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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 continue to experience a significant increase in the level of
competition in the energy supply market. The Energy Act is having a
significant impact on the Company and the electric utility industry,
primarily through amendments to the Public Utility Holding Company Act of
1935 (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.
Market Initiatives
The Company 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 electric
utilities. These wholesale customers are generally small utilities that do
not have their own generating capability and purchase electricity from
others.
While there is currently no comparable competition in the retail
electric market, the Company anticipates that it will face similar
competitive pressures in the industrial and large commercial sectors of
that market in the future.
The Company has received PUC approval to enter into negotiated rates
("flexible rates") with certain industrial and commercial customers and
also provide real time pricing rates on a three-year experimental basis to
certain industrial and commercial customers. The flexible rate initiative
will enable the Company to negotiate rates with new and existing commercial
and industrial customers that have competitive alternatives to purchasing
electricity from the Company. Rates could be negotiated between a ceiling
of full costs and a floor of variable costs of production. The real time
pricing initiative will enable the Company to offer to large commercial and
industrial customers rates based upon the Company's hourly cost of
generation. The Company will select a maximum of 25 large industrial
customers to participate in the real time pricing project.
As the electric utility industry moves toward increased competition,
the Company has developed initiatives that would make its steam electric
stations more efficient and better able to compete in an environment of
market-based pricing of electricity. Included in the proposed initiatives
are measures to decrease annual operation and maintenance costs and reduce
capital expenditures. In addition, the Company has developed initiatives
to achieve longer refueling cycles, reduce the duration of refueling
outages and reduce costs at the Susquehanna station.
Restructuring
The Company also has initiated a restructuring of its utility
operations, to better position itself for the competitive future. The
organization moved from a geographic to a functional organization and
physical workers were consolidated in a new mobile work force. The new
organization replaces the Company's five geographic operating divisions
with three new departments, based on services provided to customers.
Electrical Systems is responsible for designing, maintaining and operating
the facilities that transmit and deliver electricity to customers; Customer
Services is responsible for customer inquiries and billing; and Marketing
and Economic Development is responsible for marketing electric heat and
other applications to residential customers, providing energy services to
industrial and commercial customers, and community activities.
Ongoing department-level re-engineering efforts are expected to
continue to impact the size of the Company's workforce. The redesigned
work is expected to require fewer employees. Although no specific targets
have been set, the Company currently expects that employment levels may
decline to the 6,000 to 6,500 level over the next three years. The Company
may incur additional costs as a result of these workforce reductions.
Voluntary Early Retirement Program
In conjunction with the announcement of the corporate restructuring,
the Company offered a voluntary early retirement program to 851 employees
who were age 55 or older by December 31, 1994. A total of 640 employees
elected to retire under the program, at a total cost of $75.9 million.
Prior to the early retirement program, the Company had about 7,600
employees. The early retirement program provided for a lump sum payment
based on an employee's years of service, no reduction in retirement
benefits for age and supplemental monthly payments. The Company recorded
the cost of the program as a one-time charge in the fourth quarter of 1994,
which, after income taxes, reduced net income by $43.4 million, or 28 cents
per share of common stock. A portion of the costs applicable to the
voluntary early retirement program will be recovered through power contract
billings. Annual savings in operating expenses associated with this
reduction in employees are estimated to be approximately $35 million.
The Company's PUC base rate filing reflects an estimate of the savings
from the early retirement program and seeks recovery of the cost of the
program over a five-year period. To the extent that the PUC permits
recovery of the cost of the program in rates, the Company will record a
credit to income to recognize the income effect related to the recoverable
portion of the charge recorded in 1994.
New Markets
The Company's strategic initiatives also include an assessment of
entering 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 has decided to
pursue the formation of a holding company structure, subject to the receipt
of appropriate regulatory approvals and, ultimately, 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 Nuclear
Regulatory Commission (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.
Regulatory Developments
In light of the increased competition in the electric utility market,
in June 1994 FERC issued a Notice of Proposed Rulemaking (NOPR) regarding
recovery of stranded costs. In general, the FERC has proposed that
utilities should address stranded cost recovery in all of their contracts
with wholesale customers and that the states should address the issue of
retail stranded costs. The NOPR also provides different treatment for
stranded costs related to wholesale contracts which were existing prior to
the date of the proposed rule and those executed after that date. The
proposed rule defines wholesale stranded costs as "....any legitimate,
prudent and verifiable costs incurred by a public utility or a transmitting
utility to provide service to a wholesale requirements customer that
subsequently becomes, in whole or in part, an unbundled transmission
services customer of that public utility or transmitting utility." For
contracts executed after the date of the proposed rule, utilities will not
be allowed to seek recovery of stranded costs except through explicit
stranded cost provisions, such as exit fee provisions, contained in their
contracts and may not seek recovery of stranded costs through any
transmission rates. For contracts executed prior to the date of issuance
of the proposed rule, the FERC has proposed a three-year transition period
in which utilities are required to renegotiate their wholesale requirements
contracts which do not already contain stranded cost provisions, to include
such provisions. The NOPR also provides guidance on the conditions a
utility must demonstrate to the FERC in order to be allowed recovery of
stranded costs.
In addition, in May 1994 the PUC ordered an investigation to examine
the role of competition in Pennsylvania's electric utility industry. The
investigation will allow the PUC to solicit input regarding the potential
impact of competition on the state's electric utilities and their
customers. The investigation, which will gather and analyze data at both
the wholesale and retail levels of the electric utility industry, will be a
paper proceeding conducted over approximately one year. Interested parties
have the opportunity to file written comments addressing the following
specific topics: wheeling - issues and impact, consumer issues, safety and
reliability, the impact of market structure changes and legal issues.
The Company has submitted comments in response to both the FERC NOPR
and the PUC order.
With respect to stranded costs, the Company has three general
categories of costs whose recovery may depend to a large degree on the
transition rules established to introduce increased competition in the
industry. One category is the investment in utility plant, principally
generating facilities, that might not be fully recoverable if electricity
is based on market pricing. The second category consists of regulatory
assets, or costs that have been deferred, whose recovery is based solely on
continued cost-based rate regulation. The third category represents
purchase power agreements where the price being paid may exceed the market
price for electricity.
The Company has exposure to each of these categories of potential
stranded costs to varying degrees and may not be able to fully recover them
if the price of electricity is no longer subject to cost-based rate
regulation. However, the Company cannot predict to what extent, if any, it
may not be able to fully recover its costs if the price of electricity is
no longer subject to cost-based rate regulation.
Independent Auditors' Report
Deloitte &
Touche
Pennsylvania Power & Light Company:
We have audited the accompanying consolidated balance sheets
and statements of preferred and preference stock and long-term
debt of Pennsylvania Power & Light Company and its subsidiaries
as of December 31, 1994 and 1993, and the related consolidated
statements of income, shareowners' common equity, and cash flows
for each of the three years in the period ended December 31,
1994. Our audits also included the financial statement schedules
listed in the Index at Item 8 and in the Exhibit Index as Exhibit
99. These financial statements and the financial statement
schedules are the responsibility of the Company's management.
Our responsibility is to express an opinion on the financial
statements and financial statement schedules based on our audits.
We conducted our audits in accordance with generally
accepted auditing standards. Those standards require that we
plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as
well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our
opinion.
In our opinion, such consolidated financial statements
present fairly, in all material respects, the financial position
of the Pennsylvania Power & Light Company and its subsidiaries at
December 31, 1994 and 1993, and the results of their operations
and their cash flows for each of the three years in the period
ended December 31, 1994 in conformity with generally accepted
accounting principles. Also, in our opinion, the financial
statement schedules, when considered in relation to the basic
consolidated financial statements taken as a whole, present
fairly in all material respects the information set forth
therein.
As discussed in Note 7 to the consolidated financial
statements, in 1994 the Company changed its method of accounting
for certain investments in debt and equity securities to conform
with Statement of Financial Accounting Standards Number 115.
(Signed) Deloitte & Touche
Parsippany, New Jersey
February 3, 1994
Management's Report on Responsibility for Financial Statements
The management of Pennsylvania Power & Light Company is responsible
for the preparation, integrity and objectivity of the consolidated
financial statements and all other sections of this annual report. The
financial statements were prepared in accordance with generally accepted
accounting principles and the Uniform System of Accounts prescribed by the
Federal Energy Regulatory Commission. In preparing the financial
statements, management makes informed estimates and judgments of the
expected effects of events and transactions based upon currently available
facts and circumstances. Management believes that the financial statements
are free of material misstatement and present fairly the financial
position, results of operations and cash flows of the Company.
The Company's consolidated financial statements have been audited by
Deloitte & Touche LLP (Deloitte), independent certified public accountants,
whose report with respect to the financial statements appears on page 47.
Deloitte's appointment as auditors was previously ratified by the
shareowners. Management has made available to Deloitte all the Company's
financial records and related data, as well as the minutes of shareowners'
and directors' meetings. Management believes that all representations made
to Deloitte during its audit were valid and appropriate.
The Company maintains a system of internal control designed to provide
reasonable, but not absolute, assurance as to the integrity and reliability
of the financial statements, the protection of assets from unauthorized use
or disposition and the prevention and detection of fraudulent financial
reporting. The concept of reasonable assurance recognizes that the cost of
a system of internal control should not exceed the benefits derived and
that there are inherent limitations in the effectiveness of any system of
internal control.
Fundamental to the control system is the selection and training of
qualified personnel, an organizational structure that provides appropriate
segregation of duties, the utilization of written policies and procedures
and the continual monitoring of the system for compliance. In addition,
the Company maintains an internal auditing program to evaluate the
Company's system of internal control for adequacy, application and
compliance. Management considers the internal auditors' and Deloitte's
recommendations concerning its system of internal control and has taken
actions which are believed to be cost-effective in the circumstances to
respond appropriately to these recommendations. Management believes that
the Company's system of internal control is adequate to accomplish the
objectives discussed in this report.
The Board of Directors, acting through its Audit Committee, oversees
management's responsibilities in the preparation of the financial
statements. In performing this function, the Audit Committee, which is
composed of five independent directors, meets periodically with management,
the internal auditors and the independent certified public accountants to
review the work of each. The independent certified public accountants and
the internal auditors have free access to the Audit Committee and to the
Board of Directors, without management present, to discuss internal
accounting control, auditing and financial reporting matters.
Management also recognizes its responsibility for fostering a strong
ethical climate so that the Company's affairs are conducted according to
the highest standards of personal and corporate conduct. This
responsibility is characterized and reflected in the Company's Standards of
Integrity, which is publicized throughout the Company. The Standards of
Integrity addresses: the necessity of ensuring open communication within
the Company; potential conflicts of interest; proper procurement
activities; compliance with all applicable laws, including those relating
to financial disclosure; and the confidentiality of proprietary
information. The Company maintains a systematic program to assess
compliance with these policies.
(signed) William F. Hecht
William F. Hecht
Chairman, President and Chief Executive Officer
(signed) R. E. Hill
R. E. Hill
Senior Vice President - Financial
CONSOLIDATED STATEMENT OF INCOME
Pennsylvania Power & Light Company and Subsidiaries
(Thousands of Dollars)
1994 1993 1992
Operating Revenues (Notes 1, 2, 3 and 4)................. $2,725,099 $2,727,002 $2,744,122
Operating Expenses
Operation
Fuel................................................. 458,932 506,900 545,361
Power purchases...................................... 287,316 278,800 275,499
Other................................................ 487,431 460,482 452,999
Maintenance............................................ 179,992 193,242 201,254
Depreciation (Notes 1 and 9)........................... 288,759 271,390 258,357
Amortized depreciation (Notes 1 and 9)................. 26,258 14,249 3,563
Income taxes (Note 5).................................. 218,229 235,164 228,340
Taxes, other than income (Note 5)...................... 201,161 203,967 205,318
Voluntary early retirement
program (Note 12) ................................... 75,859
2,223,937 2,164,194 2,170,691
Operating Income ............................. 501,162 562,808 573,431
Other Income and (Deductions)
Allowance for equity funds used during
construction (Note 1)................................ 4,686 7,981 6,771
Income tax credits (expense)
(Notes 5 and 14)..................................... 38,647 1,280 (322)
Write down of coal reserves (Note 14).................. (73,670)
Other -- net........................................... (228) 8,700 12,337
(30,565) 17,961 18,786
Income Before Interest Charges........................... 470,597 580,769 592,217
Interest Charges
Long-term debt........................... 214,390 225,800 240,260
Short-term debt and other.............................. 20,259 14,443 13,402
Allowance for borrowed funds used during
construction and interest
capitalized (Note 1)................................. (8,392) (7,600) (8,169)
226,257 232,643 245,493
Net Income................................. 244,340 348,126 346,724
Dividends on Preferred and Preference Stock............. 28,405 33,885 40,495
Earnings Applicable to Common Stock........ $215,935 $314,241 $306,229
Earnings Per Share of Common Stock (a)..... $1.41 $2.07 $2.02
Average Number of Shares
Outstanding (thousands)................................ 153,458 151,904 151,676
Dividends Declared Per Share of
Common Stock........................................... $1.67 $1.65 $1.60
(a) Based on average number of shares outstanding.
See accompanying Notes to Financial Statements.
