13,878,000 for benefit plans curtailment liabilities and
special termination benefits which are primarily recorded in other
deferred credits.
</TABLE>
In 1996 and 1994, the regulated subsidiaries wrote off $10.8
million ($6.3 million after tax) and $9.2 million ($5.3 million after
tax), respectively, of previously accumulated costs related to a
proposed transmission line and a potential future power plant site. In
the industry's more competitive environment, it was no longer reasonable
to assume future recovery of these costs in rates.
In connection with changes in inventory management objectives, the
regulated subsidiaries in 1995 also recorded $7.4 million ($4.5 million
after tax) for the write-off of obsolete and slow-moving materials.
<PAGE> F-12
Note C: Income Taxes
Details of federal and state income tax provisions are:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Income taxes - current:
Federal $ 83,456 $112,482 $114,263
State 26,004 17,375 15,633
Total 109,460 129,857 129,896
Income taxes - deferred, net of amortization 29,129 35,279 33,994
Amortization of deferred investment credit (8,242) (8,260) (8,310)
Total income taxes 130,347 156,876 155,580
Income taxes - charged to other income and deductions (2,355) (2,673) (780)
Income taxes - charged to accounting change
(including state income taxes) (28,887)
Income taxes - charged to operating income $127,992 $154,203 $125,913
The total provision for income taxes is different from the amount produced by applying the federal income
statutory tax rate of 35% to financial accounting income, as set forth below:
(Thousands of Dollars) 1996 1995 1994
Financial accounting income before
cumulative effect of accounting change,
preferred dividends, and income taxes $347,319 $409,110 $369,598
Amount so produced $121,600 $143,200 $129,400
Increased (decreased) for:
Tax deductions for which deferred tax was not provided:
Lower tax depreciation 12,600 13,500 8,000
Plant removal costs (1,900) (3,500) (5,600)
State income tax, net of federal income tax benefit 14,100 16,300 11,600
Amortization of deferred investment credit (8,242) (8,260) (8,310)
Other, net (10,166) (7,037) (9,177)
Total $127,992 $154,203 $125,913
Federal income tax returns through 1993 have been
examined and substantially settled through 1991.
At December 31, the deferred tax assets and
liabilities consist of the following:
(Thousands of Dollars) 1996 1995
Deferred tax assets:
Unamortized investment tax credit $ 88,371 $ 92,715
Tax interest capitalized 35,286 35,029
Contributions in aid of construction 22,136 21,111
Restructuring 19,870 5,713
Postretirement benefits other than pensions 13,599 8,671
Deferred power costs, net 6,053 7,483
Unbilled revenue 1,110 12,187
Other 51,460 37,961
237,885 220,870
Deferred tax liabilities:
Book vs. tax plant basis differences, net 1,125,936 1,108,948
Other 72,544 69,071
1,198,480 1,178,019
Total net deferred tax liabilities 960,595 957,149
Add portion above included in current assets 39,428 28,655
Total long-term net deferred tax liabilities $1,000,023 $ 985,804
</TABLE>
<PAGE> F-13
Note D:
Dividend Restriction
Supplemental indentures relating to certain outstanding bonds of
Monongahela Power Company and West Penn Power Company contain dividend
restrictions under the most restrictive of which $121,015,000 of
consolidated retained earnings at December 31, 1996, is not available
for cash dividends on their common stocks, except that a portion thereof
may be paid as cash dividends where concurrently an equivalent amount of
cash is received by a subsidiary as a capital contribution or as the
proceeds of the issue and sale of shares of such subsidiary's common
stock.
Note E: Pension Benefits
Net pension costs, a portion of which (about 25% to 30%) was charged to
plant construction, included the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned $14,881 $ 13,695 $14,940
Interest cost on projected benefit obligation 41,500 39,901 38,630
Actual return on plan assets (56,939) (107,972) (61)
Net amortization and deferral 665 56,451 (48,983)
Pension cost 107 2,075 4,526
Reversal of previous deferrals 760 760 6,681
Total pension cost $ 867 $ 2,835 $11,207
The benefits earned to date and funded status
at December 31 using a measurement date of
September 30 were as follows:
(Thousands of Dollars) 1996 1995
Actuarial present value of accumulated benefit
obligation earned to date (including vested
benefit of $467,126,000 and $432,922,000) $495,703 $462,733
Funded status:
Actuarial present value of projected benefit obligation $586,473 $568,479
Plan assets at market value, primarily common stocks and
fixed income securities 691,063 666,740
Plan assets in excess of projected benefit obligation (104,590) (98,261)
Add:
Unrecognized cumulative net gain from past experience
different from that assumed 95,189 94,809
Unamortized transition asset, being amortized over 14
years beginning January 1, 1987 12,590 15,736
Less unrecognized prior service cost due to plan amendments (7,280) (9,510)
Pension cost (prepaid) liability at December 31 $ (4,091) $ 2,774
</TABLE>
<PAGE> F-14
In determining the actuarial present value of the projected
benefit obligation at September 30, 1996, 1995, and 1994, the discount
rates used were 7.5%, 7.5%, and 7.75%, and the rates of increase in
future compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The
expected long-term rate of return on assets was 9% in each of the years
1996, 1995, and 1994.
The pension cost prepaid at December 31, 1996, includes the net
result of a curtailment gain of $11.5 million and an expense for special
termination benefits of $4.5 million associated with the workforce
reduction.
Note F: Postretirement Benefits Other Than Pensions
The cost of postretirement benefits other than pensions (principally
health care and life insurance) for employees and covered dependents, a
portion of which (about 25% to 30%) was charged to plant construction,
included the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost-benefits earned $ 2,930 $ 2,919 $ 3,058
Interest cost on accumulated postretirement
benefit obligation 14,251 14,736 13,732
Actual (return) loss on plan assets (4,518) (6,378) 135
Amortization of unrecognized transition obligation 7,272 7,272 7,300
Other net amortization and deferral 852 5,163 206
Postretirement cost 20,787 23,712 24,431
Regulatory reversal (deferral) 1,975 492 (3,908)
Net postretirement cost $22,762 $24,204 $20,523
The benefits earned to date and funded status at
December 31 using a measurement date of
September 30 were as follows:
(Thousands of Dollars) 1996 1995
Accumulated postretirement benefit obligation:
Retirees $148,008 $115,965
Fully eligible employees 11,838 25,994
Other employees 46,383 53,883
Total obligation 206,229 195,842
Plan assets at market value, in common stocks, fixed income
securities, and short-term investments 55,802 39,875
Accumulated postretirement benefit obligation in excess of
plan assets 150,427 155,967
Less:
Unrecognized cumulative net loss from past experience different
from that assumed (10,412) (19,529)
Unrecognized transition obligation, being amortized over 20 years
beginning January 1, 1993 (102,926) (123,628)
Postretirement benefit liability at September 30 37,089 12,810
Fourth quarter contributions and benefit payments (4,200) (9,313)
Postretirement benefit liability at December 31 $ 32,889 $ 3,497
</TABLE>
In determining the accumulated postretirement benefit obligation
(APBO) at September 30, 1996, 1995, and 1994, the discount rates used
were 7.5%, 7.5%, and 7.75%, and the rates of increase in future
compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The
<PAGE> F-15
expected long-term rate of return on assets was 8.25% in each of the
years 1996, 1995, and 1994. For measurement purposes, a health care
trend rate of 7% for 1997, declining to 6.5% in 1998 and beyond, and
plan provisions which limit future medical and life insurance benefits,
were assumed. Increasing the assumed health care trend rate by 1% in
each year would increase the APBO at December 31, 1996, by $13.5 million
and the aggregate of the service and interest cost components of net
periodic postretirement benefit cost for 1996 by $1.3 million.
The postretirement benefit liability at December 31, 1996,
includes a curtailment loss of $14.6 million and an expense for special
termination benefits of $6.2 million associated with the workforce
reduction.
Note G: Nonutility Subsidiary Information
AYP Capital has two wholly owned subsidiaries which were formed in
1996, AYP Energy, Inc. (AYP Energy) and Allegheny Communications
Connect, Inc. (ACC). AYP Energy is an exempt wholesale generator and
power marketer. ACC is an exempt telecommunications company under the
Public Utility Holding Company Act of 1935 (PUHCA). ACC's purpose is to
develop nonutility opportunities in the deregulated communications
market.
AYP Capital's net loss was $2.9 million in 1996 and $.6 million in
1995. The following is a condensed consolidated balance sheet for AYP
Capital. The allocation of net assets, including intangibles, related to
the purchase of 276 MW at the Fort Martin Power Station will be
completed in 1997. This financial information does not reflect the
elimination of intercompany balances or transactions which are
eliminated in the Company's consolidated financial statements.
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Assets:
Fort Martin Generating Station $177,993
Other 29,728 $1,446
Total $207,721 $1,446
Capitalization & Liabilities:
Common equity $ 27,845 $1,266
Long-term debt 160,000
Accounts payable 15,126
Other liabilities 4,750 180
Total $207,721 $1,446
</TABLE>
Note H: Regulatory Assets and Liabilities
The Company's utility operations are subject to the provisions of
SFAS No. 71, "Accounting for the Effects of Certain Types of
Regulation." Regulatory assets represent probable future revenues
associated with deferred costs that are expected to be recovered from
customers through the ratemaking process. Regulatory liabilities
represent probable future reductions in revenues associated with amounts
that are to be credited to customers through the ratemaking process.
Regulatory assets, net of regulatory liabilities, reflected in the
Consolidated Balance Sheet at December 31 relate to:
<PAGE> F-16
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Long-Term Assets (Liabilities), Net:
Income taxes, net $434,592 $460,237
Demand-side management 15,748 16,024
Postretirement benefits 7,750 10,484
Storm damage 4,973 6,409
Deferred power costs (reported in other deferred charges/credits) 4,024 (3,263)
Other, net 8,906 11,236
Subtotal 475,993 501,127
Current Assets (Liabilities), Net:
Income taxes, net 926 972
Deferred power costs, net (portion included in other current assets) (22,845) (25,576)
Subtotal (21,919) (24,604)
Net Regulatory Assets $454,074 $476,523
</TABLE>
Note I: Fair Value of Financial Instruments
The carrying amounts and estimated fair value of financial
instruments at December 31 were as follows:
<TABLE>
<CAPTION>
1996 1995
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
<S> <C> <C> <C> <C>
Assets:
Temporary cash investments $ 4,000 $ 4,000 $ 425 $ 425
Life insurance contracts 63,197 63,197 47,545 47,545
Liabilities:
Short-term debt 156,430 156,430 200,418 200,418
Long-term debt and QUIDS 2,446,744 2,455,705 2,340,888 2,409,080
</TABLE>
The carrying amount of temporary cash investments, as well as
short-term debt, approximates the fair value because of the short
maturity of those instruments. The fair value of long-term debt and
QUIDS was estimated based on actual market prices or market prices of
similar issues. The fair value of the life insurance contracts was
estimated based on cash surrender value. The Company has no financial
instruments held or issued for trading purposes.
Note J: Capitalization
Preferred Stock
All of the preferred stock is entitled on voluntary liquidation to
its then current call price and on involuntary liquidation to $100 a
share. The holders of West Penn Power Company's market auction preferred
stock are entitled to dividends at a rate determined by an auction held
the business day preceding each quarterly dividend payment date.
Long-Term Debt and QUIDS
Maturities for long-term debt for the next five years are: 1997,
$26,900,000; 1998, $185,400,000; 1999, $4,300,000; 2000, $165,292,000;
and 2001, $165,300,000. Substantially all of the properties of the
subsidiaries are held subject to the lien securing each subsidiary's
first mortgage bonds. Some properties are also subject to a second lien
securing certain pollution control and solid waste disposal notes.
<PAGE> F-17
In 1996, AYP Energy issued $160 million of medium-term notes under
an arrangement provided by a syndicate of eight banks. The debt is
priced at a floating rate based on the 90-day London Interbank Offering
Rate plus a spread. AYP Energy entered into a floating-to-fixed interest
rate swap to fix the rate at 6.78% to hedge against fluctuations in
interest rates. Interest rate differentials to be paid or received are
recorded as adjustments to interest expense. Throughout the five-year
period, the floating rate may be above or below the fixed rate, but is
only relevant in the event of termination prior to maturity. AYP
Energy's obligation under the Credit Agreement is supported by the
Company.
Commercial paper borrowings issuable by AGC are backed by a
revolving credit agreement with a group of six banks, which provides for
loans of up to $50 million at any one time outstanding through 2000.
Each bank has the option to discontinue its loans after 2000 upon three
years' prior written notice. Without such notice, the loans are
automatically extended for one year. However, to the extent that funds
are available from the Company and its regulated subsidiaries, AGC
borrowings are made through an internal money pool as described in Note
K.
Note K: Short-Term Debt
To provide interim financing and support for outstanding
commercial paper, lines of credit have been established with several
banks. The Company and its regulated subsidiaries have fee arrangements
on all of their lines of credit and no compensating balance
requirements. At December 31, 1996, unused lines of credit with banks
were $325,000,000.
In addition to bank lines of credit, an internal money pool
accommodates intercompany short-term borrowing needs, to the extent that
certain of the regulated companies have funds available. Short-term debt
outstanding for 1996 and 1995 consisted of:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Balance and interest rate at end of year:
Commercial Paper $156,430 - 6.22% $148,768 - 5.97%
Notes Payable to Banks 51,650 - 5.96%
Average amount outstanding and interest rate during the year:
Commercial Paper 90,722 - 5.47% 97,689 - 6.08%
Notes Payable to Banks 13,862 - 5.51% 21,134 - 6.00%
</TABLE>
Note L: Commitments and Contingencies
Construction Program
The regulated subsidiaries have entered into commitments for their
construction programs, for which expenditures are estimated to be $322
million for 1997 and $324 million for 1998. Construction expenditure
levels in 2000 and beyond will depend upon future generation
requirements, as well as the strategy eventually selected for complying
with Phase II of the Clean Air Act Amendments of 1990.
<PAGE> F-18
Nonutility Operations
In 1996, AYP Energy was formed as a subsidiary of AYP Capital to
operate as a power marketer in the wholesale electricity market. In
October 1996, AYP Energy finalized the purchase of a 50% interest (276
MW) in a power station unit, selling the output as an exempt wholesale
generator in the wholesale market. Power marketing is essentially
participation in a commodity market which creates certain exposures. AYP
Energy expects to use exchange-traded and over-the-counter futures,
options, and swap contracts both to hedge its exposure to changes in
electric power prices and for trading purposes.
The Company is currently committed to invest up to an additional
$7 million in AYP Capital to fund its investment in two limited
partnerships.
Environmental Matters and Litigation
The companies are subject to various laws, regulations, and
uncertainties as to environmental matters. Compliance may require them
to incur substantial additional costs to modify or replace existing and
proposed equipment and facilities and may affect adversely the lead
time, size, and siting of future generating stations, increase the
complexity and cost of pollution control equipment, and otherwise add to
the cost of future operations. In the normal course of business, the
companies become involved in various legal proceedings. The companies do
not believe that the ultimate outcome of these proceedings will have a
material effect on their financial position.
The regulated subsidiaries previously reported that the
Environmental Protection Agency had identified them and approximately
875 others as potentially responsible parties in a Superfund site
subject to cleanup. The regulated subsidiaries have also been named as
defendants along with multiple other defendants in pending asbestos
cases involving one or more plaintiffs. The subsidiaries believe that
provisions for liabilities and insurance recoveries are such that final
resolution of these claims will not have a material effect on their
financial position.
