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Pennsylvania Power & Light Company
FORM 10 - K
Annual Report
to the Securities
and Exchange
Commission
For the Year Ended
December 31, 1994
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended December 31, 1994
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from _________ to ___________
Commission file number 1-905
PENNSYLVANIA POWER & LIGHT COMPANY
(Exact name of Registrant as specified in its charter)
PENNSYLVANIA 23-0959590
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
TWO NORTH NINTH STREET, ALLENTOWN, PENNSYLVANIA 18101-1179
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: 610-774-5151
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
Preferred Stock
4-1/2% New York & Philadelphia Stock Exchanges
3.35% Series Philadelphia Stock Exchange
4.40% Series New York & Philadelphia Stock Exchanges
4.60% Series Philadelphia Stock Exchange
Common Stock New York & Philadelphia Stock Exchanges
Securities registered pursuant to Section 12(g) of the Act: None
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 Registrant's 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 ]
Indicate by check mark whether the Registrant (1) has 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
(or for such shorter period that the Registrant was required to
file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
Estimated aggregate market value of the voting stock
(common and preferred) held by non-
affiliates at the end of January 1995 $3,615,292,207
Common stock, no par, number of shares
outstanding at January 31, 1995 156,300,839
Documents incorporated by reference:
Registrant has incorporated herein by reference certain
sections of its 1995 Notice of Annual Meeting and Proxy Statement
which will be filed with the Securities and Exchange Commission
not later than 120 days after December 31, 1994. Such Proxy
Statement will provide the information required by Part III of
this Report.
PENNSYLVANIA POWER & LIGHT COMPANY
FORM 10-K ANNUAL REPORT TO
THE SECURITIES AND EXCHANGE COMMISSION
FOR THE YEAR ENDED DECEMBER 31, 1994
TABLE OF CONTENTS
Item
PART I
1. Business
2. Properties
3. Legal Proceedings
4. Submission of Matters to a Vote of Security Holders
Executive Officers of the Registrant
PART II
5. Market for the Registrant's Common Equity and Related
Stockholder Matters
6. Selected Financial Data
7. Management's Discussion and Analysis of Financial
Condition and Results of Operations
8. Financial Statements and Supplementary Data
9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure
PART III
10. Directors and Executive Officers of the Registrant
11. Executive Compensation
12. Security Ownership of Certain Beneficial
Owners and Management
13. Certain Relationships and Related Transactions
PART IV
14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K
Signatures
Exhibit Index
Computation of Ratio of Earnings to Fixed Charges
Schedule of Property, Plant and Equipment
2
3
PART I
ITEM 1. BUSINESS
THE COMPANY
Pennsylvania Power & Light Company (Company) is an operating
electric utility, incorporated under the laws of the Commonwealth of
Pennsylvania in 1920.
The Company's general offices are located at Two North Ninth
Street, Allentown, Pennsylvania 18101. The Company's telephone
number is (610) 774-5151.
The Company is subject to regulation as a public utility by the
Pennsylvania Public Utility Commission (PUC) and is subject in
certain of its activities to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) under Parts I, II and III of the Federal
Power Act. The Company is a holding company under the Public Utility
Holding Company Act of 1935 (PUHCA) but has been exempted by the
Securities and Exchange Commission from the provisions of that Act
applicable to it as a holding company.
The Company is subject to the jurisdiction of the Nuclear
Regulatory Commission (NRC) in connection with the operation of the
two nuclear-fueled generating units at the Company's Susquehanna
station. The Company owns a 90% undivided interest in each of the
Susquehanna units and Allegheny Electric Cooperative, Inc. owns a 10%
undivided interest in each of those units.
The Company is also subject to the jurisdiction of certain
federal, regional, state and local regulatory agencies with respect
to air and water quality, land use and other environmental matters.
The operations of the Company are subject to the Occupational Safety
and Health Act of 1970 and the coal cleaning and loading operations
of a Company subsidiary are subject to the Federal Mine Safety and
Health Act of 1977.
The Company operates its generation and transmission facilities
as part of the Pennsylvania-New Jersey-Maryland Interconnection
Association (PJM). The PJM, one of the world's largest power pools,
includes 11 companies serving about 21 million people in a 50,000
square mile territory covering all or part of Pennsylvania, New
Jersey, Maryland, Delaware, Virginia and Washington, D.C.
The Company serves approximately 1.2 million customers in a
10,000 square mile territory in 29 counties of central eastern
Pennsylvania (see Map on page 17), with a population of approximately
2.6 million persons. This service area has 128 communities with
populations over 5,000, the largest cities of which are Allentown,
Bethlehem, Harrisburg, Hazleton, Lancaster, Scranton, Wilkes-Barre
and Williamsport.
During 1994, about 98% of total operating revenue was derived
from electric energy sales, with 35% coming from residential
customers, 28% from commercial customers, 20% from industrial
customers, 11% from contractual sales to other major utilities, 3%
from energy sales to members of the PJM and 3% from others. The
Company's largest industrial customer provided about 1.4% of revenues
from energy sales during 1994. Twenty-six industrial customers,
whose billings exceeded $3 million each, provided about 7.1% of such
revenues. Industrial customers are broadly distributed among
industrial classifications.
Wholly owned subsidiary companies of the Company principally are
engaged in oil pipeline operations, unregulated business activities,
passive financial investments and holding coal reserves. See
"Increasing Competition" on page 42 for information concerning the
Company's ongoing effort to create a new corporate structure to
pursue new business opportunities.
FINANCIAL CONDITION
Earnings per share of common stock were $1.41 in 1994, $2.07 in
1993 and $2.02 in 1992.
Earnings for 1994 were adversely affected by several one-time
charges, including two major charges during the fourth quarter. One
charge amounted to $75.9 million, or 28 cents per share of common
stock, resulting from costs associated with a voluntary early
retirement program; and the other charge amounted to $73.7 million,
or 26 cents per share, from a write down in the carrying value of a
subsidiary's investment in undeveloped coal reserves. In addition,
two nonrecurring charges recorded earlier in the year reflected the
disallowance by the PUC of recovery through the Energy Cost Rate
(ECR) of replacement power costs incurred during an extended outage
at the Susquehanna station, amounting to $15.7 million, or 6 cents
per share of common stock; and a decision by the Commonwealth Court
of Pennsylvania which reversed a PUC order that permitted deferral of
the cost of postretirement benefits other than pensions. The Company
charged the deferred postretirement benefit costs applicable to 1993
against income, which amounted to $10.8 million or 4 cents per share.
Although these nonrecurring charges depressed earnings in 1994,
underlying sales performance was strong, with a 4.1% increase in
sales to ultimate customers due to improving economic conditions and
colder-than-normal weather in the winter months. Other positive
effects on earnings included the Company's continued efforts to
control operating and maintenance costs, and the refinancing of
higher cost securities to take advantage of favorable market
conditions.
Due to the one-time charges to income in 1994, several financial
indicators decreased from 1993. The Company earned an 8.73% return
on average common equity during 1994, down from the 13.06% earned in
1993. The ratio of the Company's pre-tax income to interest charges
decreased from 3.3 in 1993 to 2.7 in 1994. Excluding these one-time
charges, the return on average common equity and the ratio of pre-tax
income to interest charges in 1994 would have been 12.53% and 3.1,
respectively. See "Earnings" on page 28. The Company increased
common stock dividends from an annual per share rate of $1.65 in 1993
to $1.67 in 1994. The book value per share of common stock decreased
1.0% from $15.95 at the end of 1993 to $15.79 at the end of 1994.
The ratio of the market price to book value of common stock was 120%
at the end of 1994 compared with 169% at the end of 1993.
The allowance for funds used during construction (AFUDC), a non-
cash credit to income, accounted for about 6.1% of earnings in 1994.
The amount of AFUDC recorded in the future will depend on the timing
and level of construction work in progress as well as the rate
treatment afforded the capital expenditures required to comply with
the clean air legislation. Under current Pennsylvania law,
construction work in progress for certain non-revenue producing
assets, such as capital expenditures for pollution control equipment,
can be claimed in rate base.
The Company's strong generating capacity position has enabled it
to enter into a number of capacity-related transactions, as discussed
under "Capacity-Related and Transmission Entitlement Transactions" on
page 29 and in Note 4 to Financial Statements.
Revenues from the sale of capacity credits, the reservation of
output from the generating units and the sale of transmission
entitlements, net of foregone PJM interchange savings which are
included in the Company's ECR, totaled $28.7 million in 1994, $35.0
million in 1993 and $35.0 million in 1992. The 1994 revenues exclude
approximately $8.4 million of receipts from installed capacity credit
sales which were credited to customers through the ECR. The Company
currently expects about $14.6 million of revenues from these
transactions during 1995, exclusive of credits to be applied to the
ECR.
The Company is continuing to look for opportunities to derive
additional revenues from these transactions due to its strong
generating capacity position. However, increased competition in
capacity credit transactions has reduced the Company's share of this
market and the unit price received for such sales. The amount of
revenues from these transactions depends on many factors, and the
Company cannot predict the amount of revenues it will ultimately
realize from these transactions.
In October 1994, the PUC approved a settlement agreement
resolving all complaints against the 1990-91 ECR through 1993-94 ECR,
including issues related to capacity-related transactions. The
agreement provides, among other things, for crediting the 1994-95 ECR
with a portion of the receipts from capacity credit sales. See "Rate
Matters" on page 30 for additional information.
Economic activity in the Company's service territory continued
to increase in 1994. Energy sales to service area customers, when
adjusted for normal weather, increased by 1.1 billion kilowatt-hours
(kwh), or 3.5%, over 1993. By comparison, weather-normalized energy
sales in 1993 increased by only 2.8% over 1992 levels.
In 1994, residential sales and commercial sales, when adjusted
for normal weather, increased by 2.2% and 3.5%, respectively, over
1993. Industrial sales, which are not affected by the weather, were
up 4.8%.
System sales in 1995 are currently forecasted to be
approximately 32.5 billion kwh, an increase of 136 million kwh, or
0.4%, over 1994 actual system sales, and a 419 million kwh, or 1.3%,
increase over 1994 weather-normalized sales.
The electric utility industry, including the Company, has
experienced and will continue to experience a significant increase in
the level of competition in the energy supply market. The Energy
Policy Act of 1992 (Energy Act) is having a significant impact on the
Company and the electric utility industry, primarily through
amendments to the PUHCA that create a new class of independent power
producers, and amendments to the Federal Power Act that open access
to electric transmission systems for wholesale transactions. In
response to this increased competition, the Company has undertaken
strategic initiatives to strengthen its position in the market.
In the wholesale supply market, the Company has entered into new
five-year supply agreements at reduced prices with its existing
wholesale customers. In addition, the Company is actively
participating in negotiations and proceedings involving the sale of
electricity to wholesale customers currently served by other
utilities.
While there is currently no comparable competition in the retail
electric market, the Company anticipates similar competitive
pressures in that market in the future. Accordingly, the Company has
obtained PUC approval to enter into negotiated, competitive rates
with certain industrial and commercial customers and to provide real
time pricing rates on a three-year experimental basis to certain
industrial and commercial customers.