CONSOLIDATED STATEMENT OF CASH FLOWS
Pennsylvania Power & Light Company and Subsidiaries
(Thousands of Dollars)
1994 1993 1992
Cash Flows From Operating Activities
Net income........................................ $244,340 $348,126 $346,724
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation..................................................... 317,287 289,055 270,048
Amortization of property under capital leases.................... 81,355 79,437 81,916
Amortization of contract settlement proceeds and
deferred cost of power plant spare parts....................... (37,793) (38,602) (31,973)
Deferred income taxes and investment tax credits................. (70,336) 12,229 18,309
Equity component of AFUDC........................................ (4,686) (7,981) (6,771)
Voluntary early retirement program .............................. 75,859
Write down of coal reserves ..................................... 73,670
Change in current assets and current liabilities
Accounts receivable............................................ (3,376) 4,672 16,010
Unbilled and refundable electric revenues...................... 31,365 (10,291) (37,865)
Fuel inventories............................................... (29,843) 46,672 16,997
Materials and supplies......................................... 2,046 4,541 9,071
Prepayments ................................................... (1,758) (2,122) 619
Accounts payable............................................... (25,229) 9,991 41,790
Accrued interest and taxes..................................... (13,619) 598 4,525
Other.......................................................... 5,831 3,752 (12,495)
Other operating activities -- net................................ 65,885 29,656 52,985
Net cash provided by operating activities.................... 710,998 769,733 769,890
Cash Flows From Investing Activities
Property, plant and equipment expenditures........ (505,029) (487,836) (422,209)
Proceeds from sales of nuclear fuel to trust....................... 35,790 63,431 42,778
Purchases of available-for-sale securities ........................ (203,622)
Sales and maturities of available-for-sale
securities ...................................................... 148,202
Other financial investments........................................ 7,662 (705) (17,796)
Other investing activities -- net.................................. 20,032 6,825 4,509
Net cash used in investing activities........................ (496,965) (418,285) (392,718)
Cash Flows From Financing Activities
Issuance of long-term debt........................ 918,750 850,000 390,000
Issuance of common stock........................................... 69,744 6,635 6,151
Issuance of preferred stock........................................ 80,000 300,000
Retirement of long-term debt....................................... (637,350) (809,000) (346,400)
Retirement of preferred and preference stock....................... (120,000) (342,837) (46,753)
Payments on capital lease obligations.............................. (86,271) (83,868) (85,733)
Dividends paid..................................................... (283,650) (284,642) (282,209)
Net increase (decrease) in short-term debt......................... (128,092) 42,912 12,178
Costs associated with issuance and retirement
of securities.................................................... (25,317) (37,448) (16,682)
Other financing activities -- net.................................. (39) (39) (126)
Net cash used in financing activities........................ (212,225) (358,287) (369,574)
Net Increase (Decrease) in Cash and
Cash Equivalents.................................... 1,808 (6,839) 7,598
Cash and Cash Equivalents at Beginning of Period..................... 8,271 15,110 7,512
Cash and Cash Equivalents at End of Period........................... $10,079 $8,271 $15,110
Supplemental Disclosures of Cash Flow Information
Cash paid during the year for
Interest (net of amount capitalized)............................. $200,140 $205,090 $249,303
Income taxes..................................................... $264,198 $221,049 $197,594
See accompanying Notes to Financial Statements.
CONSOLIDATED BALANCE SHEET AT DECEMBER 31
Pennsylvania Power & Light Company and Subsidiaries
(Thousands of Dollars)
Assets 1994 1993
Property, Plant and Equipment
Electric utility plant in service -- at original cost........ $9,306,519 $8,912,473
Accumulated depreciation (Notes 1 and 9)......................................... (2,871,129) (2,686,967)
Deferred depreciation (Notes 1 and 9) ........................................... 256,021 282,115
6,691,411 6,507,621
Construction work in progress -- at cost .......................................... 211,288 238,600
Nuclear fuel owned and leased -- net of amortization
(Note 8) ......................................................................... 143,591 174,979
Other leased property -- net of amortization (Note 8) ............................. 80,385 75,630
Electric utility plant -- net ................................................... 7,126,675 6,996,830
Other property -- net of depreciation, amortization
and depletion (1994, $54,199; 1993, $49,166) (Note 14)........................... 67,850 148,751
7,194,525 7,145,581
Investments
Associated company -- at equity ............................. 17,088 17,069
Nuclear plant decommissioning trust fund (Notes 1 and 6)........................... 87,490 76,913
Financial investments (Notes 1 and 7) ............................................. 119,632 149,326
Other -- at cost or less (Note 7) ................................................. 8,654 7,805
232,864 251,113
Current Assets
Cash and cash equivalents (Note 1) .......................... 10,079 8,271
Marketable securities (Notes 1 and 7).............................................. 100,537 17,792
Accounts receivable (less reserve: 1994, $29,083; 1993, $29,429)
Customers ....................................................................... 189,771 183,364
Interconnection ................................................................. 1,610
Other ........................................................................... 12,861 17,502
Unbilled revenues.................................................................. 88,668 120,589
Fuel (coal and oil) -- at average cost ............................................ 125,545 95,702
Materials and supplies -- at average cost ........................................ 123,630 125,676
Prepayments ....................................................................... 11,015 9,257
Common stock held for dividend reinvestment plan -- at cost........................... 15,937
Deferred income taxes (Note 5)..................................................... 27,572 12,688
Other ............................................................................. 26,916 24,721
718,204 631,499
Deferred Debits
Utility plant carrying charges -- net of amortization
(Notes 1 and 9) ................................................................. 23,142 24,097
Reacquired debt costs (Notes 1 and 9).............................................. 113,466 101,836
Assessment for decommissioning uranium enrichment
facilities (Notes 3 and 9)....................................................... 33,492 33,710
Retired miners' health care benefits (Notes 9 and 11).............................. 14,536 24,096
Taxes recoverable through future rates (Notes 5 and 9)............................. 986,292 1,166,118
Postretirement benefits other than pensions (Notes 9 and 11).......................... 14,855
Other ............................................................................. 55,160 61,208
1,226,088 1,425,920
$9,371,681 $9,454,113
See accompanying Notes to Financial Statements.
Liabilities 1994 1993
Capitalization
Common equity
Common stock .................................................................... $1,440,527 $1,370,783
Capital stock expense and other.................................................. (10,186) (10,906)
Earnings reinvested ............................................................. 1,024,127 1,065,958
2,454,468 2,425,835
Preferred stock
With sinking fund requirements .................................................. 295,000 335,000
Without sinking fund requirements ............................................... 171,375 171,375
Long-term debt .................................................................... 2,940,750 2,618,031
5,861,593 5,550,241
Current Liabilities
Commercial paper (Note 10) .................................. 64,000 117,000
Bank loans (Note 10) .............................................................. 10,168 85,260
Long-term debt due within one year ................................................ 39 44,539
Capital lease obligations due within one year (Note 8) ............................ 73,682 78,740
Accounts payable .................................................................. 146,073 156,992
Taxes accrued ..................................................................... 46,741 62,721
Interest accrued .................................................................. 63,958 60,373
Dividends payable ................................................................. 71,710 70,410
Accrued mine closing costs ........................................................ 5,705 7,842
Other ............................................................................. 96,219 88,791
578,295 772,668
Deferred Credits and Other Noncurrent Liabilities
Deferred investment tax credits (Note 5) .................... 230,064 242,317
Deferred income taxes (Note 5) .................................................... 2,046,861 2,269,648
Capital lease obligations (Note 8) ................................................ 151,083 170,285
Unamortized cost of power plant spare parts (Note 3) .............................. 26,406 51,147
Accrued nuclear plant decommissioning costs (Notes 1 and 6) ....................... 89,713 78,947
Accrued mine closing costs ........................................................ 56,427 55,876
Contract settlement proceeds to be credited to
customers (Note 3)............................................................... 32,931 43,894
Accrued pension costs (Note 11).................................................... 163,487 92,024
Accrued assessment for decommissioning uranium enrichment
facilities (Note 3)............................................................. 28,895 31,871
Accrued retired miners' health care benefits (Note 3) ............................. 29,568 38,751
Accrued postretirement benefits other than pensions and
postemployment benefits (Note 11)................................................ 21,784 9,862
Other ............................................................................. 54,574 46,582
2,931,793 3,131,204
Commitments and Contingent Liabilities (Note 15) ...............
$9,371,681 $9,454,113
See accompanying Notes to Financial Statements.
CONSOLIDATED STATEMENT OF SHAREOWNERS'
COMMON EQUITY
Pennsylvania Power & Light Company
and Subsidiaries
(Thousands of Dollars)
Capital
Stock
Common Stock Outstanding Expense & Earnings
Shares (a) Amount Other Reinvested Total
Balance at December 31, 1991........ 151,655,268 $1,358,091 $(12,187) $952,106 $2,298,010
Net income.................................................... 346,724 346,724
Cash dividends declared
Preferred stock........................................... (30,855) (30,855)
Preference stock......................................... (9,640) (9,640)
Common stock ($1.60) ............................... (242,655) (242,655)
Stock redemption costs................................ (920) (920)
Common stock issued (b)....................... 230,067 6,057 6,057
Other............................................................. 218 218
Balance at December 31, 1992........ 151,885,335 $1,364,148 $(11,969) $1,014,760 $2,366,939
Net income.................................................... 348,126 348,126
Cash dividends declared
Preferred stock........................................... (29,065) (29,065)
Preference stock......................................... (4,820) (4,820)
Common stock ($1.65) ............................... (250,611) (250,611)
Stock redemption costs................................ (12,432) (12,432)
Common stock issued (b)....................... 246,754 6,635 6,635
Other............................................................. 1,063 1,063
Balance at December 31, 1993........ 152,132,089 $1,370,783 $(10,906) $1,065,958 $2,425,835
Net income.................................................... 244,340 244,340
Cash dividends declared
Preferred stock........................................... (28,405) (28,405)
Common stock ($1.67)................................ (256,545) (256,545)
Stock redemption costs................................ (1,221) (1,221)
Common stock issued (b) ...................... 3,349,873 69,744 69,744
Other............................................................. 720 720
Balance at December 31, 1994........ 155,481,962 $1,440,527 ($10,186) $1,024,127 $2,454,468
(a) No par value, 170,000,000 shares
authorized. Each share entitles
the holders to one vote on any
question presented to any
shareowners' meeting.
(b) In 1992 and 1993, Common Stock was
issued through the Employee Stock
Ownership Plan (ESOP). In 1994,
Common Stock was issued through
the ESOP and the Dividend
Reinvestment Plan.
CONSOLIDATED STATEMENT OF PREFERRED
AND PREFERENCE STOCK AT DECEMBER 31
Pennsylvania Power & Light Company
and Subsidiaries
(Thousands of Dollars)
Shares
Outstanding Outstanding Shares
1994 1993 1994 Authorized
Preferred Stock -- $100 par, cumulative (a)
4-1/2%............................ $53,019 $53,019 530,189 629,936
Series........................................................ 413,356 453,356 4,133,556 10,000,000
$466,375 $506,375
(a) Each share of preferred and preference
stock entitles the holders to one vote on
any question presented to any shareowners'
meeting. In addition, there were
5,000,000 shares of preference stock
authorized; none were outstanding at
December 31, 1994 and 1993, respectively.
(b) The involuntary liquidation price of the
preferred stock is $100 per share. The
optional voluntary liquidation price is the
optional redemption price
per share in effect, except for the 4-1/2%
Preferred Stock for which such price is $100
per share (plus in each case any unpaid
dividends).
(c) The Company does not have any sinking
fund requirements through 2000.
(d) These series of preferred stock are not
redeemable prior to the following years:
5.95%, 2001; 6.05%, 2002; 6.125%,
6.15%, 6.33% and 6.75%, 2003.
(e) Share to be redeemed in full on April 1
as follows: 5.95%, 2001; 6.05%, 2002;
and 6.15%, 2003.
(f) Shares to be redeemed annually on
October 1 as follows: 2003-2007, 57,500;
2008, 862,500.
(g) Shares to be redeemed annually on July 1
as follows: 2003-2007, 50,000; 2008, 750,000.
See accompanying Notes to Financial
Statements.
Details of Preferred
Stock (b)
Sinking
Fund
Optional Provisions
Redemption (c)
Shares Price Per Shares to be
Outstanding Outstanding Share Redeemed Redemption
1994 1993 1994 1994 Annually Period
(Thousands
of Dollars)
With Sinking Fund
Requirements
Series Preferred
5.95% .............. $30,000 300,000 (d) (e) 2001
6.05%............... 25,000 250,000 (d) (e) 2002
6.125% ............. 115,000 $115,000 1,150,000 (d) (f) 2003-2008
6.15%............... 25,000 250,000 (d) (e) 2003
6.33% .............. 100,000 100,000 1,000,000 (d) (g) 2003-2008
6.875%..................... 40,000
7.00%....................... 80,000
$295,000 $335,000
Without Sinking Fund
Requirements
4-1/2% Preferred...... $53,019 $53,019 530,189 $110.00
Series Preferred
3.35%............... 4,178 4,178 41,783 103.50
4.40%............... 22,878 22,878 228,773 102.00
4.60%............... 6,300 6,300 63,000 103.00
6.75%............... 85,000 85,000 850,000 (d)
$171,375 $171,375
Increases(Decreases) in
Preferred and Preference
Stock (Thousands of
Dollars)
1994 1993 1992
Shares Amount Shares Amount Shares Amount
Series Preferred Stock
5.95% ................ 300,000 $30,000
6.05% ................ 250,000 25,000
6.125% ...................... 1,150,000 $115,000
6.15% ................ 250,000 25,000
6.33% ........................ 1,000,000 100,000
6.75% ........................ 850,000 85,000
6.875% ............... (400,000) (40,000) (100,000) (10,000)
7.00% ................ (800,000) (80,000) (200,000) (20,000)
7.375% ...................... (500,000) (50,000)
7.40% ........................ (176,000) (17,600) (16,000) $(1,600)
7.82% ........................ (500,000) (50,000)
7.927% ...................... (30,000) (3,000) (30,000) (3,000)
8.00% ........................ (250,000) (25,000) (25,000) (2,500)
8.60% ........................ (222,370) (22,237)
8.75%......................... (300,000) (30,000) (60,000) (6,000)
9.00%......................... (77,630) (7,763)
9.24%......................... (258,900) (25,890)
Preference Stock
$8.00 ........................ (350,000) (35,000)
$8.40 ........................ (400,000) (40,000)
$8.70......................... (400,000) (40,000)
Decreases in
Preferred and
Preference Stocks
represent: (i) the
redemption of stock
pursuant to sinking
fund requirements; or
(ii) shares redeemed
pursuant to
optional redemption
provisions.
See accompanying Notes
to Financial Statements.
CONSOLIDATED STATEMENT OF LONG-TERM
DEBT AT DECEMBER 31
Pennsylvania Power & Light Company
and Subsidiaries
Outstanding
1994 1993 Maturity(b)
(Thousands of Dollars)
Company
First Mortgage Bonds (a)
4-5/8% ....................... $30,000 March 1, 1994
5-5/8% .................................. $30,000 30,000 June 1, 1996
6-3/4% .................................. 30,000 30,000 November 1, 1997
5-1/2%................................... 150,000 150,000 April 1, 1998
7%....................................... 40,000 40,000 January 1, 1999
8-1/8%................................... 40,000 40,000 June 1, 1999
6% to 9% ................................ 740,000 640,000 2000-2004
6-1/2% to 8-1/2%......................... 475,000 375,000 2005-2009 (c)
7-3/8%................................... 100,000 2010-2014
9-1/4% to 10%............................ 250,000 375,000 2015-2019
6-3/4% to 9-3/8%......................... 800,000 650,000 2020-2024
First Mortgage Pollution
Control Bonds(a)
5-5/8% Series A............... 15,500 (d)
10-5/8% Series E..................................... 37,750 (d)
10-5/8% Series F .................................... 115,500 (d)
9-3/8% Series G ......................... 55,000 55,000 July 1, 2015
6.40% Series H........................... 90,000 90,000 November 1, 2021
5.50% Series I........................... 53,250 February 15, 2027
6.40% Series J........................... 115,500 September 1, 2029
2,968,750 2,673,750
Miscellaneous promissory notes ............ 39 77 January 3, 1995
2,968,789 2,673,827
Unamortized (discount) and
premium -- net........................... (28,000) (24,857)
2,940,789 2,648,970
Less amount due within one year............ 39 30,939
2,940,750 2,618,031
Subsidiaries
Notes........................... 13,600 (e)
Less amount due within one year ........... 13,600
Total long-term debt .................... $2,940,750 $2,618,031
__________________________________________
(a) Substantially all owned electric utility
plant is subject to the lien of the Company's
first mortgage.