<PAGE> F-19
Monongahela Power Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
Monongahela Power Company
In our opinion, the accompanying balance sheet and statement of
capitalization and the related statements of income, of retained
earnings and of cash flows present fairly, in all material respects, the
financial position of Monongahela Power Company (a subsidiary of
Allegheny Power System, Inc.) at December 31, 1996 and 1995, and the
results of its operations and its cash flows for each of the three years
in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note A to the financial statements, the Company changed
its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> F-20
<TABLE>
<CAPTION>
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Electric Operating Revenues:
Residential..................................................... $206,033 $209,065 $190,861
Commercial...................................................... 121,631 124,457 116,201
Industrial...................................................... 200,970 212,427 202,181
Wholesale and other, including affiliates (Note A).............. 86,474 84,193 90,351
Bulk power transactions, net (Note A)........................... 17,363 13,338 16,853
Total Operating Revenues...................................... 632,471 643,480 616,447
Operating Expenses:
Operation:
Fuel.......................................................... 135,833 136,695 150,088
Purchased power and exchanges, net (Note A)................... 101,593 97,378 98,151
Deferred power costs, net (Note A)............................ (3,051) 19,647 7,604
Other......................................................... 76,105 77,020 75,066
Maintenance..................................................... 74,735 73,041 69,389
Restructuring charges and asset write-offs (Note B)............. 24,299 5,493
Depreciation.................................................... 55,490 57,864 57,952
Taxes other than income taxes................................... 40,418 38,551 40,404
Federal and state income taxes (Note C)......................... 34,496 41,834 30,650
Total Operating Expenses...................................... 539,918 547,523 529,304
Operating Income.............................................. 92,553 95,957 87,143
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A).................................. 313 446 1,566
Other income, net............................................... 6,831 9,235 8,003
Total Other Income and Deductions............................. 7,144 9,681 9,569
Income Before Interest Charges................................ 99,697 105,638 96,712
Interest Charges:
Interest on long-term debt...................................... 36,654 37,244 35,187
Other interest.................................................. 1,950 2,628 2,969
Allowance for borrowed funds used during
construction (Note A)......................................... (359) (947) (1,380)
Total Interest Charges........................................ 38,245 38,925 36,776
Income Before Cumulative Effect of
Accounting Change............................................... 61,452 66,713 59,936
Cumulative Effect of Accounting Change,
net (Note A).................................................... 7,945
Net Income........................................................ $ 61,452 $ 66,713 $ 67,881
STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $208,761 $198,626 $185,486
Add:
Net income...................................................... 61,452 66,713 67,881
270,213 265,339 253,367
Deduct:
Dividends on capital stock:
Preferred stock............................................... 5,037 6,555 7,260
Common stock.................................................. 49,955 48,660 47,481
Charge on redemption of preferred stock......................... 1,363
Total Deductions............................................ 54,992 56,578 54,741
Balance at December 31 (Note D)................................... $215,221 $208,761 $198,626
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-21
STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
1996 1995 1994
(Thousands of Dollars)
Cash Flows from Operations:
<S> <C> <C> <C>
Net income...................................................... $ 61,452 $ 66,713 $ 67,881
Depreciation.................................................... 55,490 57,864 57,952
Deferred investment credit and income taxes, net................ 7,739 3,519 3,350
Deferred power costs, net....................................... (3,051) 19,647 7,604
Unconsolidated subsidiaries' dividends in excess of earnings.... 3,100 2,403 1,647
Allowance for other than borrowed funds used
during construction........................................... (313) (446) (1,566)
Restructuring liability (Note B)................................ 13,734 3,693
Cumulative effect of accounting change before
income taxes (Note A)......................................... (13,279)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative effect
of accounting change (Note A)............................... 4,356 (11,222) 4,756
Materials and supplies........................................ 5,123 6,639 (5,944)
Accounts payable.............................................. (9,970) (3,373) (2,044)
Taxes accrued................................................. (3,565) 8,506 (950)
Interest accrued.............................................. (343) (2,350) 286
Other, net...................................................... 12,906 (3,107) 1,731
146,658 148,486 121,424
Cash Flows from Investing:
Construction expenditures....................................... (72,577) (75,458) (103,975)
Allowance for other than borrowed
funds used during construction................................ 313 446 1,566
(72,264) (75,012) (102,409)
Cash Flows from Financing:
Sale of preferred stock......................................... 49,635
Retirement of preferred stock................................... (41,406)
Issuance of long-term debt and QUIDS............................ 132,137 9,718
Retirement of long-term debt.................................... (18,500) (99,403)
Short-term debt, net............................................ 1,271 (6,702) (26,530)
Notes payable to affiliates..................................... (2,900) 2,900
Dividends on capital stock:
Preferred stock............................................... (5,037) (6,555) (7,260)
Common stock.................................................. (49,955) (48,660) (47,481)
(72,221) (73,489) (19,018)
Net Change in Cash and Temporary Cash Investments
(Note A)........................................................ 2,173 (15) (3)
Cash and Temporary Cash Investments at January 1.................. 117 132 135
Cash and Temporary Cash Investments at December 31................ $ 2,290 $ 117 $ 132
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 37,190 $ 42,394 $ 35,347
Income taxes.................................................. 31,064 30,696 29,939
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-22
<TABLE>
<CAPTION>
BALANCE SHEET
DECEMBER 31
ASSETS 1996 1995
(Thousands of Dollars)
<S> <C> <C>
Property, Plant, and Equipment:
At original cost, including $33,366,000 and
$29,443,000 under construction...................................... $1,879,622 $1,821,613
Accumulated depreciation.............................................. (790,649) (747,013)
1,088,973 1,074,600
Investments:
Allegheny Generating Company--common stock
at equity (Note E).................................................. 54,798 57,821
Other................................................................. 346 422
55,144 58,243
Current Assets:
Cash.................................................................. 2,290 117
Accounts receivable:
Electric service, net of $1,949,000 and
$2,267,000 uncollectible allowance (Note A)....................... 65,615 71,759
Affiliated and other................................................ 13,365 11,577
Materials and supplies--at average cost:
Operating and construction.......................................... 19,785 21,297
Fuel................................................................ 16,694 20,305
Prepaid taxes......................................................... 18,331 17,778
Deferred income taxes................................................. 6,442 7,972
Other................................................................. 4,251 4,857
146,773 155,662
Deferred Charges:
Regulatory assets (Note H)............................................ 171,692 164,900
Unamortized loss on reacquired debt................................... 15,256 16,174
Other................................................................. 8,917 11,012
195,865 192,086
Total................................................................... $1,486,755 $1,480,591
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes D and J)............................................ $ 512,212 $ 505,752
Preferred stock (Note J).............................................. 74,000 74,000
Long-term debt and QUIDS (Note J)..................................... 474,841 489,995
1,061,053 1,069,747
Current Liabilities:
Short-term debt (Note K).............................................. 28,239 29,868
Long-term debt due within one year (Note J)........................... 15,500 18,500
Notes payable to affiliates (Note K).................................. 2,900
Accounts payable...................................................... 12,997 24,582
Accounts payable to affiliates........................................ 10,170 6,500
Taxes accrued:
Federal and state income............................................ 3,788 8,068
Other............................................................... 21,464 20,749
Deferred power costs (Note A)......................................... 12,419 14,202
Interest accrued...................................................... 8,234 8,577
Restructuring liability (Note B)...................................... 13,997 3,693
Other................................................................. 13,613 15,940
143,321 150,679
Deferred Credits and Other Liabilities:
Unamortized investment credit......................................... 20,445 22,590
Deferred income taxes................................................. 225,841 206,616
Regulatory liabilities (Note H)....................................... 18,554 20,183
Other................................................................. 17,541 10,776
282,381 260,165
Commitments and Contingencies (Note L)
Total................................................................... $1,486,755 $1,480,591
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-23
STATEMENT OF CAPITALIZATION
<TABLE>
<CAPTION>
DECEMBER 31
1996 1995 1996 1995
(Thousands of Dollars) (Capitalization Ratios)
<S> <C> <C> <C> <C>
Common Stock:
Common stock--par value $50 per share, authorized
8,000,000 shares, outstanding 5,891,000 shares.... $ 294,550 $ 294,550
Other paid-in capital (Note J)...................... 2,441 2,441
Retained earnings (Note D).......................... 215,221 208,761
Total........................................... 512,212 505,752 48.3% 47.3%
Preferred Stock
Cumulative preferred stock--par value $100 per share,
authorized 1,500,000 shares, outstanding as follows
(Note J):
December 31, 1996
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
4.40% .... 90,000 $106.50 1945 9,000 9,000
4.80% B... 40,000 105.25 1947 4,000 4,000
4.50% C... 60,000 103.50 1950 6,000 6,000
$6.28 D... 50,000 102.86 1967 5,000 5,000
$7.73 L... 500,000 100.00 1994 50,000 50,000
Total (annual dividend requirements $5,037,000) 74,000 74,000 7.0 6.9
Long-Term Debt and QUIDS (Note J):
First mortgage Date of Date Date
bonds: Issue Redeemable Due
5-1/2% ... 1966 1996 1996 18,000
6-1/2% ... 1967 1997 1997 15,000 15,000
5-5/8% ... 1993 2000 2000 65,000 65,000
7-3/8% ... 1992 2002 2002 25,000 25,000
7-1/4% ... 1992 2002 2007 25,000 25,000
8-5/8% ... 1991 2001 2021 50,000 50,000
8-1/2% ... 1992 1997 2022 65,000 65,000
8-3/8% ... 1992 2002 2022 40,000 40,000
7-5/8% ... 1995 2005 2025 70,000 70,000
December 31, 1996
Interest Rate
Quarterly Income Debt Securities
due 2025...................... 8.00% 40,000 40,000
Secured notes due 1998-2024..... 5.95%-6.875% 74,050 74,050
Unsecured notes due 1996-2012... 6.30%-6.40% 7,060 7,560
Installment purchase
obligations due 1998.......... 6.875% 19,100 19,100
Unamortized debt discount and premium, net.......... (4,869) (5,215)
Total (annual interest requirements $36,453,631) 490,341 508,495
Less current maturities............................. (15,500) (18,500)
Total........................................... 474,841 489,995 44.7 45.8
Total Capitalization.................................. $1,061,053 $1,069,747 100.0% 100.0%
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-24
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.
Use of Estimates
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates that affect the
reported amounts of assets, liabilities, revenues, expenses, and disclosures
of contingencies during the reporting period, which in the normal course of
business are subsequently adjusted to actual results.
Revenues
Revenues, including amounts resulting from the application of fuel and energy
cost adjustment clauses, are recognized in the same period in which the related
electric services are provided to customers, by recording an estimate for
unbilled revenues for services provided from the meter reading date to the end
of the accounting period.
Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and revenues from
sales to other companies, including transmission services, are deferred until
they are either recovered from or credited to customers under fuel and energy
cost recovery procedures.
Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with regulated
affiliates in the System, are stated at original cost, less contributions in
aid of construction, except for capital leases, which are recorded at present
value. 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 postretirement benefits, taxes, and other fringe benefits related to
employees engaged in construction.
The cost of depreciable property units retired, plus removal costs less salvage,
are charged to accumulated depreciation.
Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is defined
in applicable regulatory systems of accounts as including "the net cost for the
period of construction of borrowed funds used for construction purposes and a
reasonable rate on other funds when so used." AFUDC is recognized as a cost of
property, plant, and equipment with offsetting credits to other income and
interest charges. Rates used for computing AFUDC in 1996, 1995, and 1994
were 7.90%, 7.29%, and 8.16%, respectively. AFUDC is not included in the
cost of such construction when the cost of financing the construction is
being recovered through rates.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a straight-line method
based on estimated service lives of depreciable properties and amounted to
approximately 3.1%, 3.4%, and 3.6% of average depreciable property in 1996,
1995, and 1994, respectively. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.
Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash investments with
original maturities of three months or less, generally in the form of
commercial paper, certificates of deposit, and repurchase agreements, are
considered to be the equivalent of cash.
Regulatory Deferrals
In accordance with the Financial Accounting Standards Board's Statement of
Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation," the Company's financial statements reflect
assets and liabilities based on current cost-based ratemaking regulation.
<PAGE> F-25
Income Taxes
The Company joins with its parent and affiliates in filing a consolidated
federal income tax return. The consolidated tax liability is allocated among
the participants generally in proportion to the taxable income of each
participant, except that no subsidiary pays tax in excess of its separate
return tax liability.
Financial accounting income before income taxes differs from taxable income
principally because certain income and deductions for tax purposes are
recorded in the financial income statement in another period. Differences
between income tax expense computed on the basis of financial accounting income
and taxes payable based on taxable income are accounted for substantially in
accordance with the accounting procedures followed for ratemaking purposes.
Deferred tax assets and liabilities represent the tax effect of temporary
differences between the financial statement and tax basis of assets and
liabilities computed utilizing the most current tax rates.
Provisions for federal income tax were reduced in previous years by investment
credits, and amounts equivalent to such credits were charged to income with
concurrent credits to a deferred account. These balances are being amortized
over the estimated service lives of the related properties.
Postretirement Benefits
The Company participates with affiliated companies in the System in a
noncontributory, defined benefit pension plan covering substantially all
employees, including officers. Benefits are based on the employee's years
of service and compensation. The funding policy is to contribute annually at
least the minimum amount required under the Employee Retirement Income
Security Act and not more than can be deducted for federal income tax purposes.
The Company also provides partially contributory medical and life insurance
plans for eligible retirees and dependents. Medical benefits, which comprise
the largest component of the plans, are based upon an age and years-of-
service vesting schedule and other plan provisions. The funding plan for these
costs is to contribute the maximum amount that can be deducted for federal
income tax purposes. Funding of these benefits is made primarily into Voluntary
Employee Beneficiary Association trust funds. Medical benefits are self-
insured; the life insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification
Effective in 1996, the Company changed its method of reporting certain bulk
power transmission transactions with nonaffiliated utilities and reclassified
prior years' bulk power and other revenues and operation expenses to achieve
a consistent presentation. In prior years, some use of the Company's
transmission system was recorded as purchased power from selling utilities
and as sales of power to buying utilities. The benefit to the Company was
the difference between the two. Because of new FERC requirements, the
Company predominantly does not "buy" and "sell" such energy, but rather a
transmission fee is charged.
Under the new reporting method, all such transactions are recorded on a net
revenue basis. The effect of the reclassifications was to reduce amounts
previously reported for bulk power transactions revenues and operation
expenses by $79 million and $64 million for 1995 and 1994, respectively, with no
change in operating income or net income.
Accounting Change
Effective January 1, 1994, the Company changed its revenue recognition method to
include the accrual of estimated unbilled revenues for electric services. The
cumulative effect of this accounting change for years prior to 1994 which is
shown separately in the statement of income for 1994, resulted in a benefit of
$7.9 million (after related income taxes of $5.4 million). The effect of the
change on 1994 income before the cumulative effect of accounting change is not
material.
NOTE B: RESTRUCTURING CHARGES AND ASSET WRITE-OFFS
In 1996, the System, including the Company, essentially completed its
restructuring initiatives undertaken in 1995, simplifying the management
structure and streamlining operations. During 1996, restructuring activities
included consolidating operating divisions, customer services, and other
functions. By reorganizing and eliminating certain processes and
consolidating common decentralized functions, the System reduced employment
by about 1,000 employees since October 1994. These reductions were accomplished
through a voluntary separation plan, attrition, and layoffs.
In 1996 and 1995, the Company recorded restructuring charges of $24.3 million
($14.6 million after tax) and $4.1 million ($2.5 million after tax) in operating
expenses, including its share of all restructuring charges associated with the
reorganization, which is essentially complete. These charges reflect
liabilities and payments for severance, employee termination costs, and other
restructuring costs. The restructuring liability consists of:
<PAGE> F-26
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S><C> <C> <C>
Restructuring Liability (before tax):
Balance at the beginning of period............. $ 3,693
Accruals..................................... 24,299 $4,117
Less payments................................ (10,565) (424)
Balance at end of period....................... $17,427* $3,693
</TABLE>
*Includes $3,430,000 for benefit plans curtailment liabilities and special
termination benefits which are primarily recorded in other deferred credits.
In connection with changes in inventory management objectives, the Company in
1995 also recorded $1.4 million ($.8 million after tax) for the write-off of
obsolete and slow-moving materials.
NOTE C: INCOME TAXES
Details of federal and state income tax provisions are:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Income taxes--current:
Federal............................. $19,412 $30,236 $27,793
State............................... 7,317 8,707 4,841
Total............................. 26,729 38,943 32,634
Income taxes--deferred, net of
amortization........................ 9,883 5,664 5,499
Amortization of deferred
investment credit................... (2,145) (2,145) (2,149)
Total income taxes................ 34,467 42,462 35,984
Income taxes--credited (charged)
to other income and deductions...... 29 (628) 1
Income taxes--charged to accounting
change (including state income
taxes).............................. (5,335)
Income taxes--charged to operating
income.............................. $34,496 $41,834 $30,650
</TABLE>
The total provision for income taxes is different from the amount produced by
applying the federal income statutory tax rate of 35% to financial accounting
income, as set forth below:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Financial accounting income before
cumulative effect of accounting
change and income taxes............. $ 95,948 $108,547 $90,648
Amount so produced.................... $ 33,600 $ 38,000 $31,700
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation.......... 4,300 4,300 5,400
Plant removal costs............. (2,200) (1,500) (2,100)
State income tax, net of federal
income tax benefit................ 4,000 4,800 3,500
Amortization of deferred
investment credit................. (2,145) (2,145) (2,149)
Equity in earnings of subsidiaries.. (2,500) (2,500) (2,800)
Adjustments of provisions for
prior years....................... (40) 2,431 (1,900)
Other, net.......................... (519) (1,552) (1,001)
Total........................... $ 34,496 $ 41,834 $30,650
</TABLE>
Federal income tax returns through 1993 have been examined and substantially
settled through 1991.
At December 31, the deferred tax assets and liabilities consist of the
following:
<PAGE> F-27
(Thousands of Dollars) 1996 1995
Deferred tax assets:
Unamortized investment tax credit............ $ 13,744 $ 15,133
Deferred power costs......................... 5,297 7,483
Restructuring................................ 4,968 1,481
Tax interest capitalized..................... 4,300 4,759
Contributions in aid of construction......... 2,483 2,488
Advances for construction.................... 1,939 1,939
Other........................................ 10,153 10,565
42,884 43,848
Deferred tax liabilities:
Book vs. tax plant basis differences, net.... 230,738 209,527
Other........................................ 31,545 32,964
262,283 242,491
Total net deferred tax liabilities............. 219,399 198,643
Add portion above included in current assets... 6,442 7,973
Total long-term net deferred tax liabilities... $225,841 $206,616
NOTE D: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of the Company
contain dividend restrictions under the most restrictive of which
$76,384,000 of retained earnings at December 31, 1996, is not available for
cash dividends on common stock, except that a portion thereof may be paid as
cash dividends where concurrently an equivalent amount of cash is received by
the Company as a capital contribution or as the proceeds of the issue and
sale of shares of its common stock.
NOTE E: ALLEGHENY GENERATING COMPANY
The Company owns 27% of the common stock of Allegheny Generating Company (AGC),
and affiliates of the Company own the remainder. AGC owns an undivided 40%
interest, 840 MW, in the 2,100-MW pumped-storage hydroelectric station in
Bath County, Virginia operated by the 60% owner, Virginia Electric and Power
Company, a nonaffiliated utility.
AGC recovers from the Company and its affiliates all of its operation and
maintenance expenses, depreciation, taxes, and a return on its investment under
a wholesale rate schedule approved by the FERC. AGC's rates are set by a
formula filed with and previously accepted by the FERC. The only component
which changes is the return on equity (ROE). AGC's ROE was 11.13% for 1994 and
11.2% for 1995. Pursuant to a settlement agreement filed April 4, 1996, with
the FERC, AGC's ROE was set at 11% for 1996 and will continue until the time
any affected party seeks renegotiation of the ROE. Notice of such intent to
seek a revision in ROE must be filed during a notice period each year between
November 1 and November 15. No requests for change were filed during the 1996
notice period. Therefore, AGC's ROE will remain at 11% for 1997.
Following is a summary of financial information for AGC:
<TABLE>
<CAPTION>
December 31
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Balance sheet information:
Property, plant, and equipment............... $660,872 $677,857
Current assets............................... 7,659 7,586
Deferred charges............................. 23,877 24,844
Total assets............................... $692,408 $710,287
Total capitalization......................... $431,589 $463,862
Current liabilities.......................... 15,531 11,892
Deferred credits............................. 245,288 234,533
Total capitalization and liabilities....... $692,408 $710,287
</TABLE>
<PAGE> F-28
<TABLE>
<CAPTION>
Year Ended December 31
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Income statement information:
Electric operating revenues......... $83,402 $86,970 $91,022
Operation and maintenance expense... 5,165 5,740 6,695
Depreciation........................ 17,160 17,018 16,852
Taxes other than income taxes....... 4,801 5,091 5,223
Federal income taxes................ 13,297 13,552 14,737
Interest charges.................... 16,193 18,361 17,809
Other income, net................... (3) (16) (11)
Net income........................ $26,789 $27,224 $29,717
</TABLE>
The Company's share of the equity in earnings above was $7.2 million, $7.4
million, and $8.0 million for 1996, 1995, and 1994, respectively, and is
included in other income, net, on the Statement of Income.
NOTE F: PENSION BENEFITS
The Company's share of net pension costs under the System's pension plan, a
portion of which (about 25% to 30%) was charged to plant construction, included
the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned........ $ 3,526 $ 3,340 $ 3,677
Interest cost on projected
benefit obligation.................. 9,735 9,375 9,045
Actual (return) loss on plan assets... (16,433) (27,269) 87
Net amortization and deferral......... 3,250 15,183 (11,563)
Pension cost.......................... 78 629 1,246
Reversal of previous deferrals........ 3,718
Total pension cost.................... $ 78 $ 629 $ 4,964
</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>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of
$110,659,000 and $100,006,000)............... $118,118 $107,672
Funded status:
Actuarial present value of projected
benefit obligation......................... $140,333 $133,485
Plan assets at market value, primarily
common stocks and fixed income securities.. 165,360 156,554
Plan assets in excess of projected
benefit obligation......................... (25,027) (23,069)
Add:
Unrecognized cumulative net gain from
past experience different from
that assumed............................. 25,365 24,151
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987.......................... 2,532 3,242
Less unrecognized prior service cost due
to plan amendments......................... (1,714) (2,195)
Pension cost liability at December 31........ $ 1,156 $ 2,129
</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 September 30, 1996, 1995, and 1994, the discount rates used
<PAGE> F-29
were 7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation
levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term rate of
return on assets was 9% in each of the years 1996, 1995, and 1994.
The pension cost liability at December 31, 1996, includes the net result of a
curtailment gain of $2.9 million and an expense for special termination benefits
of $1.4 million associated with the work force reduction.
NOTE G: POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The cost of postretirement benefits other than pensions (principally health care
and life insurance) for employees and covered dependents, a portion of which
(about 25% to 30%) was charged to plant construction, included the following
components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned.......... $ 735 $ 741 $ 764
Interest cost on accumulated
postretirement benefit obligation..... 3,759 3,939 3,655
Actual (return) loss on plan assets..... (1,191) (1,702) 38
Amortization of unrecognized
transition obligation................. 1,786 1,783 1,783
Other net amortization and deferral..... 223 1,376 50
Postretirement cost..................... 5,312 6,137 6,290
Regulatory reversal (deferral).......... 149 345 (3,450)
Net postretirement cost................. $ 5,461 $ 6,482 $ 2,840
</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>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees.................................... $40,898 $32,249
Fully eligible employees.................... 2,577 5,221
Other employees............................. 12,439 14,177
Total obligation.......................... 55,914 51,647
Plan assets at market value, in common stocks,
fixed income securities, and short-term
investments................................. 12,721 10,515
Accumulated postretirement benefit
obligation in excess of plan assets......... 43,193 41,132
Less:
Unrecognized cumulative net loss from past
experience different from that assumed.... (8,662) (7,559)
Unrecognized transition obligation, being
amortized over 20 years beginning
January 1, 1993........................... (26,136) (30,378)
Postretirement benefit liability
at September 30............................. 8,395 3,195
Fourth quarter contributions and benefit
payments.................................... (1,233) (2,046)
Postretirement benefit liability at
December 31................................. $ 7,162 $ 1,149
</TABLE>
<PAGE> F-30
In determining the accumulated postretirement benefit obligation (APBO) at
September 30, 1996, 1995, and 1994, the discount rates used were 7.5%, 7.5%, and
7.75% and the rates of increase in future compensation levels were 4.5%,
4.5%, and 4.75%, respectively. The expected long-term rate of return on assets
was 8.25% in each of the years 1996, 1995, and 1994. For measurement purposes,
a health care trend rate of 7% for 1997, declining to 6.5% in 1998 and beyond,
and plan provisions which limit future medical and life insurance benefits, were
assumed. Increasing the assumed health care trend rate by 1% in each year would
increase the APBO at December 31, 1996, by $3.7 million and the aggregate of the
service and interest cost components of net periodic postretirement benefit cost
for 1996 by $.3 million.