To remain competitive, the Company also has taken steps to
increase efficiency and reduce costs. The Company has initiated a
program to make its generating stations more efficient and
competitive in the power supply market. In addition, the Company has
reorganized its operations along functional, instead of geographic,
lines to enhance customer service. The Company's ongoing re-
engineering efforts also are expected to improve efficiency and
reduce costs. As part of its effort to reduce costs, the Company in
1994 offered an early retirement program to 851 employees, which was
accepted by 640 employees.
Finally, the Company's strategic initiatives include investment
in power-related businesses outside of the Company's service
territory, both domestically and in foreign countries. Any expansion
by the Company into these areas would be methodical and deliberate.
To take advantage of these new business opportunities, the Company
will form a holding company structure, subject to the receipt of
appropriate regulatory approvals and shareowner approval at the 1995
annual meeting.
In March 1994, the Company incorporated a new subsidiary, Power
Markets Development Company (PMD), and made an initial investment of
$50 million in this new subsidiary. PMD will help the Company take
advantage of new opportunities in the building and operation of power
plants in North America and elsewhere. Other subsidiaries will be
formed to take advantage of new business opportunities.
In connection with the formation of the holding company
structure, the Company filed the requisite applications for approval
with the PUC, the FERC, the Securities and Exchange Commission (SEC)
and the NRC. The FERC, the NRC and the PUC approvals have been
obtained, while the SEC application remains pending. The PUC
approval is subject to certain conditions, which are not expected to
materially restrict the Company's entry into unregulated business
activities.
For a further discussion of these competitive initiatives, see
"Increasing Competition" on page 41.
For a discussion of the assessment on the Company pursuant to
the Energy Act for the Uranium Enrichment Decontamination and
Decommissioning Fund, see the discussion under that caption on page
40.
CAPITAL EXPENDITURE REQUIREMENTS, FINANCING AND RATE MATTERS
See "Capital Expenditure Requirements" on page 34 for
information concerning the Company's estimated capital expenditure
requirements for the years 1995-1997. See "Clean Air Legislation and
Other Environmental Matters" on page 37 and Note 15 to Financial
Statements for information concerning the Company's estimate of the
cost to comply with the federal clean air legislation enacted in
1990, to address groundwater degradation and waste water control at
Company facilities and to comply with solid waste disposal
regulations adopted by the Pennsylvania Department of Environmental
Resources (DER).
After the payment of dividends, internally generated funds
during the years 1995-1997 are currently expected to provide
approximately 70-85% of the Company's construction expenditures which
are expected to be $1.3 billion. Sales of securities will be
undertaken during the 1995-1997 period as needed to meet the
Company's capital requirements, to meet a total of $211 million of
long-term debt maturities and to provide funds for the early
retirement of high cost securities if such retirements are determined
to be appropriate in the light of market conditions and other
factors. The Company expects to issue $180 million of common stock
in 1995 through its Dividend Reinvestment Plan and a public sale of
common stock. In addition, the Company expects to arrange for the
refinancing of $55 million of higher cost tax-exempt securities
issued to provide pollution control and solid waste disposal
facilities at the Company's generating stations.
The Company's ability to issue securities during the next three
years is not expected to be limited by earnings or other issuance
tests.
In December 1994, the Company filed a request with the PUC for a
$261 million increase in electric base rates, an 11.7% increase in
PUC - jurisdictional rates. The PUC has decided to hold hearings and
conduct an investigation of the request. A final rate decision is
expected in late September 1995. See Note 3 to Financial Statements
for information concerning the base rate case and other rate matters.
POWER SUPPLY
The Company's system capacity (winter rating) at December 31,
1994 was as follows:
Net
Kilowatt
Plant Capacity
Nuclear-fueled steam station
Susquehanna 1,950,000 (a)
Coal-fired steam stations
Montour 1,525,000
Brunner Island 1,469,000
Sunbury 389,000
Martins Creek 300,000
Keystone 210,000 (b)
Conemaugh 194,000 (c)
Holtwood 73,000
Total coal-fired 4,160,000
Oil-fired steam station
Martins Creek 1,640,000
Combustion turbines and diesels 508,000
Hydroelectric 146,000
Total generating capacity 8,404,000
Firm purchases
Hydroelectric 139,000 (d)
Qualifying facilities 504,000 (e)
Total firm purchases 643,000
Total system capacity 9,047,000
_____________________________
(a) Company's 90% undivided interest.
(b) Company's 12.34% undivided interest.
(c) Company's 11.39% undivided interest.
(d) From Safe Harbor Water Power Corporation.
(e) From non-utility generating companies.
The system capacity shown in the preceding tabulation does not
reflect: (i) sales of capacity and energy to Atlantic City Electric
Company (Atlantic) through September 2000; (ii) sales of capacity
and energy to Baltimore Gas and Electric Company (BG&E) through 2001;
(iii) sales of capacity and energy to Jersey Central Power & Light
Company (JCP&L) through 1999; or (iv) sales of capacity credits to
GPU Service Corporation for PJM installed capacity accounting
purposes only, which capacity credit sales aggregated 390,000
kilowatts at December 31, 1994. Giving effect to the sales to
Atlantic (125,000 kilowatts), BG&E (129,000 kilowatts) and JCP&L
(945,000 kilowatts), the Company's net system capacity at December
31, 1994 was 7,844,000 kilowatts.
The capacity of generating units is based upon a number of
factors, including the operating experience and physical condition of
the units, and may be revised from time to time to reflect changed
circumstances.
During 1994, the Company produced about 37.9 billion kwh in
plants owned by it. The Company purchased 5.0 billion kwh under
purchase agreements and received 1.0 billion kwh as power pool
interchange. During the year, the Company delivered about 3.2
billion kwh as pool interchange and about 0.4 billion kwh under
purchase agreements.
During 1994, 56.9% of the energy generated by the Company's
plants came from coal-fired stations, 36.4% from nuclear operations
at the Susquehanna station, 4.7% from the Martins Creek oil-fired
steam station and 2.0% from hydroelectric stations.
The maximum one-hour demand recorded on the Company's system is
6,508,000 kilowatts, which occurred on February 6, 1995. The maximum
recorded one-hour summer demand is 5,638,000 kilowatts, which
occurred on July 20, 1994. The peak demands do not include energy
sold to Atlantic, BG&E or JCP&L.
The Company purchases energy from other utilities when it is
economically desirable to do so. The Company occasionally purchases
energy from systems located to the west of the Company's service area
on a weekly basis at advantageous prices. The amount of energy
purchased depends on a number of factors, including cost and the
import capability of the transmission network. When it has been
economical to do so, the Company has sold portions of its entitlement
to use the bulk power transmission system to import energy from
utilities outside the PJM, rather than utilize its entitlement for
purchases from such western systems.
The Company also has entered into separate agreements with
several utilities in New York and New England to provide energy on an
as available, as needed basis. Transactions under these agreements
are expected to continue to allow the Company to make more efficient
use of its generating capacity and provide benefits to customers of
both the Company and the purchasing utilities. The Company also has
entered into agreements with several utilities both inside and
outside the PJM for the reservation of output during certain periods
from the Company's Martins Creek units, with the option to purchase
energy from those units.
See "Capacity-Related and Transmission Entitlement Transactions"
on page 29 and Note 4 to Financial Statements for additional
information concerning the sale of capacity and energy to Atlantic,
BG&E and JCP&L, the sale of capacity credits (but not energy) to
other electric utilities in the PJM and the sale of transmission
entitlements and the reservation of output from the Martins Creek
units. See "Rate Matters" on page 30 and Note 3 to Financial
Statements for information concerning a settlement agreement between
the Company and ECR complainants with respect to capacity-related
transactions.
In addition to the 504,000 kilowatts of non-utility generation
shown in the preceding tabulation, the Company is purchasing about
3,000 kilowatts of output from various other non-utility generating
companies. The payments made to non-utility generating companies,
all of whose facilities are located in the Company's service area,
are recovered from customers through the ECR applicable to PUC-
jurisdictional customers and base rate charges applicable to FERC-
jurisdictional customers.
The PJM companies had approximately 56 million kilowatts of
installed generating capacity at December 31, 1994, and transmission
line connections with neighboring power pools have the capability of
transferring an additional 4 to 5 million kilowatts between the PJM
and neighboring power pools. Through December 31, 1994, the maximum
one-hour demand recorded on the PJM was approximately 46.4 million
kilowatts, which occurred on July 8, 1993. The Company is also a
party to the Mid-Atlantic Area Coordination Agreement, which provides
for the coordinated planning of generation and transmission
facilities by the companies included in the PJM.
The Company currently plans to convert the two oil-fired
generating units at the Martins Creek station to burn both oil and
natural gas, subject to appropriate regulatory approvals. A Company
subsidiary filed an application with the PUC for authority to also
transport natural gas through the pipeline to the existing pipeline
customers, which include the Company and another utility. Two
parties have protested the subsidiary's application, asserting that
they have the sole authority to provide such gas service to the
Company and the other utility, respectively. The matter is presently
being litigated at the PUC and the Company cannot predict the
outcome.
FUEL SUPPLY
Coal
During 1994, the Company's generating stations burned about 7.8
million tons of bituminous coal and about 1.2 million tons of
anthracite and petroleum coke.
During 1994, 78% of the coal delivered to the Company's
generating stations was purchased under contracts and 22% was
obtained through open market purchases.
The amount of bituminous coal carried in inventory at the
Company's generating stations varies from time to time depending on
market conditions and plant operations. As of December 31, 1994, the
Company's bituminous coal supply was sufficient for about 48 days of
operations.
Contracts with non-affiliated coal producers provided the
Company with about 5.4 million tons of bituminous coal in 1994 and
are expected to provide the Company with about 5.4 million tons in
both 1995 and 1996.
A wholly owned subsidiary of the Company also holds certain
undeveloped coal reserves which the Company does not plan to develop.
At December 31, 1994, the investment by the subsidiary in those coal
reserves was about $10 million. See "Write Down of Coal Reserves" on
page 41 and Note 14 to Financial Statements for information
concerning the impairment of the subsidiary's investment in these
coal reserves.
The coal burned in the Company's generating stations contains
both organic and pyritic sulfur. Mechanical cleaning processes are
utilized to reduce the pyritic sulfur content of the coal. The
reduction of the pyritic sulfur content by either mechanical cleaning
or blending has lowered the total sulfur content of the coal burned
to levels which permit compliance with current sulfur dioxide
emission regulations established by the DER. For information
concerning the Company's plans to achieve compliance with the federal
clean air legislation enacted in 1990, see "Clean Air Legislation and
Other Environmental Matters" on page 37 and Note 15 to Financial
Statements.
The Company owns a 12.34% undivided interest in the Keystone
station and an 11.39% undivided interest in the Conemaugh station,
both of which are generating stations located in western
Pennsylvania. The owners of the Keystone station have a long-term
contract with a coal supplier to provide at least two-thirds of that
station's requirements through 1999 and declining amounts thereafter
until the contract expires at the end of 2004. The balance of the
Keystone station requirements are purchased in the open market. The
coal supply requirements for the Conemaugh station are being met from
several sources through a blend of long-term and short-term contracts
and spot market purchases.