(b) Aggregate long-term debt maturities through
1999 are (thousands of dollars): 1995, $39;
1996, $30,000; 1997, $30,000; 1998, $150,000;
1999, $80,000. Maximum sinking fund
requirements aggregate $19.0 million through
1999 and may be met with property additions
or retirement of bonds.
(c) Includes $200 million principal amount of
First Mortgage Bonds, 7.70% Series due
2009. Any registered owner of these bonds
has the right to require the Company to
redeem such owner's bonds on October 1,
1999 at a price of 100% of the principal amount.
(d) The Series A Bonds, Series E Bonds and
Series F Bonds were redeemed at the optional
redemption price of 100%, 103% and 102%,
respectively, of the principal amount.
(e) In January 1994, a subsidiary company
repaid $13.6 million of its 9% notes.
See accompanying Notes to Financial
Statements.
NOTES TO FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Accounting Records
Accounting records for utility operations are maintained in accordance
with the Uniform System of Accounts prescribed by the Federal Energy
Regulatory Commission (FERC) and adopted by the Pennsylvania Public Utility
Commission (PUC).
Regulation
The Company prepares its financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation." SFAS 71
requires a rate-regulated entity to reflect the effects of regulatory
decisions in its financial statements. In accordance with SFAS 71, the
Company has deferred certain costs pursuant to the rate actions of the PUC
and the FERC and is recovering or expects to recover such costs in electric
rates charged to customers. These deferred costs or "regulatory assets"
are enumerated and discussed in Note 9.
The Company's base rate filing with the PUC discussed in Note 3
includes claims for recovery of certain of these costs. To the extent that
the Company concludes that recovery of a regulatory asset is no longer
probable, due to regulatory treatment, the effects of competition or other
factors, the amount would have to be written off against income.
Principles of Consolidation
All wholly owned subsidiaries (principally involved in oil pipeline
operations, conducting unregulated business activities, passive financial
investments and holding coal reserves) have been consolidated in the
accompanying financial statements and all significant intercompany
transactions have been eliminated. Income and expenses of subsidiaries not
related to utility operations have been classified under other income and
deductions on the Consolidated Statement of Income.
The investment in Safe Harbor Water Power Corporation (Safe Harbor),
of which the Company owns one-third of the outstanding capital stock
representing one-half of the voting securities, is recorded using the
equity method of accounting. The Company's principal transaction with Safe
Harbor is the purchase of electricity amounting to (millions of dollars):
1994, $9.6; 1993, $9.9 and 1992, $9.4. Under equity accounting, the
operations of Safe Harbor resulted in additional income to the Company of
(millions of dollars): 1994, $2.2; 1993, $2.1 and 1992, $2.1.
Utility Plant and Depreciation
Additions to utility plant and replacement of units of property are
capitalized at cost. The cost of units of property retired or replaced is
removed from utility plant accounts and charged to accumulated
depreciation. Expenditures for maintenance and repairs of property and the
cost of replacing items determined to be less than units of property are
charged to operating expense.
For financial statement purposes, depreciation is being provided over
the estimated useful lives of property and is computed using a straight-
line method for all property except for property placed in service prior to
January 1, 1989 at the nuclear-fueled Susquehanna steam electric station.
Current PUC and FERC rate orders provide for an increasing amount of annual
depreciation for property placed in service prior to January 1, 1989 at the
Susquehanna station through 1998, at which time depreciation will change to
the straight-line method. Provisions for depreciation, as a percent of
average depreciable property, approximated 3.5% in 1994, 3.3% in 1993 and
3.2% in 1992.
Utility Plant Carrying Charges
Carrying charge accruals on certain facilities for the Susquehanna and
Martins Creek stations are recorded as deferred debits in accordance with a
FERC order. These amounts are being amortized to expense over the
remaining lives of the stations.
Nuclear Decommissioning and Fuel Disposal
An annual provision for the Company's share of the future
decommissioning of the Susquehanna station, equal to the amount allowed for
ratemaking purposes, is charged to operating expense. Such amounts are
invested in trust funds which can be used only for future decommissioning
costs. See Note 6.
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.
Financial Investments and Marketable Securities
In January 1994, the Company adopted SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities." SFAS 115 addresses the
accounting and reporting for investments in equity securities that have
readily determinable fair values and for all investments in debt
securities.
Securities subject to the requirements of SFAS 115 are carried at fair
value, determined at the balance sheet date. Net unrealized gains and
losses on available-for-sale securities are included in common equity. Net
unrealized gains and losses on trading securities are included in income.
Net unrealized gains and losses on securities that are not available for
unrestricted use by the Company due to regulatory or legal reasons are
reflected in the related asset and liability accounts. Realized gains and
losses on the sale of securities are recognized utilizing the specific cost
identification method. The adoption of SFAS 115 did not have a material
effect on the Company's net income. Investments in financial limited
partnerships are accounted for using the equity method of accounting and
venture capital investments are recorded at cost.
For years prior to 1994, marketable equity securities were carried at
the lower of their aggregate cost or market value, determined at the
balance sheet date. Noncurrent marketable debt securities were carried at
amortized cost. Current marketable debt securities were carried at the
lower of amortized cost or market value. See Note 7.
Premium on Reacquired Long-Term Debt
As provided in the Uniform System of Accounts, the premium paid and
expenses incurred to redeem long-term debt are deferred and amortized over
the life of the new debt issue or the remaining life of the retired debt
when the redemption is not financed by a new issue.
Allowance for Funds Used During Construction
As provided in the Uniform System of Accounts, the cost of funds used
to finance construction projects is capitalized as part of construction
cost. The components of allowance for funds used during construction
(AFUDC) shown on the Consolidated Statement of Income under other income
and deductions and interest charges are non-cash items equal to the cost of
funds capitalized during the period.
AFUDC serves to offset on the Consolidated Statement of Income the
interest charges on debt and dividends on preferred and preference stock
incurred to finance construction. In addition, a return on common equity
used to finance construction is imputed.
Capital Leases
Leased property capitalized on the Consolidated Balance Sheet is
recorded at the present value of future lease payments and is amortized so
that the total of interest on the lease obligation and amortization of the
leased property equals the rental expense allowed for ratemaking purposes.
See Note 8.
Revenues
Electric revenues are recorded based on the amounts of electricity
delivered to customers through the end of each accounting period. This
includes amounts customers will be billed for electricity delivered from
the time meters were last read to the end of the respective period.
The Company's PUC tariffs contain an Energy Cost Rate (ECR) under
which customers are billed an estimated amount for fuel and other energy
costs. Any difference between the actual and estimated amount for such
costs is collected from or refunded to customers in a subsequent period.
Revenues applicable to ECR billings are recorded at the level of actual
energy costs and the difference is recorded as payable to or receivable
from customers.
The Company's PUC tariffs include a Special Base Rate Credit
Adjustment (SBRCA) that currently credits retail customers' bills for three
nonrecurring items related to: (i) the use of an inventory method of
accounting for certain power plant spare parts; (ii) the sale of capacity
and related energy from the Company's wholly owned coal-fired stations to
Atlantic City Electric Company (Atlantic); and (iii) the proceeds from a
settlement of outstanding contract claims arising from construction of the
Susquehanna station.
The Company reflects changes in certain state taxes through a State
Tax Adjustment Surcharge (STAS). See Note 3.
Income Taxes
The Company and its wholly owned subsidiaries file a consolidated
federal income tax return. Income taxes are allocated to operating
expenses and other income and deductions on the Consolidated Statement of
Income.
In January 1993, the Company adopted SFAS 109, "Accounting for Income
Taxes." SFAS 109 required a change from the deferred method to the asset
and liability method of accounting for income taxes. See Note 5.
The provision for deferred income taxes included on the Consolidated
Statement of Income is based upon the ratemaking principles reflected in
rates established by the PUC and FERC. The difference in the provision for
deferred income taxes determined under SFAS 109 and the amount recorded
based on ratemaking procedures adopted by the PUC and FERC is deferred and
included in taxes recoverable through future rates on the Consolidated
Balance Sheet. See Note 5.
Investment tax credits were deferred when utilized and are amortized
over the average lives of the related property.
Pension Plan and Other Postretirement and Postemployment Benefits
The Company has a noncontributory pension plan covering substantially
all employees, and subsidiary companies formerly engaged in coal mining
have a noncontributory pension plan for substantially all non-bargaining,
full-time employees. Funding is based upon actuarially determined
computations that take into account the amount deductible for income tax
purposes and the minimum contribution required under the Employee
Retirement Income Security Act of 1974.
In January 1993, the Company adopted SFAS 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions." SFAS 106 requires the
Company to accrue, during the years that the employees render the necessary
service, the expected cost of providing retiree health care and life
insurance benefits.
In December 1993, the Company adopted SFAS 112, "Employers' Accounting
for Postemployment Benefits." SFAS 112 requires the accrual of the
expected cost of providing benefits to former or inactive employees after
employment but before retirement.
For additional information on these matters, see Note 11.
Cash Equivalents
The Company considers all highly liquid debt instruments purchased
with original maturities of three months or less to be cash equivalents.
Reclassification
Certain amounts from prior years' financial statements have been
reclassified to conform to the current year presentation.
2. Sources of Revenues
The Company is an operating electric utility serving about 1.2 million
customers in a 10,000 square-mile territory of central eastern Pennsylvania
with a population of approximately 2.6 million persons. Substantially all
of the Company's operating revenues are derived from the sale of electric
energy subject to PUC and FERC regulation. Customers are generally billed
for electric service on a monthly basis after electricity is delivered.
During 1994, about 98% of total operating revenues were 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
Pennsylvania-New Jersey-Maryland Interconnection Association (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.
3. 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. Various parties have filed complaints against the
rate increase including the Office of Consumer Advocate (OCA), the PUC's
Office of Trial Staff (OTS) and a group of industrial customers. In
January 1995, the PUC suspended the request for investigation and hearings.
A final rate decision is not expected until late September 1995.
Several items included in the rate filing relate to the Company's
Susquehanna station. The Company currently uses a modified sinking fund
method of depreciation for property placed in service at Susquehanna prior
to January 1989, which results in substantial increases in annual
depreciation expense each year until 1999. At that time, annual
depreciation expense is scheduled to decline by about $90 million to the
amount that would have been recorded if a straight-line method of
depreciation had been in effect since the in-service dates of the units.
The Company is seeking to levelize this depreciation expense at an annual
amount of about $173 million over the period October 1995 through December
1998, which would eliminate the currently scheduled increases in
depreciation during that time period.
The Company also is seeking recovery, over a 10-year period, of
certain deferred operating and capital costs, net of energy savings,
incurred from the time the Susquehanna units were placed in service until
the effective dates of the rate increases for those units. These costs,
which were deferred in accordance with PUC orders, total about $39 million
including related deferred income taxes.
When the PUC decided the Company's last rate case in 1985, it
determined that the Company had excess generating capacity and disallowed a
return on the common equity investment in Susquehanna Unit 2. The
Company's generating reserves have declined over the past 10 years and are
projected to be below the level considered excess by the PUC in 1985.
Accordingly, the Company's rate increase request also reflects a return on
its common equity investment in Susquehanna Unit 2.
Additionally, the Company is requesting an $18 million increase in the
amount it collects from customers for the estimated cost to decommission
the Susquehanna station. This increase reflects a site-specific
decommissioning study completed in late 1993 which indicates that the
Company's 90 percent share of the cost to decommission Susquehanna will be
about $724 million, an amount substantially greater than the amount
currently reflected in rates.
The Company also is requesting to collect about $43 million annually
for the estimated cost of dismantling its fossil-fuel plants at the end of
their expected useful lives.
The rate request also seeks recovery of the full amount of retiree
health care costs being recorded in accordance with SFAS 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions," including the
amount the Company began to defer as of January 1993 pursuant to a PUC
order but subsequently charged to expense due to a decision by the
Commonwealth Court of Pennsylvania that reversed the PUC order. The charge
to expense in 1994 amounted to $22.9 million, which included $10.8 million
applicable to 1993.
The filing also requests shortening the depreciation lives of certain
coal-fired generating stations by up to twelve years and lengthening the
depreciation lives of certain transmission, distribution and other
property.
The Company is seeking recovery of the costs related to the voluntary
early retirement program over a 5-year period, as discussed in Note 12.
The rate filing reflects an estimate of the savings from the early
retirement program. To the extent that the PUC permits recovery of the
cost of the program in rates, the Company will record a credit to income to
reverse the recoverable portion of the charge recorded in the fourth
quarter of 1994.
The Company has also proposed a method of recovering costs currently
being billed to other utilities pursuant to contractual arrangements for
the sale of capacity and related energy to those utilities. These
contracts begin to phase-out in 1996, and the Company has proposed to
recover the costs associated with the returning capacity through the ECR.
Under the proposal, the ECR would be adjusted automatically each year as
capacity is returned pursuant to the contracts. In this way, customer
rates, through ECR billings, will reflect both the capital-related and
operating costs associated with the returning capacity. The Company's
proposal provides for all the revenues associated with sales of any
returning capacity or related energy to be flowed through the ECR for the
benefit of customers.
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 period 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 reached a settlement with the complainants and the OTS 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 the settlement
agreement the Company reached in January 1994 with the 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 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 the settlement agreement, 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
Pursuant to a PUC order, the Company had been deferring the increase
in retiree benefits costs arising from adoption of SFAS 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" beginning
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.
The OCA appealed the PUC's decision permitting deferral and future
recovery of the increased retiree benefits costs to the Commonwealth Court
of Pennsylvania. In May 1994, the Commonwealth Court reversed the PUC
order and held that the Company could not defer these costs. As a result,
in the second quarter of 1994, the Company began expensing the increased
costs applicable to operations that would have otherwise been deferred and
wrote off the costs deferred from January 1, 1993. The PUC and the Company
requested the Pennsylvania Supreme Court to hear an appeal of the
Commonwealth Court decision. See Note 11.
Uranium Enrichment Decontamination and Decommissioning Fund
The Energy Policy Act of 1992 (Energy Act) provides for an assessment,
over a 15-year period, on utilities with nuclear power operations,
including the Company, to provide funds for the decontamination and
decommissioning of DOE's uranium enrichment facilities.
As of December 31, 1994, the Company's 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
and is being amortized as the Company recovers its annual payments from
customers. As a result, the assessment does not affect net income.