The postretirement benefit liability at December 31, 1996, includes a
curtailment loss of $3.4 million and an expense for special termination benefits
of $1.5 million associated with the workforce reduction.
NOTE H: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Regulatory assets
represent probable future revenues associated with deferred
costs that are expected to be recovered from customers through the ratemaking
process. Regulatory liabilities represent probable future reductions in
revenues associated with amounts that are to be credited to customers through
the ratemaking process. Regulatory assets, net of regulatory liabilities,
reflected in the Balance Sheet at December 31 relate to:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Long-Term Assets (Liabilities), Net:
Income taxes, net.......................... $140,804 $129,933
Postretirement benefits.................... 4,937 5,087
Storm damage............................... 3,375 4,539
Other, net................................. 4,022 5,158
Subtotal................................. 153,138 144,717
Current Assets (Liabilities), Net:
Income taxes, net.......................... 1,847 1,847
Deferred power costs....................... (12,419) (14,202)
Subtotal................................. (10,572) (12,355)
Net Regulatory Assets.................. $142,566 $132,362
</TABLE>
NOTE I: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments at
December 31 were as follows:
<TABLE>
<CAPTION>
1996 1995
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
<S> <C> <C> <C> <C>
Liabilities:
Short-term debt..... $ 31,139 $ 31,139 $ 29,868 $ 29,868
Long-term debt and
QUIDS............. 495,210 505,922 513,710 540,387
</TABLE>
The carrying amount of short-term debt approximates the fair value because of
the short maturity of those instruments. The fair value of long-term debt and
QUIDS was estimated based on actual market prices or market prices of similar
issues. The Company has no financial instruments held or issued for trading
purposes.
NOTE J: CAPITALIZATION
Other Paid-In Capital
Other paid-in capital decreased $76,000 in 1995 as a result of preferred stock
transactions and $477,000 in 1994 as a result of underwriting fees and
commissions associated with the Company's sale of $50 million of preferred
stock.
Preferred Stock
All of the preferred stock is entitled on voluntary liquidation to its then
current call price and on involuntary liquidation to $100 a share.
<PAGE> F-31
Long-Term Debt and QUIDS
Maturities for long-term debt for the next five years are: 1997, $15,500,000;
1998, $20,100,000; 1999, $1,000,000; 2000, $66,000,000; 2001, $1,000,000.
Substantially all of the properties of the Company are held subject to the
lien securing its first mortgage bonds. Some properties are also subject to a
second lien securing certain pollution control and solid waste disposal notes.
Certain first mortgage bonds series are not redeemable by certain refunding
until dates established in the respective supplemental indentures.
NOTE K: SHORT-TERM DEBT
To provide interim financing and support for outstanding commercial paper, the
System companies have established lines of credit with several banks. The
Company has SEC authorization for total short-term borrowings of $100
million, including money pool borrowings described below. The Company has fee
arrangements on all of its lines of credit and no compensating balance
requirements. In addition to bank lines of credit, an internal money pool
accommodates intercompany short-term borrowing needs, to the extent that
certain of the regulated companies have funds available. Short-term debt
outstanding for 1996 and 1995 consisted of:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C> <C>
Balance and interest rate
at end of year:
Commercial Paper.................. $28,239-7.00% $22,368-6.09%
Notes Payable to Banks............ 7,500-6.00%
Money Pool........................ 2,900-5.53%
Average amount outstanding and
interest rate during the year:
Commercial Paper.................. 3,176-5.64% 8,699-5.96%
Notes Payable to Banks............ 2,266-5.46% 7,153-5.99%
Money Pool........................ 1,058-5.29% 3,116-5.85%
</TABLE>
NOTE L: COMMITMENTS AND CONTINGENCIES
Construction Program
The Company has entered into commitments for its construction program, for which
expenditures are estimated to be $83 million for 1997 and $91 million for
1998. Construction expenditure levels in 2000 and beyond will depend upon
future generation requirements, as well as the strategy eventually selected for
complying with Phase II of the Clean Air Act Amendments of 1990.
Environmental Matters and Litigation
System companies are subject to various laws, regulations, and uncertainties as
to environmental matters. Compliance may require them to incur substantial
additional costs to modify or replace existing and proposed equipment and
facilities and may affect adversely the lead time, size, and siting of future
generating stations, increase the complexity and cost of pollution control
equipment, and otherwise add to the cost of future operations. In the normal
course of business, the Company becomes involved in various legal proceedings.
The Company does not believe that the ultimate outcome of these proceedings
will have a material effect on its financial position.
The Company previously reported that the Environmental Protection Agency had
identified it and its affiliates and approximately 875 others as potentially
responsible parties in a Superfund site subject to cleanup. The Company has
also been named as a defendant along with multiple other defendants in pending
asbestos cases involving one or more plaintiffs. The Company believes that
provisions for liabilities and insurance recoveries are such that final
resolution of these claims will not have a material effect on their financial
position.
The Company is guarantor as to 27% of a $50 million revolving credit agreement
of AGC, which in 1996 was used by AGC solely as support for its indebtedness for
commercial paper outstanding.
<PAGE> F-32
The Potomac Edison Company
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
The Potomac Edison Company
In our opinion, the accompanying balance sheet and statement of
capitalization and the related statements of income, of retained
earnings and of cash flows present fairly, in all material respects, the
financial position of The Potomac Edison Company (a subsidiary of
Allegheny Power System, Inc.) at December 31, 1996 and 1995, and the
results of its operations and its cash flows for each of the three years
in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note A to the financial statements, the Company changed
its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> F-33
<TABLE>
<CAPTION>
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1996 1995 1994
<S> <C> <C> <C>
(Thousands of Dollars)
Electric Operating Revenues:
Residential..................................................... $324,120 $316,714 $296,090
Commercial...................................................... 146,432 145,096 135,937
Industrial...................................................... 196,813 200,890 195,089
Wholesale and other, including affiliates (Note A).............. 34,901 28,592 24,178
Bulk power transactions, net (Note A)........................... 24,494 19,377 21,607
Total Operating Revenues...................................... 726,760 710,669 672,901
Operating Expenses:
Operation:
Fuel.......................................................... 137,310 134,459 145,045
Purchased power and exchanges, net (Note A)................... 141,027 137,280 130,672
Deferred power costs, net (Note A)............................ 5,040 13,056 1,321
Other......................................................... 89,756 89,936 85,129
Maintenance..................................................... 62,248 60,052 58,624
Restructuring charges and asset write-offs (Note B)............. 26,094 6,847
Depreciation.................................................... 71,254 68,826 59,989
Taxes other than income taxes................................... 45,809 47,629 46,740
Federal and state income taxes (Note C)......................... 34,132 36,936 33,126
Total Operating Expenses...................................... 612,670 595,021 560,646
Operating Income.............................................. 114,090 115,648 112,255
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A).................................. 1,409 1,054 3,671
Other income, net............................................... 11,791 12,044 10,310
Total Other Income and Deductions............................. 13,200 13,098 13,981
Income Before Interest Charges................................ 127,290 128,746 126,236
Interest Charges:
Interest on long-term debt...................................... 47,982 49,113 44,706
Other interest.................................................. 2,215 2,066 1,750
Allowance for borrowed funds used during
construction (Note A)......................................... (1,082) (698) (2,203)
Total Interest Charges........................................ 49,115 50,481 44,253
Income Before Cumulative Effect of
Accounting Change............................................... 78,175 78,265 81,983
Cumulative Effect of Accounting Change,
net (Note A).................................................... 16,471
Net Income........................................................ $ 78,175 $ 78,265 $ 98,454
STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $216,852 $207,722 $176,053
Add:
Net income...................................................... 78,175 78,265 98,454
295,027 285,987 274,507
Deduct:
Dividends on capital stock:
Preferred stock............................................... 818 2,455 4,331
Common stock.................................................. 66,483 64,693 62,454
Charges on redemption of preferred stock........................ 1,987
Total Deductions.............................................. 67,301 69,135 66,785
Balance at December 31............................................ $227,726 $216,852 $207,722
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-34
<TABLE>
<CAPTION>
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows from Operations:
Net income...................................................... $ 78,175 $ 78,265 $ 98,454
Depreciation.................................................... 71,254 68,826 59,989
Deferred investment credit and income taxes, net................ 5,157 14,279 12,688
Deferred power costs, net....................................... 5,040 13,056 1,321
Unconsolidated subsidiaries' dividends in excess of earnings.... 3,211 2,489 1,704
Allowance for other than borrowed funds used
during construction........................................... (1,409) (1,054) (3,671)
Restructuring liability (Note B)................................ 15,801 4,251
Cumulative effect of accounting change before
income taxes (Note A)......................................... (26,163)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative effect
of accounting change (Note A)............................... (2,016) (25,050) 6,004
Materials and supplies........................................ 6,768 4,554 (5,367)
Accounts payable.............................................. 4,184 885 (9,981)
Taxes accrued................................................. (4,231) 457 (1,083)
Interest accrued.............................................. (226) 443 563
Other, net...................................................... 1,771 (9,222) (198)
183,479 152,179 134,260
Cash Flows from Investing:
Construction expenditures....................................... (86,256) (92,240) (142,826)
Allowance for other than borrowed
funds used during construction................................ 1,409 1,054 3,671
(84,847) (91,186) (139,155)
Cash Flows from Financing:
Retirement of preferred stock................................... (48,396) (1,190)
Issuance of long-term debt and QUIDS............................ 207,019 86,877
Retirement of long-term debt.................................... (18,700) (175,248) (16,000)
Short-term debt, net............................................ (14,140) 21,637
Notes receivable from affiliates................................ 1,900 2,700
Dividends on capital stock:
Preferred stock............................................... (818) (2,455) (4,331)
Common stock.................................................. (66,483) (64,693) (62,454)
(100,141) (60,236) 5,602
Net Change in Cash and Temporary Cash Investments
(Note A)........................................................ (1,509) 757 707
Cash and Temporary Cash Investments at January 1.................. 2,953 2,196 1,489
Cash and Temporary Cash Investments at December 31................ $ 1,444 $ 2,953 $ 2,196
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 47,580 $ 49,399 $ 42,680
Income taxes.................................................. 37,694 25,679 30,771
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-35
<TABLE>
<CAPTION>
BALANCE SHEET
DECEMBER 31
<S> <C> <C>
ASSETS 1996 1995
(Thousands of Dollars)
Property, Plant, and Equipment:
At original cost, including $60,082,000 and
$49,987,000 under construction...................................... $2,124,956 $2,050,835
Accumulated depreciation.............................................. (791,257) (729,653)
1,333,699 1,321,182
Investments:
Allegheny Generating Company--common stock
at equity (Note D).................................................. 56,827 59,963
Other................................................................. 642 868
57,469 60,831
Current Assets:
Cash.................................................................. 1,444 2,953
Accounts receivable:
Electric service, net of $1,580,000 and $1,344,000
uncollectible allowance (Note A).................................. 95,215 93,250
Affiliated and other................................................ 2,968 2,917
Materials and supplies--at average cost:
Operating and construction.......................................... 23,775 26,414
Fuel................................................................ 15,019 19,148
Prepaid taxes......................................................... 17,648 13,748
Other................................................................. 7,764 3,158
163,833 161,588
Deferred Charges:
Regulatory assets (Note G)............................................ 94,919 80,693
Unamortized loss on reacquired debt................................... 18,010 18,926
Other................................................................. 9,956 11,224
122,885 110,843
Total................................................................... $1,677,886 $1,654,444
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Note I)................................................... $ 678,116 $ 667,242
Preferred stock (Note I).............................................. 16,378 16,378
Long-term debt and QUIDS (Note I)..................................... 628,431 628,854
1,322,925 1,312,474
Current Liabilities:
Short-term debt (Note J).............................................. 7,497 21,637
Long-term debt due within one year (Note I)........................... 800 18,700
Accounts payable...................................................... 33,152 28,931
Accounts payable to affiliates........................................ 17,896 15,608
Taxes accrued:
Federal and state income............................................ 123 3,293
Other............................................................... 11,542 12,603
Interest accrued...................................................... 9,412 9,638
Customer deposits..................................................... 6,121 6,540
Restructuring liability (Note B)...................................... 14,970 4,251
Other................................................................. 7,603 8,251
109,116 129,452
Deferred Credits and Other Liabilities:
Unamortized investment credit......................................... 23,622 25,816
Deferred income taxes................................................. 183,727 155,432
Regulatory liabilities (Note G)....................................... 13,907 15,255
Other................................................................. 24,589 16,015
245,845 212,518
Commitments and Contingencies (Note K)
Total................................................................... $1,677,886 $1,654,444
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-36
<TABLE>
<CAPTION>
STATEMENT OF CAPITALIZATION
DECEMBER 31
1996 1995 1996 1995
<S> <C> <C> <C> <C>
(Thousands of Dollars) (Capitalization Ratios)
Common Stock:
Common stock--no par value, authorized 23,000,000
shares, outstanding 22,385,000 shares..................... $ 447,700 $ 447,700
Other paid-in capital (Note I).............................. 2,690 2,690
Retained earnings........................................... 227,726 216,852
Total................................................... 678,116 667,242 51.3% 50.8%
</TABLE>
Preferred Stock:
Cumulative preferred stock--par value $100 per share,
authorized 5,378,611 shares, outstanding as follows
(Note I):
<TABLE>
<CAPTION>
December 31, 1996
Regular
<S> <C> <C> <C> <C> <C>
Shares Call Price Date of
Series Outstanding Per Share Issue
3.60% .... 63,784 $103.75 1946 6,378 6,378
$5.88 C... 100,000 102.85 1967 10,000 10,000
Total (annual dividend requirements $817,622) 16,378 16,378 1.2 1.3
Long-Term Debt and QUIDS (Note I):
First mortgage Date of Date Date
bonds: Issue Redeemable Due
5-7/8% ...... 1966 1996 1996 18,000
5-7/8% ...... 1993 2000 2000 75,000 75,000
8 % ...... 1991 2001 2006 50,000 50,000
8-7/8% ...... 1991 2001 2021 50,000 50,000
8 % ...... 1992 2002 2022 55,000 55,000
7-3/4% ...... 1993 2003 2023 45,000 45,000
8 % ...... 1994 2004 2024 75,000 75,000
7-5/8% ...... 1995 2005 2025 80,000 80,000
7-3/4% ...... 1995 2005 2025 65,000 65,000
December 31, 1996
Interest Rate
Quarterly Income Debt Securities
due 2025........................ 8.00% 45,457 45,457
Secured notes due 1998-2024....... 5.95%-6.875% 91,700 91,700
Unsecured note due 1996-2002...... 6.30% 4,800 5,500
Unamortized debt discount................................... (7,726) (8,103)
Total (annual interest requirements $47,605,858)........ 629,231 647,554
Less current maturities..................................... (800) (18,700)
Total................................................... 628,431 628,854 47.5 47.9
Total Capitalization.......................................... $1,322,925 $1,312,474 100.0% 100.0%
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-37
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.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
that affect the reported amounts of assets, liabilities, revenues,
expenses, and disclosures of contingencies during the reporting period,
which in the normal course of business are subsequently adjusted to
actual results.
Revenues
Revenues, including amounts resulting from the application of fuel and
energy cost adjustment clauses, are recognized in the same period in
which the related electric services are provided to customers, by
recording an estimate for unbilled revenues for services provided from
the meter reading date to the end of the accounting period. Revenues of
$64 million from one industrial customer were 9% of total electric
operating revenues in 1996.
Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other companies, including transmission services,
are deferred until they are either recovered from or credited to
customers under fuel and energy cost recovery procedures.
Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated 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
postretirement benefits, taxes, and other fringe benefits related to
employees engaged in construction.
The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
<PAGE> F-38
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 1996, 1995, and 1994 were 9.32%, 9.71%, and 9.73%,
respectively. AFUDC is not included
in the cost of such construction when the cost of financing the
construction is being recovered through rates. AFUDC is not recorded
for construction applicable to the state of Virginia, where construction
work in progress is included in rate base.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a straight-line
method based on estimated service lives of depreciable properties and
amounted to approximately 3.6% of average depreciable property in 1996
and 1995 and 3.4% in 1994. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged principally to
operating expenses.
Temporary Cash Investments
For purposes of the statement of cash flows, temporary cash investments
with original maturities of three months or less, generally in the form
of commercial paper, certificates of deposit, and repurchase agreements,
are considered to be the equivalent of cash.
Regulatory Deferrals
In accordance with the Financial Accounting Standards Board's Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation," the Company's financial
statements reflect assets and liabilities based on current cost-based
ratemaking regulation.
Income Taxes
The Company joins with its parent and affiliates in filing a
consolidated federal income tax return. The consolidated tax liability
is allocated among the participants generally in proportion to the
taxable income of each participant, except that no subsidiary pays tax
in excess of its separate return tax liability.
Financial accounting income before income taxes differs from taxable
income principally because certain income and deductions for tax
purposes are recorded in the financial income statement in another
period. Differences between income tax expense computed on the basis of
financial accounting income and taxes payable based on taxable income
are accounted for substantially in accordance with the accounting
procedures followed for ratemaking purposes. Deferred tax assets and
liabilities represent the tax effect of temporary differences between
the financial statement and tax basis of assets and liabilities computed
utilizing the most current tax rates.
<PAGE> F-39
Provisions for federal income tax were reduced in previous years by
investment credits, and amounts equivalent to such credits were charged
to income with concurrent credits to a deferred account. These balances
are being amortized over the estimated service lives of the related
properties.
Postretirement Benefits
The Company participates with affiliated companies in the System in a
noncontributory, defined benefit pension plan covering substantially all
employees, including officers. Benefits are based on the employee's
years of service and compensation. The funding policy is to contribute
annually at least the minimum amount required under the Employee
Retirement Income Security Act and not more than can be deducted for
federal income tax purposes.
The Company also provides partially contributory medical and life
insurance plans for eligible retirees and dependents. Medical benefits,
which comprise the largest component of the plans, are based upon an age
and years-of-service vesting schedule and other plan provisions. The
funding plan for these costs is to contribute the maximum amount that
can be deducted for federal income tax purposes. Funding of these
benefits is made primarily into Voluntary Employee Beneficiary
Association trust funds. Medical benefits are self-insured; the life
insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification
Effective in 1996, the Company changed its method of reporting certain
bulk power transmission transactions with nonaffiliated utilities and
reclassified prior years' bulk power and other revenues and operation
expenses to achieve a consistent presentation. In prior years, some use
of the Company's transmission system was recorded as purchased power
from selling utilities and as sales of power to buying utilities. The
benefit to the Company was the difference between the two. Because of
new FERC requirements, the Company predominantly does not "buy" and
"sell" such energy, but rather a transmission fee is charged.
Under the new reporting method, all such transactions are recorded on a
net revenue basis. The effect of the reclassifications was to reduce
amounts previously reported for bulk power transactions revenues and
operation expenses by $108 million and $86 million for 1995 and 1994,
respectively, with no change in operating income or net income.
Accounting Change
Effective January 1, 1994, the Company changed its revenue recognition
method to include the accrual of estimated unbilled revenues for
electric services. The cumulative effect of this accounting change for
years prior to 1994, which is shown separately in the statement of
income for 1994, resulted in a benefit of $16.5 million (after related
income taxes of $9.7 million). The effect of the change on 1994 income
before the cumulative effect of accounting change is not material.