At December 31, 1994, the Company's inventory of anthracite was
about 4.9 million tons. The Company's requirements for petroleum
coke and any additional anthracite that may be required over the
remainder of the expected useful lives of the Company's anthracite-
fired generating stations are expected to be obtained by contract and
market purchases.
Nuclear
The nuclear fuel cycle consists of the mining of uranium ore and
its milling to produce uranium concentrates; the conversion of
uranium concentrates to uranium hexafluoride; the enrichment of
uranium hexafluoride; the fabrication of fuel assemblies; the
utilization of the fuel assemblies in the reactor; the temporary
storage of spent fuel; and the permanent disposal of spent fuel.
The Company has entered into uranium supply agreements that,
together with options to extend, satisfy 100% of the uranium
concentrate requirements for the Susquehanna units through 1997,
approximately 70% of the requirements for the period 1998-1999, and
approximately 35% of the requirements for the period 2000-2001.
Deliveries under these agreements are expected to provide sufficient
quantities of uranium concentrates to permit Unit 1 to operate into
the third quarter of 1999 and Unit 2 to operate into the third
quarter of 1998.
The Company has entered into agreements that satisfy 100% of its
conversion requirements through 1997 and approximately 25% of the
conversion requirements for the period 1998-1999.
The Company also has entered into agreements for other segments
of the nuclear fuel cycle. Based upon the current operating plans
for each of the Susquehanna units, the following tabulation shows the
years through which contracts, including options to extend, could
provide the indicated segments of the nuclear fuel cycle:
Enrichment 2014
Fabrication 2004
The Company has elected to cancel all or a portion of deliveries
under its existing enrichment contract during the period 1999 through
2002, and plans to competitively bid those requirements on the open
market. Additional arrangements will be necessary to satisfy the
remaining fuel requirements of the Susquehanna units over their
anticipated useful lives.
The Company estimates that there is sufficient storage
capability in the spent fuel pools at Susquehanna to accommodate the
fuel that is expected to be discharged through the year 1997.
Federal law requires the federal government to provide for the
permanent disposal of commercial spent nuclear fuel. Pursuant to the
requirements of that law, the United States Department of Energy
(DOE) has initiated an analysis of a site in Nevada for a permanent
nuclear waste repository. The most recent estimated in-service date
for the repository is beyond 2010. However, the location of the site
for the repository in Nevada has been opposed by the state of Nevada.
The DOE is also pursuing implementation of a Monitored Retrievable
Storage (MRS) facility which is intended to permit the receipt of
spent nuclear fuel for interim storage by the year 1998, or shortly
thereafter. Even if the DOE is successful in implementing its plans
for the MRS, it is unlikely that any spent fuel will be shipped from
Susquehanna until well after the year 2000 because of the limited
capacity of the MRS and the large volume of other utilities' spent
fuel that is scheduled to be shipped before the Company's spent fuel.
Therefore, expansion of Susquehanna's spent fuel storage capability
will be necessary. To support this expansion, a contract was
recently signed providing for the design and construction of a new
spent fuel storage facility at the Susquehanna plant. The facility
will be modular so that additional storage capacity can be added as
needed. The Company currently estimates that the initial
construction will be completed in the spring of 1997.
Federal law also provides that the costs of spent nuclear fuel
disposal will be the responsibility of the generators of such wastes.
The Company includes in customer rates the fees charged by the DOE to
fund the permanent disposal of spent nuclear fuel.
For a discussion of the assessment on the Company pursuant to
the Energy Act for the Uranium Enrichment Decontamination and
Decommissioning Fund, see the discussion under that caption on page
40.
Oil
The Company has agreements with two suppliers under which it can
purchase its expected oil requirements for the Martins Creek units.
However, if there are price advantages to be realized from purchasing
oil in the spot market, these contracts permit the Company to acquire
up to one-half of its expected oil requirements for the Martins Creek
units in that manner. One oil purchase agreement expired in mid-1994
and was replaced with a similar two-year agreement which will expire
in mid-1996. The other agreement expires in mid-1995.
During 1994, approximately 80% of the oil requirements for the
Martins Creek units was purchased under the Company's oil contracts
and the balance was purchased on the spot market.
See "POWER SUPPLY" on page 6 for information concerning the
planned conversion of the two oil-fired generating units at the
Martins Creek station to burn both oil and natural gas.
ENVIRONMENTAL MATTERS
The Company is subject to certain present and developing
federal, regional, state and local laws and regulations with respect
to air and water quality, land use and other environmental matters.
See "Capital Expenditure Requirements" on page 34 for information
concerning environmental expenditures during the years 1992-1994 and
the Company's estimate of those expenditures during the years 1995-
1997. The Company believes that it is presently in substantial
compliance with applicable environmental laws and regulations.
See "Clean Air Legislation and Other Environmental Matters" on
page 37 and Note 15 to Financial Statements for information
concerning federal clean air legislation enacted in 1990, groundwater
degradation and waste water control at Company facilities, DER's
solid waste disposal regulations, the Company's negotiations with the
DER concerning remediation at certain sites of past operations, and
the issue of electric and magnetic fields. Other environmental laws,
regulations and developments that may have a substantial impact on
the Company are discussed below.
Air
The Federal Clean Air Act includes, among other things,
provisions that: (a) require the prevention of significant
deterioration of existing air quality in regions where air quality is
better than applicable ambient standards; (b) restrict the
construction of and revise the performance standards for new coal-
fired and oil-fired generating stations; and (c) authorize the United
States Environmental Protection Agency (EPA) to impose substantial
noncompliance penalties of up to $25,000 per day of violation for
each facility found to be in violation of the requirements of an
applicable state implementation plan. The DER administers the EPA's
air quality regulations through the Pennsylvania State Implementation
Plan and has concurrent authority to impose penalties for
noncompliance.
As a result of computer dispersion modeling of the effects of
the Company's Martins Creek station (located in Pennsylvania) on
ambient air quality in New Jersey, the EPA redesignated Warren
County, New Jersey to non-attainment status for sulfur dioxide,
effective February 1, 1988. However, the EPA withheld further
regulatory action until the Company, the EPA, the DER and the New
Jersey Department of Environmental Protection (NJDEP) could agree
upon and apply a computer model that will more accurately predict the
actual ambient air quality of the area. The Company negotiated with
the EPA, the DER and the NJDEP on a study to allow the use of a more
accurate model. This study began in May 1992 and is expected to be
concluded in 1996. In addition, the regulatory agencies have
required the Company to expand the study area beyond the designated
sulfur dioxide non-attainment area to include any predicted "areas of
concern" in the vicinity of the plant. The Company is developing a
study to address this expanded area. If it is determined that the
Martins Creek operations are causing ambient air violations, the
Company may be required to make changes to reduce sulfur dioxide
emissions. However, it is currently expected that the reductions
planned to meet the requirements of the Clean Air Act acid rain
provisions should be adequate to meet any reduction that may be
required as a result of these studies. See "Clean Air Legislation
and Other Environmental Matters" on page 37 and Note 15 to Financial
Statements.
Water
To implement the requirements established by the Federal Water
Pollution Control Act of 1972, as amended by the Clean Water Act of
1977 and the Water Quality Act of 1987, the EPA has adopted
regulations including effluent standards for steam electric stations.
The DER administers the EPA's effluent standards through state laws
and regulations relating, among other things, to effluent discharges
and water quality. The standards adopted by the EPA pursuant to the
Clean Water Act may have a significant impact on the Company's
existing facilities depending on the DER's interpretation and future
amendments to its regulations.
The EPA and DER limitations, standards and guidelines for the
discharge of pollutants from point sources into surface waters are
enforced through the issuance of National Pollutant Discharge
Elimination System (NPDES) permits. The Company has NPDES permits
necessary for the operation of its facilities.
Pursuant to the Surface Mining and Reclamation Act of 1977
(Reclamation Act), the United States Office of Surface Mining (OSM)
has adopted effluent guidelines which are applicable to Company
subsidiaries as a result of their past coal mining and continued coal
processing activities. The EPA and the OSM limitations, guidelines
and standards also are enforced through the issuance of NPDES
permits. In accordance with the provisions of the Clean Water Act
and the Reclamation Act, the EPA and the OSM have authorized the DER
to implement the NPDES program for Pennsylvania sources. Compliance
with applicable water quality standards is assured by DER review of
NPDES permit conditions. The Company's subsidiaries have received
NPDES permits for their mines and related facilities.
Solid and Hazardous Waste
The 1976 Resource Conservation and Recovery Act (RCRA) regulates
the generation, transportation, treatment, storage and disposal of
hazardous wastes. RCRA also imposes joint and several liability on
generators of solid or hazardous waste for clean-up costs. A
revision of RCRA in late 1984 lowered the threshold for the amount
of on-site hazardous waste generation requiring regulation and
incorporated underground tanks used for the storage of petroleum and
petroleum products as regulated units. Based upon the results of a
survey of its solid waste practices, the Company in the past has
filed notices with the EPA indicating that hazardous waste is
occasionally generated at all of its steam electric generating
stations and service centers. The Company has established routine
operating procedures for handling this hazardous waste. Therefore,
at this time RCRA and related DER regulations are not expected to
have a significant additional impact on the Company.
The provisions of the Comprehensive Environmental Response,
Compensation and Liability Act of 1980, as amended (Superfund),
authorize the EPA to require past and present owners of contaminated
sites and generators of any hazardous substance found at a site to
clean up the site or pay the EPA or the state for the costs of clean-
up. The generators and past owners can be liable even if the
generator contributed only a minute portion of the hazardous
substances at the site. Present owners can be liable even if they
contributed no hazardous substances to the site.
In 1981 the Company was notified by the EPA that the Company
could be liable for the cost of removing coal tar deposits discovered
at a former gas plant site owned by the Company along Brodhead Creek
in Monroe County, Pennsylvania, and on adjacent property owned by a
company unrelated to the Company. The EPA used Superfund monies to
construct a slurry wall which was paid for by the adjacent property
owner. The Company removed approximately 8,000 gallons of coal tar
from its property. To determine whether additional work needed to be
done, a Remedial Investigation and a Risk Assessment were conducted
by the Company and the adjacent property owner and submitted to the
EPA and the DER. Although the Risk Assessment showed acceptable risk
levels, the EPA and the DER required a Feasibility Study to identify
whether additional remedial action was required.
Based on the results of that Feasibility Study and other
investigations, the Company and the adjacent property owner signed a
consent decree with the EPA in November 1991. Under the terms of
that consent decree, the Company and the adjacent property owner will
remove two subsurface coal tar accumulations, monitor the site for up
to 30 years and pay all past unreimbursed and all future EPA
oversight costs. The Company's share of the costs associated with
the consent decree is estimated to be about $2 million.