Special Base Rate Credit Adjustment
The SBRCA has been in effect since April 1, 1991 and currently reduces
PUC-jurisdictional customers' bills for the effects of three nonrecurring
items. The first item is the annual amortization over a five-year period
of a credit to income associated with the Company's use of an inventory
method of accounting for power plant spare parts beginning January 1, 1991.
The second relates to costs that are being recovered from Atlantic
pursuant to the sale of 125,000 kilowatts of capacity (summer rating) and
related energy from the Company's wholly owned coal-fired stations
beginning October 1, 1991. The costs recovered from Atlantic are currently
reflected in PUC base rate tariffs. Accordingly, the Company included a
credit in the SBRCA for the costs, except energy costs, recovered from
Atlantic. The change in energy costs associated with the sale is reflected
in the ECR.
The third relates to the proceeds from the settlement of outstanding
contract claims arising from construction of the Susquehanna station. In
accordance with approval of the settlement by the PUC, the Company began on
April 1, 1992 to return the settlement proceeds to PUC customers through
the SBRCA at the rate of $11 million per year for five years. In addition,
the proceeds from the settlement applicable to FERC-jurisdictional and
other major utilities are being credited to those customers.
The SBRCA reduced revenues from PUC customers by about $45.4 million
in 1994, $44.5 million in 1993 and $39.1 million in 1992. The reductions
in revenues due to the SBRCA do not affect the Company's net income.
Refund of State Tax Decrease
In June 1994, legislation was enacted that decreased the 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. In accordance with the terms of its tariffs, the
Company filed with the PUC a recomputation of its STAS to reflect the
decrease in state income taxes for 1994. The application of the STAS
reflecting the 1994 tax decrease began in July 1994 and is expected to
reduce customer bills through March 1995 by about $1.5 million.
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.
4. Sales to Other Major Electric Utilities
The Company provides Atlantic with 125,000 kilowatts of capacity
(summer rating) and related energy from the Company's wholly owned coal-
fired stations. Sales to Atlantic will continue through September 2000.
The Company also provides Baltimore Gas & Electric (BG&E) with 129,000
kilowatts or 6.6 percent of the Company's share of capacity and related
energy from the Susquehanna station. Sales to BG&E will continue through
May 2001.
The Company provides Jersey Central Power and Light Company (JCP&L)
with 945,000 kilowatts of capacity and related energy from all the
Company's generating units. Sales to JCP&L will continue at the 945,000
kilowatt level through 1995, with the amount then declining uniformly each
year until the end of the agreement on December 31, 1999.
These agreements provide that sales are to be made at a price equal to
the Company's cost of providing service, which includes a return on the
Company's investment in generating capacity. Revenues from these sales
totaled $286.3 million in 1994, $282.2 million in 1993 and $293.8 million
in 1992.
The Company has also sold capacity credits to other electric utilities
in the PJM from the Company's system capacity. These capacity credits are
used by the other utilities to meet their installed capacity obligations in
the PJM. The price received for these sales is based on a percentage of
the rate the utilities would have paid to purchase installed capacity under
the PJM agreement. These sales are currently being made under short-term
arrangements and it is uncertain how this market will continue to develop.
The Company includes, as a credit to the ECR, about one-third of the
receipts from these sales.
The Company has entered into arrangements with several utilities both
inside and outside the PJM for the reservation of output from any of the
Company's steam generating stations during certain periods of time.
Specific deliveries of energy are requested by the purchasing utility as
needed during the reservation period. One utility has agreed to purchase a
maximum of 10 megawatt hours per hour of the output the Company purchases
from non-utility generating companies through May 1995. The Company
includes as a credit to the ECR, the revenue received for deliveries of
energy under reservation of output sales, the revenue received for
deliveries of output from non-utility generating companies and the foregone
PJM energy savings that were not realized when PJM energy sales are reduced
because of reservation agreements.
Arrangements also have been entered into whereby PJM utilities can
purchase a portion of the Company's entitlement to use the PJM transmission
system to import energy from utilities outside the PJM. These transactions
are made through negotiated prices for various periods of time. The
Company includes, as a credit to the ECR, the foregone PJM energy savings
that are not realized when the sale of transmission entitlements reduces
the amount of energy the Company imports and sells to other utilities.
Revenues from the sale of capacity credits, the reservation of output
from generating units and the sale of transmission entitlements (net of the
amount that is credited to customers through the ECR) totaled $28.7 million
in 1994 and $35.0 million in both 1993 and 1992. For information relating
to a settlement agreement between the Company and complainants to the ECR
with respect to capacity-related sales, see Note 3.
5. Taxes
In January 1993, the Company adopted SFAS 109, "Accounting for Income
Taxes." SFAS 109 required a change from the deferred method to the asset
and liability method of accounting for income taxes. Under the asset and
liability method, deferred income tax assets and liabilities are recognized
for the tax consequences of temporary differences by applying enacted
statutory tax rates applicable to future years to differences between the
financial statement carrying amount and the tax bases of existing assets
and liabilities.
Under SFAS 109, the Company in January 1993 recorded an increase of
approximately $1.1 billion in its deferred tax liability for tax benefits
previously flowed through to customers and for other temporary differences.
The increased tax liability was offset by a corresponding asset
representing the future revenue expected through the ratemaking process to
pay for the taxes, based on the established regulatory practices and
legislative history in Pennsylvania permitting recovery of actual taxes
payable. The adoption of SFAS 109 did not have a material effect on the
Company's net income.
In August 1993, federal legislation was enacted that increased the
corporate federal income tax rate to 35% from 34% retroactive to January 1,
1993. For 1993, the Company recorded additional income tax expense of $5.9
million and an increase in deferred income tax liabilities and taxes
recoverable through future rates of $79.5 million to reflect the new tax
rate.
In June 1994, state legislation was enacted that decreased the 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. For 1994, the Company recorded a decrease in
income tax expense of $0.8 million, substantially all of which will be
reflected in lower customer rates through the STAS. The Company also
recorded a decrease in deferred income tax liabilities and taxes
recoverable through future rates of $124.0 million to reflect the new tax
rates.
The tax effects of significant temporary differences comprising the
Company's net deferred income tax liability were as follows (thousands of
dollars):
December 31
1994 1993
Deferred tax assets
Deferred investment tax
credits $ 94,650 $ 103,084
Accrued pension costs 67,327 38,821
Other 107,830 108,441
Valuation allowance (8,183) (8,694)
261,624 241,652
Deferred tax liabilities
Electric utility plant - net 1,790,378 1,892,366
Other property - net 13,829 26,629
Taxes recoverable through
future rates 409,417 500,959
Reacquired debt costs 46,934 43,580
Other 20,355 35,120
2,280,913 2,498,654
Net deferred tax liability $2,019,289 $2,257,002
In 1993, the valuation allowance related to deferred tax assets
decreased $2.9 million from $11.6 million established upon the adoption of
SFAS 109 at January 1, 1993.
Details of the components of income tax expense and a reconciliation
of federal income taxes derived from statutory tax rates applied to income
from continuing operations for accounting purposes are as follows
(thousands of dollars):
Income Tax Expense 1994 1993 1992
Included in operating expenses
Provision - Federal $198,777 $162,795 $144,546
State 76,903 63,508 64,648
275,680 226,303 209,194
Deferred - Federal (34,177) 22,491 30,654
State (11,021) (124) 2,521
(45,198) 22,367 33,175
Investment tax credit, net -
Federal (12,253) (13,506) (14,029)
218,229 235,164 228,340
Included in other income and deductions
Provision (credit) - Federal (18,453) (5,134) 676
State (7,309) 486 483
(25,762) (4,648) 1,159
Deferred - Federal (8,688) 4,047 (441)
State (4,197) (679) (396)
(12,885) 3,368 (837)
(38,647) (1,280) 322
Total income tax expense - Federal 125,206 170,693 161,406
State 54,376 63,191 67,256
$179,582 $233,884 $228,662
Detail of deferred taxes in operating expenses
Tax depreciation $ (2,133) $ 33,195 $ 38,026
Pension and early retirement
costs (28,176) (4,602) (5,341)
Other (14,889) (6,226) 490
$(45,198) $ 22,367 $ 33,175
Reconciliation of Income Tax Expense
Indicated federal income tax on
pre-tax income at statutory tax rate
(1994, 35%; 1993, 35%; 1992, 34%) $148,373 $203,704 $195,631
Increase (decrease) due to:
State income taxes 35,017 41,829 44,575
Depreciation differences not
normalized 14,883 8,470 6,805
Amortization of investment tax credit (12,253) (13,506) (14,029)
AFUDC (Note 1) (1,640) (2,794) (2,302)
Other (4,798) (3,819) (2,018)
31,209 30,180 33,031
Total income tax expense $179,582 $233,884 $228,662
Effective income tax rate 42.4% 40.2% 39.7%
Taxes, other than income, consist of the following (thousands of dollars):
Taxes, Other Than Income
State gross receipts $ 99,311 $ 98,280 $ 94,926
State utility realty 46,556 45,292 48,511
State capital stock 34,739 35,943 37,279
Social security and other 20,555 24,452 24,602
$201,161 $203,967 $205,318
6. Nuclear Decommissioning Costs
The Company's most recent estimate of the cost to decommission the
Susquehanna nuclear-fueled generating station was completed in 1993 and was
a site-specific study, based on immediate dismantlement and decommissioning
each unit following final shutdown. The study indicates that the Company's
ninety percent share of the total estimated cost of decommissioning the
Susquehanna station is approximately $724 million in 1993 dollars. The
operating licenses for Units 1 and 2 expire in 2022 and 2024, respectively.
The estimated cost includes decommissioning the radiological portions of
the station and the cost of removal of nonradiological structures and
materials.
Decommissioning costs charged to operating expense were $7.2 million
in 1994, and $6.9 million in 1993 and 1992 and are based upon amounts
included in customer rates. Decommissioning costs included in PUC-
jurisdictional customer rates are based upon estimates developed in 1985
and are substantially lower than the level needed to recover the cost
estimates in the 1993 site-specific study. In its pending base rate
filing, the Company has requested an $18 million annual increase in the
amount it collects from PUC-jurisdictional customers for decommissioning
costs. Rates charged to other small utilities reflect the estimated cost
of decommissioning in the 1993 study.
Amounts collected from customers for decommissioning, less applicable
taxes, are deposited in external trust funds for investment and can be used
only for future decommissioning costs. The market value of securities held
and accrued income in the trust funds at December 31, 1994 and 1993
aggregated approximately $87.5 and $82.9 million, respectively. The trust
funds experienced a net loss in 1994 of $2.3 million on a fair value basis,
which includes unrealized depreciation in the value of securities of $6.7
million. The net loss reduced the trust fund balance and accrued nuclear
plant decommissioning costs recognized on the Company's Consolidated
Balance Sheet at December 31, 1994. The net loss of the trust funds
excludes the recognition by the Company of unrealized appreciation in the
value of securities in the trust funds on January 1, 1994 of $5.9 million
in connection with the adoption of SFAS 115, "Accounting for Certain
Investments in Debt and Equity Securities." Recognition of the unrealized
appreciation at January 1, 1994 increased the balance in the trust funds
and accrued nuclear plant decommissioning costs recognized on the Company's
Consolidated Balance Sheet.
The Financial Accounting Standards Board is currently reviewing the
accounting for removal costs, including decommissioning of nuclear power
plants. As a result, current electric utility industry accounting
practices for decommissioning may change, including the possibility that
the estimated cost for decommissioning could be recorded as a liability on
a basis other than an accrual over the estimated life of the power plant.
7. Financial Instruments
The fair value of investments including securities subject to the
requirements of SFAS 115 at December 31, 1994 on the Consolidated Balance
Sheet was (thousands of dollars):
Nuclear
Marketable Financial Decommissioning
Aggregate Securities(a) Investments(b) Trust Fund(c)
Trading securities $ 12,302 $ 12,302
Available-for-sale
securities:
Equity securities 11,268 9,113 $ 2,155
Debt securities 215,189 79,122 51,502 $84,565
Total available-
for-sale 226,457 88,235 53,657 84,565
Total trading and
available-for-sale 238,759 100,537 53,657 84,565
Other investments 68,900 65,975 2,925
$307,659 $100,537 $119,632 $87,490
Available-for-sale securities at amortized cost consisted of the
following (thousands of dollars):
Nuclear
Marketable Financial Decommissioning
Aggregate Securities(a) Investments(b) Trust Fund(c)
Debt-U.S. Government $ 27,436 $ 3,414 $24,022
Debt - Municipals 187,873 75,919 $ 52,373 59,581
Debt - Other 1,656 1,656
216,965 79,333 52,373 85,259
Common Stock 9,572 9,113 459
$226,537 $88,446 $ 52,832 $85,259
Maturities of debt securities included in available-for-sale
securities consisted of the following (thousands of dollars):
Nuclear
Marketable Financial Decommissioning
Aggregate Securities(a) Investments(b) Trust Fund(c)
Fair Value
Within 1 year $ 80,773 $79,122 $ 1,651
1-5 years 29,824 $10,353 19,471
5-10 years 46,455 11,450 35,005
over 10 years 58,137 29,699 28,438
$215,189 $79,122 $51,502 $84,565
Amortized Cost
Within 1 year $ 80,989 $79,333 $ 1,656
1-5 years 29,935 $10,658 19,277
5-10 years 46,364 11,771 34,593
over 10 years 59,677 29,944 29,733
$216,965 $79,333 $52,373 $85,259
Unrealized gains and losses on available-for-sale securities at
December 31, 1994 were (thousands of dollars):
Nuclear
Marketable Financial Decommissioning
Aggregate Securities(a) Investments(b) Trust Fund(c)
Unrealized holding
gains $3,582 $ 1 $2,363 $1,218
Unrealized holding
losses $3,663 $ 212 $1,539 $1,912
Net unrealized gains on available-for-sale securities included in
common equity at December 31, 1994 amounted to $0.3 million after
applicable income taxes. The net unrealized loss on trading securities
included in income for 1994 was $0.2 million.
Realized gains and losses on the sale of securities are based on the
specific cost identification method. The proceeds from sales and
maturities and the gross realized gains and losses for 1994 were (thousands
of dollars):
Nuclear
Marketable Financial Decommissioning
Aggregate Securities(a) Investments(b) Trust Fund(c)
Proceeds from sales
and maturities $224,453 $149,384 $28,101 $46,968
Gross realized gains $ 398 $ 48 $ 350
Gross realized losses $ 676 $ 4 $ 672
_____________________
(a) Included in the amount shown as Current Assets-Marketable Securities on the
Consolidated Balance Sheet.
(b) Included in the amount shown as Investments-Financial Investments on the
Consolidated Balance Sheet.