<PAGE> F-40
NOTE B: RESTRUCTURING CHARGES AND ASSET WRITE-OFFS
In 1996, the System, including the Company, essentially completed its
restructuring initiatives undertaken in 1995, simplifying the management
structure and streamlining operations. During 1996, restructuring
activities included consolidating operating divisions, customer
services, and other functions. By reorganizing and eliminating certain
processes and consolidating common decentralized functions, the System
reduced employment by about 1,000 employees since October 1994. These
reductions were accomplished through a voluntary separation plan,
attrition, and layoffs.
In 1996 and 1995, the Company recorded restructuring charges of $26.1
million ($16.5 million after tax) and $4.6 million ($2.9 million after
tax) in operating expenses, including its share of all restructuring
charges associated with the reorganization, which is essentially
complete. These charges reflect liabilities and payments for severance,
employee termination costs, and other restructuring costs. The
restructuring liability consists of:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Restructuring liability (before tax):
Balance at the beginning of period........... $ 4,251
Accruals................................... 26,094 $4,602
Less payments.............................. (10,293) (351)
Balance at end of period..................... $20,052* $4,251
</TABLE>
*Includes $5,082,000 for benefit plans curtailment liabilities and special
termination benefits which are primarily recorded in other deferred
credits.
In connection with changes in inventory management objectives, the
Company in 1995 also recorded $2.2 million ($1.4 million after tax) for
the write-off of obsolete and slow-moving materials.
NOTE C: INCOME TAXES
<TABLE>
<CAPTION>
Details of federal and state income tax provisions are:
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Income taxes--current:
Federal............................. $26,651 $25,949 $34,193
State............................... 4,833 (640) (2,849)
Total............................. 31,484 25,309 31,344
Income taxes--deferred, net of
amortization........................ 7,351 16,504 14,955
Amortization of deferred
investment credit................... (2,194) (2,225) (2,267)
Total income taxes................ 36,641 39,588 44,032
Income taxes--charged to other
income and deductions............... (2,509) (2,652) (1,213)
Income taxes--charged to accounting
change (including state income
taxes).............................. (9,693)
Income taxes--charged to operating
income.............................. $34,132 $36,936 $33,126
</TABLE>
<PAGE> F-41
The total provision for income taxes is different from the amount
produced by applying the federal income statutory tax rate of 35% to
financial accounting income, as set forth below:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Financial accounting income before
cumulative effect of accounting
change and income taxes............ $112,305 $115,201 $115,146
Amount so produced................... $ 39,300 $ 40,300 $ 40,300
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation......... 4,300 4,200 100
Plant removal costs............ (1,800) (1,200) (1,700)
State income tax, net of federal
income tax benefit............... 1,300 2,200 1,300
Amortization of deferred
investment credit................ (2,194) (2,225) (2,267)
Equity in earnings of subsidiaries. (2,600) (2,600) (2,900)
Other, net......................... (4,174) (3,739) (1,707)
Total.......................... $ 34,132 $ 36,936 $ 33,126
</TABLE>
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
At December 31, the deferred tax assets and liabilities consist of the
following:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Deferred tax assets:
Unamortized investment tax credit............ $ 13,929 $ 15,084
Contributions in aid of construction......... 13,414 12,614
Tax interest capitalized..................... 12,124 11,221
Restructuring................................ 4,844 1,568
Postretirement benefits other than pensions.. 2,560 1,347
Advances for construction.................... 1,327 1,573
Unbilled revenue............................. 3,492
Other........................................ 3,002 2,728
51,200 49,627
Deferred tax liabilities:
Book vs. tax plant basis differences, net.... 215,884 189,618
Other........................................ 15,060 15,803
230,944 205,421
Total net deferred tax liabilities............. 179,744 155,794
Add portion above included in current
assets (liabilities)......................... 3,983 (362)
Total long-term net deferred
tax liabilities.............................. $183,727 $155,432
</TABLE>
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 Electric and Power Company, a nonaffiliated utility.
AGC recovers from the Company and its affiliates all of its operation
and maintenance expenses, depreciation, taxes, and a return on its
investment under a wholesale rate schedule approved by the FERC. AGC's
rates are set by a formula filed with and previously accepted by the
<PAGE> F-42
FERC. The only component which changes is the return on equity (ROE).
AGC's ROE was 11.13% for 1994 and 11.2% for 1995. Pursuant to a
settlement agreement filed April 4, 1996, with the FERC, AGC's ROE was
set at 11% for 1996 and will continue until the time any affected party
seeks renegotiation of the ROE. Notice of such intent to seek a
revision in ROE must be filed during a notice period each year between
November 1 and November 15. No requests for change were filed during
the 1996 notice period. Therefore, AGC's ROE will remain at 11% for
1997.
Following is a summary of financial information for AGC:
<TABLE>
<CAPTION>
December 31
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Balance sheet information:
Property, plant, and equipment............... $660,872 $677,857
Current assets............................... 7,659 7,586
Deferred charges............................. 23,877 24,844
Total assets............................... $692,408 $710,287
Total capitalization......................... $431,589 $463,862
Current liabilities.......................... 15,531 11,892
Deferred credits............................. 245,288 234,533
Total capitalization and liabilities....... $692,408 $710,287
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Income statement information:
Electric operating revenues......... $83,402 $86,970 $91,022
Operation and maintenance expense... 5,165 5,740 6,695
Depreciation........................ 17,160 17,018 16,852
Taxes other than income taxes....... 4,801 5,091 5,223
Federal income taxes................ 13,297 13,552 14,737
Interest charges.................... 16,193 18,361 17,809
Other income, net................... (3) (16) (11)
Net income........................ $26,789 $27,224 $29,717
</TABLE>
The Company's share of the equity in earnings above was $7.5 million,
$7.6 million, and $8.3 million for 1996, 1995, and 1994, respectively,
and is included in other income, net, on the Statement of Income.
NOTE E: PENSION BENEFITS
The Company's share of net pension costs under the System's pension
plan, a portion of which (about 25% to 30%) was charged to plant
construction, included the following components:
<PAGE> F-43
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned........ $ 3,535 $ 3,286 $ 3,555
Interest cost on projected
benefit obligation.................. 10,582 10,161 9,867
Actual (return) loss on plan assets... (11,310) (25,718) 304
Net amortization and deferral......... (3,008) 12,631 (12,808)
Pension (credit) cost................. (201) 360 918
Reversal of previous deferrals........ 1,194
Net pension (credit) cost............. $ (201) $ 360 $ 2,112
</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>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of
$118,977,000 and $111,538,000)............... $126,271 $119,383
Funded status:
Actuarial present value of projected
benefit obligation......................... $146,646 $144,800
Plan assets at market value, primarily
common stocks and fixed income securities.. 172,799 169,830
Plan assets in excess of projected
benefit obligation......................... (26,153) (25,030)
Add:
Unrecognized cumulative net gain from
past experience different from
that assumed............................. 23,331 23,839
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987.......................... 2,654 3,435
Less unrecognized prior service cost due
to plan amendments......................... (1,858) (2,450)
Pension cost prepaid at December 31.......... $ (2,026) $ (206)
</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 September 30, 1996, 1995, and 1994, the discount rates
used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future
compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The
expected long-term rate of return on assets was 9% in each of the years
1996, 1995, and 1994.
<PAGE> F-44
The pension cost prepaid at December 31, 1996, includes the net result
of a curtailment gain of $3.8 million and an expense for special
termination benefits of $1.6 million associated with the workforce
reduction.
NOTE F: POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The cost of postretirement benefits other than pensions (principally
health care and life insurance) for employees and covered dependents, a
portion of which (about 25% to 30%) was charged to plant construction,
included the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned.............. $ 666 $ 683 $ 696
Interest cost on accumulated
postretirement benefit obligation......... 4,241 4,476 4,047
Actual (return) loss on plan assets......... (1,339) (1,938) 47
Amortization of unrecognized
transition obligation..................... 2,008 2,011 1,976
Other net amortization and deferral......... 255 1,570 53
Postretirement cost......................... 5,831 6,802 6,819
Regulatory reversal (deferral).............. 11 (457)
Net postretirement cost..................... $5,831 $6,813 $6,362
</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>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees...................................... $44,615 $35,852
Fully eligible employees...................... 4,108 8,699
Other employees............................... 11,973 13,805
Total obligation............................ 60,696 58,356
Plan assets at market value, in common stocks,
fixed income securities, and short-term
investments................................... 14,427 11,882
Accumulated postretirement benefit
obligation in excess of plan assets........... 46,269 46,474
Less:
Unrecognized cumulative net loss from past
experience different from that assumed...... (6,065) (8,578)
Unrecognized transition obligation, being
amortized over 20 years beginning
January 1, 1993............................. (28,360) (34,125)
Postretirement benefit liability
at September 30............................... 11,844 3,771
Fourth quarter contributions and benefit
payments...................................... (966) (2,221)
Postretirement benefit liability at
December 31................................... $10,878 $ 1,550
</TABLE>
<PAGE> F-45
In determining the accumulated postretirement benefit obligation (APBO)
at September 30, 1996, 1995, and 1994, the discount rates used were
7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation
levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term
rate of return on assets was 8.25% in each of the years 1996, 1995, and
1994. For measurement purposes, a health care trend rate of 7% for
1997, declining to 6.5% in 1998 and beyond, and plan provisions which
limit future medical and life insurance benefits, were assumed.
Increasing the assumed health care trend rate by 1% in each year would
increase the APBO at December 31, 1996, by $4 million and the aggregate
of the service and interest cost components of net periodic
postretirement benefit cost for 1996 by $.4 million.
The postretirement benefit liability at December 31, 1996, includes a
curtailment loss of $4.9 million and an expense for special termination
benefits of $2.4 million associated with the workforce reduction.
NOTE G: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Regulatory
assets represent probable future revenues associated with deferred costs
that are expected to be recovered from customers through the ratemaking
process. Regulatory liabilities represent probable future reductions in
revenues associated with amounts that are to be credited to customers
through the ratemaking process. Regulatory assets, net of regulatory
liabilities, reflected in the Balance Sheet at December 31 relate to:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Long-Term Assets (Liabilities), Net:
Income taxes, net.......................... $62,625 $46,055
Demand-side management..................... 15,748 16,024
Postretirement benefits.................... 1,292 1,292
Deferred power costs (reported in other
deferred charges/credits)................ (3,187) 509
Other, net................................. 1,347 2,067
Subtotal................................. 77,825 65,947
Current Assets (Liabilities), Net:
Deferred power costs (reported in
other current assets/liabilities)........ (319) 1,026
Income taxes, net.......................... (29)
Subtotal................................. (319) 997
Net Regulatory Assets.................. $77,506 $66,944
</TABLE>
<PAGE> F-46
NOTE H: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments
at December 31 were as follows:
<TABLE>
<CAPTION>
1996 1995
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
<S> <C> <C> <C> <C>
Liabilities:
Short-term debt...... 7,497 7,497 21,637 21,637
Long-term debt and
QUIDS.............. 636,957 648,586 655,657 689,003
</TABLE>
The carrying amount of short-term debt approximates the fair value
because of the short maturity of those instruments. The fair value of
long-term debt and QUIDS was estimated based on actual market prices or
market prices of similar issues. The Company has no financial
instruments held or issued for trading purposes.
NOTE I: CAPITALIZATION
Other Paid-In Capital
Other paid-in capital decreased $34,000 in 1995 and increased $10,000 in
1994 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.
Long-Term Debt and QUIDS
Maturities for long-term debt for the next five years are: 1997,
$800,000; 1998, $1,800,000; 1999, $1,800,000; 2000, $76,800,000; and
2001, $1,800,000. Substantially all of the properties of the Company
are held subject to the lien securing its first mortgage bonds. Some
properties are also subject to a second lien securing certain pollution
control and solid waste disposal notes. Certain first mortgage bond
series are not redeemable by certain refunding until dates established
in the respective supplemental indentures.
NOTE J: SHORT-TERM DEBT
To provide interim financing and support for outstanding commercial
paper, the System companies have established lines of credit with
several banks. The Company has SEC authorization for total short-term
borrowings of $115 million, including money pool borrowings described
below. The Company has fee arrangements on all of its lines of credit
and no compensating balance requirements. In addition to bank lines of
credit, an internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated companies
have funds available. Short-term debt outstanding for 1996 and 1995
consisted of:
<PAGE> F-47
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Balance and interest rate
at end of year:
Commercial Paper................ $7,497-7.00% $21,637-6.10%
Average amount outstanding and
interest rate during the year:
Commercial Paper................ $1,116-5.70% $ 499-5.94%
Notes Payable to Banks.......... 793-5.60% 995-6.04%
Money Pool...................... - 179-5.96%
</TABLE>
NOTE K: COMMITMENTS AND CONTINGENCIES
Construction Program
The Company has entered into commitments for its construction program,
for which expenditures are estimated to be $98 million for 1997 and
$109 million for 1998. Construction expenditure levels in 2000 and
beyond will depend upon future generation requirements, as well as the
strategy eventually selected for complying with Phase II of the Clean
Air Act Amendments of 1990.
Environmental Matters and Litigation
System companies are subject to various laws, regulations, and
uncertainties as to environmental matters. Compliance may require them
to incur substantial additional costs to modify or replace existing and
proposed equipment and facilities and may affect adversely the lead
time, size, and siting of future generating stations, increase the
complexity and cost of pollution control equipment, and otherwise add to
the cost of future operations. In the normal course of business, the
Company becomes involved in various legal proceedings. The Company does
not believe that
the ultimate outcome of these proceedings will have a material effect on
its financial position.
The Company previously reported that the Environmental Protection Agency
had identified it and its affiliates and approximately 875 others as
potentially responsible parties in a Superfund site subject to cleanup.
The Company has also been named as a defendant along with multiple other
defendants in pending asbestos cases involving one or more plaintiffs.
The Company believes that provisions for liabilities and insurance
recoveries are such that final resolution of these claims will not have
a material effect on its financial position.
The Company is guarantor as to 28% of a $50 million revolving credit
agreement of AGC, which in 1996 was used by AGC solely as support for
its indebtedness for commercial paper outstanding.
<PAGE> F-48
West Penn Power Company
and Subsidiaries
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors of
West Penn Power Company
In our opinion, the accompanying consolidated balance sheet and consolidated
statement of capitalization and the related consolidated statements of income,
of retained earnings and of cash flows present fairly, in all material
respects, the financial position of West Penn Power Company (a subsidiary of
Allegheny Power System, Inc.) and its subsidiaries at December 31, 1996 and
1995, and the results of their operations and their cash flows for each of
the three years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for the opinion expressed above.
As discussed in Note A to the consolidated financial statements, the Company
changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> F-49
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Electric Operating Revenues:
Residential..................................................... $ 402,083 $ 401,186 $ 376,776
Commercial...................................................... 224,663 224,144 207,165
Industrial...................................................... 355,120 356,937 330,739
Wholesale and other, including affiliates (Note A).............. 74,328 73,388 67,320
Bulk power transactions, net (Note A)........................... 32,930 25,438 29,337
Total Operating Revenues...................................... 1,089,124 1,081,093 1,011,337
Operating Expenses:
Operation:
Fuel.......................................................... 239,337 237,376 252,108
Purchased power and exchanges, net (Note A)................... 126,908 129,457 130,288
Deferred power costs, net (Note A)............................ 13,635 15,091 2,880
Other......................................................... 151,642 141,355 145,783
Maintenance..................................................... 104,211 114,489 111,841
Restructuring charges and asset write-offs (Note B)............. 53,343 11,099 8,919
Depreciation.................................................... 119,066 112,334 88,935
Taxes other than income taxes................................... 90,132 89,694 87,224
Federal and state income taxes (Note C)......................... 47,455 61,745 46,645
Total Operating Expenses...................................... 945,729 912,640 874,623
Operating Income.............................................. 143,395 168,453 136,714
Other Income and Deductions:
Allowance for other than borrowed funds used
during construction (Note A).................................. 1,434 2,974 6,729
Other income, net............................................... 13,439 12,287 13,798
Total Other Income and Deductions............................. 14,873 15,261 20,527
Income Before Interest Charges................................ 158,268 183,714 157,241
Interest Charges:
Interest on long-term debt...................................... 64,988 64,571 58,102
Other interest.................................................. 6,084 3,331 2,172
Allowance for borrowed funds used during
construction (Note A)......................................... (1,289) (2,067) (4,048)
Total Interest Charges........................................ 69,783 65,835 56,226
Consolidated Income Before Cumulative
Effect of Accounting Change..................................... 88,485 117,879 101,015
Cumulative Effect of Accounting Change,
net (Note A).................................................... 19,031
Consolidated Net Income........................................... $ 88,485 $ 117,879 $ 120,046
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
Balance at January 1.............................................. $ 451,719 $ 433,801 $ 412,288
Add:
Consolidated net income......................................... 88,485 117,879 120,046
540,204 551,680 532,334
Deduct:
Dividends on capital stock of the Company:
Preferred stock............................................... 3,423 6,204 8,504
Common stock.................................................. 95,498 91,600 90,029
Charge on redemption of preferred stock........................ 2,157
Total Deductions............................................ 98,921 99,961 98,533
Balance at December 31 (Note D)................................... $ 441,283 $ 451,719 $ 433,801
See accompanying notes to consolidated financial statements.