In May 1992, the Company and the adjacent property owner signed
a consent order from the EPA directing that an additional Remedial
Investigation and Feasibility Study be performed to address
groundwater contamination at the site. This investigation is now
underway and could result in the EPA requiring additional site
remediation, the cost of which cannot now be determined but could be
material.
The EPA has placed the site of a former Company gas plant in
Columbia, Pennsylvania on the national Superfund list. The Company
and another potentially responsible party (PRP) had previously
conducted a detailed investigation of the site, and the Company
removed a substantial amount of coal tar from a pedestrian tunnel at
the rear of the property. However, coal tar remains in two brick
pits on the site. There also is coal tar contamination of the soil
and groundwater at the site and of river sediment adjacent to the
site. The Company is negotiating with EPA and DER on additional
investigation and remediation required at the site. The costs of
investigation and remediation of the areas of the site where the
agencies have required action are estimated at $1.2 million, all of
which has been spent or is budgeted. Further remediation of other
areas of the site may be required, the costs of which are not now
determinable but could be material.
The Company at one time also owned and operated several other
gas plants in its service area. None of these sites is presently on
the Superfund list. However, a few of them may be possible
candidates for listing at a future date. The Company expects to
continue to investigate and, if necessary, remediate these sites.
The cost of this work is not now determinable but could be material.
See "LEGAL PROCEEDINGS" on page 18 for information concerning an
EPA order and a complaint filed by the EPA in federal district court
against the Company and 35 unrelated parties for remediation of a
Superfund site in Berks County, Pennsylvania; a complaint filed by
the Company and 16 unrelated parties in federal district court
against other parties for contribution under Superfund relating to
the Novak landfill site in Lehigh County, Pennsylvania; an EPA
complaint in federal district court against the Company and 10
unrelated parties to recover all past and future EPA costs of
investigating and remediating the Heleva landfill site in Lehigh
County, Pennsylvania; and action by the EPA for reimbursement of the
EPA's past response costs and remediation at the site of a former
metal salvaging operation in Montour County, Pennsylvania.
The Company is involved in several other sites where it may be
required, along with other parties, to contribute to investigation
and remediation. Some of these sites have been listed by the EPA
under Superfund, and others may be candidates for listing at a future
date. Future investigation or remediation work at sites currently
under review, or at sites currently unknown, may result in material
additional operating costs which the Company cannot estimate at this
time. In addition, certain federal and state statutes, including
Superfund and the Pennsylvania Hazardous Sites Cleanup Act, empower
certain governmental agencies, such as the EPA and the DER, to seek
compensation from the responsible parties for the lost value of
damaged natural resources. The EPA and the DER may file such
compensation claims against the parties, including the Company, held
responsible for cleanup of such sites. Such natural resource damage
claims against the Company could result in material additional
liabilities.
The Pennsylvania Superfund law gives the DER broad authority to
identify hazardous or contaminated sites in Pennsylvania and to order
owners or responsible parties to clean up the sites. If responsible
parties cannot or will not perform the clean-up, the DER can hire
contractors to clean up the sites and then require reimbursement from
the responsible parties after the clean-up is completed. To date,
the Company's involvement in such state sites has been minimal.
Low-Level Radioactive Waste
Under federal law, each state is responsible for the disposal of
low-level radioactive waste generated in that state. States may join
in regional compacts to jointly fulfill their responsibilities. The
states of Pennsylvania, Maryland, Delaware and West Virginia are
members of the Appalachian States Low-Level Radioactive Waste
Compact. Efforts to develop a regional disposal facility in
Pennsylvania are currently underway. Low-level radioactive wastes
resulting from the operation of Susquehanna are currently stored
onsite. Any additional required storage capacity will have to be
provided by the Company. The Company cannot predict the future
availability of low-level waste disposal facilities or the cost of
such disposal.
General
In addition to the matters described above, the Company and its
subsidiaries have been cited from time to time for temporary
violations of the DER and EPA regulations with respect to air and
water quality and solid waste disposal in connection with the
operation of their facilities and may be cited for such violations in
the future. As a result, the Company and its subsidiaries may be
subject to certain penalties which are not expected to be material in
amount.
The Company is unable to predict the ultimate effect of evolving
environmental laws and regulations upon its existing and proposed
facilities and operations. In complying with statutes, regulations
and actions by regulatory bodies involving environmental matters,
including the areas of water and air quality, hazardous and solid
waste handling and disposal and toxic substances, the Company may be
required to modify, replace or cease operating certain of its
facilities. The Company may also incur material capital expenditures
and operating expenses in amounts which are not now determinable.
FRANCHISES AND LICENSES
The Company has authority to provide electric public utility
service throughout its entire service area as a result of grants by
the Commonwealth of Pennsylvania in corporate charters to the Company
and companies to which it has succeeded and as a result of
certification thereof by the PUC. The Company has been granted the
right to enter the streets and highways by the Commonwealth subject
to certain conditions. In general, such conditions have been met by
ordinance, resolution, permit, acquiescence or other action by an
appropriate local political subdivision or agency of the
Commonwealth.
The Company operates Susquehanna Unit 1 and Unit 2 pursuant to
NRC operating licenses which expire in 2022 and 2024, respectively.
The Company operates two hydroelectric projects pursuant to licenses
which were renewed by the FERC in 1980: Wallenpaupack (44,000
kilowatts capacity) and Holtwood (102,000 kilowatts capacity). The
Wallenpaupack license expires in 2004 and the Holtwood license
expires in 2014.
The Company also owns one-third of the capital stock of Safe
Harbor Water Power Corporation, which holds a project license which
extends until 2030 for the operation of its hydroelectric plant. The
total capability of the Safe Harbor plant is 417,500 kilowatts, and
the Company is entitled by contract to one-third of the total
capacity (139,000 kilowatts).
EMPLOYEE RELATIONS
As of December 31, 1994, approximately 4,428 of the Company's
6,934 full-time employees were represented by the International
Brotherhood of Electrical Workers under a three-year agreement which
expires in May 1997.
Page 17 contains a map of the Company's service territory which shows
its location, the location of each of the Company's coal-fired, oil-fired,
hydro and nuclear-fueled generating stations and the location of major
population centers.
ITEM 2. PROPERTIES
The Map on page 17 shows the location of the Company's
service area and generating stations.
Reference is made to Exhibit 99 - Schedule of Property,
Plant and Equipment for information concerning the Company's
investment in property, plant and equipment. Substantially all
electric utility plant is subject to the lien of the Company's
first mortgage. Additional information concerning capital leases
is set forth in Note 8 to Financial Statements.
For additional information concerning the properties of the
Company see Item 1, "BUSINESS - Power Supply" and "BUSINESS -
Fuel Supply".
ITEM 3. LEGAL PROCEEDINGS
Reference is made to Note 3 to Financial Statements for
information concerning rate matters.
Reference is made to Note 15 to Financial Statements for
information concerning two complaints filed against the Company
by fuel oil dealers alleging that the Company's promotion of
electric heat pumps and off-peak storage systems had violated and
continues to violate the federal antitrust laws.
In April 1991, the U.S. Department of Labor through its Mine
Safety and Health Administration (MSHA) issued citations to one
of the Company's coal-mining subsidiaries for alleged coal-dust
sample tampering at one of the subsidiary's mines. The MSHA at
the same time issued similar citations to more than 500 other
coal-mine operators. Based on a review of its dust sampling
procedures, the subsidiary is contesting all of the citations.
It is believed at this time, based on the information available,
that the MSHA allegations are without merit. Citations were also
issued against the independent operator of another subsidiary
mine, who is also contesting the citations issued with respect to
that mine. The Administrative Law Judge (Judge) assigned to the
proceedings ordered that one case be tried against a single mine
operator unrelated to the Company to determine whether the MSHA
could prove its general allegations regarding sample tampering.
In April 1994, the Judge ruled in favor of the mine operator and
vacated the 75 citations against it. The MSHA is appealing the
Judge's decision to the Mine Safety & Health Review Commission.
The other cases, including those involving the Company's
subsidiaries, have been stayed pending the outcome of the appeal.
The Company cannot predict the eventual outcome of this
matter. If violations are found, it is currently estimated that
potential administrative penalties could range from approximately
$90,000 to approximately $4.6 million.
On July 25, 1994, Mon Valley Steel Company, Inc. (Mon
Valley) filed suit in the Court of Common Pleas of Fayette
County, Pennsylvania, against the Company and two of its
subsidiaries, claiming that the Company and those subsidiaries
made fraudulent misrepresentations during negotiations for the
1992 sale to Mon Valley of Tunnelton Mining Company (Tunnelton).
Tunnelton was a coal-mining operation formerly owned by the
Company's subsidiary, Pennsylvania Mines Corporation.
Specifically, Mon Valley alleges that the Company and those
subsidiaries misrepresented Tunnelton's capability to produce
coal, as well as the amount of funding Tunnelton would receive
for mine closing costs. Mon Valley is claiming about $6 million
to cover mine closing costs, as well as punitive damages in an
unspecified amount. In July 1994, the Company and those
subsidiaries filed a legal action in the Court of Common Pleas of
Allegheny County, Pennsylvania, requesting a judicial
determination that they had not breached any of their contractual
obligations to Mon Valley. The Company cannot predict the
outcome of these proceedings.
In August 1991, the Company and 35 other unrelated parties
received an Environmental Protection Agency (EPA) order under
Section 106 of the federal Comprehensive Environmental Response
Compensation and Liability Act of 1980, as amended (Superfund),
requiring that certain remedial actions be taken at a former oil
recovery site in Berks County, Pennsylvania, which has been
included on the federal Superfund list. The Company had been
identified by the EPA as a potentially responsible party, along
with over 100 other parties. The EPA order required remediation
by the 36 named parties of four specific areas of the site.
Remedial action under this order has essentially been completed
at a cost of approximately $2 million, of which the Company's
share was approximately $50,000.
The EPA at the same time filed a complaint under Section 107
of Superfund in the United States District Court for the Eastern
District of Pennsylvania (District Court) against the Company and
the same 35 unrelated parties. The complaint asks the District
Court to hold the parties jointly and severally liable for all
past and future EPA costs of remediating some of the remaining
areas of the site. The EPA claims it has spent approximately $21
million to date. The Company and a group of the other named
parties have sued in District Court approximately 460 other
parties that have contributed waste to the site, demanding that
these companies contribute to the clean-up costs.
In July 1993, the Company and 33 of the 35 unrelated parties
received an EPA order under Section 106 of Superfund requiring
remediation of the remaining areas of the site identified by EPA.
Current estimates of remediating the remainder of the site range
from $50 million to $200 million. These costs would be shared
among the responsible parties. The Company is negotiating with
the federal government to settle both the Section 107 and Section
106 actions, for an amount which currently is not expected to be
material.
In October 1993, the Pennsylvania Department of
Environmental Resources (DER) moved to intervene in the EPA suit,
seeking to hold 16 of the originally named parties, including the
Company, liable for all past and future DER costs of remediating
the site and for any natural resource damages at the site.
According to the complaint, the DER has spent at least $800,000
to date. The Company may incur material costs for this DER
action in amounts which are not now determinable.