(c) Included in the amount shown as Nuclear Plant Decommissioning Trust Funds
on the Consolidated Balance Sheet. Realized and unrealized gains and
losses are reflected in the related asset and liability accounts.
The carrying amount and the estimated fair value of the Company's
financial instruments are as follows (thousands of dollars):
December 31, 1994 December 31, 1993
Carrying Fair Carrying Fair
Amount Value Amount Value
Assets
Nuclear plant decommissioning
trust funds (a) $ 87,490 $ 87,490 $ 76,913 $ 82,860
Financial investments (b) 119,632 118,501 149,326 155,237
Other investments (c) 8,654 8,654 7,805 7,805
Cash and cash equivalents (c) 10,079 10,079 8,271 8,271
Marketable securities (d) 100,537 100,537 17,792 16,791
Other financial instruments
included in other current
assets (c) 2,435 2,435 3,102 3,102
Liabilities
Preferred stock with sinking fund
requirements (e) 295,000 265,275 335,000 336,388
Long-term debt (e) 2,940,789 2,756,131 2,662,570 2,843,635
Commercial paper and bank
loans (c) 74,168 74,168 202,260 202,260
Taxes and interest accrued,
dividends payable and other
liabilities included in other
current liabilities (c) 187,367 187,367 219,505 219,505
Accrued nuclear assessment --
noncurrent (c) 31,522 31,522 31,871 31,871
__________________
(a) The fair value generally is based on established market prices. For a
minor portion, the fair value approximates the carrying amount.
(b) The fair value is based on established market prices. For venture capital
investments included in financial investments, fair value is determined
in good faith by management of the venture capital entity.
(c) The fair value approximates carrying amount.
(d) The fair value is based on established market prices.
(e) The fair value is based on quoted market prices for the securities where
available and estimates based on current rates offered to the Company
where quoted market prices are not available.
Financial investments as shown on the Consolidated Balance Sheet
consisted of the following (thousands of dollars):
December 31
1994 1993
Marketable equity securities $ 23,570 (a) $ 11,196 (b)
Marketable debt securities 130,624 (a) 84,337 (c)
Financial limited partnerships 60,739 (e) 65,378 (e)
Venture capital investments 5,236 (b) 6,207 (b)
220,169 167,118
Less marketable securities
included in current assets 100,537 (a) 17,792 (d)
Total $119,632 $149,326
_____________
(a) At fair value
(b) At cost
(c) At amortized cost
(d) At the lower of amortized cost or market value
(e) At equity
The fair value of marketable equity securities and marketable debt
securities at December 31, 1993 was (thousands of dollars) $13,337 and
$88,594, respectively.
8. Leases
The Company has entered into capital leases consisting of the
following (thousands of dollars):
December 31
1994 1993
Nuclear fuel, net of accumulated amortization
(1994, $196,617; 1993, $191,812) $144,380 $173,395
Vehicles, oil storage tanks and other property,
net of accumulated amortization
(1994, $84,330; 1993, $83,224) 80,385 75,630
Net property under capital leases $224,765 $249,025
Capital lease obligations incurred for the acquisition of nuclear fuel
and other property were (millions of dollars): 1994, $62.0; 1993, $84.0
and 1992, $64.8.
Nuclear fuel lease payments, which are charged to expense as the fuel
is used for the generation of electricity, were (millions of dollars):
1994, $71.8; 1993, $67.6 and 1992, $70.4. Future nuclear fuel lease
payments will be based on the quantity of electricity produced by the
Susquehanna station. The maximum amount of unamortized nuclear fuel
leasable under current arrangements is $200 million.
Future minimum lease payments under capital leases in effect at
December 31, 1994 (excluding nuclear fuel) would aggregate $96.7 million,
including $16.3 million in imputed interest. During the five years ending
1999, such payments would decrease from $26.8 million per year to $7.1
million per year.
Interest on capital lease obligations was recorded as operating
expenses on the Consolidated Statement of Income in the following amounts
(millions of dollars): 1994, $11.1; 1993, $9.1 and 1992, $10.5.
Generally, capital leases contain renewal options and obligate the
Company to pay maintenance, insurance and other related costs. Various
operating leases have also been entered into which are not material with
respect to the Company's financial position.
9. Regulatory Assets
The Company has deferred certain costs (regulatory assets) in
accordance with the rate actions of the PUC and FERC and is recovering or
expects to recover such costs in electric rates charged to customers.
Regulatory assets consist of the following (thousands of dollars):
December 31
1994 1993
Deferred depreciation $ 256,021 $ 282,115
Deferred operating and carrying costs - Susquehanna 39,215 39,215
Utility plant carrying charges - net of amortization 23,142 24,097
Deferred refueling outage costs - Susquehanna 14,629 16,027
Reacquired debt costs 113,466 101,836
Taxes recoverable through future rates 986,292 1,166,118
Retired miners' health care benefits 14,536 24,096
Assessment for decommissioning uranium enrichment
facilities 33,492 33,710
Postretirement benefits other than pensions 14,855
$1,480,793 $1,702,069
Deferred depreciation is the accumulated difference between the
straight-line depreciation that would have been recorded on property placed
in service at the Susquehanna station prior to January 1, 1989 and the
amount of depreciation on such property provided for financial reporting
purposes and included in rates. The annual difference is shown as
amortized depreciation on the Consolidated Statement of Income.
Deferred operating and carrying costs - Susquehanna consist of certain
operating and capital costs, net of energy savings, associated with Units 1
and 2 at the Susquehanna station. The costs, deferred in accordance with
orders from the PUC, were incurred from the date the units were placed in
commercial operation until the effective dates of the rate increases
reflecting operation of the units. The deferred costs include related
deferred income taxes. See Note 3 for information on recovery of these
costs. No return is being accrued on the deferred costs.
Utility plant carrying charges were reclassified from electric utility
plant in service to a deferred debit in accordance with a FERC order. Such
charges are being amortized over the remaining depreciable lives of the
related property and are included in PUC electric service rates.
Deferred refueling outage costs - Susquehanna represent incremental
maintenance costs incurred during refueling and inspection outages which
are deferred and subsequently amortized from the cessation of the outage
until the next scheduled refueling and inspection outage is completed.
Such costs are included in electric service rates.
Reacquired debt costs represent premiums and expenses incurred in the
redemption of long-term debt. In accordance with FERC regulations,
reacquired debt costs are amortized over either the life of the refunding
issue or the remaining life of the redeemed issue, as appropriate. The
Company is seeking recovery of reacquired debt costs in its current base
rate filing.
For a discussion of taxes recoverable through future rates,
postretirement benefits other than pensions, retired miners' health care
benefits and assessment for decommissioning uranium enrichment facilities,
see Notes 3, 5 and 11.
10. Credit Arrangements
The Company issues commercial paper and, from time to time, borrows
from banks to provide short-term funds required for general corporate
purposes. In addition, certain subsidiaries also borrow from banks to
obtain short-term funds. Bank borrowings generally bear interest at rates
negotiated at the time of the borrowing. The Company's weighted average
interest rate on short-term borrowings was 6.1% and 3.4% at December 31,
1994 and 1993, respectively.
In 1994, the Company entered into a $250 million revolving credit
arrangement with a group of banks in return for the payment of commitment
fees which replaced a similar credit arrangement totaling $140 million.
Any loans made under this credit arrangement would mature in September 1999
and, at the option of the Company, interest rates would be based upon
certificate of deposit rates, Eurodollar deposit rates or the prime rate.
The Company has additional credit arrangements with another group of banks
in return for the payment of commitment fees. The banks have committed to
lend the Company up to $45 million under these credit arrangements, which
mature on November 2, 1995 at interest rates based upon Eurodollar deposit
rates or the prime rate. These credit arrangements produce a total of $295
million of lines of credit 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 credit arrangements.
The Company leases its nuclear fuel from a trust funded by sales of
commercial paper. The maximum financing capacity of the trust under
existing credit arrangements is $200 million.
Commitment fees incurred were (millions of dollars): 1994, $0.4;
1993, $0.3 and 1992, $0.4.
11. Pension Plan and Other Postretirement and Postemployment Benefits
Pension Plan
The Company has a funded noncontributory defined benefit pension plan
(Plan) covering substantially all employees. Benefits are based upon a
participant's earnings and length of participation in the Plan, subject to
meeting certain minimum requirements.
The Company also has two supplemental retirement plans for certain
management employees and directors that are not funded. Benefit payments
pursuant to these supplemental plans are made directly by the Company. At
December 31, 1994, the projected benefit obligation of these supplemental
plans was approximately $12.5 million.
The components of the Company's net periodic pension cost for the
three plans were (thousands of dollars):
1994 1993 1992
Service cost-benefits earned during
the period $ 33,527 $ 31,381 $ 29,967
Interest cost 51,330 48,266 44,203
Actual return on plan assets 28,680 (92,085) (95,969)
Net amortization and deferral (96,413) 29,696 40,251
Net periodic pension cost $ 17,124 $ 17,258 $ 18,452
The net periodic pension cost charged to operating expenses was $9.9
million in 1994, $10.1 million in 1993 and $11.6 million in 1992. The
balance was charged to construction and other accounts. The funded status
of the Company's Plan was (thousands of dollars):
December 31
1994 1993
Fair value of plan assets $888,214 $943,889
Actuarial present value of benefit obligations:
Vested benefits 573,564 490,567
Nonvested benefits 1,396 1,543
Accumulated benefit obligation 574,960 492,110
Effect of projected future compensation 173,311 191,302
Projected benefit obligation 748,271 683,412
Plan assets in excess of projected
benefit obligation 139,943 260,477
Unrecognized transition assets (being
amortized over 23 years) (67,796) (72,316)
Unrecognized prior service cost 61,941 34,240
Unrecognized net gain (288,105) (305,577)
Accrued expense $(154,017) $(83,176)
The weighted average discount rate used in determining the actuarial
present value of projected benefit obligations was 7.5% and 7.0% on
December 31, 1994 and 1993, respectively. The rate of increase in future
compensation used in determining the actuarial present value of projected
benefit obligations was 5.7%, on December 31, 1994 and 1993. The assumed
long-term rates of return on assets used in determining pension cost in
1994 and 1993 was 8.0%. Plan assets consist primarily of common stocks,
government and corporate bonds and temporary cash investments.
Subsidiary companies formerly engaged in coal mining have a
noncontributory defined benefit pension plan covering substantially all
non-bargaining, full-time employees which is fully funded, primarily by
group annuity contracts with insurance companies. In addition, the
companies are liable under federal and state laws to pay black lung
benefits to claimants and dependents with respect to approved claims, and
are members of a trust which was established to facilitate payment of such
liabilities. Such costs were not material in 1994, 1993 and 1992.
Postretirement Benefits Other Than Pensions
Substantially all employees of the Company and its subsidiaries will
become eligible for certain health care and life insurance benefits upon
retirement. The Company sponsors four health and welfare benefit plans
that cover substantially all management and bargaining unit employees upon
retirement. One plan provides for retiree health care benefits to certain
management employees, another plan provides retiree health care benefits to
bargaining unit employees, a third plan provides retiree life insurance
benefits to certain management employees up to a specified amount and a
fourth plan provides retiree life insurance benefits to bargaining unit
employees.
Dollar limits have been established for the amount the Company will
contribute annually toward the cost of retiree health care for employees
retiring after March 1993.
In January 1993, the Company adopted SFAS 106, "Employers' Accounting
for Postretirement Benefits Other Than Pensions," which requires the
Company to accrue, during the years that the employees render the necessary
service, the expected cost of providing retiree health care and life
insurance benefits. The adoption of SFAS 106 did not have a material
effect on the Company's net income. In accordance with a PUC order, the
Company deferred the PUC-jurisdictional accrued cost of retiree health and
life insurance benefits in excess of actual claims paid pending recovery of
the increased cost in retail rates. As a result of a decision of the
Commonwealth Court, in 1994, the Company began expensing the increased
costs applicable to operations that were previously being deferred and
wrote off such costs deferred in 1993.
In December 1993, the Company established a separate Voluntary
Employee Benefit Association trust (VEBA) for each of the four health and
welfare benefit plans for retirees and adopted a funding policy that takes
into account the maximum amount allowed as a deduction for federal income
tax purposes. After making initial contributions, additional funding of
the trusts was deferred pending resolution of the Company's ability to
recover the costs of the plans in rates.
Life insurance benefits for certain management employees beyond a
specified amount are not funded through the VEBA for retiree life insurance
benefits to management employees but are combined with the disclosures
below for the health care and life insurance plans. The cost of retiree
health care and life insurance benefits for officers of the Company are not
material and are combined with the disclosures below for health care and
life insurance plans.
The following table sets forth the plans' combined funded status
reconciled with the amount shown on the Company's Consolidated Balance
Sheet (thousands of dollars):
December 31
1994 1993
Accumulated postretirement benefit obligation:
Retirees $ 124,484 $ 95,046
Fully eligible active plan participants 13,604 32,742
Other active plan participants 68,828 75,185
206,916 202,973
Plan assets at fair value, primarily temporary
cash investments 23,506 14,848
Accumulated postretirement benefit obligation
in excess of plan assets 183,410 188,125
Unrecognized net loss (13,770) (20,573)
Unrecognized transition obligation (being
amortized over 20 years) (156,448) (165,140)
Accrued postretirement benefit cost $ 13,192 $ 2,412
At December 31, 1993, the plan that provides retiree health care
benefits to certain management employees was unfunded; the amount included
in the accumulated postretirement benefit obligation attributable to that
plan was (thousands of dollars) $70,630.
The net periodic postretirement benefit cost included the following
components (thousands of dollars):
1994 1993
Service cost - benefits attributed to service
during the period $ 4,286 $ 3,699
Interest cost on accumulated postretirement
benefit obligation 14,189 13,008
Actual return on plan assets (435)
Net amortization and deferral 7,645 8,691
Net periodic postretirement benefit cost $ 25,685 $ 25,398
Retiree health and benefits costs charged to operating expenses were
approximately (millions of dollars): 1994, $27.2 (which includes $10.8
million of retiree health and benefits costs previously deferred in 1993)
and 1993, $6.9. Costs in excess of the amount charged to expense were
charged to construction and other accounts. In 1993, the increase in
expenses due to the adoption of SFAS 106 was $2.3 million. The cost of
retiree health and life insurance benefits recognized as expense by the
Company and its subsidiaries in 1992 was approximately $5.5 million.
For measurement purposes, a 9% annual rate of increase in the per
capita cost of covered health care benefits was assumed for 1995; the rate
was assumed to decrease gradually to 6% by 2006 and remain at that level
thereafter. Increasing the assumed health care cost trend rates by 1% in
each year would increase the accumulated postretirement benefit obligation
as of December 31, 1994 by about $9.4 million and the aggregate of the
service and interest cost components of net periodic postretirement benefit
cost for the year then ended by about $1.0 million.