</TABLE>
<PAGE> F-50
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows from Operations:
Consolidated net income......................................... $ 88,485 $117,879 $120,046
Depreciation.................................................... 119,066 112,334 88,935
Deferred investment credit and income taxes, net................ 2,022 2,364 699
Deferred power costs, net....................................... 13,635 15,091 2,880
Unconsolidated subsidiaries' dividends in excess of earnings.... 5,191 4,034 2,773
Allowance for other than borrowed funds used
during construction........................................... (1,434) (2,974) (6,729)
Restructuring liability (Note B)................................ 25,879 6,492
Cumulative effect of accounting change before
income taxes (Note A)......................................... (32,891)
Changes in certain current assets and liabilities:
Accounts receivable, net, excluding cumulative effect
of accounting change (Note A)............................... 23,671 (30,280) 18,951
Materials and supplies........................................ 8,847 9,022 (9,205)
Accounts payable.............................................. (14,809) (15,041) (675)
Taxes accrued................................................. 4,622 (5,577) (4,502)
Interest accrued.............................................. (149) (585) 2,620
Other, net...................................................... (2,759) (5,096) 25,019
272,267 207,663 207,921
Cash Flows from Investing:
Construction expenditures....................................... $(130,606) (149,122) (260,366)
Allowance for other than borrowed
funds used during construction................................ 1,434 2,974 6,729
(129,172) (146,148) (253,637)
Cash Flows from Financing:
Sale of common stock............................................ 40,000
Retirement of preferred stock................................... (72,369)
Issuance of long-term debt and QUIDS............................ 143,700 80,129
Retirement of long-term debt.................................... (105,888)
Short-term debt, net............................................ (36,831) 70,218
Notes receivable from affiliates................................ (2,900) 1,000 23,900
Dividends on capital stock:
Preferred stock............................................... (3,423) (6,204) (8,504)
Common stock.................................................. (95,498) (91,600) (90,029)
(138,652) (61,143) 45,496
Net Change in Cash and Temporary Cash Investments
(Note A)........................................................ 4,443 372 (220)
Cash and Temporary Cash Investments at January 1.................. 717 345 565
Cash and Temporary Cash Investments at December 31................ $ 5,160 $ 717 $ 345
Supplemental cash flow information
Cash paid during the year for:
Interest (net of amount capitalized).......................... $ 65,149 $ 64,374 $ 51,745
Income taxes.................................................. 57,126 64,330 54,958
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-51
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
DECEMBER 31
ASSETS 1996 1995
(Thousands of Dollars)
<S> <C> <C>
Property, Plant, and Equipment:
At original cost, including $102,003,000 and
$67,626,000 under construction...................................... $3,182,208 $3,097,522
Accumulated depreciation.............................................. (1,152,383) (1,063,399)
2,029,825 2,034,123
Investments and Other Assets:
Allegheny Generating Company--common stock
at equity (Note E).................................................. 91,330 96,369
Other................................................................. 881 1,239
92,211 97,608
Current Assets:
Cash and temporary cash investments (Note I).......................... 5,160 717
Accounts receivable:
Electric service, net of $11,524,000 and $9,436,000
uncollectible allowance (Note A).................................. 117,240 140,979
Affiliated and other................................................ 20,251 20,183
Notes receivable from affiliates (Note K)............................. 2,900
Materials and supplies--at average cost:
Operating and construction.......................................... 34,011 36,660
Fuel................................................................ 26,247 32,445
Deferred income taxes................................................. 29,003 21,024
Prepaid and other..................................................... 28,180 17,744
262,992 269,752
Deferred Charges:
Regulatory assets (Note H)............................................ 284,099 342,150
Unamortized loss on reacquired debt................................... 10,990 12,256
Other................................................................. 19,620 15,275
314,709 369,681
Total................................................................... $2,699,737 $2,771,164
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock, other paid-in capital, and retained
earnings (Notes D and J)............................................ $ 962,752 $ 973,188
Preferred stock (Note J).............................................. 79,708 79,708
Long-term debt and QUIDS (Note J)..................................... 905,243 904,669
1,947,703 1,957,565
Current Liabilities:
Short-term debt (Note K).............................................. 33,387 70,218
Accounts payable...................................................... 74,229 86,935
Accounts payable to affiliates........................................ 7,985 6,251
Taxes accrued:
Federal and state income............................................ 250 4,128
Other............................................................... 28,649 20,149
Interest accrued...................................................... 15,741 15,890
Deferred power costs (Note A)......................................... 10,107 12,399
Restructuring liability (Note B)...................................... 27,134 6,492
Other................................................................. 21,341 19,927
218,823 242,389
Deferred Credits and Other Liabilities:
Unamortized investment credit......................................... 47,786 50,366
Deferred income taxes................................................. 429,122 469,559
Regulatory liabilities (Note H)....................................... 33,302 35,077
Other................................................................. 23,001 16,208
533,211 571,210
Commitments and Contingencies (Note L)
Total................................................................... $2,699,737 $2,771,164
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-52
<TABLE>
<CAPTION>
CONSOLIDATED STATEMENT OF CAPITALIZATION
DECEMBER 31
1996 1995 1996 1995
(Thousands of Dollars) (Capitalization Ratios)
<S> <C> <C> <C> <C>
Common Stock of the Company:
Common stock--no par value, authorized 28,902,923
shares, outstanding 24,361,586 shares (issued
2,000,000 shares in 1994) (Note J)................ $ 465,994 $ 465,994
Other paid-in capital (Note J)...................... 55,475 55,475
Retained earnings (Note D).......................... 441,283 451,719
Total........................................... 962,752 973,188 49.4% 49.7%
Preferred Stock of the Company:
Cumulative preferred stock--par value $100 per share,
authorized 3,097,077 shares, outstanding as follows
(Note J):
December 31, 1996
Regular
Shares Call Price Date of
Series Outstanding Per Share Issue
4-1/2% .. 297,077 $110.00 1939 29,708 29,708
4.20% B.. 50,000 102.205 1948 5,000 5,000
4.10% C.. 50,000 103.50 1949 5,000 5,000
Auction
4.02%-4.25% 400,000 100.00 1992 40,000 40,000
Total (annual dividend requirements $3,359,047) 79,708 79,708 4.1 4.1
Long-Term Debt and QUIDS (Note J):
First mortgage
bonds: Date of Date Date
Issue Redeemable Due
5-1/2% JJ.... 1993 1998 1998 102,000 102,000
6-3/8% KK.... 1993 2003 2003 80,000 80,000
7-7/8% GG.... 1991 2001 2004 70,000 70,000
7-3/8% HH.... 1992 2002 2007 45,000 45,000
8-7/8% FF.... 1991 2001 2021 100,000 100,000
7-7/8% II.... 1992 2002 2022 135,000 135,000
8-1/8% LL.... 1994 2004 2024 65,000 65,000
7-3/4% MM.... 1995 2005 2025 30,000 30,000
December 31, 1996
Interest Rate
Quarterly Income Debt Securities
due 2025........................ 8.00% 70,000 70,000
Secured notes due 1998-2024....... 4.95%-6.75% 202,550 202,550
Unsecured notes due 2000-2007..... 6.10% 14,435 14,435
Unamortized debt discount........................... (8,742) (9,316)
Total (annual interest requirements $64,988,743) 905,243 904,669 46.5 46.2
Total Capitalization.................................. $1,947,703 $1,957,565 100.0% 100.0%
</TABLE>
See accompanying notes to consolidated financial statements.
<PAGE> F-53
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(These notes are an integral part of the consolidated financial
statements.)
NOTE A: SUMMARY OF SIGNIFICANT
ACCOUNTING POLICIES
The Company is a wholly owned subsidiary of Allegheny Power System, Inc.
and is a part of the Allegheny Power integrated electric utility system
(the System).
The Company is subject to regulation by the Securities and Exchange
Commission (SEC), by various state bodies having jurisdiction, and by
the Federal Energy Regulatory Commission (FERC). Significant accounting
policies of the Company are summarized below.
Consolidation
The consolidated financial statements include the accounts of the
Company and its wholly owned subsidiaries (the companies).
Use Of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
that affect the reported amounts of assets, liabilities, revenues,
expenses, and disclosures of contingencies during the reporting period,
which in the normal course of business are subsequently adjusted to
actual results.
Revenues
Revenues, including amounts resulting from the application of fuel and
energy cost adjustment clauses, are recognized in the same period in
which the related electric services are provided to customers, by
recording an estimate for unbilled revenues for services provided from
the meter reading date to the end of the accounting period.
Deferred Power Costs, Net
The costs of fuel, purchased power, and certain other costs, and
revenues from sales to other companies, including transmission services,
are deferred until they are either recovered from or credited to
customers under fuel and energy cost recovery procedures.
Property, Plant, and Equipment
Property, plant, and equipment, including facilities owned with
regulated affiliates in the System, are stated at original cost, less
contributions in aid of construction, except for capital leases, which
are recorded at present value. 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 postretirement benefits,
<PAGE> F-54
taxes, and other fringe benefits related to employees engaged in
construction.
The cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
Allowance for Funds Used During Construction
AFUDC, an item that does not represent current cash income, is defined
in applicable regulatory systems of accounts as including "the net cost
for the period of construction of borrowed funds used for construction
purposes and a reasonable rate on other funds when so used." AFUDC is
recognized as a cost of property, plant, and equipment with offsetting
credits to other income and interest charges. Rates used for computing
AFUDC in 1996, 1995, and 1994 were 7.83%, 8.90%, and 8.88%,
respectively. AFUDC is not included in the cost of such construction
when the cost of financing the construction is being recovered through
rates.
Depreciation and Maintenance
Provisions for depreciation are determined generally on a straight-line
method based on estimated service lives of depreciable properties and
amounted to approximately 4.0%, 3.9%, and 3.5% of average depreciable
property in 1996, 1995, and 1994, respectively. The cost of maintenance
and of certain replacements of property, plant, and equipment is charged
principally to operating expenses.
Temporary Cash Investments
For purposes of the consolidated statement of cash flows, temporary cash
investments with original maturities of three months or less, generally
in the form of commercial paper, certificates of deposit, and repurchase
agreements, are considered to be the equivalent of cash.
Regulatory Deferrals
In accordance with the Financial Accounting Standards Board's Statement
of Financial Accounting Standards (SFAS) No. 71, "Accounting for the
Effects of Certain Types of Regulation," the Company's consolidated
financial statements reflect assets and liabilities based on current
cost-based ratemaking regulation.
Income Taxes
The companies join with their parent and affiliates in filing a
consolidated federal income tax return. The consolidated tax liability
is allocated among the participants generally in proportion to the
taxable income of each participant, except that no subsidiary pays tax
in excess of its separate return tax liability.
Financial accounting income before income taxes differs from taxable
income principally because certain income and deductions for tax
purposes are recorded in the financial income statement in another
period. Differences between income tax expense computed on the basis of
financial accounting income and taxes payable based on taxable income
are accounted for substantially in accordance with the accounting
<PAGE> F-55
procedures followed for ratemaking purposes. Deferred tax assets and
liabilities represent the tax effect of temporary differences between
the financial statement and tax basis of assets and liabilities computed
utilizing the most current tax rates.
Provisions for federal income tax were reduced in previous years by
investment credits, and amounts equivalent to such credits were charged
to income with concurrent credits to a deferred account. These balances
are being amortized over the estimated service lives of the related
properties.
Postretirement Benefits
The Company participates with affiliated companies in the System in a
noncontributory, defined benefit pension plan covering substantially all
employees, including officers. Benefits are based on the employee's
years of service and compensation. The funding policy is to contribute
annually at least the minimum amount required under the Employee
Retirement Income Security Act and not more than can be deducted for
federal income tax purposes.
The Company also provides partially contributory medical and life
insurance plans for eligible retirees and dependents. Medical benefits,
which comprise the largest component of the plans, are based upon an age
and years-of-service vesting schedule and other plan provisions. The
funding plan for these costs is to contribute the maximum amount that
can be deducted for federal income tax purposes. Funding of these
benefits is made primarily into Voluntary Employee Beneficiary
Association trust funds. Medical benefits are self-insured; the life
insurance plan is paid through insurance premiums.
Bulk Power Transactions Reclassification
Effective in 1996, the Company changed its method of reporting certain
bulk power transmission transactions with nonaffiliated utilities and
reclassified prior years' bulk power and other revenues and operation
expenses to achieve a consistent presentation. In prior years, some use
of the Company's transmission system was recorded as purchased power
from selling utilities and as sales of power to buying utilities. The
benefit to the Company was the difference between the two. Because of
new FERC requirements, the Company predominantly does not "buy" and
"sell" such energy, but rather a transmission fee is charged.
Under the new reporting method, all such transactions are recorded on a
net revenue basis. The effect of the reclassifications was to reduce
amounts previously reported for bulk power transactions revenues and
operation expenses by $145 million and $117 million for 1995 and 1994,
respectively, with no change in operating income or consolidated net
income.
Accounting Change
Effective January 1, 1994, the Company changed its revenue recognition
method to include the accrual of estimated unbilled revenues for
electric services. The cumulative effect of this accounting change for
<PAGE> F-56
years prior to 1994, which is shown separately in the consolidated
statement of income for 1994, resulted in a benefit of $19.0 million
(after related income taxes of $13.9 million). The effect of the change
on 1994 consolidated income before the cumulative effect of accounting
change is not material.
NOTE B: RESTRUCTURING CHARGES AND ASSET WRITE-OFFS
In 1996, the System, including the Company, essentially completed its
restructuring initiatives undertaken in 1995, simplifying the management
structure and streamlining operations. During 1996, restructuring
activities included consolidating operating divisions, customer
services, and other functions. By reorganizing and eliminating certain
processes and consolidating common decentralized functions, the System
reduced employment by about 1,000 employees since October 1994. These
reductions were accomplished through a voluntary separation plan,
attrition, and layoffs.
In 1996 and 1995, the Company recorded restructuring charges of $42.6
million ($25.1 million after tax) and $7.3 million ($4.3 million after
tax) in operating expenses, including its share of all restructuring
charges associated with the reorganization, which is essentially
complete. These charges reflect liabilities and payments for severance,
employee termination costs, and other restructuring costs. The
restructuring liability consists of:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Restructuring liability (before tax):
Balance at beginning of period................. $ 6,492
Accruals..................................... 42,580 $7,276
Less payments................................ (16,701) (784)
Balance at end of period....................... $32,371* $6,492
</TABLE>
*Includes $5,237,000 for benefit plans curtailment liabilities and
special termination benefits which are primarily recorded in other deferred
credits.
In 1996 and 1994, the Company wrote off $10.8 million ($6.3 million
after tax) and $8.9 million ($5.2 million after tax), respectively, of
previously accumulated costs related to a proposed transmission line and
a potential future power plant site. In the industry's more competitive
environment, it was no longer reasonable to assume future recovery of
these costs in rates.
In connection with changes in inventory management objectives, the
Company in 1995 also recorded $3.8 million ($2.3 million after tax) for
the write-off of obsolete and slow-moving materials.
<PAGE> F-57
NOTE C: INCOME TAXES
Details of federal and state income tax provisions are:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Income taxes--current:
Federal............................. $32,778 $49,928 $46,964
State............................... 12,975 9,344 13,282
Total............................. 45,753 59,272 60,246
Income taxes--deferred, net of
amortization........................ 4,602 4,944 3,277
Amortization of deferred
investment credit................... (2,580) (2,580) (2,578)
Total income taxes................ 47,775 61,636 60,945
Income taxes--(charged) credited
to other income and deductions...... (320) 109 (440)
Income taxes--charged to accounting
change (including state income
taxes).............................. (13,860)
Income taxes--charged to
operating income.................... $47,455 $61,745 $46,645
</TABLE>
The total provision for income taxes is different from the amount
produced by applying the federal income statutory tax rate of 35% to
financial accounting income, as set forth below:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Financial accounting income before
cumulative effect of accounting
change and income taxes............ $135,900 $179,600 $147,700
Amount so produced................... $ 47,600 $ 62,900 $ 51,700
Increased (decreased) for:
Tax deductions for which deferred
tax was not provided:
Lower tax depreciation......... 3,300 4,300 2,000
Plant removal costs............ 2,100 (900) (1,700)
State income tax, net of federal
income tax benefit............... 8,900 9,300 6,400
Amortization of deferred
investment credit................ (2,580) (2,580) (2,578)
Equity in earnings of subsidiaries. (4,600) (4,300) (4,600)
Other, net......................... (7,265) (6,975) (4,577)
Total.......................... $ 47,455 $ 61,745 $ 46,645
</TABLE>
<PAGE> F-58
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
At December 31, the deferred tax assets and liabilities consist of the
following:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Deferred tax assets:
Unamortized investment tax credit............ $ 33,243 $ 35,043
Tax interest capitalized..................... 18,862 19,049
Postretirement benefits other than pensions.. 11,039 7,324
Restructuring................................ 10,058 2,664
Contributions in aid of construction......... 6,239 6,009
Unbilled revenue............................. 631 8,594
Other........................................ 28,177 19,343
108,249 98,026
Deferred tax liabilities:
Book vs. tax plant basis differences, net.... 483,042 526,257
Other........................................ 25,326 20,304
508,368 546,561
Total net deferred tax liabilities............. 400,119 448,535
Add portion above included in current
assets....................................... 29,003 21,024
Total long-term net deferred
tax liabilities.............................. $429,122 $469,559
</TABLE>
NOTE D: DIVIDEND RESTRICTION
Supplemental indentures relating to certain outstanding bonds of the
Company contain dividend restrictions under the most restrictive of
which $70,576,000 of consolidated retained earnings at December 31,
1996, is not available for cash dividends on common stock, except that a
portion thereof may be paid as cash dividends where concurrently an
equivalent amount of cash is received by the Company as a capital
contribution or as the proceeds of the issue and sale of shares of its
common stock.
NOTE E: ALLEGHENY GENERATING COMPANY
The Company owns 45% of the common stock of Allegheny Generating Company
(AGC), and affiliates of the Company own the remainder. AGC owns an
undivided 40% interest, 840 MW, in the 2,100-MW pumped-storage
hydroelectric station in Bath County, Virginia operated by the 60%
owner, Virginia Electric and Power Company, a nonaffiliated utility.
<PAGE> F-59
AGC recovers from the Company and its affiliates all of its operation
and maintenance expenses, depreciation, taxes, and a return on its
investment under a wholesale rate schedule approved by the FERC. AGC's
rates are set by a formula filed with and previously accepted by the
FERC. The only component which changes is the return on equity (ROE).
AGC's ROE was 11.13% for 1994 and 11.2% for 1995. Pursuant to a
settlement agreement filed April 4, 1996, with the FERC, AGC's ROE was
set at 11% for 1996 and will continue until the time any affected party
seeks renegotiation of the ROE. Notice of such intent to seek a
revision in ROE must be filed during a notice period each year between
November 1 and November 15. No requests for change were filed during
the 1996 notice period. Therefore, AGC's ROE will remain at 11% for
1997.
Following is a summary of financial information for AGC:
<TABLE>
<CAPTION>
December 31
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Balance sheet information:
Property, plant, and equipment............... $660,872 $677,857
Current assets............................... 7,659 7,586
Deferred charges............................. 23,877 24,844
Total assets............................... $692,408 $710,287
Total capitalization......................... $431,589 $463,862
Current liabilities.......................... 15,531 11,892
Deferred credits............................. 245,288 234,533
Total capitalization and liabilities....... $692,408 $710,287
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Income statement information:
Electric operating revenues......... $83,402 $86,970 $91,022
Operation and maintenance expense... 5,165 5,740 6,695
Depreciation........................ 17,160 17,018 16,852
Taxes other than income taxes....... 4,801 5,091 5,223
Federal income taxes................ 13,297 13,552 14,737
Interest charges.................... 16,193 18,361 17,809
Other income, net................... (3) (16) (11)
Net income........................ $26,789 $27,224 $29,717
</TABLE>
The Company's share of the equity in earnings above was $12.1 million,
$12.3 million, and $13.4 million for 1996, 1995, and 1994, respectively,
and is included in other income, net, on the Consolidated Statement of
Income.
<PAGE> F-60
NOTE F: PENSION BENEFITS
The Company's share of net pension costs under the System's pension
plan, a portion of which (about 25% to 30%) was charged to plant
construction, included the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned........ $ 4,998 $ 4,655 $ 5,124
Interest cost on projected
benefit obligation.................. 14,532 14,412 14,051
Actual (return) loss on plan assets... (24,299) (32,610) 358
Net amortization and deferral......... 4,573 14,000 (18,210)
Pension (credit) cost................. (196) 457 1,323
Reversal of previous deferrals........ 760 760
Net pension cost...................... $ 564 $ 1,217 $ 1,323
</TABLE>
It is expected that regulatory deferrals amounting to $1,520,000 will be
amortized to operating expenses in 1997 and 1998 in accordance with
authorized rate recovery.
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>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Actuarial present value of accumulated
benefit obligation earned to date
(including vested benefit of
$167,508,000 and $155,921,000)............... $176,560 $165,162
Funded status:
Actuarial present value of projected
benefit obligation......................... $208,952 $199,683
Plan assets at market value, primarily
common stocks and fixed income securities.. 246,217 234,200
Plan assets in excess of projected
benefit obligation......................... (37,265) (34,517)
Add:
Unrecognized cumulative net gain from
past experience different from
that assumed............................. 29,784 29,164
Unamortized transition asset, being
amortized over 14 years beginning
January 1, 1987.......................... 5,927 7,178
Less unrecognized prior service cost due
to plan amendments......................... (3,594) (4,467)
Pension cost prepaid at December 31.......... $ (5,148) $ (2,642)
</TABLE>
<PAGE> F-61
The foregoing includes the Company's portion of amounts applicable to
employees at power stations which are owned jointly with affiliates.
In determining the actuarial present value of the projected benefit
obligation at September 30, 1996, 1995, and 1994, the discount rates
used were 7.5%, 7.5%, and 7.75%, and the rates of increase in future
compensation levels were 4.5%, 4.5%, and 4.75%, respectively. The
expected long-term rate of return on assets was 9% in each of the years
1996, 1995, and 1994.
The pension cost prepaid at December 31, 1996, includes the net result
of a curtailment gain of $4.8 million and an expense for special
termination benefits of $1.5 million associated with the workforce
reduction.