In December 1991, the Company and 16 unrelated parties filed
complaints against 64 other parties in District Court seeking
reimbursement under Superfund for costs the plaintiffs have
incurred and will incur to investigate and remediate the Novak
landfill site in Lehigh County, Pennsylvania. The complaints
allege that the 64 defendants generated or transported substances
disposed of at the Superfund site. A Remedial Investigation and
Feasibility Study for the site has been completed at a cost of
approximately $3 million, of which the Company's share was
approximately $300,000. EPA's selected remedy is currently
estimated to cost approximately $20 million. EPA has issued a
proposed Consent Decree to the Company and several other parties
to implement the remedy. The Company may incur material costs
for this matter in amounts which are not now determinable.
In March 1993, the EPA filed a complaint under Section 107
of Superfund in District Court against the Company and 10
unrelated parties to recover all past and future EPA costs of
investigating and remediating the Heleva landfill site in Lehigh
County, Pennsylvania. The EPA alleges it has spent approximately
$10 million to date at this site. The Company has filed an
answer to the complaint denying liability based on the absence of
evidence that the Company sent any hazardous substances to the
site. The Company expects to settle this matter for a sum which
currently is not expected to be material.
In April 1993, the Company received an order under Section
106 of Superfund requiring that actions be taken at the site of a
former metal salvaging operation in Montour County, Pennsylvania.
The EPA has taken similar action with two other potentially
responsible parties at the site. The cost of compliance with the
order is currently estimated to be approximately $37 million.
The EPA currently estimates that additional remediation work not
covered by the order will cost an additional $36 million. In
addition, the EPA has already incurred clean-up costs of
approximately $5 million to date. The EPA had indicated that it
will seek to recover these additional costs at a later date. The
Company's records indicate that scrap metal, wire and
transformers were sold to the salvage operator between 1969 and
1971. Current information indicates that the Company's
contribution to the site, if any, is de minimis.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security
holders, through the solicitation of proxies or otherwise, during
the fourth quarter of 1994.
EXECUTIVE OFFICERS OF THE REGISTRANT
Officers are elected annually by the Board of Directors to
serve at the pleasure of the Board. There are no family
relationships among any of the executive officers, or any
arrangement or understanding between any executive officer and
any other person pursuant to which the officer was selected.
There have been no events under any bankruptcy act, no
criminal proceedings and no judgments or injunctions material to
the evaluation of the ability and integrity of any executive
officer during the past five years.
Listed below are the executive officers of the Company:
Effective Date of
Election to
Name Age Position Present Position
William F. Hecht 51 Chairman, President
and Chief Executive
Officer January 1, 1993
Francis A. Long 54 Executive Vice
President and Chief
Operating Officer January 1, 1993
Robert G. Byram 49 Senior Vice President-
Nuclear March 26, 1993
Ronald E. Hill 52 Senior Vice President-
Financial January 1, 1994
Linda Curry 46 Vice President -
Bartholomew Public Affairs June 1, 1989
John R. Biggar 50 Vice President-
Finance March 1, 1984
John M. Chappelear 56 Vice President-
Investments and
Pensions June 1, 1986
Robert M. Geneczko 42 Vice President-
Electrical Systems November 1, 1994
Effective Date of
Election to
Name Age Position Present Position
Robert S. Gombos 51 Vice President-
Mobile Work Force November 1, 1994
Robert J. Grey 44 Vice President,
General Counsel and
Secretary March 6, 1995
Michael D. Hill 52 Vice President-Infor-
mation Services August 1, 1993
George T. Jones 47 Vice President-Nuclear
Engineering June 1, 1993
John P. Kierzkowski 55 Vice President and
Treasurer March 1, 1984
Joseph J. McCabe 44 Controller May 1, 1994
John R. Menichini 47 Vice President-
Customer Service November 1, 1994
Robert J. Shovlin 54 Vice President-Power
Production and
Engineering January 1, 1992
Harold G. Stanley 54 Vice President-Nuclear
Operations June 1, 1993
Raymond F. Suhocki 49 Vice President-Marketing
and Economic Develop-
ment November 1, 1994
Each of the above officers, with the exception of Mr. Grey,
Mr. Jones and Mr. McCabe, has been employed by the Company for
more than five years as of December 31, 1994. Mr. Jones joined
the Company in September 1991 and was previously employed by
Entergy Operations, Inc. The positions he held at Entergy
Operations, Inc. between January 1990 and September 1991 were
General Manager-Engineering and Director of Engineering-Arkansas
Nuclear One. Mr. McCabe joined the Company in May 1994 and was
previously employed by Deloitte & Touche LLP (Deloitte). He held
the position of partner at Deloitte between Janaury 1990 and May
1994. Mr. Grey will join the Company on March 6, 1995. Mr. Grey
has been General Counsel of Long Island Lighting Company since
1992. Prior to that time, he held the position of partner at the
law firm of Preston, Thorgrimson Shidler Gates & Ellis between
1982 and 1992.
Prior to election to the positions shown above, the
following executive officers held other positions with the
Company since January 1, 1990: Mr. Hecht was Senior Vice
President-System Power and Engineering, Executive Vice President-
Operations and President and Chief Operating Officer; Mr. Long
was Vice President-Power Supply and Senior Vice President -
System Power & Engineering; Mr. Byram was Vice President-Nuclear
Operations and Senior Vice President - System Power &
Engineering; Mr. R. E. Hill was Vice President and Comptroller;
Ms. Bartholomew was Senior Director and Economist-Public Affairs;
Mr. Geneczko was Manager-System Planning and Vice President-
Division; Mr. Gombos was Vice President-Human Resource and
Development; Mr. M. D. Hill was Manager-Bulk Power Engineering
and Manager-System Operating; Mr. Jones was Manager-Nuclear Plant
Engineering and Manager-Nuclear Engineering; Mr. Menichini was
Vice President-Division; Mr. Shovlin was Director-Power
Production and Engineering; Mr. Stanley was Superintendent of
Plant-Susquehanna Steam Electric Station and Mr. Suhocki was
Manager-Marketing & Economic Development, Vice President-Division
and Vice President-System Power.
1
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S
COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
Additional information for this item is set forth in the
section entitled "Shareowner and Investor Information" on pages
87 through 89 of this report, and the number of common
shareowners is set forth in the section entitled "Selected
Financial and Operating Data" on page 85.
ITEM 6. SELECTED FINANCIAL DATA
Information for this item is set forth in the section
entitled "Selected Financial and Operating Data" on pages 85 and
86 of this report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
Information for this item is set forth in the section
entitled "Review of the Company's Financial Condition and Results
of Operations" on pages 28 through 45 of this report.
ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA
Financial statements and supplementary data are set forth on
the pages indicated below.
Page
Independent Auditors' Report 47
Management's Report on Responsibility for Financial
Statements 48
Financial Statements:
Consolidated Statement of Income for the Three Years
Ended December 31, 1994 49
Consolidated Statement of Cash Flows for the Three
Years Ended December 31, 1994 50
Consolidated Balance Sheet at December 31, 1994 and
1993 51
Consolidated Statement of Shareowners' Common Equity
for the Three Years Ended December 31, 1994 53
Consolidated Statement of Preferred and Preference
Stock at December 31, 1994 and 1993 53
Consolidated Statement of Long-Term Debt at
December 31, 1994 and 1993 55
Notes to Financial Statements 56
Quarterly Financial, Common Stock Price and Dividend Data 90
Supplemental Financial Statement Schedule:
II - Valuation and Qualifying Accounts and
Reserves for the Three Years Ended
December 31, 1994 91
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
Based upon a recommendation of its Audit Committee, the
Company's Board of Directors decided on January 25, 1995 that
Deloitte & Touche LLP (Deloitte) would not be retained as the
Company's independent auditors for 1995. On February 22, 1995,
the Company's Board of Directors, based upon a recommendation of
it's Audit Committee, appointed Price Waterhouse LLP as the
Company's new independent auditors.
The auditors' reports of Deloitte on the Company's financial
statements for each of the two most recent fiscal years reported
upon, ending December 31, 1994, did not contain any adverse
opinion or disclaimer of opinion, nor were the reports modified
or qualified in any manner.
During the period of such two fiscal years and the period
from December 31, 1994 through January 25, 1995, there were no
disagreements with Deloitte on any matter of accounting
principles or practices, financial statement disclosure or
auditing scope or procedure. During such periods, there were no
"reportable events" as that term is defined in Item 304(a)(1)(v)
of Regulation S-K.
Deloitte provided a letter to the Company regarding this
matter, dated February 1, 1995, indicating that they agreed with
the statements in the two preceding paragraphs.
(THIS PAGE LEFT BLANK INTENTIONALLY.)
REVIEW OF THE COMPANY'S FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Results of Operations
Earnings
Earnings per share of common stock were $1.41 in 1994, $2.07 in 1993
and $2.02 in 1992.
Earnings for 1994 were adversely affected by several one-time charges,
including two major charges, during the fourth quarter. One amounted to
$75.9 million, or 28 cents per share of common stock, resulting from costs
associated with a voluntary early retirement program, and the other
amounted to $73.7 million, or 26 cents per share, from a write down in the
carrying value of a subsidiary's investment in undeveloped coal reserves.
In addition, two nonrecurring charges recorded earlier in the year
reflected the disallowance by the Pennsylvania Public Utility Commission
(PUC) of recovery of replacement power costs, incurred during an extended
outage at the Susquehanna station, through the Energy Cost Rate (ECR)
amounting to $15.7 million, or 6 cents per share of common stock, and a
decision of the Commonwealth Court of Pennsylvania which reversed a PUC
order that permitted deferral of the cost of postretirement benefits other
than pensions. The Company charged the deferred postretirement benefit
costs applicable to 1993 against income which amounted to $10.8 million or
4 cents per share. These matters are discussed in more detail in this
review.
Although the nonrecurring charges depressed earnings in 1994,
underlying sales performance was strong, with a 4.1% increase in sales to
ultimate customers, due to improving economic conditions and colder-than-
normal weather in the winter months. Other positive effects on earnings
included the Company's continued efforts to control operating and
maintenance costs, and refinancing higher cost securities to take advantage
of favorable market conditions.
In 1993 increasing economic activity and the effects of hotter-than-
normal weather in the summer were the primary causes for the earnings
improvement over 1992. Earnings in 1993 also benefited from the Company's
efforts to control costs and refinance higher cost securities. In 1993 the
Company recorded charges against income that, in the aggregate, adversely
affected earnings by about $31.5 million, or 12 cents per share, related
to: (i) a settlement agreement with complainants against the Company's
1990-91 through 1993-94 ECRs; (ii) the write off of certain deferred
retiree benefit costs; and (iii) the adoption of Statement of Financial
Accounting Standards (SFAS) 112, "Employers' Accounting for Postemployment
Benefits."