In determining the accumulated postretirement benefit obligation, the
weighted average discount rate used was 7.5% and 7.0% on December 31, 1994
and 1993, respectively. The trusts holding plan assets, except for retiree
health care benefits to certain management employees, are tax-exempt. The
expected long-term rate of return on plan assets for the tax-exempt trusts
was 6.5% on December 31, 1994 and 1993.
Subsidiary companies formerly engaged in coal mining had accrued $32
million for an estimated payment they expected to make for future retiree
health care. However, the Energy Act imposed a new liability, currently
estimated at about $58 million on a net present value basis, on the Company
or its subsidiary coal-mining companies for the cost of health care of
retired miners previously employed by those subsidiaries.
Postemployment Benefits
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.
Employee Stock Ownership Plan
The Company has an Employee Stock Ownership Plan (ESOP) for all full-
time employees having more than one year of service. Contributions to the
ESOP had been funded with investment and payroll-based tax credits
previously available to the Company under federal law to acquire shares of
the Company's common stock. Contributions funded with these tax credits
were completed in 1991. Since 1990, all dividends on shares credited to
participants' accounts have been paid in cash. The Company deducts the
amount of those dividends for income tax purposes and contributes to the
ESOP shares having a cost equal to the tax savings resulting from that
deduction and contribution.
12. Voluntary Early Retirement Program
As part of its efforts to continue to reduce costs, the Company
offered a voluntary early retirement program to 851 employees who were age
55 or older by December 31, 1994. A total of 640 employees elected to
retire under the program, at a total cost of $75.9 million. The early
retirement program provided for a lump sum payment based on an employee's
years of service, no reduction in retirement benefits for age and
supplemental monthly payments. The Company recorded the cost of the
program as a charge against income in the fourth quarter of 1994, which
reduced net income by $43.4 million, or 28 cents per share of common stock.
Annual savings in operating expenses associated with this program are
estimated to be approximately $35 million.
The Company's PUC base rate filing reflects an estimate of the savings
from the early retirement program and seeks recovery of the cost of the
program over a five-year period. To the extent that the PUC permits
recovery of the cost of the program in rates, the Company will record a
credit to income to recognize the income effect related to the recoverable
portion of the charge recorded in 1994.
13. Jointly Owned Facilities
At December 31, 1994, the Company or a subsidiary owned undivided
interests in the following facilities (millions of dollars):
Merrill
------Generating Stations----- Creek
Susquehanna Keystone Conemaugh Reservoir
Ownership interest 90.00% 12.34% 11.39% 8.37%
Electric utility plant in service $4,015 $60 $91
Other property $22
Accumulated depreciation 697 29 26 6
Construction work in progress 56 2 7
Each participant in these facilities provides its own financing. The
Company receives a portion of the total output of the generating stations
equal to its percentage ownership. The Company's share of fuel and other
operating costs associated with the stations is reflected on the
Consolidated Statement of Income. The Merrill Creek Reservoir provides
water during periods of low river flow to replace water from the Delaware
River used by the Company and other utilities in the production of
electricity.
14. 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 in order 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, resulting in a $73.7 million pre-tax charge to income. 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.
15. Commitments and Contingent Liabilities
Construction Expenditures
The Company's construction expenditures are estimated to aggregate
$387 million in 1995, $401 million in 1996 and $478 million in 1997,
including AFUDC. For discussion pertaining to construction expenditures,
see Review of the Company's Financial Condition and Results of Operations
under the caption "Financial Condition - Capital Expenditure Requirements"
(Capital Expenditure Requirements) on page 34.
Nuclear Operations
The Company is a member of certain insurance programs which provide
coverage for property damage to members' nuclear generating stations.
Facilities at the Susquehanna station are insured against property damage
losses up to $3.6 billion under these programs. The Company is also a
member of an insurance program which provides insurance coverage for the
cost of replacement power during prolonged outages of nuclear units caused
by certain specified conditions. Under the property and replacement power
insurance programs, the Company could be assessed retrospective premiums in
the event of the insurers' adverse loss experience. The maximum amount the
Company could be assessed under these programs at December 31, 1994 was
about $41.9 million.
Nuclear Regulatory Commission regulations require that in the event of
an accident, where the estimated cost of stabilization and decontamination
exceeds $100 million, proceeds of property damage insurance be segregated
and used, first, to place and maintain the reactor in a safe and stable
condition and, second, to complete required decontamination operations
before any insurance proceeds would be made available to the Company or the
trustee under the Mortgage. The Company's on-site property damage
insurance policies for the Susquehanna station conform to these
regulations.
The Company's public liability for claims resulting from a nuclear
incident at the Susquehanna station is limited to about $8.9 billion under
provisions of The Price Anderson Amendments Act of 1988 (the Act). The
Company is protected against this liability by a combination of commercial
insurance and an industry assessment program. A utility's liability under
the assessment program will be indexed not less than once during each five-
year period for inflation and will be subject to an additional surcharge of
5% in the event the total amount of public claims and costs exceeds the
basic assessment. In the event of a nuclear incident at any of the
reactors covered by the Act, the Company could be assessed up to $151
million per incident, payable at a rate of $20 million per year, plus the
additional 5% surcharge, if applicable.
Fuel Oil Dealers' Litigation
In August 1991, a group of 21 fuel oil dealers in the Company's
service area filed a complaint against the Company in United States
District Court for the Eastern District of Pennsylvania (District Court)
alleging that the Company's promotion of electric heat pumps and off-peak
thermal storage systems, through the use of a special customer rate (Rate
RTS) and incentives to builders and developers, had violated and continues
to violate the federal antitrust laws. The complaint also alleged that the
Company's use of incentives for the installation of high efficiency heat
pumps violated and continues to violate the Racketeer Influenced and
Corrupt Organizations Act (RICO).
The complaint requested judgment against the Company for a sum in
excess of $10 million for the alleged antitrust violations, treble the
damages alleged to have been sustained by the plaintiffs. Separately, the
complaint requested judgment for a sum in excess of $10 million for the
alleged RICO violations, treble the damages alleged to have been sustained
by the plaintiffs. Finally, the complaint requested a permanent injunction
against all activities found to be illegal (including the cash grant
program described below).
In April 1992, a fuel oil dealer in the Company's service area filed a
class action complaint against the Company in the District Court alleging,
as did the August 1991 complaint, that the Company's promotion of electric
heat pumps and off-peak thermal storage systems had violated and continues
to violate the federal antitrust laws. The complaint did not allege any
violation of RICO, but did allege that the Company engaged in a civil
conspiracy and unfair competition in violation of Pennsylvania law.
The plaintiff sought to represent as a class all fuel oil dealers in
the Company's service area. The complaint requested a permanent injunction
against all activities found to be illegal and treble the damages alleged
to have been sustained by the class. No specific damage amount was set
forth in the complaint. This second antitrust complaint was consolidated
with the August 1991 complaint for pre-trial purposes.
In September 1992, the Court granted the Company's motion for summary
judgment and dismissed both suits filed against the Company. The
plaintiffs appealed the decision to the United States Court of Appeals for
the Third Circuit (Court of Appeals).
In April 1994, the Court of Appeals affirmed in part and reversed in
part the District Court's decision. The Court of Appeals affirmed the
District Court's grant of summary judgment for the Company as to the
Company's use of Rate RTS and the Company's builder and developer
incentives, but reversed and remanded as to plaintiffs' claims regarding
the Company's alleged agreements with developers that their developments
consist of only electrically heated units (all-electric agreements). The
Court of Appeals also reversed and remanded the grant of summary judgment
as to the state law claims related to such agreements.
The case is now proceeding in the District Court on the issue of the
all-electric agreements and the related state law claims. In addition, in
June 1994 plaintiffs filed an amended complaint in District Court alleging
that the Company's former residential conversion program -- under which
cash grants were offered to contractors and homeowners to convert from
fossil fuel heating systems to electric systems -- also violated the
federal antitrust laws.
The Company cannot predict the outcome of this litigation.
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 34.
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 34. 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.
Other
At December 31, 1994, the Company had guaranteed $11.7 million of
obligations of Safe Harbor. The Company does not expect to fund the
guarantee and has concluded that it is impractical to determine the fair
value of the guarantee.
SELECTED FINANCIAL AND OPERATING DATA
1994 1993 1992 1991 1990
CONSOLIDATED OPERATIONS
Income Items -- thousands
Operating revenues ........... $2,725,099 $2,727,002 $2,744,122 $2,740,715 $2,637,922
Operating income............................. 501,162 562,808 573,431 582,331 590,366
Net income................................... 244,340 (d) 348,126 346,724 348,414 343,906
Earnings applicable to common stock.......... 215,935 (d) 314,241 306,229 303,727 297,781
Balance Sheet Items -- thousands (a)
Electric utility plant in service -- net.. $6,691,411 $6,507,621 $6,391,857 $6,296,496 $6,240,608
Construction work in progress................ 211,288 238,600 211,534 183,242 143,084
Other property, plant and equipment -- net... 291,826 399,360 416,113 449,840 510,529
Total assets................................. 9,371,681 9,454,113 8,191,768 7,934,595 7,735,442
Long-term debt............................... 2,940,789 2,662,570 2,627,159 2,582,233 2,470,596
Preferred and preference stock
With sinking fund requirements............. 295,000 335,000 325,600 364,590 383,690
Without sinking fund requirements.......... 171,375 171,375 223,612 231,375 231,375
Common equity................................ 2,454,468 2,425,835 2,366,939 2,298,010 2,221,759
Short-term debt.............................. 74,168 202,260 159,348 147,170 265,940
Total capital provided by investors.......... 5,935,800 5,797,040 5,702,658 5,623,378 5,573,360
Capital lease obligations ................... 224,765 249,025 251,058 271,976 302,754
Financial Ratios
Return on average common equity -- % ..... 8.73 13.06 13.11 13.42 13.65
Embedded cost rates (a)
Long-term debt -- %........................ 8.07 8.63 9.36 9.72 9.69
Preferred and preference stock -- %........ 6.07 6.30 7.36 7.51 7.54
Times interest earned before income taxes.... 2.73 3.33 3.18 3.06 2.86
Ratio of earnings to fixed charges --
total enterprise basis (b)................. 2.70 3.31 3.15 3.04 2.81
Depreciation as % of average depreciable
property.................................. 3.5 3.3 3.2 3.1 2.9
Common Stock Data
Number of shares outstanding -- thousands
Year-end.................................. 155,482 152,132 151,885 151,655 151,298
Average.................................... 153,458 151,904 151,676 151,382 150,924
Number of shareowners (a).................... 132,632 130,677 129,394 127,272 130,719
Earnings per share .......................... $1.41 (d) $2.07 $2.02 $2.01 $1.97
Dividends declared per share................. $1.67 $1.65 $1.60 $1.55 $1.49
Book value per share (a)..................... $15.79 $15.95 $15.58 $15.15 $14.68
Market price per share (a)................... $19 $27 $27-1/4 $26-3/8 $21-7/8
Dividend payout rate -- %.................... 119 80 79 77 76
Dividend yield -- % (c)...................... 7.74 5.64 6.07 6.69 7.15
Price earnings ratio (c)..................... 15.33 14.14 13.05 11.55 10.56
ELECTRIC OPERATIONS
Revenue Data
By class of service -- thousands
Residential................................ $931,427 $905,650 $876,531 $842,771 $800,587
Commercial................................. 755,352 735,192 713,406 687,632 647,949
Industrial................................. 526,175 524,160 523,367 506,038 503,806
Other energy sales......................... 93,422 91,205 85,456 83,630 78,489
System sales........................... 2,306,376 2,256,207 2,198,760 2,120,071 2,030,831
Contractual sales to other major
utilities ............................... 300,261 313,578 330,017 322,298 313,207
PJM energy sales .......................... 75,756 96,848 111,602 180,434 217,430
Total from energy sales billed ........ 2,682,393 2,666,633 2,640,379 2,622,803 2,561,468
Unbilled revenues -- net................... (23,575) (2,455) 36,567 47,022 5,043
Other operating revenues .................. 64,845 61,561 64,670 68,868 69,725
Total electric operating revenues ..... $2,723,663 $2,725,739 $2,741,616 $2,738,693 $2,636,236
Average price per kwh billed -- cents
Residential................................ 8.14 8.20 8.27 8.12 7.92
Commercial................................. 7.78 7.84 7.89 7.76 7.59
Industrial................................. 5.52 5.76 5.98 5.98 5.78
Total for ultimate customers........... 7.24 7.37 7.48 7.39 7.17
Total for system sales................. 7.14 7.27 7.39 7.30 7.08
(a) Year-end
(b) Computed using earnings and fixed charges of
the Company and all of its affiliated companies.
Fixed charges consist of interest on short-
and long-term debt, other interest charges,
interest on capital lease obligations and the
estimated interest component of other rentals.
(c) Based on average of month-end market prices.
(d) 1994 earnings were adversely affected by
several one-time charges including: costs
associated with a voluntary early retirement
program; a write down in the carrying value of a
subsidiary's investment in undeveloped coal
reserves; disallowances of replacement power
costs through the Energy Cost Rate; and a
decision of the Commonwealth Court of Pennsylvania
related to deferral of postretirement benefit
costs. See Financial Notes 3, 12 and 14.