<PAGE> F-62
NOTE G: POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
The cost of postretirement benefits other than pensions (principally
health care and life insurance) for employees and covered dependents, a
portion of which (about 25% to 30%) was charged to plant construction,
included the following components:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Service cost - benefits earned.............. $1,062 $1,055 $1,154
Interest cost on accumulated
postretirement benefit obligation......... 4,467 4,595 4,461
Actual (return) loss on plan assets......... (1,413) (1,990) 31
Amortization of unrecognized
transition obligation..................... 2,830 2,830 2,817
Other net amortization and deferral......... 267 1,610 83
Postretirement cost......................... 7,213 8,100 8,546
Regulatory reversal......................... 1,826 137
Net postretirement cost..................... $9,039 $8,237 $8,546
The benefits earned to date and funded status of the Company's share of
the System plan at December 31 using a measurement date of September 30
were as follows:
(Thousands of Dollars) 1996 1995
Accumulated postretirement benefit obligation:
Retirees...................................... $44,784 $36,041
Fully eligible employees...................... 3,211 7,802
Other employees............................... 15,199 17,608
Total obligation............................ 63,194 61,451
Plan assets at market value, in common stocks,
fixed income securities, and short-term
investments................................... 22,377 12,512
Accumulated postretirement benefit
obligation in excess of plan assets........... 40,817 48,939
Add:
Unrecognized cumulative net gain from past
experience different from that assumed...... 12,432 3,292
Less:
Unrecognized transition obligation,
being amortized over 20 years
beginning January 1, 1993................... (40,699) (48,099)
Postretirement benefit liability
at September 30............................... 12,550 4,132
Fourth quarter contributions and benefit
payments...................................... (1,246) (3,649)
Postretirement benefit liability
at December 31................................ $11,304 $ 483
</TABLE>
<PAGE> F-63
In determining the accumulated postretirement benefit obligation (APBO)
at September 30, 1996, 1995, and 1994, the discount rates used were
7.5%, 7.5%, and 7.75%, and the rates of increase in future compensation
levels were 4.5%, 4.5%, and 4.75%, respectively. The expected long-term
rate of return on assets was 8.25% in each of the years 1996, 1995, and
1994. For measurement purposes, a health care trend rate of 7% for
1997, declining to 6.5% in 1998 and beyond, and plan provisions which
limit future medical and life insurance benefits, were assumed.
Increasing the assumed health care trend rate by 1% in each year would
increase the APBO at December 31, 1996, by $4.1 million and the
aggregate of the service and interest cost components of net periodic
postretirement benefit cost for 1996 by $.4 million.
The postretirement benefit liability at December 31, 1996, includes a
curtailment loss of $6.2 million and an expense for special termination
benefits of $2.3 million associated with the workforce reduction.
NOTE H: REGULATORY ASSETS AND LIABILITIES
The Company's operations are subject to the provisions of SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation." Regulatory
assets represent probable future revenues associated with deferred costs
that are expected to be recovered from customers through the ratemaking
process. Regulatory liabilities represent probable future reductions in
revenues associated with amounts that are to be credited to customers
through the ratemaking process. Regulatory assets, net of regulatory
liabilities, reflected in the Consolidated Balance Sheet at December 31
relate to:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Long-Term Assets (Liabilities), Net:
Income taxes, net........................... $244,142 $297,087
Postretirement benefits..................... 1,520 4,105
Storm damage................................ 1,598 1,870
Deferred power costs (reported in other
deferred charges/credits)................. 7,211 (3,772)
Other, net.................................. 3,537 4,011
Subtotal................................. 258,008 303,301
Current Liabilities:
Income taxes................................ (921) (846)
Deferred power costs........................ (10,107) (12,399)
Subtotal.................................. (11,028) (13,245)
Net Regulatory Assets................... $246,980 $290,056
</TABLE>
<PAGE> F-64
NOTE I: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments
at December 31 were as follows:
<TABLE>
<CAPTION>
1996 1995
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
<S> <C> <C> <C> <C>
Assets:
Temporary cash
investments........ $ 425 $ 425
Liabilities:
Short-term debt...... $ 33,387 $ 33,387 70,218 70,218
Long-term debt
and QUIDS............ 913,985 931,725 913,985 955,336
</TABLE>
The carrying amount of temporary cash investments, as well as short-term
debt, approximates the fair value because of the short maturity of those
instruments. The fair value of long-term debt and QUIDS was estimated
based on actual market prices or market prices of similar issues. The
Company has no financial instruments held or issued for trading
purposes.
NOTE J: CAPITALIZATION
Common Stock and Other Paid-In Capital
The Company issued and sold 2,000,000 shares of common stock to its
parent, at $20 per share, in October 1994. Other paid-in capital
decreased $212,000 in 1995 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 per
share. The holders of the Company's market auction preferred stock are
entitled to dividends at a rate determined by an auction held the
business day preceding each quarterly dividend payment date.
Long-Term Debt and QUIDS
Maturities for long-term debt for the next five years are: 1997, none;
1998, $103,500,000; 1999, $1,500,000; 2000, $2,500,000; and 2001,
$2,500,000. Substantially all of the properties of the Company are held
subject to the lien securing its first mortgage bonds. Some properties
are also subject to a second lien securing certain pollution control and
solid waste disposal notes. Certain first mortgage bond series are not
redeemable by certain refunding until dates established in the
respective supplemental indentures.
<PAGE> F-65
NOTE K: SHORT-TERM DEBT
To provide interim financing and support for outstanding commercial
paper, the System companies have established lines of credit with
several banks. The Company has SEC authorization for total short-term
borrowings of $170 million, including money pool borrowings described
below. The Company has fee arrangements on all of its lines of credit
and no compensating balance requirements. In addition to bank lines of
credit, an internal money pool accommodates intercompany short-term
borrowing needs, to the extent that certain of the regulated companies
have funds available. Short-term debt outstanding for 1996 and 1995
consisted of:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Balance and interest rate
at end of year:
Commercial Paper.................. $33,387-7.00% $36,318-6.09%
Notes Payable to Banks............ 33,900-5.90%
Average amount outstanding and
interest rate during the year:
Commercial Paper.................. $ 9,245-5.51% $5,692-6.00%
Notes Payable to Banks............ 10,200-5.51% 5,342-5.96%
Money Pool........................ 3,229-5.25% 592-5.79%
</TABLE>
NOTE L: COMMITMENTS AND CONTINGENCIES
Construction Program
The Company has entered into commitments for its construction program,
for which expenditures are estimated to be $140 million for 1997 and
$123 million for 1998. Construction expenditure levels in 2000 and
beyond will depend upon future generation requirements, as well as the
strategy eventually selected for complying with Phase II of the Clean
Air Act Amendments of 1990.
Environmental Matters and Litigation
System companies are subject to various laws, regulations, and
uncertainties as to environmental matters. Compliance may require them
to incur substantial additional costs to modify or replace existing and
proposed equipment and facilities and may affect adversely the lead
time, size, and siting of future generating stations, increase the
complexity and cost of pollution control equipment, and otherwise add to
the cost of future operations. In the normal course of business, the
Company becomes involved in various legal proceedings. The Company does
not believe that the ultimate outcome of these proceedings will have a
material effect on its financial position.
The Company previously reported that the Environmental Protection Agency
had identified it and its affiliates and approximately 875 others as
potentially responsible parties in a Superfund site subject to cleanup.
The Company has also been named as a defendant along with multiple other
<PAGE> F-66
defendants in pending asbestos cases involving one or more plaintiffs.
The Company believes that provisions for liabilities and insurance
recoveries are such that final resolution of these claims will not have
a material effect on its financial position.
The Company is guarantor as to 45% of a $50 million revolving credit
agreement of AGC, which in 1996 was used by AGC solely as support for
its indebtedness for commercial paper outstanding.
<PAGE> F-67
Allegheny Generating Company
REPORT OF INDEPENDENT ACCOUNTANTS
To The Board of Directors of
Allegheny Generating Company
In our opinion, the accompanying balance sheet and the related statements of
income, of retained earnings and of cash flows present fairly, in all material
respects, the financial position of Allegheny Generating Company (an
Allegheny Power System, Inc. affiliate) at December 31, 1996 and 1995, and
the results of its operations and its cash flows for each of the three years in
the period ended December 31, 1996, in conformity with generally accepted
accounting principles. These financial statements are the responsibility of
the Company's management; our responsibility is to express an opinion on
these financial statements based on our audits. We conducted our audits of
these statements in accordance with generally accepted auditing standards
which require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management,
and evaluating the overall financial statement presentation. We believe that
our audits provide a reasonable basis for the opinion expressed above.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> F-68
<TABLE>
<CAPTION>
STATEMENT OF INCOME
YEAR ENDED DECEMBER 31
1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Electric Operating Revenues....................................... $83,402 $86,970 $91,022
Operating Expenses:
Operation and maintenance expense............................... 5,165 5,740 6,695
Depreciation.................................................... 17,160 17,018 16,852
Taxes other than income taxes................................... 4,801 5,091 5,223
Federal income taxes (Note B)................................... 13,297 13,552 14,737
Total Operating Expenses...................................... 40,423 41,401 43,507
Operating Income.............................................. 42,979 45,569 47,515
Other Income, net................................................. 3 16 11
Income Before Interest Charges.................................. 42,982 45,585 47,526
Interest Charges:
Interest on long-term debt...................................... 15,235 16,859 16,863
Other interest.................................................. 958 1,502 946
Total Interest Charges........................................ 16,193 18,361 17,809
Net Income........................................................ $26,789 $27,224 $29,717
STATEMENT OF RETAINED EARNINGS (Note D)
Balance at January 1.............................................. $ 4,153 $12,729 $18,512
Add:
Net income...................................................... 26,789 27,224 29,717
30,942 39,953 48,229
Deduct:
Dividends on common stock....................................... 30,942 35,800 35,500
Balance at December 31............................................ $ 0 $ 4,153 $12,729
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-69
<TABLE>
<CAPTION>
STATEMENT OF CASH FLOWS
YEAR ENDED DECEMBER 31
1996 1995 1994
(Thousands of Dollars)
<S> <C> <C> <C>
Cash Flows from Operations:
Net income...................................................... $ 26,789 $ 27,224 $ 29,717
Depreciation.................................................... 17,160 17,018 16,852
Deferred investment credit and income taxes, net................ 10,898 6,508 9,567
Changes in certain current assets and liabilities:
Accounts receivable........................................... 3,937 (3,758) 7,099
Materials and supplies........................................ (43) 144 (2)
Accounts payable.............................................. 206 (32) 37
Taxes accrued................................................. (113) 80 (216)
Interest accrued.............................................. (442) 251 (200)
Other, net...................................................... (3,184) 2,703 (7,133)
55,208 50,138 55,721
Cash Flows from Investing:
Construction expenditures....................................... (178) (2,177) (1,065)
Cash Flows from Financing:
Retirement of long-term debt.................................... (16,943) (12,175) (19,126)
Cash dividends on common stock.................................. (37,987) (35,800) (35,500)
(54,930) (47,975) (54,626)
Net Change in Cash................................................ 100 (14) 30
Cash at January 1................................................. 31 45 15
Cash at December 31............................................... $ 131 $ 31 $ 45
Supplemental Cash Flow Information
Cash paid during the year for:
Interest...................................................... $ 15,703 $ 17,165 $ 17,078
Income taxes.................................................. 6,256 5,274 7,137
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-70
<TABLE>
<CAPTION>
BALANCE SHEET
DECEMBER 31
ASSETS 1996 1995
(Thousands of Dollars)
<S> <C> <C> <C>
Property, Plant, and Equipment:
At original cost, including $508,000 and
$412,000 under construction..................................... $ 837,050 $ 836,894
Accumulated depreciation.......................................... (176,178) (159,037)
660,872 677,857
Current Assets:
Cash.............................................................. 131 31
Accounts receivable from parents.................................. 1,337 5,274
Materials and supplies--at average cost........................... 2,092 2,049
Prepaid taxes..................................................... 3,860 19
Other............................................................. 239 213
7,659 7,586
Deferred Charges:
Regulatory assets (Note B)........................................ 14,475 14,617
Unamortized loss on reacquired debt............................... 9,147 9,900
Other............................................................. 255 327
23,877 24,844
Total............................................................... $ 692,408 $ 710,287
CAPITALIZATION AND LIABILITIES
Capitalization (Note D):
Common stock - $1.00 par value per share,
authorized 5,000 shares, outstanding
1,000 shares.................................................... $ 1 $ 1
Other paid-in capital............................................. 202,954 209,999
Retained earnings................................................. 4,153
202,955 214,153
Long-term debt (Note E)........................................... 228,634 249,709
431,589 463,862
Current Liabilities:
Long-term debt due within one year (Note E)....................... 10,600 6,375
Accounts payable.................................................. 222 16
Interest accrued.................................................. 4,709 5,151
Taxes accrued..................................................... 113
Other............................................................. 237
15,531 11,892
Deferred Credits:
Unamortized investment credit..................................... 49,665 50,987
Deferred income taxes............................................. 168,168 156,091
Regulatory liabilities (Note B)................................... 27,455 27,455
245,288 234,533
Total............................................................... $ 692,408 $ 710,287
</TABLE>
See accompanying notes to financial statements.
<PAGE> F-71
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.
Use of Estimates
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
that affect the reported amounts of assets, liabilities, revenues,
expenses, and disclosures of contingencies during the reporting period,
which in the normal course of business are subsequently adjusted to
actual results.
Property, Plant, and Equipment
Property, plant, and equipment are stated at original cost, and consist
of a 40% undivided interest in the Bath County pumped-storage
hydroelectric station and its connecting transmission facilities. The
cost of depreciable property units retired, plus removal costs less
salvage, are charged to accumulated depreciation.
Depreciation and Maintenance
Provisions for depreciation are determined on a straight-line method
based on estimated service lives of depreciable properties and amounted
to approximately 2.1% of average depreciable property in each of the
years 1996, 1995, and 1994. The cost of maintenance and of certain
replacements of property, plant, and equipment is charged to operating
expenses.
Income Taxes
The Company joins with its parents and affiliates in filing a
consolidated federal income tax return. The consolidated tax liability
is allocated among the participants generally in proportion to the
taxable income of each participant, except that no subsidiary pays tax
in excess of its separate return tax liability.
Financial accounting income before income taxes differs from taxable
income principally because certain income and deductions for tax
purposes are recorded in the financial income statement in another
period. Differences between income tax expense computed on the basis of
financial accounting income and taxes payable based on taxable income
are deferred. Deferred tax assets and liabilities represent the tax
effect of temporary differences between the financial statement and tax
<PAGE> F-72
basis of assets and liabilities computed utilizing the most current tax
rates.
Prior to 1987, provisions for federal income tax were reduced by
investment credits, and amounts equivalent to such credits were charged
to income with concurrent credits to a deferred account. These balances
are being amortized over the estimated service lives of the related
properties.
NOTE B: INCOME TAXES
Details of federal income tax provisions are:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995 1994
<S> <C> <C> <C>
Current income taxes payable.......... $ 2,401 $ 7,053 $ 5,176
Deferred income taxes--
accelerated depreciation............ 12,220 7,818 10,883
Amortization of deferred
investment credit................... (1,322) (1,310) (1,316)
Total income taxes................ 13,299 13,561 14,743
Income taxes--charged to
other income........................ (2) (9) (6)
Income taxes--charged to
operating income.................... $13,297 $13,552 $14,737
</TABLE>
In 1996, the total provision for income taxes ($13,297,000) was less
than the amount produced by applying the federal income tax statutory
rate of 35% to financial accounting income before income taxes
($14,030,000), due primarily to amortization of deferred investment
credit ($1,322,000).
Federal income tax returns through 1993 have been examined and
substantially settled through 1991.
At December 31, the deferred tax assets and liabilities were comprised
of the following:
<TABLE>
<CAPTION>
(Thousands of Dollars) 1996 1995
<S> <C> <C>
Deferred tax assets
Unamortized investment tax credit............ $ 27,455 $ 27,455
Deferred tax liabilities
Book vs. tax plant basis differences, net.... 195,623 183,546
Total long-term net deferred tax liabilities... $168,168 $156,091
</TABLE>
It is expected the FERC will allow recovery of the deferred tax
liabilities in future years as they are paid, and accordingly, the
Company has recorded regulatory assets of $14.5 million and $14.6
<PAGE> F-73
million as of December 31, 1996 and 1995, respectively. Regulatory
liabilities of $27.5 million as of December 31, 1996, and 1995, have
been recorded in order to reflect the Company's obligation to pass such
tax benefits on to its customers as the benefits are realized in cash in
future years.
NOTE C: FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and estimated fair value of financial instruments
at December 31 were as follows:
<TABLE>
<CAPTION>
1996 1995
Carrying Fair Carrying Fair
(Thousands of Dollars) Amount Value Amount Value
<S> <C> <C> <C> <C>
Liabilities:
Long-term debt:
Debentures......... $150,000 $138,872 $150,000 $146,279
Medium term notes.. 70,600 70,600 76,975 78,075
Commercial paper... 19,992 19,992 30,561 30,561
</TABLE>
The carrying amount of debentures and medium-term notes was based on
actual market prices or market prices of similar issues. The carrying
amount of commercial paper approximates the fair value because of the
short maturity of those instruments. The Company does not have any
financial instruments held or issued for trading purposes.
NOTE D: CAPITALIZATION
The Company systematically reduces capitalization each year as its asset
depreciates, and this has resulted in the payment of dividends in excess
of current earnings. The SEC has approved the Company's request to pay
common stock dividends out of capital. In 1996 common dividends of
$30,942,000 were paid from retained earnings, reducing the account
balance to zero, and common dividends of $7,045,000 were paid from other
paid-in capital.
<PAGE> F-74
<TABLE>
<CAPTION>
NOTE E: LONG-TERM DEBT
The Company had long-term debt outstanding as follows:
Interest December 31
(Thousands of Dollars) Rate - % 1996 1995
<S> <C> <C> <C>
Debentures due:
September 1, 2003............... 5.625 $ 50,000 $ 50,000
September 1, 2023............... 6.875 100,000 100,000
Commercial paper.................. 7.00 (1) 19,992 30,561
Medium term notes due 1996-1998... 6.33 (1) 70,600 76,975
Unamortized debt discount......... (1,358) (1,452)
Total......................... 239,234 256,084
Less current maturities........... 10,600 6,375
Total......................... $228,634 $249,709
</TABLE>
(1) Weighted average interest rate at December 31, 1996.
The Company has a revolving credit agreement with a group of six banks,
which provides for loans of up to $50 million at any one time
outstanding through 2000. Each bank has the option to discontinue its
loans after 2000 upon three years' prior written notice. Without such
notice, the loans are automatically extended for one year. Amounts
borrowed are guaranteed by the Parents in proportion to their equity
interest. Interest rates are determined at the time of each borrowing.
The revolving credit agreement serves as support for the Company's
commercial paper. In addition to bank lines of credit, an internal
money pool accommodates intercompany short-term borrowing needs, to the
extent that certain of the Company's regulated affiliates have funds
available.
Maturities for long-term debt for the next five years are: 1997,
$10,600,000; 1998, $60,000,000; 1999, none; 2000, $19,992,000; and 2001,
none.
<PAGE>
S-1
SCHEDULE II
ALLEGHENY POWER SYSTEM, INC. AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1996, 1995, and 1994
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
Allowance for uncollectible
accounts:
Year ended December 31, 1996 $13 046 900 $12 970 000 $ 3 243 945 $14 208 351 $15 052 494
Year ended December 31, 1995 $11 352 674 $ 9 206 000 $ 3 130 418 $10 642 192 $13 046 900
Year ended December 31, 1994 $ 3 418 261 $14 714 000 $ 3 060 544 $ 9 840 131 $11 352 674
</TABLE>
(A) Recoveries.
(B) Uncollectible accounts charged off.
<PAGE>
S-2
SCHEDULE II
MONONGAHELA POWER COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1996, 1995, and 1994
<TABLE>
<CAPTION>
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)
<S> <C> <C> <C> <C> <C>
Allowance for uncollectible
accounts:
Year ended December 31, 1996 $ 2 266 808 $ 1 970 000 $ 666 816 $ 2 954 405 $ 1 949 219
Year ended December 31, 1995 $ 1 910 605 $ 2 266 000 $ 700 288 $ 2 610 085 $ 2 266 808
Year ended December 31, 1994 $ 1 084 037 $ 2 240 000 $ 667 910 $ 2 081 342 $ 1 910 605
</TABLE>
(A) Recoveries.