Electric Energy Sales
System, or service area, sales were 32.3 billion kwh in 1994, an
increase of about 1.3 billion kwh, or 4.1%, over 1993. The extreme cold
weather in the first quarter of 1994 and the continued increase in economic
activity in Central Eastern Pennsylvania were the primary reasons for the
increases in system sales. Sales in all major customer categories were
higher in 1994 than in 1993. The higher system sales in 1994 followed an
increase in 1993 system sales over 1992 of about 1.3 billion kwh that was
due to increased economic activity in the service area and the effect of
hotter summer weather resulting in higher air conditioner use. The Company
estimates that if normal weather had been experienced in both years, system
sales for 1994 would have increased by 1.1 billion kwh, or 3.5%, over 1993.
Actual sales to residential and commercial customers in 1994 increased
402 million kwh, or 3.6%, and 342 million kwh, or 3.6%, respectively, over
1993. The Company estimates that under normal weather conditions for both
years, sales to residential and commercial customers in 1994 would have
increased 243 million kwh, or 2.2%, and 327 million kwh, or 3.5%,
respectively, over 1993.
Industrial sales, which are not affected by weather conditions,
increased 437 million kwh in 1994, or 4.8%, over 1993. Industrial sales
are an important indicator of the economic health of the Company's service
area.
System sales in 1995 are currently forecasted to be approximately 32.5
billion kwh, an increase of 136 million kwh, or 0.4%, over 1994 system
sales, and a 419 million kwh, or 1.3%, increase over 1994 weather-
normalized sales.
Total electric energy sales, which include contractual sales to other
major utilities and energy sales to Pennsylvania-New Jersey-Maryland
Interconnection Association (PJM) utilities, were essentially unchanged
during the 1992-1994 period.
Contractual sales to other major utilities include: (i) energy sold
to Atlantic City Electric Company (Atlantic), Baltimore Gas & Electric
Company (BG&E) and Jersey Central Power & Light Company (JCP&L) pursuant to
long-term contracts under which these utilities purchase a specified
percentage of the capacity and related energy from Company-owned generating
units; and (ii) energy sold on a short-term basis to other electric
utilities. Contractual sales to other major utilities were 6.3 billion kwh
in 1994, or 11.7% lower than 1993, as a result of reduced output from the
Company's coal-fired generating units. Contractual sales to other major
utilities in 1993 were about 7.1 billion kwh, or 2.5% lower than 1992.
Sales to JCP&L will continue at the current level through 1995 and
then begin to phase out in equal annual amounts during the remaining term
of the agreement which ends in December 1999. Sales to Atlantic and BG&E
continue through September 2000 and May 2001, respectively. In its pending
rate case (see "Rate Matters"), the Company has proposed that the costs
associated with the returning capacity be recovered through the ECR. If
the PUC denies this request, the Company expects that any sales of the
returning capacity and related energy under bulk power marketing conditions
would be at prices less than those reflected in the existing agreements.
PJM energy sales were about 3.2 billion kwh in 1994, or 23.7% lower than
1993. In 1993 PJM energy sales were about 4.1 billion kwh, or 19.7% lower
than 1992. The decreases in both years were primarily due to increased
system sales and a decrease in the output of the Company's generating
units. In 1994 the decrease in output was primarily due to lower
availability of the coal-fired units. The decrease of output in 1993
resulted from an increase in the availability of nuclear generating
capacity of the other PJM utilities.
Capacity-Related and Transmission
Entitlement Transactions
The Company's strong generating capacity position has enabled it to
enter into a number of transactions with other electric utilities. These
transactions include: (i) the sale of capacity credits but no energy to
other utilities in the PJM to enable them to satisfy their PJM contractual
capacity obligations; (ii) agreements with both PJM and non-PJM utilities
for the reservation of output during certain periods from the Company's
generating units, with the option to purchase energy from those units; and
(iii) arrangements whereby other PJM utilities can purchase the Company's
entitlements to use the PJM transmission system to import energy from
utilities outside the PJM.
Revenues from the sale of capacity credits, the reservation of output
from generating units and the sale of transmission entitlements, net of
foregone PJM interchange savings which are included in the Company's ECR,
totaled $28.7 million in 1994, $35.0 million in 1993 and $35.0 million in
1992. The 1994 revenues exclude approximately $8.4 million of receipts
from installed capacity credit sales which were credited to customers
through the ECR. The Company currently expects about $14.6 million of
revenues from these transactions during 1995, exclusive of credits to be
applied to the ECR.
The Company is continuing to look for opportunities to derive
additional revenues from these transactions due to its strong generating
capacity position. However, increased competition in capacity credit
transactions has reduced the Company's share of this market and the unit
price received for such sales. The amount of revenues from these
transactions depends on many factors, and the Company cannot predict the
amount of revenues it will ultimately realize from these transactions.
In October 1994, the PUC approved a settlement agreement resolving all
complaints against the 1990-91 ECR through 1993-94 ECR including issues
related to capacity-related transactions. The agreement provides, among
other things, for crediting the 1994-95 ECR with a portion of the receipts
from capacity credit sales. See "Rate Matters" below for additional
information.
Rate Matters
Base Rate Filing with the PUC
In December 1994, the Company filed a request with the PUC for a $261
million increase in electric base rates, an 11.7% increase in PUC-
jurisdictional rates. The PUC has decided to hold hearings and conduct an
investigation of the request. A final rate decision is expected in late
September 1995. A detailed discussion of the rate filing is presented in
Financial Note 3.
Energy Cost Rate Issues
In April 1994, the PUC reduced the Company's 1994-95 ECR claim by
approximately $15.7 million to reflect costs associated with replacement
power during a portion of the time that Unit 1 of the Company's Susquehanna
station was out of service for refueling and repairs. As a result of the
PUC's action, the Company recorded a charge against income in the first
quarter of 1994 for the $15.7 million of unrecovered replacement power
costs. This charge adversely affected net income by about $9.0 million or
6 cents per share of common stock.
The Company filed a complaint with the PUC objecting to the decision
to exclude these replacement power costs from the 1994-95 ECR and
subsequently entered into a settlement agreement with the complainants and
the Office of Trial Staff on this matter.
The PUC approved the settlement agreement on February 24, 1995. As a
result of the PUC Order, the Company, in the first quarter of 1995, will
record a credit to income of $9.7 million which would increase net income
by about $5.5 million or 4 cents per share of common stock.
In October 1994, the PUC issued an order approving a settlement
agreement the Company reached in January 1994 with the Office of Consumer
Advocate (OCA) and certain industrial customers concerning the 1990-91 ECR
through the 1993-94 ECR. The PUC order resolved all complaints against
those ECRs, and required the Company to credit the 1994-95 ECR with a one-
time adjustment for a portion of the receipts from installed capacity
credit sales made from April 1990 through December 31, 1993 and also
provided that about one-third of the receipts from installed capacity
credit sales made after December 31, 1993 will be credited through future
ECRs. These capacity credit sales are discussed in Financial Notes 3 and
4. The PUC order also provided that a portion of the PUC-jurisdictional
amount of deferred retired miners' health care benefits costs, which the
Company sought to recover through the ECR, will not be recoverable. As a
result of this order, in the fourth quarter of 1993 the Company recorded a
charge to expense of $17.1 million, which reduced 1993 net income by
approximately $9.7 million or 6 cents per share of common stock.
Postretirement Benefits Other Than Pensions
In March 1993, the PUC approved the Company's petition to defer the
increase in retiree benefits costs arising from adoption of SFAS 106,
"Employers' Accounting for Postretirement Benefits Other Than Pensions."
Under the PUC order, the increased costs applicable to PUC-jurisdictional
customers would have been deferred from January 1, 1993 until such costs
were included in customer rates in the Company's next retail base rate
proceeding. Accounting rules permit deferral of the costs for about five
years.
In May 1994, in response to an appeal by the OCA, the Commonwealth
Court of Pennsylvania reversed the PUC order and held that the Company
could not defer these costs.
As a result of the Court's decision, the Company began expensing the
increased costs applicable to operations that would have otherwise been
deferred and wrote off the costs that had been deferred from January 1,
1993. The charge to expense for 1994 amounted to $22.9 million, which
included $10.8 million applicable to 1993. The Company is charging expense
on a current basis for retiree benefits costs.
In June 1994, the PUC and the Company requested the Pennsylvania
Supreme Court to hear an appeal of the Commonwealth Court decision.
FERC-Jurisdictional Rates
The Company has entered into five year sales contracts with certain
small utilities the Company currently serves, which reduced rates to these
small utilities by about $3.3 million in 1994 and will reduce rates by
about an additional $4.1 million in 1996. In connection with these
agreements, in the fourth quarter of 1993 the Company wrote off the
deferred portions of retired miners' health care benefits costs and
postretirement benefits other than pensions applicable to FERC-
jurisdictional customers. The charge to expense amounted to $8.9 million,
which reduced 1993 net income by $5.1 million or 3 cents per share of
common stock.
Operating Revenues
Total operating revenues in 1994 decreased $1.9 million, or 0.1%, from
1993. Revenues from energy sales to ultimate customers in 1994 increased
$44.7 million over 1993 due to higher customer usage and recoverable fuel
and energy costs. These increases were principally offset by: (i) lower
sales to other major utilities, $13.3 million; (ii) lower sales on the PJM,
$21.1 million; and (iii) unrecovered replacement power costs, $15.7 million
as discussed in "Rate Matters." Operating revenues for 1993 decreased
$17.1 million, or 0.6%, from 1992. Changes in 1993 operating revenues from
1992 principally included: (i) revenues from sales to ultimate customers
increased $18.4 million; (ii) sales to other major utilities decreased
$16.4 million; and (iii) PJM sales decreased $14.8 million.
Tariffs subject to PUC-jurisdiction accounted for approximately 83% of
the Company's revenues from energy sales in 1994. The remaining 17% of
such revenues resulted from sales regulated by the FERC and include the
Company's PJM energy sales.
Billings to customers under PUC jurisdiction include: (i) base rate
charges; (ii) the ECR which is a supplemental charge or credit for fuel and
other energy costs over or under the levels included in base rates; (iii) a
State Tax Adjustment Surcharge (STAS) which adjusts retail customers' bills
for the effects of changes in state tax rates; and (iv) a Special Base Rate
Credit Adjustment (SBRCA) that flows through to customers the effects of
certain nonrecurring items.
Billings to utilities are subject to FERC jurisdiction. In the case
of certain small utilities, billings include base rate charges and a
supplemental charge or credit for fuel costs over or under the levels
included in base rates. The FERC also regulates contractual sales to other
major utilities, PJM energy sales and capacity-related and transmission
entitlement transactions. Sales to Atlantic, BG&E and JCP&L are made at a
price covering the Company's cost of service, including a return on
investment.
Energy sales relating to the reservation of output from the Company's
generating units are generally made at a price equal to the cost of fuel
plus an amount to reflect foregone interchange savings. PJM energy sales
are made at a price equal to the midpoint between the sellers' actual costs
and costs that the buyers would have incurred to produce the energy.
Capacity-related and transmission entitlement transactions are made at
prices negotiated by the Company and the purchaser, subject to a price cap
accepted by the FERC.