SELECTED FINANCIAL AND OPERATING DATA
1994 1993 1992 1991 1990
ELECTRIC OPERATIONS (Continued)
Sales Data
Customers(a)................................ 1,213,023 1,203,139 1,186,682 1,173,680 1,161,232
Average annual residential kwh use ......................... 10,767 10,503 10,207 10,101 9,947
Electric energy sales billed -- millions of kwh
Residential .............................................. 11,444 11,043 10,604 10,385 10,103
Commercial ............................................... 9,716 9,373 9,039 8,861 8,538
Industrial ............................................... 9,536 9,100 8,746 8,456 8,716
Other .................................................... 1,618 1,534 1,366 1,334 1,315
System sales ........................................... 32,314 31,050 29,755 29,036 28,672
Contractual sales to other major utilities ............... 6,307 7,142 7,327 7,183 7,028
PJM energy sales ......................................... 3,158 4,142 5,160 7,553 8,971
Total electric energy sales billed ..................... 41,779 42,334 42,242 43,772 44,671
Sources of energy sold -- millions of kwh
Generated
Coal-fired steam stations .............................. 21,537 24,960 25,153 24,805 26,409
Nuclear steam station .................................. 13,779 12,181 12,216 14,271 13,254
Oil-fired steam station ................................ 1,764 1,452 1,057 1,939 1,442
Combustion turbines and diesels (oil) .................. 41 16 10 15 33
Hydroelectric stations ................................. 753 637 750 521 804
37,874 39,246 39,186 41,551 41,942
Power purchases .......................................... 6,063 5,586 5,347 4,542 4,634
Company use, line losses and other ....................... (2,158) (2,498) (2,291) (2,321) (1,905)
Total electric energy sales billed ..................... 41,779 42,334 42,242 43,772 44,671
Generation Data
Net system capacity -- thousands of
kw (a)..................................................... 7,844 7,802 7,802 7,797 7,912
Winter peak demand -- thousands of kw (c) .................. 6,508 6,403 6,130 5,974 5,661
Generation by fuel source -- %
Coal ..................................................... 56.9 63.6 64.2 59.7 63.0
Nuclear................................................... 36.4 31.0 31.2 34.3 31.6
Oil....................................................... 4.7 3.8 2.7 4.7 3.5
Hydroelectric ............................................ 2.0 1.6 1.9 1.3 1.9
Steam station availability -- %
Coal-fired ............................................... 74.3 82.6 81.7 78.1 82.5
Nuclear................................................... 82.1 73.8 73.7 86.3 80.2
Oil-fired ................................................ 80.3 81.9 94.8 86.7 82.8
Steam station capacity factor -- %
Coal-fired ............................................... 59.1 68.5 68.8 68.2 72.7
Nuclear .................................................. 81.5 73.0 73.0 85.8 80.1
Oil-fired ................................................ 12.3 10.1 7.3 13.5 10.0
Fuel Cost Data
Cost per kwh generated -- cents
Coal-fired steam stations ................................ 1.48 1.53 1.74 1.75 1.66
Nuclear steam station..................................... 0.50 0.54 0.54 0.57 0.59
Oil-fired steam station .................................. 3.92 3.89 3.73 3.58 4.18
Combustion turbines and diesels (oil) .................... 6.33 7.03 7.50 7.52 7.68
Average ........................................... 1.24 1.31 1.42 1.43 1.41
Cost of fossil fuel received at steam stations
Coal -- per ton .......................................... $35.05 $36.23 $41.44 $42.87 $40.64
Residual oil -- per barrel ............................... $19.29 $18.70 $16.56 $18.76 $21.52
Capitalization Ratios -- %(a)
Long-term debt .............................. 49.6 46.5 46.7 46.3 44.5
Short-term debt ............................................ 1.1 2.0 1.2 1.3 3.8
Preferred and preference stock ............................. 7.9 8.9 9.8 10.8 11.2
Common equity .............................................. 41.4 42.6 42.3 41.6 40.5
Times Interest Earned Before Income Taxes ......... 2.79 3.37 3.21 3.11 2.93
Employees (a)(d)................................... 7,489 7,765 7,981 8,144 8,149
(a) At year-end.
(b) Total generating capacity plus firm capacity
purchases less firm capacity sales.
(c) The winter peaks shown were reached early
in the subsequent year.
(d) After giving effect to the voluntary early
retirement program, the number of employees
on January 1, 1995 was 6,978.
SHAREOWNER AND INVESTOR INFORMATION
The following information is provided as a service to
shareowners and other investors. For any questions you may
have or additional information you may require about PP&L or
your investments in the Company, please feel free to call
the toll-free number listed below, or write to:
George I. Kline, Manager
Investor Services Department
Pennsylvania Power & Light Co.
Two North Ninth Street
Allentown, PA 18101-1179
Toll-Free Phone Number: For information regarding your
investor account, or other inquiries, call toll-free: 800-
345-3085.
Annual Meeting: The annual meeting of shareowners is held
each year on the fourth Wednesday of April. The 1995 annual
meeting will be held at 1:30 p.m. on Wednesday, April 26,
1995, at Lehigh University's Stabler Arena, Lower Saucon
Valley Goodman Campus Complex, Bethlehem, PA. A reservation
card for meeting attendance is included with shareowners'
proxy material.
Proxy Material: A proxy statement, a proxy and a
reservation card for the Company's annual meeting are mailed
in a package that includes the Company's Annual Report.
This material was mailed to all shareowners of record as of
February 28, 1995.
Dividends: For 1995, the dates the declaration of dividends
is considered by the board or its executive committee are:
February 22, May 24, August 23 and November 22, for payment
on April 1, July 1 and October 1, 1995, and January 1, 1996,
respectively. Dividend checks are mailed ahead of those
dates with the intention that they arrive as close as
possible to the payment dates.
Record Dates: The 1995 record dates for dividends are March
10, June 9, September 8 and December 8.
Direct Deposit of Dividends: Shareowners may choose to have
their dividend checks deposited directly into their checking
or savings account. Quarterly dividend payments are
electronically credited on the dividend date, or the first
business day thereafter.
Dividend Reinvestment Plan: Shareowners may choose to have
dividends on their common or preferred stocks reinvested in
PP&L common stock instead of receiving the dividend by
check.
Certificate Safekeeping: Shareowners participating in the
Dividend Reinvestment Plan may choose to have their common
stock certificates forwarded to the Company for safekeeping.
These shares will be registered in the name of the Company
as agent for plan participants and will be credited to the
participants' accounts.
Lost Dividend or Interest Checks: Dividend or interest
checks lost by investors, or those that may be lost in the
mail, will be replaced if the check has not been located by
the 10th business day following the payment date.
Transfer of Stock or Bonds: Stock or bonds may be
transferred from one name to another or to a new account in
the name of another person. Please call or write regarding
transfer instructions.
Bondholder Information: Much of the information and many of
the procedures detailed here for shareowners also apply to
bondholders. Questions related to bondholder accounts
should be directed to Investor Services.
Lost Stock or Bond Certificates: Please call or write to
Investor Services for an explanation of the procedure to
replace lost stock or bond certificates.
Publications: Several publications are prepared each year
and sent to all investors of record and to others who
request their names be placed on our mailing lists. These
publications are:
Annual Report -- published and mailed to all shareowners of
record in mid-March.
Shareowners' Newsletter -- an easy-to-read newsletter
containing current items of interest to shareowners --
published and mailed at the beginning of each quarter.
Additionally, a special year-end edition containing
unaudited results of the year's operations is mailed in
early February.
Quarterly Review -- published in May, August and November to
provide quarterly financial information to investors.
Periodic Mailings: Letters from the Company regarding new
investor programs, special items of interest, or other
pertinent information are mailed on a non-scheduled basis as
necessary.
Duplicate Mailings: Annual reports and other investor
publications are mailed to each investor account. If you
have more than one account, or if there is more than one
investor in your household, you may call or write to request
that only one publication be delivered to your address.
Please provide account numbers for all duplicate mailings.
Form 10-K and PP&L Profile: The Company's annual report,
filed with the Securities and Exchange Commission on Form
10-K, is available about mid-March. The PP&L Profile, a 10-
year statistical review containing in-depth information
about the Company, is available in May. Investors may
obtain a copy of these publications, at no cost, by calling
or writing to Investor Services.
Listed Securities: Fiscal Agents:
New York Stock Exchange Stock Transfer Agents and
Common Stock (Code: PPL) Registrars
4-1/2% Preferred Stock First Chicago Trust Co. of
(Code: PPLPRB) New York
4.40% Series Preferred Stock P.O. Box 2506
(Code: PPLPRA) Suite 4659
Jersey City, NJ 07303-2506
Philadelphia Stock Exchange Pennsylvania Power & Light Co.
Common Stock Investor Services Department
4-1/2% Preferred Stock Dividend Disbursing Office
3.35% Series Preferred Stock and Dividend Reinvestment
4.40% Series Preferred Stock Plan Agent
4.60% Series Preferred Stock Pennsylvania Power & Light Co.
Investor Services Department
Mortgage Bond Trustee
Bankers Trust Co.
Attn: Security Transfer Unit
P.O. Box 291569
Nashville, TN 37229
Bond Interest Paying Agent
Pennsylvania Power & Light Co.
Investor Services Department
Quarterly Financial, Common Stock Price and
Dividend Data (Unaudited)
For the Quarters Ended (a)
March 31 June 30 Sept. 30 Dec. 31
(Thousands of Dollars, Except Per Share Amounts)
1994
Operating revenues ................................ $769,453 $640,218 $661,142 $654,286
Operating income................................... 169,306 108,378 131,933 91,545
Net income (loss).................................. 113,666 53,999 76,954 (279)(d)
Earnings (loss) applicable to common stock......... 106,088 47,057 70,012 (7,222)(d)
Earnings (loss) per common share (b)............... 0.70 0.31 0.46 (0.05)(d)
Dividends declared per common
share (c)........................................ 0.4175 0.4175 0.4175 0.4175
Price per common share
High............................................. 27 1/4 24 7/8 21 7/8 20 3/4
Low.............................................. 22 5/8 19 1/2 19 1/4 18 5/8
1993
Operating revenues .......................... $727,386 $620,439 $683,466 $695,711
Operating income................................... 171,476 123,849 134,129 133,354
Net income......................................... 115,749 69,867 81,775 80,735
Earnings applicable to common stock................ 106,206 60,231 74,826 72,978
Earnings per common share (b)...................... 0.70 0.40 0.49 0.48
Dividends declared per common
share (c)........................................ 0.4125 0.4125 0.4125 0.4125
Price per common share
High............................................. 30 1/2 30 3/4 31 30 1/4
Low.............................................. 26 1/4 28 3/8 29 1/2 26 1/8
(a) The Company's electric utility business
is seasonal in nature with peak sales periods
generally occurring in the winter months.
Accordingly, comparisons among quarters of a
year may not be indicative of overall trends
and changes in operations.
(b) The sum of the quarterly amounts may not
equal annual earnings per share due to
changes in the number of common shares
outstanding during the year or rounding.
(c) The Company has paid quarterly cash
dividends on its common stock in every
year since 1946. The dividends paid per
share in 1994 and 1993 were $1.665 and
$1.6375, respectively. The most recent regular
quarterly dividend paid by the Company was
41.75 cents per share (equivalent to $1.67 per
annum) paid January 1, 1995. Future dividends
will be dependent upon future earnings,
financial requirements and other factors.
(d) Fourth quarter earnings were adversely
affected by two one-time charges. Costs
associated with a voluntary early retirement
program reduced net income and earnings
applicable to common stock by $43.4 million,
or 28 cents per share of common stock. Also,
a write down in the carrying value of a
subsidiary's investment in undeveloped coal
reserves reduced net income and earnings
applicable to common stock by $40.0 million,
or 26 cents per share. For additional information,
see Financial Notes 12 and 14.
Pennsylvania Power & Light Company
and Subsidiaries
SCHEDULE II - VALUATION AND QUALIFYING
ACCOUNTS AND RESERVES
(Thousands of Dollars)
Column A Column B Column C Column D Column E
Deductions
from
Balance Additions Additions Reserves -
at Charges Losses or Balance at
Beginning Charged to Other Expenses End of
Description of Period to Income Accounts Applicable Period
Year Ended December 31, 1994
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts ..................... $29,429 $16,942 $17,288 $29,083
Obsolete inventory - Materials and supplies. 172 172 0
Year Ended December 31, 1993
Reserves deducted from assets in
the Balance Sheet
Uncollectible accounts ..................... 27,660 18,660 16,891 29,429
Obsolete inventory - Materials and supplies 1,406 1,234 172
Year Ended December 31, 1992
Reserves deducted from assets in
the Balance Sheet
Accumulated provision for amortization
of Mine development costs ................ 41,785 1,462 43,247 0
Uncollectible accounts ..................... 27,655 16,162 16,157 27,660
Obsolete inventory - Materials and supplies 1,886 10 490 1,406
61
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information for this item concerning directors of the
Company will be set forth in the sections entitled "Nominees
for Directors" and "Directors Continuing in Office" in the
Company's 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,
and such information is incorporated herein by reference.
Information required by this item concerning the
executive officers of the Company is set forth on pages 22
through 24 of this report.
ITEM 11. EXECUTIVE COMPENSATION
Information for this item will be set forth in the
sections entitled "Compensation of Directors," "Summary
Compensation Table" and "Retirement Plans for Executive
Officers" in the Company's 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, and such information is incorporated herein by
reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
Information for this item will be set forth in the
section entitled "Stock Ownership" in the Company's 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, and such information
is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Information for this item will be set forth in the
section entitled "Certain Transactions Involving Directors
or Executive Officers" in the Company's 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, and such information is
incorporated herein by reference.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial Statements - included in response to Item 8.
Independent Auditors' Report
Consolidated Statement of Income for the Three
Years Ended December 31, 1994
Consolidated Statement of Cash Flows for
the Three Years Ended December 31, 1994
Consolidated Balance Sheet at December 31, 1994
and 1993
Consolidated Statement of Shareowners' Common Equity
for the Three Years Ended December 31, 1994
Consolidated Statement of Preferred and Preference
Stock at December 31, 1994 and 1993
Consolidated Statement of Long-Term Debt at
December 31, 1994 and 1993
Notes to Financial Statements
2. Supplementary Data and Supplemental Financial Statement
Schedule - included in response to Item 8.
Schedule II - Valuation and Qualifying Accounts and
Reserves for the Three Years Ended
December 31, 1994
All other schedules are omitted because of the absence
of the conditions under which they are required or
because the required information is included in the
financial statements or notes thereto.
3. Exhibits
Exhibit Index on page 96.
(b) Reports on Form 8-K:
The following Reports on Form 8-K were filed during the
three months ended December 31, 1994:
Report dated October 3, 1994
Item 5. Other Events
Information regarding (l) the Company's early retirement
program offer to eligible employees, and (2) an agreement
in principle to settle the Company's proposed 1994-95 ECR
proceeding.
Item 7. Financial Statements, Pro Forma Financial Infor-
mation and Exhibits.
Conformed copy of Sixty-second Supplemental Indenture
related to the Company's issuance of First Mortgage Bonds,
Pollution Control Series J, filed as an Exhibit to the
Report on Form 8-K.
Conformed copy of Underwriting Agreement and Sixty-third
Supplemental Indenture related to the Company's issuance of
$200,000,000 principal amount of First Mortgage Bonds, 7.70%
Series due 2009, filed as Exhibits to the Report on Form
8-K.
Conformed copy of Consent of Counsel.
Statement of Eligibility of Trustee, filed due to the
designation of Bankers Trust Company as Trustee under the
Company's Mortgage and Deed of Trust, as successor to Morgan
Guaranty Trust Company of New York.
No financial statements were required to be filed with the
above referenced report.
Report dated December 12, 1994
Item 5. Other Events
Information regarding the write down of a Company
subsidiary's undeveloped coal reserves to net realizable
value.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the
Securities Exchange Act of 1934, the Registrant has duly caused this report
to be signed on its behalf by the undersigned, thereunto duly authorized.
PENNSYLVANIA POWER & LIGHT COMPANY
(Registrant)
By (Signed) William F. Hecht
William F. Hecht - Chairman, President
and Chief Executive
Officer
Pursuant to the requirements of the Securities Exchange Act of
1934, this report has been signed below by the following persons on behalf
of the Registrant and in the capacities and on the date indicated.