(B) Uncollectible accounts charged off.
<PAGE>
<TABLE>
<CAPTION>
S-3
SCHEDULE II
THE POTOMAC EDISON COMPANY
Valuation and Qualifying Accounts
For Years Ended December 31, 1996, 1995, and 1994
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, 1996 $ 1 344 077 $ 2 514 000 $ 957 372 $ 3 235 946 $ 1 579 503
Year ended December 31, 1995 $ 1 175 437 $ 1 630 000 $ 983 776 $ 2 445 136 $ 1 344 077
Year ended December 31, 1994 $ 1 207 979 $ 1 624 000 $ 1 007 652 $ 2 664 194 $ 1 175 437
</TABLE>
(A) Recoveries.
(B) Uncollectible accounts charged off.
<PAGE>
S-4
SCHEDULE II
WEST PENN POWER COMPANY AND SUBSIDIARY COMPANIES
Valuation and Qualifying Accounts
For Years Ended December 31, 1996, 1995, and 1994
<TABLE>
<CAPTION>
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, 1996 $ 9 436 015 $ 8 486 000 $ 1 619 757 $ 8 018 000 $11 523 772
Year ended December 31, 1995 $ 8 266 632 $ 5 310 000 $ 1 446 354 $ 5 586 971 $ 9 436 015
Year ended December 31, 1994 $ 1 126 244 $10 850 000 $ 1 384 982 $ 5 094 594 $ 8 266 632
</TABLE>
(A) Recoveries.
(B) Uncollectible accounts charged off.
<PAGE> - 45 -
Supplementary Data
Quarterly Financial Data (Unaudited)
(Thousands of Dollars)
<TABLE>
<CAPTION>
Electric
Operating Operating Net Earnings
Revenues* Income** Income** Per Share**
Quarter ended
<S> <C> <C> <C> <C>
APS
March 1996 $648 018 $ 97 592 $ 51 418 $ .43
June 1996 550 945 100 891 53 786 .44
September 1996 553 990 99 918 56 227 .46
December 1996 574 696 92 453 48 616 .40
March 1995 615 804 122 239 76 129 .64
June 1995 529 035 89 613 42 693 .36
September 1995 583 974 102 735 58 236 .49
December 1995 586 398 107 526 62 634 .52
Monongahela
March 1996 175 617 20 900 12 989
June 1996 152 126 24 735 16 712
September 1996 152 167 24 428 16 917
December 1996 152 561 22 490 14 834
March 1995 167 992 26 676 19 470
June 1995 149 986 20 048 12 886
September 1995 165 774 24 161 16 979
December 1995 159 728 25 072 17 378
Potomac Edison
March 1996 208 928 31 665 22 154
June 1996 167 991 30 234 21 080
September 1996 167 327 25 027 16 381
December 1996 182 514 27 164 18 560
March 1995 190 764 34 983 26 439
June 1995 157 340 21 457 12 089
September 1995 176 236 26 770 16 727
December 1995 186 329 32 438 23 010
West Penn
March 1996 296 445 34 368 20 382
June 1996 258 431 34 939 19 459
September 1996 263 682 39 912 26 330
December 1996 270 566 34 176 22 314
March 1995 288 898 49 891 37 412
June 1995 249 840 36 781 24 613
September 1995 270 837 40 892 28 634
December 1995 271 518 40 889 27 220
AGC
March 1996 20 909 10 946 6 721
June 1996 21 023 10 958 6 777
September 1996 20 825 10 766 6 686
December 1996 20 645 10 309 6 605
March 1995 22 096 11 554 6 569
June 1995 22 061 11 516 7 093
September 1995 21 573 11 344 6 964
December 1995 21 240 11 155 6 598
</TABLE>
These notes do not pertain to AGC.
* Amounts for 1996 quarters have been reclassified for comparative purposes to
reflect a change in 1996 for reporting certain bulk power transmission
transactions.
** Results for the quarters ended September and December 1995 and for each of
the quarters in 1996 include restructuring charges and asset write-offs.
<PAGE> - 46 -
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, 1996 and 1995, and the results of their operations and
their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the
Company's management; our responsibility is to express an opinion on
these financial statements based on our audits. We conducted our audits
of these statements in accordance with generally accepted auditing
standards which require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable
basis for the opinion expressed above.
As discussed in Note A to the consolidated financial
statements, the Company changed its method of accounting for revenue
recognition in 1994.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> - 47 -
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, 1996 and 1995, and the
results of its operations and its cash flows for each of the three years
in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note A to the financial statements, the Company
changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> - 48 -
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, 1996 and 1995, and the
results of its operations and its cash flows for each of the three years
in the period ended December 31, 1996, in conformity with generally
accepted accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note A to the financial statements, the Company
changed its method of accounting for revenue recognition in 1994.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> - 49 -
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors of
West Penn Power Company
In our opinion, the consolidated financial statements listed in
the accompanying index present fairly, in all material respects, the
financial position of West Penn Power Company (a subsidiary of Allegheny
Power System, Inc.) at December 31, 1996 and 1995, and the results of
its operations and its cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted
accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note A to the consolidated financial
statements, the Company changed its method of accounting for revenue
recognition in 1994.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> - 50 -
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, 1996 and 1995, and the results
of its operations and its cash flows for each of the three years in the
period ended December 31, 1996, in conformity with generally accepted
accounting principles. These financial statements are the
responsibility of the Company's management; our responsibility is to
express an opinion on these financial statements based on our audits.
We conducted our audits of these statements in accordance with generally
accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting
principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe
that our audits provide a reasonable basis for the opinion expressed
above.
PRICE WATERHOUSE LLP
New York, New York
February 5, 1997
<PAGE> - 51 -
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE
For APS and the Subsidiaries, none.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANTS
APS, Monongahela, Potomac Edison, West Penn, and AGC. Reference is
made to the Executive Officers of the Registrants in Part I of this
report. The names, ages as of December 31, 1996, 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> <C>
Eleanor Baum See below (a) 56 1988 1988 1988 1988
William L. Bennett See below (b) 47 1991 1991 1991 1991
Klaus Bergman System employee (1) 65 1985 1985 1985 1979 1982
Thomas K. Henderson System employee (1) 56 1996
Wendell F. Holland See below (c) 44 1994 1994 1994 1994
Kenneth M. Jones System employee (1) 59 1991
Phillip E. Lint See below (d) 67 1989 1989 1989 1989
Edward H. Malone See below (e) 72 1985 1985 1985 1985
Frank A. Metz, Jr. See below (f) 62 1984 1984 1984 1984
Michael P. Morrell System employee (1) 48 1996 1996 1996 1996
Alan J. Noia System employee (1) 49 1994 1994 1987 1994 1994
Jay S. Pifer System employee (1) 59 1995 1995 1992
Steven H. Rice See below (g) 53 1986 1986 1986 1986
Gunnar E. Sarsten See below (h) 59 1992 1992 1992 1992
Peter L. Shea See below (i) 64 1993 1993 1993 1993
Peter J. Skrgic System employee (1) 55 1990 1990 1990 1989
</TABLE>
(1) See Executive Officers of the Registrants in Part I of this report for
further details.
(a) Eleanor Baum. Dean of The Albert Nerken School of Engineering of The Cooper
Union for the Advancement of Science and Art. Director of Avnet, Inc. and
United States Trust Company. Commissioner of the Engineering Manpower
Commission, a fellow of the Institute of Electrical and Electronic
Engineers, member of Board of Governors, New York Academy of Sciences and
President of Accreditation Board for Engineering and Technology. Formerly,
President, American Society of Engineering Education.
(b) William L. Bennett. Chairman, HealthPlan Services Corporation, a leading
managed health care services company. Formerly, Chairman and Chief
Executive Officer of Noel Group, Inc. Director of Belding Heminway
Company, Inc., Noel Group, Inc. and Sylvan, Inc.
(c) Wendell F. Holland. Vice President, American Water Works Service Company.
Formerly, Of Counsel, Law Firm of Reed, Smith, Shaw & McClay; Partner, Law
Firm of LeBoeuf, Lamb, Greene & MacRae; and Commissioner of the
Pennsylvania Public Utility Commission.
(d) Phillip E. Lint. Retired. Formerly, partner, Price Waterhouse.
(e) Edward H. Malone. Retired. Formerly, Vice President of General Electric
Company and Chairman, General Electric Investment Corporation. Director of
Fidelity Group of Mutual Funds, General Re Corporation, and Mattel, Inc.
(f) Frank A. Metz, Jr. Retired. Formerly, Senior Vice President, Finance and
Planning, and Director of International Business Machines Corporation.
Director of Monsanto Company and Norrell Corporation.
(g) Steven H. Rice. Bank and real estate consultant and attorney-at-law.
Director and Vice Chairman of the Board of Stamford Federal Savings Bank.
Formerly, President and Director of The Seamen's Bank for Savings and
Director of Royal Group, Inc.
(h) Gunnar E. Sarsten. Chairman and Chief Executive Officer of MK
International. Formerly, President and Chief Operating Officer of
Morrison Knudsen Corporation, President and Chief Executive Officer of
United Engineers & Constructors International, Inc. (now Raytheon
Engineers & Constructors, Inc.), and Deputy Chairman of the Third District
Federal Reserve Bank in Philadelphia.
(i) Peter L. Shea. Managing Member of Temblor Petroleum Company L.L.C., a
privately owned oil and gas exploration and production company operating
exclusively in California, and an Individual General Partner of Panther
Partners, L.P., a closed-end, non-diversified management company.
Formerly, managing director of Hydrocarbon Energy, Inc., a privately owned
oil and gas development drilling and production company.
<PAGE> - 52 -
ITEM 11. EXECUTIVE COMPENSATION
During 1996, and for 1995 and 1994, the annual compensation
paid by the System companies, APS, APSC, Monongahela, Potomac Edison,
West Penn and AGC directly or indirectly for services in all capacities
to such companies to their Chief Executive Officer and each of the four
most highly paid executive officers of the System whose cash
compensation exceeded $100,000 was as follows:
<TABLE>
<CAPTION>
Summary Compensation Tables (a)
APS(b), Monongahela, Potomac Edison, West Penn and AGC(c)
Annual Compensation
All
Name Other
and Long-Term Compen-
Principal Annual Perform- sation
Position(d) Year Salary($) Bonus($)(e) ance Plan($)(f) ($)(g)
<S> <C> <C> <C> <C> <C>
Alan J. Noia, 1996 360,000 253,750 131,071 92,769
Chief Executive Officer 1995 305,000 120,000 48,983
1994 236,336 57,000 47,867
Klaus Bergman, 1996 220,835 - 0 -(h) 239,327 119,258(i)
Chairman of the Board(h) 1995 515,000 187,500 63,677
1994 485,004 120,000 91,458
Peter J. Skrgic, 1996 245,000 176,300 96,119 24,830
Senior Vice President 1995 238,000 73,800 37,830
1994 213,336 50,000 57,253
Jay S. Pifer, 1996 230,000 112,000 87,381 30,949
Senior Vice President 1995 220,000 72,600 34,098
1994 189,996 39,000 50,630
Richard J. Gagliardi 1996 175,008 100,800 52,429 17,898
Vice President 1995 160,008 48,400 18,769
1994 142,008 32,500 19,655
Kenneth M. Jones 1996 175,500 62,000 52,429 25,688
Vice President 1995 168,000 43,200 28,217
1994 160,008 31,000 30,026
</TABLE>
(a) The individuals appearing in this chart perform policy-making
functions for each of the Registrants. The compensation shown is
for all services in all capacities to APS, APSC and the
Subsidiaries. All salaries and bonuses of these executives are
paid by APSC.
(b) APS has no paid employees.
(c) AGC has no paid employees.
(d) See Executive Officers of the Registrants for all positions held.
(e) Incentive awards are based upon performance in the year in which
the figure appears but are paid in the following year. The
incentive award plan will be continued for 1997.
(f) In 1994, the Boards of Directors of APS, APSC and the Operating
Subsidiaries implemented a Performance Share Plan (the "Plan") for
senior officers which was approved by the shareholders of APS at
the annual meeting in May 1994. The first Plan cycle began on
January 1, 1994 and ended on December 31, 1996. The figure shown
represents the dollar value to be paid to each of the named
executive officers who participated in Cycle I. A second cycle
began on January 1, 1995 and will end on December 31, 1997. A
third cycle began on January 1, 1996 and will end on December 31,
1998. A fourth cycle began on January 1, 1997 and will end on
December 31, 1999. After completion of each cycle, APS stock
<PAGE> - 53 -
or cash may be paid if performance criteria have been met.
(g) Effective January 1, 1992, the basic group life insurance provided
employees was reduced from two times salary during employment,
which reduced to one times salary after 5 years in retirement, to a
new plan which provides one times salary until retirement and
$25,000 thereafter. Some executive officers and other senior
managers remain under the prior plan. In order to pay for this
insurance for these executives, during 1992 insurance was purchased
on the lives of each of them. Effective January 1, 1993, APS
started to provide funds to pay for the future benefits due under
the supplemental retirement plan (Secured Benefit Plan) as
described in note (d) on p. 54. To do this, APS purchased, during
1993, life insurance on the lives of the covered executives. The
premium costs of both the 1992 and 1993 policies plus a factor for
the use of the money are returned to APS at the earlier of (a)
death of the insured or (b) the later of age 65 or 10 years from
the date of the policy's inception. The figures in this column
include the present value of the executives' cash value at
retirement attributable to the current year's premium payment
(based upon the premium, future valued to retirement, using the
policy internal rate of return minus the corporation's premium
payment), as well as the premium paid for the basic group life
insurance program plan and the contribution for the 401(k) plan.
For 1996, 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 $88,269 and $4,500; Mr. Bergman $58,700 and
$4,500; Mr. Skrgic $20,330 and $4,500; Mr. Pifer $26,449 and
$4,500; Mr. Gagliardi $13,398 and $4,500; and Mr. Jones $21,188 and
$4,500, respectively.
(h) Mr. Bergman retired effective June 1, 1996 from his position as
Chief Executive Officer of APS and each Subsidiary. He will retire
from his position as Chairman of the Board effective May 8, 1997. Mr.
Bergman did not receive an incentive award for 1996 because six months
of service is required before an award may be granted.
(i) Included in this amount is $56,058 representing accrued vacation
for which he was paid.
ALLEGHENY POWER SYSTEM PERFORMANCE SHARE PLAN
UNITS AWARDED IN LAST FISCAL YEAR - (CYCLE III)
<TABLE>
<CAPTION>
Estimated Future Payout
Performance Threshold Target Maximum
Number of Period Until Number of Number of Number of
Name Shares Payout Shares Shares Shares
<S> <C> <C> <C> <C> <C>
Alan J. Noia
Chief Executive Officer 6,114 1996-98 3,668 6,114 12,228
Peter J. Skrgic
Senior Vice President 4,367 1996-98 2,620 4,367 8,734
Jay S. Pifer
Senior Vice President 2,795 1996-98 1,677 2,795 5,590
Richard J. Gagliardi
Vice President 2,445 1996-98 1,467 2,445 4,890
Kenneth M. Jones
Vice President 1,747 1996-98 1,048 1,747 3,494
</TABLE>
<PAGE> - 54 -
The named executives were awarded the above number of shares for
Cycle III. Such number of shares are only targets. As described below, no
payouts will be made unless certain criteria are met. Each executive's
1996-1998 target long-term incentive opportunity was converted into performance
shares equal to an equivalent number of shares of APS common stock based on the
price of such stock on December 31, 1995. At the end of this three-year
performance period, the performance shares attributed to the calculated award
will be valued based on the price of APS common stock on December 31, 1998 and
will reflect dividends that would have been paid on such stock during the
performance period as if they were reinvested on the date paid. If an
executive retires, dies or otherwise leaves the employment of the Allegheny
Power prior to the end of the three-year period, the executive may still
receive an award based on the number of months worked during the period.
However, an executive must work at least eighteen months during the three-year
period to be eligible for an award payout. The final value of an executive's
account, if any, will be paid to the executive in stock or cash in early 1999.
The actual payout of an executive's award may range from 0 to 200% of
the target amount, before dividend re-investment. The payout is based upon
customer and stockholder performance factors and APS's rankings versus the peer
group. The combined customer and stockholder rating is then compared to a pre-
established percentile ranking chart to determine the payout percentage of
target. A ranking below 30% results in a 0% payout. The minimum payout begins
at the 30% ranking, which results in a payout of 60% of target, ranging up to a
payout of 200% of target if there is a 90% or higher ranking.
DEFINED BENEFIT OR ACTUARIAL PLAN DISCLOSURE (a)
APS(b), Monongahela, Potomac Edison, West Penn and AGC (c)
<TABLE>
<CAPTION>
Estimated
Name and Capacities Annual Benefits
In Which Served on Retirement (d)
<S> <C>
Alan J. Noia, $275,998
Chief Executive Officer (e)(f)
Klaus Bergman, $302,000
Chairman of the Board (e)(g)
Peter J. Skrgic, $159,005
Senior Vice President (e)(f)
Jay S. Pifer, $140,800
Senior Vice President(e)(f)
Richard J. Gagliardi
Vice President(e)(f) $111,075
Kenneth M. Jones
Vice President(e)(f) $102,938
</TABLE>
(a) The individuals appearing in this chart perform policy-making functions
for each of the Registrants.
(b) APS has no paid employees.
(c) AGC has no paid employees.
(d) Assumes present insured benefit plan and salary continue and retirement at
age 65 with single life annuity. Under plan provisions, the annual rate
of benefits payable at the normal retirement age of 65 are computed by
adding (i) 1% of final average pay up to covered compensation times
years of service up to 35 years, plus (ii) 1.5% of final
average pay in excess of covered compensation times years of service up to
35 years, plus (iii) 1.3% of final average pay times years of service in
excess of 35 years. Covered
<PAGE> - 55 -
compensation is the average of the maximum
taxable Social Security wage bases during the 35 years preceding the
member's retirement. The final average pay benefit is based on the
member's average total earnings during the highest-paid 60 consecutive
calendar months or, if smaller, the member's highest rate of pay as of any
July 1st. Effective July 1, 1994 the maximum amount of any employee's
compensation that may be used in these computations was decreased to
$150,000. Benefits for employees retiring between 55 and 62 differ from
the foregoing.
Pursuant to a supplemental plan (Secured Benefit Plan), senior executives
of Allegheny Power System companies who retire at age 60 or over with
40 or more years of service are entitled to a supplemental retirement
benefit in an amount that, together with the benefits under the basic
plan and from other employment, will equal 60% of the executive's highest
average monthly earnings for any 36 consecutive months. The earnings
include 50% of the actual annual bonus paid effective February 1, 1996.
The figures shown do not give any effect to bonus payments. The
supplemental benefit is reduced for less than 40 years service and for
retirement age from 60 to 55. It is included in the amounts shown where
applicable. In order to provide funds to pay such benefits, effective
January 1, 1993 the Company purchased insurance on the lives of the
plan participants. The Secured Benefit Plan has been designed that if
the assumptions made as to mortality experience, policy dividends, and
other factors are realized, the Company will recover all premium
payments, plus a factor for the use of the Company's money. The amount
of the premiums for this insurance required to be deemed "compensation"
by the SEC is described and included in the "All Other Compensation"
column on page 52. All executive officers are participants in the
Secured Benefit Plan. The figures shown do 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 1996, all eligible employees may elect to
have from 2% to 7% of their compensation contributed to the Plan as
pre-tax contributions and an additional 1% to 6% as post-tax
contributions. Employees direct the investment of these contributions
into one or more available funds. Each System company matches 50% of
the pre-tax contributions up to 6% of compensation with common stock of
Allegheny Power System, Inc. Effective January 1, 1994 the maximum amount
of any employee's compensation that may be used in these computations was
decreased to $150,000. Employees' interests in the ESOSP vest
immediately. Their pre-tax contributions may be withdrawn only upon
meeting certain financial hardship requirements or upon termination of
employment.