Fuel Expense
Fuel expense for 1994 and 1993 decreased by $33.3 million and $49.5
million, respectively, from the prior year. These decreases excluded the
write off of $11 million of deferred retired miners' health care benefits
in 1993 and a related credit to expense of $3.6 million in 1994. The
decrease in 1994 was primarily due to lower availability of coal-fired
generation which resulted in reduced sales to PJM and other major
utilities. Lower fuel costs for off-system sales were partially offset by
higher cost oil-fired generation for base load during the first quarter of
1994. The decrease in 1993 was primarily due to lower unit fuel costs for
coal-fired generation, partially offset by higher oil-fired generation.
For 1993, the cost of coal delivered to the Company's generating stations
declined to $36.23 per ton from $41.44 per ton for 1992.
Spent Nuclear Fuel
The U.S. Department of Energy (DOE) is responsible for the permanent
storage and disposal of spent nuclear fuel removed from nuclear reactors.
The Company currently pays DOE a fee for future disposal services and
recovers such costs in customer rates.
Delays in opening a federal permanent storage facility will require
the Company to provide interim storage for spent fuel at the Susquehanna
station beginning in 1997 until at least 2010.
Power Purchases
In 1994, power purchases were $287.3 million, an increase of $8.5
million over 1993. Power purchases were $278.8 million in 1993, an
increase of $3.3 million over 1992. The increases were due to greater
quantities of power purchased from PJM and other utilities, partially
offset by lower power purchases from non-utility generators.
Other Operation, Maintenance and Depreciation
The increase in other operation expenses in 1994 compared to 1993 is
primarily the result of the Commonwealth Court of Pennsylvania decision
reversing the PUC order regarding the deferral of postretirement benefits
costs other than pensions. See "Rate Matters" for further discussion.
In 1993 the Company wrote off $9.1 million of obsolete and excess
materials and supplies at its fossil-fueled steam generating stations. Of
this amount, $2.2 million was charged to other operation expense and $6.9
million was charged to maintenance expense.
The amortization of the deferred income effect of adopting the
inventory method of accounting for power plant spare parts is credited to
maintenance expense on the Consolidated Statement of Income. This
amortization amounted to $24.7 million in 1994, $24.3 million in 1993, and
$23.5 million in 1992. Excluding the credits associated with power plant
spare parts and the 1993 accrual for the recognition of obsolete and excess
materials and supplies, maintenance expense decreased by $5.9 million, or
2.8% in 1994 compared to 1993. A similar comparison of 1993 to 1992
indicated a $14.1 million, or 6.3%, decrease. The reduction in maintenance
expense resulted primarily from lower costs associated with maintaining the
Company's generating stations.
Higher depreciation expense reflects the annual increase associated
with the method of depreciating the Susquehanna station and the
depreciation of new property, plant and equipment placed in service. As
approved by the PUC and the FERC, depreciation expense for the Susquehanna
station will increase annually through the year 1998. In 1993 and 1994,
the amount of depreciation expense applicable to the Susquehanna station
exceeded the amount that would have been recorded using the straight-line
method, resulting in an amortization of previously deferred depreciation.
Beginning in 1999, depreciation is scheduled to change to the straight-line
method at a level substantially less than the amount expected to be
recorded in 1998. The amount of depreciation applicable to that portion of
the Susquehanna station subject to an annual increase in the amount of
depreciation was $128 million in 1994 and $116 million in 1993, and will
increase annually to $192 million in 1998 and then decline to $102 million
in 1999. Proposed changes to the Company's current depreciation methods
were included in the December 1994 base rate filing with the PUC. See
Financial Note 3.
For a discussion of the Company's efforts to continue to reduce costs,
see "Increasing Competition" on page 42.
Taxes
In June 1994, Pennsylvania enacted legislation that decreased the
Company's state corporate net income tax rate from 12.25% to 11.99%
retroactive to January 1, 1994 with further reductions to 10.99%, 10.75%
and 9.99% in 1995, 1996 and 1997, respectively. This resulted in a
decrease of $0.8 million in income tax expense for 1994. Substantially all
of this amount was reflected in lower customer rates through the STAS
beginning in July 1994.
In August 1993, the Omnibus Budget Reconciliation Act of 1993 was
enacted, which contained a provision that increased the Company's federal
income tax rate from 34% to 35% retroactive to January 1, 1993. This
higher tax rate increased the Company's federal income tax expense for 1993
by $5.9 million.
Financing Costs
The Company continued in 1994 to take advantage of opportunities to
reduce its financing costs by retiring long-term debt and preferred stock
with the proceeds from the sales of securities at a lower cost. Interest
on long-term debt and dividends on preferred and preference stock decreased
by $34 million from $277 million in 1991 to $243 million in 1994.
Financial Condition
Capital Expenditure Requirements
The schedule below shows the Company's actual capital expenditures for
electric utility operations for the years 1992-1994 and current projections
for the years 1995-1997. Construction expenditures during the years 1992-
1994 totaled about $1.3 billion and are expected to be at the same level
during the years 1995-1997.
Capital Expenditure Requirements (a)
------Actual------ ----Projected----
1992 1993 1994 1995 1996 1997
(Millions of Dollars)
Construction expenditures
Generating facilities $136 $142 $152 $111 $107 $ 99
Transmission and
distribution facilities 186 173 170 166 159 165
Environmental 13 65 94 40 52 156
Other 52 51 58 70 83 58
387 431 474 387 401 478
Nuclear fuel owned and
leased 42 64 35 54 79 49
Other leased property 20 20 25 39 31 22
Total $449 $515 $534 $480 $511 $549
(a) Capital expenditure plans are revised from time to time to
reflect changes in conditions. Actual expenditures may vary
from those projected because of changes in plans, cost
fluctuations, environmental regulations and other factors.
Construction expenditures include Allowance for Funds Used
During Construction (AFUDC) which is expected to be less
than $25 million in each of the years 1995-1997.
Financing and Liquidity
Net cash provided by operating activities in 1994 decreased by $58.7
million primarily due to lower earnings, increases in income tax payments,
higher fuel inventories and a reduction in accounts payable. Cash provided
by operating activities in 1993 and 1992 were essentially unchanged.
Net cash used in investing activities was $78.7 million higher in 1994
than 1993 and $25.6 million higher in 1993 than in 1992. The increase in
1994 was due to higher construction expenditures and an increase in
financial investments by a subsidiary of the Company. The increase in
investing activities in 1993 was due to higher construction expenditures.
For the years 1992-1994, the Company issued $2.16 billion of long-term
debt, $380 million of preferred stock and about $83 million of common
stock. Proceeds from security sales were used to retire about $1.8 billion
of long-term debt and about $500 million of preferred and preference stock
to lower the Company's financing costs, to reduce short-term debt and to
finance construction expenditures. During the years 1992-1994, the Company
also incurred $211 million of obligations under capital leases (primarily
nuclear fuel). In 1994, the Company sold $919 million principal amount of
first mortgage bonds and $80 million of preferred stock and issued $70
million of common stock of which $63 million was issued through its
Dividend Reinvestment Plan (DRIP) and the remaining $7 million issued to
the Employee Stock Ownership Plan. During the year, the Company retired
$637 million of long-term debt, $120 million of preferred stock and
decreased its short-term debt by $128 million.
After the payment of dividends, internally generated funds during the
years 1995-1997 are expected to provide approximately 70-85% of the
Company's construction expenditures which are expected to be $1.3 billion.
Sales of securities will be undertaken during the 1995-1997 period as
needed to meet the Company's capital requirements, to meet a total of $211
million of long-term debt maturities and to provide funds for the early
retirement of high cost securities if such retirements are determined to be
appropriate in the light of market conditions and other factors. The
Company expects to issue $180 million of common stock in 1995 through its
DRIP and a public sale of common stock. In addition, the Company expects
to arrange for the refinancing of $55 million of higher cost tax-exempt
securities issued to provide pollution control and solid waste disposal
facilities at the Company's generating stations.
The Company's ability to issue securities during the 1995-1997 period
is not expected to be limited by earnings or other issuance tests. To
enhance financing flexibility, a $250 million revolving credit arrangement
is maintained with a group of banks and is used principally as a back-up
for the Company's commercial paper and $45 million in credit arrangements
are maintained with a group of banks to provide back-up for the Company's
commercial paper and short-term borrowings of certain subsidiaries. No
borrowings were outstanding at December 31, 1994 under these arrangements.
Allowance for Funds Used During Construction
The AFUDC, a non-cash credit to income, accounted for about 6.1% of
earnings in 1994. The amount of AFUDC recorded will depend on the timing
and level of construction work in progress as well as the rate treatment
afforded the capital expenditures required to comply with the clean air
legislation. Under current Pennsylvania law, construction work in progress
for certain non-revenue producing assets, such as capital expenditures for
pollution control equipment, can be claimed in rate base.
Financial Indicators
Due to one-time charges to income in 1994, several financial
indicators decreased from 1993. The Company earned an 8.73% return on
average common equity during 1994, down from the 13.06% earned in 1993.
The ratio of the Company's pre-tax income to interest charges decreased
from 3.3 in 1993 to 2.7 in 1994. Excluding these one-time charges, the
return on average common equity and the ratio of pre-tax income to interest
charges in 1994 would have been 12.53% and 3.1, respectively. See
"Earnings" on page 28. The Company increased common stock dividends from
an annual per share rate of $1.65 in 1993 to $1.67 in 1994. The book value
per share of common stock decreased 1.0% from $15.95 at the end of 1993 to
$15.79 at the end of 1994. The ratio of the market price to book value of
common stock was 120% at the end of 1994 compared with 169% at the end of
1993.
Clean Air Legislation and Other Environmental Matters
The Federal Clean Air Act Amendments of 1990 deal, in part, with acid
rain under Title IV, attainment of federal ambient ozone standards under
Title I, and toxic air emissions under Title III. The acid rain provisions
specify Phase I sulfur dioxide emission limits for about 55% of the
Company's coal-fired generating capacity by January 1995, and more
stringent Phase II sulfur dioxide emission limits for all of the Company's
fossil-fueled generating units by January 2000.
The Company's capital costs of compliance with the Phase I
requirements under Title IV are included in the table of "Capital
Expenditure Requirements" on page 35. The Company may also incur operating
expenses not reflected therein, and may choose to limit the generation of
certain units and to bank or trade emission allowances among its generating
units or with other utilities, to the extent permitted by the legislation.
To meet the Phase II acid rain sulfur dioxide emission standards, the
Company may install flue gas desulfurization equipment (FGD) on up to 60%
of its coal-fired generating capacity, purchase lower sulfur coal, and bank
or trade emission allowances among its generating units or with other
utilities to the extent permitted by the legislation. The exact mix of
lower sulfur fuel, emission allowance purchases, sales or trades, and the
amount and timing of FGD will be based on FGD installation costs, fuel cost
and availability and emission allowance prices.
The ambient ozone attainment provisions contained in Title I of the
legislation require all major stationary sources within the Northeast Ozone
Transport Region (which includes all of Pennsylvania) to install reasonably
available control technology (RACT) for nitrogen oxides emissions by May
1995. The Company has complied with this requirement. The associated
capital costs are included in the table of "Capital Expenditure
Requirements" on page 35.