(e) See Executive Officers of the Registrants for all positions held.
(f) The total estimated annual benefits on retirement payable to Messrs.
Noia, Skrgic, Pifer, Gagliardi and Jones for services in all capacities to
APS, APSC and the Subsidiaries is set forth in the table.
(g) Mr. Bergman retired effective June 1, 1996 as Chief Executive Officer and
will retire effective May 8, 1997 as Chairman of the Board. The actual
amount he is receiving for service in all capacities to APS, APSC and the
Subsidiaries is set forth in the table.
Change In Control Contracts
In March 1996, APS entered into Change in Control contracts with
certain Allegheny Power executive officers (Agreements). Each Agreement
sets forth (i) the severance benefits that will be provided to the
employee in the event the employee is terminated subsequent to a Change
in Control of APS (as defined in the Agreements), and (ii) the
employee's obligation to continue his or her employment after the
occurrence of certain circumstances that could lead to a Change in
Control. The Agreements provide generally that if there is a Change in
Control, unless employment is terminated by APS for Cause, Disability or
Retirement or by the employee for Good Reason (each as defined in the
Agreements), severance benefits payable to the employee will consist of
a cash payment equal to 2.99 times the employee's annualized
compensation and APS will maintain existing benefits for the employee
and the employee's dependents for a period of three years. Each
Agreement initially expires on December 31, 1997 but will be
automatically extended for one year periods thereafter unless either APS
or the employee gives notice otherwise. Notwithstanding the delivery of
such notice, the Agreements will continue in effect for thirty-six
months after a Change in Control.
<PAGE> - 56 -
Compensation of Directors
In 1996, 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, for which fees are $200, and (c)
$250 for each Board meeting of each company attended, and 200 shares of
APS common stock pursuant to the Restricted Stock Plan for Outside
Directors. Under an unfunded deferred compensation plan, a director may
elect to defer receipt of all or part of his or her director's fees for
succeeding calendar years to be payable with accumulated interest when
the director ceases to be such, in equal annual installments, or, upon
authorization by the Board of Directors, in a lump sum. Subsequent to
June 1, 1996, Mr. Bergman has received a fixed fee at the annual rate of
$100,000 for services in all capacities to APS and the Subsidiaries.
In addition to the fees mentioned above, the Chairperson of each
of the Audit, Finance, Management Review, New Business, and Strategic
Affairs Committees receives a further fee of $4,000 per year. The
outside Directors also were covered by a Directors' Retirement Plan
(Plan) in 1996 which provides an annual pension equal to the retainer
fee paid to the outside director at the time of his or her retirement,
provided the director was serving at December 5, 1996, has at least five
(5) years of service and, except under special circumstances described
in the Plan, serves until age 65. Directors elected after December 5,
1996 will not be covered under the Plan.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The table below shows the number of shares of APS common stock
that are beneficially owned, directly or indirectly, by each director
and named executive officer of APS, Monongahela, Potomac Edison, West
Penn, and AGC and by all directors and executive officers of each such
company as a group as of December 31, 1996. 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.
<PAGE> - 57 -
<TABLE>
<CAPTION>
Executive Shares of
Officer or APS Percent
Name Director of Common Stock of Class
<S> <C> <C> <S> <C>
Eleanor Baum APS,MP,PE,WP 2,400 Less than .01%
William L. Bennett APS,MP,PE,WP 3,050 "
Klaus Bergman APS,MP,PE,WP,AGC 12,207 "
Richard J. Gagliardi APS 4,852 "
Thomas K. Henderson MP,PE,WP,AGC 4,923 "
Wendell F. Holland APS,MP,PE,WP 573 "
Kenneth M. Jones APS,AGC 5,470 "
Phillip E. Lint APS,MP,PE,WP 1,033 "
Edward H. Malone APS,MP,PE,WP 1,868 "
Frank A. Metz, Jr. APS,MP,PE,WP 2,617 "
Michael P. Morrell APS,MP,PE,WP,AGC 0 "
Alan J. Noia APS,MP,PE,WP,AGC 13,263 "
Jay S. Pifer APS,MP,PE,WP 9,251 "
Steven H. Rice APS,MP,PE,WP 2,868 "
Gunnar E. Sarsten APS,MP,PE,WP 6,400 "
Peter L. Shea APS,MP,PE,WP 2,100 "
Peter J. Skrgic APS,MP,PE,WP,AGC 6,714 "
</TABLE
>
</TABLE>
<TABLE>
<CAPTION>
<S> <C> <S> <C>
All directors and executive officers
of APS as a group (18 persons) 81,536 Less than .08%
All directors and executive officers
of MP as a group (23 persons) 100,119 "
All directors and executive officers
of PE as a group (22 persons) 99,491 "
All directors and executive officers
of WP as a group (22 persons) 100,108 "
All directors and executive officers
of AGC as a group (9 persons) 53,374 "
</TABLE>
All of the shares of common stock of Monongahela (5,891,000), Potomac Edison
(22,385,000), and West Penn (24,361,586) are owned by APS. All of the common
stock of AGC is owned by Monongahela (270 shares), Potomac Edison (280
shares), and West Penn (450 shares).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
In connection with the relocation of the New York office,
Allegheny Power made available to each employee involved in the
relocation an interest-free loan of up to 95% of the appraised equity in
the employee's current residence for the purchase of a new residence.
The loan terms required repayment to Allegheny Power upon actual
relocation. In addition, relocating employees were reimbursed by
Allegheny Power for interest paid on a new mortgage until the actual
date of relocation. On October 10, 1995, Allegheny Power made an
interest-free loan in the amount of $215,000 to Richard J. Gagliardi, a
Vice President of APS. On December 7, 1995, Allegheny Power made an
interest-free loan in the amount of $75,000 to Thomas K. Henderson, a
Vice President of Monongahela, Potomac Edison and West Penn. On January
5, 1996, Allegheny Power made an interest-free loan in the amount of
$61,000 to Peter J. Skrgic, a Senior Vice President of APS and a Vice
President of Potomac Edison and AGC. On June 21, 1996, Allegheny Power
made an interest-free loan in the amount of $85,000 to Eileen M. Beck,
Secretary of APS, Monongahela, Potomac Edison, West Penn and AGC. All
outstanding balances on these loans were repaid in full in 1996.
<PAGE> - 58 -
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 44.
(b) No reports on Form 8-K were filed by System companies during the
quarter ended December 31, 1996.
(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> - 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.
ALLEGHENY POWER SYSTEM, INC.
By: ALAN J. NOIA
(Alan J. Noia) President and
Chief Executive Officer
Date: March 6, 1997
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.
<TABLE>
<CAPTION>
Signature Title Date
<S> <C> <C> <C>
(i) Principal Executive Officer:
President, Chief Executive 3/6/97
ALAN J. NOIA Officer, and Director
(Alan J. Noia)
(ii) Principal Financial Officer:
MICHAEL P. MORRELL Senior Vice President, 3/6/97
(Michael P. Morrell) Finance
(iii) Principal Accounting Officer:
KENNETH M. JONES Vice President and 3/6/97
(Kenneth M. Jones) Controller
(iv) A Majority of the Directors:
*Eleanor Baum *Frank A. Metz, Jr.
*William L. Bennett *Alan J. Noia
*Klaus Bergman *Steven H. Rice
*Wendell F. Holland *Gunnar E. Sarsten
*Phillip E. Lint *Peter L. Shea
*Edward H. Malone
*By: THOMAS K. HENDERSON 3/6/97
(Thomas K. Henderson)
</TABLE>
<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.
MONONGAHELA POWER COMPANY
By: JAY S. PIFER
(Jay S. Pifer) President
and Director
Date: March 6, 1997
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.
<TABLE>
<CAPTION>
Signature Title Date
<S> <C> <C> <C>
(i) Principal Executive Officer:
Chairman of the Board, 3/6/97
ALAN J. NOIA Chief Executive Officer,
(Alan J. Noia) and Director
(ii) Principal Financial Officer:
MICHAEL P. MORRELL Vice President, 3/6/97
(Michael P. Morrell) Finance
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 3/6/97
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Eleanor Baum *Michael P. Morrell
*William L. Bennett *Alan J. Noia
*Klaus Bergman *Jay S. Pifer
*Wendell F. Holland *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Edward H. Malone *Peter L. Shea
*Frank A. Metz, Jr. *Peter J. Skrgic
*By: THOMAS K. HENDERSON 3/6/97
(Thomas K. Henderson)
</TABLE>
<PAGE> - 61 -
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the registrant has duly caused this report to
be signed on its behalf by the undersigned, thereunto duly authorized. The
signature of the undersigned company shall be deemed to relate only to matters
having reference to such company and any subsidiaries thereof.
THE POTOMAC EDISON COMPANY
By: JAY S. PIFER
(Jay S. Pifer) President
and Director
Date: March 6, 1997
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.
<TABLE>
<CAPTION>
Signature Title Date
<S> <C> <C> <C>
(i) Principal Executive Officer:
Chairman of the Board, 3/6/97
ALAN J. NOIA Chief Executive Officer,
(Alan J. Noia) and Director
(ii) Principal Financial Officer:
MICHAEL P. MORRELL Vice President, 3/6/97
(Michael P. Morrell) Finance
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 3/6/97
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Eleanor Baum *Michael P. Morrell
*William L. Bennett *Alan J. Noia
*Klaus Bergman *Jay S. Pifer
*Wendell F. Holland *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Edward H. Malone *Peter L. Shea
*Frank A. Metz, Jr. *Peter J. Skrgic
*By: THOMAS K. HENDERSON 3/6/97
(Thomas K. Henderson)
</TABLE>
<PAGE> - 62 -
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
and Director
Date: March 6, 1997
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.
<TABLE>
<CAPTION>
Signature Title Date
<S> <C> <C> <C>
(i) Principal Executive Officer:
Chairman of the Board, 3/6/97
ALAN J. NOIA Chief Executive Officer,
(Alan J. Noia) and Director
(ii) Principal Financial Officer:
MICHAEL P. MORRELL Vice President, 3/6/97
(Michael P. Morrell) Finance
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 3/6/97
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Eleanor Baum *Michael P. Morrell
*William L. Bennett *Alan J. Noia
*Klaus Bergman *Jay S. Pifer
*Wendell F. Holland *Steven H. Rice
*Phillip E. Lint *Gunnar E. Sarsten
*Edward H. Malone *Peter L. Shea
*Frank A. Metz, Jr. *Peter J. Skrgic
*By: THOMAS K. HENDERSON 3/6/97
(Thomas K. Henderson)
</TABLE>
<PAGE> - 63 -
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: ALAN J. NOIA
(Alan J. Noia)
Chief Executive Officer
Date: March 6, 1997
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.
<TABLE>
<CAPTION>
Signature Title Date
<S> <C> <C> <C>
(i) Principal Executive Officer:
ALAN J. NOIA President, Chief Executive 3/6/97
(Alan J. Noia) Officer and Director
(ii) Principal Financial Officer:
MICHAEL P. MORRELL Vice President, 3/6/97
(Michael P. Morrell) Finance
(iii) Principal Accounting Officer:
THOMAS J. KLOC Controller 3/6/97
(Thomas J. Kloc)
(iv) A Majority of the Directors:
*Thomas K. Henderson
*Kenneth M. Jones
*Michael P. Morrell
*Alan J. Noia
*Peter J. Skrgic
*By: THOMAS K. HENDERSON 3/6/97
(Thomas K. Henderson)
</TABLE>
<PAGE> - 64 -
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Prospectus
constituting part of Allegheny Power System, Inc.'s Registration
Statements on Form S-3 (Nos. 33-36716 and 33-57027) relating to the
Dividend Reinvestment and Stock Purchase Plan of Allegheny Power System,
Inc.; in the Prospectus constituting part of Allegheny Power System,
Inc.'s Registration Statement on Form S-3 (No. 33-49791) relating to the
common stock shelf registration; in the Prospectus constituting part of
Monongahela Power Company's Registration Statements on Form S-3 (Nos.
33-51301, 33-56262 and 33-59131); in the Prospectus constituting part of
The Potomac Edison Company's Registration Statements on Form S-3 (Nos.
33-51305 and 33-59493); and in the Prospectus constituting part of West
Penn Power Company's Registration Statements on Form S-3 (Nos. 33-51303,
33-56997, 33-52862, 33-56260 and 33-59133); of our reports dated
February 5, 1997 included in ITEM 8 of this Form 10-K. We also consent
to the references to us under the heading "Experts" in such
Prospectuses.
PRICE WATERHOUSE LLP
New York, New York
March 21, 1997
<PAGE> - 65 -
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of
Allegheny Power System, Inc., a Maryland corporation, Monongahela Power
Company, an Ohio corporation, The Potomac Edison Company, a Maryland and
Virginia corporation, and West Penn Power Company, a Pennsylvania
corporation, do hereby constitute and appoint THOMAS K. HENDERSON and
EILEEN M. BECK, and each of them, a true and lawful attorney in his or
her name, place and stead, in any and all capacities, to sign his or her
name to Annual Reports on Form 10-K for the year ended December 31, 1996
under the Securities Exchange Act of 1934, as amended, and to any and
all amendments, of said Companies, and to cause the same to be filed
with the SEC, granting unto said attorneys and each of them full power
and authority to do and perform any act and thing necessary and proper
to be done in the premises, as fully and to all intents and purposes as
the undersigned could do if personally present, and the undersigned
hereby ratifies and confirms all that said attorneys or any one of them
shall lawfully do or cause to be done by virtue hereof.
Dated: March 6, 1997
<TABLE>
<CAPTION>
<S> <C>
ELEANOR BAUM FRANK A. METZ, JR.
(Eleanor Baum) (Frank A. Metz, Jr.)
WILLIAM L. BENNETT ALAN J. NOIA
(William L. Bennett) (Alan J. Noia)
KLAUS BERGMAN STEVEN H. RICE
(Klaus Bergman) (Steven H. Rice)
WENDELL F. HOLLAND GUNNAR E. SARSTEN
(Wendell F. Holland) (Gunnar E. Sarsten)
PHILLIP E. LINT PETER L. SHEA
(Phillip E. Lint) (Peter L. Shea)
EDWARD H. MALONE
(Edward H. Malone)
</TABLE>
<PAGE> - 66 -
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of
Monongahela Power Company, an Ohio corporation, The Potomac Edison
Company, a Maryland and Virginia corporation, and West Penn Power
Company, a Pennsylvania corporation, do hereby constitute and appoint
THOMAS K. HENDERSON and EILEEN M. BECK, and each of them, a true and
lawful attorney in his name, place and stead, in any and all capacities,
to sign his or her name to the Annual Report on Form 10-K for the year
ended December 31, 1996 under the Securities Exchange Act of 1934, as
amended, and to any and all amendments, of said Company, and to cause
the same to be filed with the SEC, granting unto said attorneys and each
of them full power and authority to do and perform any act and thing
necessary and proper to be done in the premises, as fully and to all
intents and purposes as the undersigned could do if personally present,
and the undersigned hereby ratify and confirm all that said attorneys or
any one of them shall lawfully do or cause to be done by virtue hereof.
Dated: March 6, 1997
MICHAEL P. MORRELL
(Michael P. Morrell)
JAY S. PIFER
(Jay S. Pifer)
PETER J. SKRGIC
(Peter J. Skrgic)
<PAGE> - 67 -
POWER OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS THAT the undersigned directors of
Allegheny Generating Company, a Virginia corporation, do hereby
constitute and appoint THOMAS K. HENDERSON and EILEEN M. BECK, and each
of them, a true and lawful attorney in his name, place and stead, in any
and all capacities, to sign his or her name to the Annual Report on Form
10-K for the year ended December 31, 1996 under the Securities Exchange
Act of 1934, as amended, and to any and all amendments, of said Company,
and to cause the same to be filed with the SEC, granting unto said
attorneys and each of them full power and authority to do and perform
any act and thing necessary and proper to be done in the premises, as
fully and to all intents and purposes as the undersigned could do if
personally present, and the undersigned hereby ratify and confirm all
that said attorneys or any one of them shall lawfully do or cause to be
done by virtue hereof.
Dated: March 6, 1997
THOMAS K. HENDERSON
(Thomas K. Henderson)
KENNETH M. JONES
(Kenneth M. Jones)
MICHAEL P. MORRELL
(Michael P. Morrell)
ALAN J. NOIA
(Alan J. Noia)
PETER J. SKRGIC
(Peter J. Skrgic)
<PAGE>
E-2
Monongahela Power Company
<TABLE>
<CAPTION>
Incorporation
Documents by Reference
<S> <C> <C>
3.1 Charter of the Company, Form 10-Q of the Company
as amended (1-5164), September 1995,
exh. (a)(3)(i)
3.2 Code of Regulations, Form 10-Q of the Company
as amended (1-5164), September 1995,
exh. (a)(3)(ii)
4 Indenture, dated as of S 2-5819, exh. 7(f)
August 1, 1945, and S 2-8782, exh. 7(f)(1)
certain Supplemental S 2-8881, exh. 7(b)
Indentures of the S 2-9355, exh. 4(h)(1)
Company defining rights S 2-9979, exh. 4(h)(1)
of security holders.* S 2-10548, exh. 4(b)
S 2-14763, exh. 2(b)(i)
S 2-24404, exh. 2(c);
S 2-26806, exh. 4(d);
Forms 8-K of the Company
(1-268-2) dated November 21, 1991,
June 4, 1992, July 15, 1992, September 1, 1992, April 29,
1993 and May 23, 1995
* There are omitted the Supplemental Indentures which do no more
than subject property to the lien of the above Indentures since
they are not considered constituent instruments defining the
rights of the holders of the securities. The Company agrees to
furnish the Commission on its request with copies of such
Supplemental Indentures.
10 Form of Employment Contract Form 8-K of the Company
with Certain Executive Officers (1-5164) dated April 11,
Under Age 55 1996, exh. 10.1
Form of Employment Contract Form 8-K of the Company
with Certain Executive Officers (1-5164) dated April 11,
Over Age 55 1996, exh. 10.2
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 64 herein.
24 Powers of Attorney See pages 65-67 herein.
27 Financial Data Schedule
</TABLE>
<PAGE>
EXHIBIT 12
COMPUTATION IN SUPPORT OF RATIO OF EARNINGS TO FIXED CHARGES
For Year Ended December 31, 1996
(Dollar Amounts in Thousands)
Monongahela Power Company
Earnings:
Net Income $ 61,453
Fixed charges (see below) 39,385
Income taxes 34,469
Total earnings $135,307
Fixed Charges:
Interest on long-term debt $ 36,654
Other interest 1,950
Estimated interest
component of rentals 781
Total fixed charges $ 39,385
Ratio of Earnings to
Fixed Charges 3.44
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<MULTIPLIER> 1,000
<CURRENCY> U.S.DOLLARS
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1996
<PERIOD-START> JAN-01-1996
<PERIOD-END> DEC-31-1996
<EXCHANGE-RATE> 1
<CASH> 2,290
<SECURITIES> 0
<RECEIVABLES> 80,929
<ALLOWANCES> 1,949
<INVENTORY> 36,479
<CURRENT-ASSETS> 146,773
<PP&E> 1,879,622
<DEPRECIATION> 790,649
<TOTAL-ASSETS> 1,486,755
<CURRENT-LIABILITIES> 143,321
<BONDS> 474,841
0
74,000
<COMMON> 294,550
<OTHER-SE> 217,662
<TOTAL-LIABILITY-AND-EQUITY> 1,486,755
<SALES> 632,471
<TOTAL-REVENUES> 632,471
<CGS> 409,275
<TOTAL-COSTS> 505,422
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 38,245
<INCOME-PRETAX> 95,948
<INCOME-TAX> 34,496
<INCOME-CONTINUING> 61,452
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 61,452
<EPS-PRIMARY> 0.00<F1>
<EPS-DILUTED> 0.00<F1>
<FN>
<F1>All common stock is owned by parent, no EPS required.
</FN>
</TABLE>