Further ozone reductions may be required as a result of modeling of
nitrogen oxides and volatile organic compounds emissions in the Northeast
Ozone Transport Region. A two-phase nitrogen oxides reduction from pre-
Clean Air Act levels has been proposed for the area where the Company's
plants are located -- a 55% reduction by May 1999 and a 75% reduction by
2003 -- unless scientific studies to be completed by 1997 indicate a
different reduction. The reductions would be required during a five-month
ozone season from May through September.
In addition to acid rain and ambient ozone attainment provisions, the
legislation requires the Environmental Protection Agency (EPA) to conduct a
study of hazardous air emissions from power plants. EPA is also studying
the health effects of fine particulates which are emitted from power plants
and other sources. Adverse findings from either study could cause the EPA
to mandate additional ultra high efficiency particulate removal baghouses
or specialized flue gas scrubbing to remove certain vaporous trace metals
and certain gaseous emissions.
In addition to the "Capital Expenditure Requirements" shown on page
35, the Company currently estimates that additional capital expenditures
and operating costs for environmental compliance will be incurred beyond
1997. Capital expenditures that may be required and the additional revenue
required to recover these costs, based on 1994 revenues, are as follows:
Capital Cost Revenue
($ millions) Requirement
Phase II acid rain
1998-2005 $300-500 3.0%
Nitrogen oxides and
ambient ozone by:
1999 80 0.5%
2003 150 1.3%
Hazardous air emissions by 2000 310 1.8%
Collectively, these costs represent a potential capital exposure of up
to $1.0 billion beyond 1997, as well as additional operating costs in
amounts which are not now determinable but could be material.
The Pennsylvania Air Pollution Control Act implements the Federal
Clean Air Act Amendments of 1990. The state legislation essentially
requires that new state air emission standards be no more stringent than
federal standards. This legislation has no effect on the Company's plans
for compliance with the Federal Clean Air Act Amendments of 1990.
The PUC's policy regarding the trading and usage of, and the
ratemaking treatment for, emission allowances by Pennsylvania electric
utilities provides, among other things, that the PUC will not require
approval of specific transactions and the cost of allowances will be
recognized as energy-related power production expenses and recoverable
through the ECR.
The Pennsylvania Department of Environmental Resources (DER)
regulations governing the handling and disposal of industrial (or residual)
solid waste require the Company to submit detailed information on waste
generation, minimization and disposal practices. They also require the
Company to upgrade and repermit existing ash basins at all of its coal-
fired generating stations by applying updated standards for waste disposal.
Ash basins that cannot be repermitted are required to close by July 1997.
Any groundwater contamination caused by the basins must also be addressed.
Any new ash disposal facility must meet the rigid site and design standards
set forth in the regulations. In addition, the siting of future facilities
at Company facilities could be affected.
To address the DER regulations, the Company plans to install dry fly
ash handling systems at the Brunner Island, Sunbury and Holtwood stations.
The Company, with siting assistance from a public advisory group, has
chosen mine sites at which to use the dry fly ash from the Sunbury and
Holtwood stations for reclamation. In addition, the Company is exploring
opportunities to beneficially use coal ash from Brunner Island in various
roadway construction projects in the vicinity of the plant that may delay
or preclude the need for a new disposal facility.
Groundwater degradation related to fuel oil leakage from underground
facilities and seepage from coal refuse disposal areas and coal storage
piles has been identified at several Company generating stations. Many
requirements of the DER regulations address these groundwater degradation
issues. The Company has reviewed its remedial action plans with the DER.
Remedial work is substantially completed at one generating station, and
remedial work may be required at others.
The DER regulations to implement the toxic control provisions of the
Federal Water Quality Act of 1987 and to advance Pennsylvania's toxic
control program authorize the DER to use both biomonitoring and a water
quality based chemical-specific approach in the National Pollutant
Discharge Elimination System (NPDES) permits to control toxics. In 1993,
the Company received new NPDES permits for the Montour and Holtwood
stations. The Montour permit contains very stringent limits for certain
toxic metals and increased monitoring requirements. More toxic reduction
studies will be conducted at Montour before the permit limits become
effective. Additional water treatment facilities may be needed at Montour,
depending on the results of the studies.
At Holtwood, toxics are required to be monitored at the fly ash basin
until its closure in 1997. No limits have been set at this time. The
Company will therefore comply with an implementation schedule for such
closure and for construction of a new dry fly ash handling system at
Holtwood. The closure of the Holtwood fly ash basin will require changes
to the facility's existing waste water treatment system. Improvements and
upgrades are being planned for the Sunbury and Brunner Island waste water
treatment systems to meet the anticipated permit requirements.
Capital expenditures through 1997, to comply with the residual waste
regulations, correct groundwater degradation at fossil-fueled generating
stations and address waste water control at Company facilities, are
included in the "Capital Expenditure Requirements" on page 35. The Company
currently estimates that about $77 million of additional capital
expenditures could be required beyond 1997. Actions taken to correct
groundwater degradation, to comply with the DER's regulations and to
address waste water control are also expected to result in increased
operating costs in amounts which are not now determinable but could be
material.
The Company has been discussing with the DER the issue of potential
polychlorinated biphenyl (PCB) contamination at certain of the Company's
substations and pole sites. In addition, the Company at one time owned and
operated a number of coal gas manufacturing facilities, all of which were
later sold. During their operation, these gas plants produced waste
byproducts, some amount of which may still remain at the plant sites.
Also, oil and/or other contamination may exist at some of the Company's
former generating facilities. As a current or past owner/operator of these
sites, the Company may be liable under the Federal Comprehensive
Environmental Response, Compensation and Liability Act of 1980, as amended
(Superfund), or other laws for the costs associated with addressing any
hazardous substances at these sites.
In early 1995 the Company expects to finalize a negotiated Consent
Order with the DER to address a number of these sites where remediation may
be necessary or desirable. The sites will be prioritized based upon a
number of factors, including any human health or environmental risk posed
by the site, the public's interest in the site, and the Company's plans for
the site. Under the Consent Order, the Company will not be required by DER
to spend more than $5 million per year on investigation and remediation at
those sites covered by the Consent Order.
At December 31, 1994, the Company had accrued $8.3 million,
representing the amount the Company can reasonably estimate it will have to
spend to remediate sites involving the removal of hazardous or toxic
substances including those covered by the Consent Order mentioned above.
The Company is involved in several other sites where it may be required,
along with other parties, to contribute to such remediation. Some of these
sites have been listed by the EPA under Superfund, and others may be
candidates for listing at a future date. Future cleanup or remediation
work at sites currently under review, or at sites currently unknown, may
result in material additional operating costs which the Company cannot
estimate at this time. In addition, certain federal and state statutes,
including Superfund and the Pennsylvania Hazardous Sites Cleanup Act,
empower certain governmental agencies, such as the EPA and the DER, to seek
compensation from the responsible parties for the lost value of damaged
natural resources. The EPA and the DER may file such compensation claims
against the parties, including the Company, held responsible for cleanup of
such sites. Such natural resource damage claims against the Company could
result in material additional liabilities.
Concerns have been expressed by some members of the scientific
community and others regarding the potential health effects of electric and
magnetic fields (EMF). These fields are emitted by all devices carrying
electricity, including electric transmission and distribution lines and
substation equipment. Federal, state and local officials are focusing
increased attention on this issue. The Company is actively participating
in the current research effort to determine whether or not EMF causes any
human health problems and is taking steps to reduce EMF, where practical,
in the design of new transmission and distribution facilities. The Company
is unable to predict what effect the EMF issue might have on Company
operations and facilities.
In complying with statutes, regulations and actions by regulatory
bodies involving environmental matters, including the areas of water and
air quality, hazardous and solid waste handling and disposal and toxic
substances, the Company may be required to modify, replace or cease
operating certain of its facilities. The Company may also incur material
capital expenditures and operating expenses in amounts which are not now
determinable.
Uranium Enrichment Decontamination and Decommissioning Fund
The Energy Policy Act of 1992 (Energy Act) established the Uranium
Enrichment Decontamination and Decommissioning Fund (Fund) and provides for
an assessment on domestic utilities with nuclear power operations,
including the Company. Assessments are based on the amount of uranium a
utility had processed for enrichment prior to enactment of the Energy Act
and are expected to be paid to the Fund by such utilities over a 15-year
period. Amounts paid to the Fund are to be used for the ultimate
decontamination and decommissioning of the Department of Energy's uranium
enrichment facilities. The Energy Act states that the assessment shall be
deemed a necessary and reasonable current cost of fuel and shall be fully
recoverable in rates in all jurisdictions in the same manner as the
utility's other fuel costs.
As of December 31, 1994, the Company's recorded liability for its
total assessment amounted to about $31.5 million. The liability is subject
to adjustment for inflation. The corresponding charge to expense was
deferred because the Company includes its annual payments to the Fund in
the ECR which is in the Company's PUC tariffs and in the fuel adjustment
clause which is in the Company's FERC tariffs. As a result, the assessment
does not affect net income.
Postretirement Benefits Other Than Pensions
and Postemployment Benefits
In January 1993, the Company adopted SFAS 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions." SFAS 106 establishes new
rules for accounting for the costs of postretirement benefits other than
pensions. The statement requires accrual, during the years that the
employees render the necessary service, of the expected cost of providing
those benefits. Caps have been established on the amount the Company will
pay for retiree health care costs for all employees who retire after March
1993. See "Rate Matters" on page 13 for additional information on
postretirement benefit issues.
The Company provides health and life insurance benefits to disabled
employees and income benefits to eligible spouses of deceased employees.
In December 1993, the Company adopted SFAS 112, "Employers' Accounting for
Postemployment Benefits," which requires the Company to accrue, during the
years that the employees render the necessary service, the expected cost of
providing benefits to former or inactive employees after employment but
before retirement. The adoption of SFAS 112 did not have a material effect
on the Company's net income. Postemployment benefits charged to operating
expenses were $2.1 million, $6.5 million and $1.0 million for 1994, 1993
and 1992, respectively.
Write Down of Coal Reserves
In connection with a review by the Company of its non-core business
assets performed in 1994, a subsidiary of the Company initiated an
evaluation of the carrying value of its $83.5 million investment in
undeveloped coal reserves in western Pennsylvania. The Company had
acquired these reserves in 1974 through the subsidiary with the intent to
supply future coal-fired generating stations. The Company has concluded
that it would not develop such reserves as a source of fuel for its
generating stations.
This evaluation of the carrying value of the subsidiary's investment
in such reserves was completed by outside appraisal firms and indicated
that an impairment had occurred. Accordingly, the carrying value of this
investment was written down to its estimated net realizable value of $9.8
million. This write down resulted in an after-tax charge to income of $40
million in the fourth quarter of 1994, which reduced 1994 earnings by
approximately 26 cents per share of common stock.
Increasing Competition
The electric utility industry, including the Company, has experienced
and will con