Title
By (Signed) William F. Hecht Principal Executive
William F. Hecht - Chairman, President Officer and Director
and Chief Executive
Officer
By (Signed) R. E. Hill Principal Financial and
R. E. Hill - Senior Vice President- Accounting Officer
Financial
By (Signed) J. J. McCabe Chief Accounting
J. J. McCabe - Controller Officer
Richard S. Barton
Jeffrey J. Burdge
E. Allen Deaver
Nance K. Dicciani
William J. Flood
Daniel G. Gambet
Elmer D. Gates Directors
Stuart Heydt
Clifford L. Jones
John T. Kauffman
Robert Y. Kaufman
Ruth Leventhal
Francis A. Long
Norman Robertson
David L. Tressler
By (Signed) William F. Hecht
William F. Hecht, Attorney-in-fact
PENNSYLVANIA POWER AND LIGHT COMPANY
EXHIBIT INDEX
The following Exhibits indicated by an asterisk preceding
the Exhibit number are filed herewith. The balance of the
Exhibits have heretofore been filed with the Commission and
pursuant to Rule 12(b)-32 are incorporated herein by
reference. Exhibits indicated by a # are filed or listed
pursuant to Item 601(b)(10)(iii) of Regulation S-K.
3(i) - Copy of Restated Articles of
Incorporation (Exhibit 3(i) to the
Company's Form 8-K Report (File No. 1-905)
dated January 26, 1994)
3(i)-1 - Copy of Amendments to the
Restated Articles of Incorporation (Exhibit
4(b) to the Company's Form 8-K Report (File
No. 1-905) dated March 15, 1994)
3(ii) - Copy of By-laws (Exhibit 3(ii)
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1993)
4(a)-1 - Copy of Amended and Restated
Employee Stock Ownership Plan, dated
October 26, 1988 (Exhibit 4(b) to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1988)
4(a)-2 - Copy of Amendment No. 1 to
said Employee Stock Ownership Plan,
effective January 1, 1989 (Exhibit 4(b)-2
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1989)
4(a)-3 - Copy of Amendment No. 2 to
said Employee Stock Ownership Plan,
effective January 1, 1990 (Exhibit 4(b)-3
to the Company's Form 10-K Report (File No.
1 - 905) for the year ended December 31,
1989)
4(a)-4 - Copy of Amendment No. 3 to
said Employee Stock Ownership Plan,
effective January 1, 1991 (Exhibit 4(b)-4
to the Company's Form 10-K Report (File No.
1 - 905) for the year ended December 31,
1990)
4(a)-5 - Copy of Amendment No. 4 to
said Employee Stock Ownership Plan,
effective January 1, 1991 (Exhibit 4(a)-5
to the Company's Form 10-K Report (File No.
1 - 905) for the year ended December 31,
1991)
4(a)-6 - Copy of Amendment No. 5 to
said Employee Stock Ownership Plan,
effective October 23, 1991 (Exhibit 4(a)-6
to the Company's Form 10-K Report (File No.
1 - 905) for the year ended December 31,
1991)
4(a)-7 - Copy of Amendment No. 6 to
said Employee Stock Ownership Plan,
effective January 1, 1990 and January 1,
1992 (Exhibit 4(a)-7 to the Company's Form
10-K Report (File No. 1-905) for the year
ended December 31, 1991)
4(a)-8 - Copy of Amendment No. 7 to
said Employee Stock Ownership Plan,
effective January 1, 1992 (Exhibit 4(a)-8
to the Company's Form 10-K Report (File No.
1 - 905) for the year ended December 31,
1991)
4(a)-9 - Copy of Amendment No. 8 to said Employee
Stock Ownership Plan, effective July 1,
1992 (Exhibit 4(a)-9 to the Company's Form
10-K Report (File No. 1-905) for the year
ended December 31, 1992)
4(a)-10 - Copy of Amendment No. 9 to said Employee
Stock Ownership Plan, effective January 1,
1993 (Exhibit 4(a)-10 to the Company's Form
10-K Report (File No. 1 - 905) for the year
ended December 31, 1992)
4(a)-11 - Copy of Amendment No. 10 to said
Employee Stock Ownership Plan, effective
January 1, 1993 (Exhibit 4(a)-11 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1993)
*4(a)-12 - Copy of Amendment No. 11 to said
Employee Stock Ownership Plan, effective
January 1, 1994
*4(a)-13 - Copy of Amendment No. 12 to said
Employee Stock Ownership Plan, effective
January 1, 1994
*4(a)-14 - Copy of Amendment No. 14 to said
Employee Stock Ownership Plan, effective
January 1, 1989 and January 1, 1995
4(b)-l - Mortgage and Deed of Trust,
dated as of October l, 1945, between the
Company and Guaranty Trust Company of New
York (now Morgan Guaranty Trust Company of
New York), as Trustee (Exhibit 2(a)-4 to
Registration Statement No. 2-60291)
4(b)-2 - Supplement, dated as of July
1, 1954, to said Mortgage and Deed of Trust
(Exhibit 2(b)-5 to Registration Statement
No. 219255)
4(b)-3 - Supplement, dated as of June
l, 1966, to said Mortgage and Deed of Trust
(Exhibit 2(a)-l3 to Registration Statement
No. 2-60291)
4(b)-4 - Supplement, dated as of
November 1, 1967, to said Mortgage and Deed
of Trust (Exhibit 2(a)-14 to Registration
Statement No. 2-60291)
4(b)-5 - Supplement, dated as of
January 1, 1969, to said Mortgage and Deed
of Trust (Exhibit 2(a)-16 to Registration
Statement No. 2-60291)
4(b)-6 - Supplement, dated as of June
1, 1969, to said Mortgage and Deed of Trust
(Exhibit 2(a)-17 to Registration Statement
No. 2-60291)
4(b)-7 - Supplement, dated as of
February 1, 1971, to said Mortgage and Deed
of Trust (Exhibit 2(a)-19 to Registration
Statement No. 2-60291)
4(b)-8 - Supplement, dated as of
February 1, 1972, to said Mortgage and Deed
of Trust (Exhibit 2(a)-20 to Registration
Statement No. 2-60291)
4(b)-9 - Supplement, dated as of
January 1, 1973, to said Mortgage and Deed
of Trust (Exhibit 2(a)-21 to Registration
Statement No. 2-60291)
4(b)-10 - Supplement, dated as of June
15, 1985, to said Mortgage and Deed of
Trust (Exhibit 4(a)-35 to the Company's
Form l0-K Report (File No. l-905) for the
year ended December 31, 1985)
4(b)-11 - Supplement, dated as of
October 1, 1989, to said Mortgage and Deed
of Trust (Exhibit 4(a) to the Company's
Form 8-K Report (File No. 1-905) dated
November 6, 1989)
4(b)-12 - Supplement, dated as of
July 1, 1991, to said Mortgage and Deed of
Trust (Exhibit 4(a) to the Company's Form 8-
K Report (File No. 1-905) dated July 29,
1991)
4(b)-13 - Supplement, dated as of May 1,
1992, to said Mortgage and Deed of Trust
(Exhibit 4(a) to the Company's Form 8-K
Report (File No. 1-905) dated June 1, 1992)
4(b)-14 - Supplement, dated as of
November 1, 1992, to said Mortgage and Deed
of Trust (Exhibit 4(b)-29 to the Company's
Form 10-K Report (File 1-905) for the year
ended December 31, 1992)
4(b)-15 - Supplement, dated as of
February 1, 1993, to said Mortgage and Deed
of Trust (Exhibit 4(a) to the Company's
Form 8-K Report (File No. 1-905) dated
February 16, 1993)
4(b)-16 - Supplement, dated as of April
1, 1993, to said Mortgage and Deed of Trust
(Exhibit 4(a) to the Company's Form 8-K
Report (File No. 1-905) dated April 30,
1993
4(b)-17 - Supplement, dated as of June
1, 1993, to said Mortgage and Deed of Trust
(Exhibit 4(a) to the Company's Form 8-K
Report (File No. 1-905) dated July 7, 1993)
4(b)-18 - Supplement, dated as of
October 1, 1993, to said Mortgage and Deed
of Trust (Exhibit 4(a) to the Company's
Form 8-K Report (File No. 1-905) dated
October 29, 1993)
4(b)-19 - Supplement, dated as of February 15,
1994, to said Mortgage and Deed of Trust
(Exhibit 4(a) to the Company's Form 8-K
Report (File No. 1-905) dated March 11,
1994)
4(b)-20 - Supplement, dated as of March 1, 1994,
to said Mortgage and Deed of Trust (Exhibit
4(b) to the Company's Form 8-K Report (File
No. 1-905) dated March 11, 1994)
4(b)-21 - Supplement, dated as of March 15, 1994,
to said Mortgage and Deed of Trust (Exhibit
4(a) to the Company's Form 8-K Report (File
No. 1-905) dated March 30, 1994)
4(b)-22 - Supplement, dated as of September 1,
1994, to said Mortgage and Deed of Trust
(Exhibit 4(a) to the Company's Form 8-K
(File No. 1-905) dated October 3, 1994)
4(b)-23 - Supplement, dated as of October 1, 1994,
to said Mortgage and Deed of Trust (Exhibit
4(a) to the Company's Form 8-K Report (File
No. 1-905) dated October 3, 1994)
*l0(a)-1 - Revolving Credit Agreement,
dated as of August 30, 1994, between the
Company and the Banks named therein
l0(b) - Copy of Pollution Control
Facilities Agreement, dated as of May 1,
1973, between the Company and the Lehigh
County Industrial Development Authority
(Exhibit 5(z) to Registration Statement No.
2-60834)
l0(c)-l - Copy of Interconnection
Agreement, dated September 26, 1956, among
Public Service Electric & Gas Company,
Philadelphia Electric Company, the Company,
Baltimore Gas & Electric Company,
Pennsylvania Electric Company, Metropolitan
Edison Company, New Jersey Power & Light
Company and Jersey Central Power & Light
Company (Exhibit 5(e) to Registration
Statement No. 2-60291)
l0(c)-2 - Copy of Supplemental
Agreement, dated April 1, 1974, to said
Interconnection Agreement (Exhibit 5(f)-4
to Registration Statement No. 2-51312)
l0(c)-3 - Copy of Supplemental
Agreement, dated June 15, 1977, to said
Interconnection Agreement (Exhibit 5(e)-5
to Registration Statement No. 2-60291)
l0(c)-4 - Copy of Agreement of
Settlement and Compromise, dated July 25,
1980, among the parties to said
Interconnection Agreement (Exhibit 20(b)-8
to the Company's Form l0-Q Report (File No.
l-905) for the quarter ended September 30,
1980)
l0(c)-5 - Copy of Supplemental
Agreement, dated March 26, 1981, to said
Interconnection Agreement (Exhibit l0(b)-l0
to the Company's Form l0-K Report (File No.
1-905) for the year ended December 31,
1981)
l0(c)-6 - Copy of Revisions to Schedules
4.02, 7.01, and 9.01, all effective August
9, 1982, to said Interconnection Agreement
(Exhibit 10(e)-11 to the Company's Form l0-
K Report (File No. l-905) for the year
ended December 31, 1982)
l0(c)-7 - Copy of Schedules 4.02, 5.01,
5.02, 5.04, 5.05, 6.01, 6.03, 6.04, 7.01,
7.02 7.03; all effective February 6, 1984,
to said Interconnection Agreement (Exhibit
10(e)-8 to the Company's Form l0-K Report
(File No. 1-905) for the year ended
December 31, 1985)
l0(c)-8 - Copy of Schedule 5.03,
Revision l, Exhibit A, revised May 31,
1985, to said Interconnection Agreement
(Exhibit 10(e)-10 to the Company's Form
l0-K Report (File No. 1-905) for the year
ended December 31, 1985)
10(c)-9 - Copy of Schedule 4.02,
Revision No. 2, effective December 4, 1989,
to said Interconnection Agreement (Exhibit
10(d)-13 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1989)
10(c)-10 - Copy of Schedule 5.06,
Revision No. 1, effective June 1, 1990, to
said Interconnection Agreement (Exhibit
10(d)-14 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1990)
10(c)-11 - Copy of Schedule 2.21,
Revision No. 1, effective June 1, 1990, to
said Interconnection Agreement (Exhibit
10(d)-15 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1990)
10(c)-12 - Copy of Schedule 2.212,
Revision No. 2, effective June 1, 1990, to
said Interconnection Agreement (Exhibit
10(d)-16 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1990)
10(c)-13 - Copy of Schedule 9.01,
Revision No. 4, effective June 1, 1992, to
said Interconnection Agreement (Exhibit
10(d)-18 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1990)
10(c)-14 - Copy of Schedule 3.01,
Revision No. 3, effective June 1, 1992, to
said Interconnection Agreement (Exhibit
10(c)-15 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1991)
10(c)-15 - Copy of Schedule 4.01,
Revision No. 13, effective June 1, 1993, to
said Interconnection Agreement (Exhibit
10(c)-15 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1993)
l0(d) - Copy of Capacity and Energy
Sales Agreement, dated June 29, 1983,
between the Company and Atlantic City
Electric Company (Exhibit 10(f)-2 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1983)
10(e)-1 - Copy of Capacity and Energy
Sales Agreement, dated March 9, 1984,
between the Company and Jersey Central
Power & Light Company (Exhibit l0(f)-3 to
the Company's Form l0-K Report (File No. 1-
905) for the year ended December 31, 1984)
10(e)-2 - Copy of First Supplement,
effective February 28, 1986, to said
Capacity and Energy Sales Agreement
(Exhibit 10(e)-4 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1986)
10(e)-3 - Copy of Second Supplement,
effective January 1, 1987, to said Capacity
and Energy Sales Agreement (Exhibit 10(g)-3
to the Company's Form 10-K Report (File
No. 1-905) for the year ended December 31,
1989)
10(e)-4 - Copy of amendments to Exhibit
A, effective October 1, 1987, to said
Capacity and Energy Sales Agreement
(Exhibit 10(e)-6 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1987)
10(e)-5 - Copy of Third Supplement,
effective December 1, 1988, to said
Capacity and Energy Sales Agreement
(Exhibit 10(g)-5 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1989)
10(e)-6 - Copy of Fourth Supplement,
effective December 1, 1988, to said
Capacity and Energy Sales Agreement
(Exhibit 10(g)-6 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1989)
10(f)-1 - Copy of Capacity and Energy
Sales Agreement, dated December 21, 1989,
between the Company and GPU Service
Corporation (Exhibit 10(h) to the Company's
Form 10-K Report (File No. 1-905) for the
year ended December 31, 1989)
10(f)-2 - Copy of First Supplement,
effective June 1, 1991, to said Capacity
and Energy Sales Agreement between the
Company and GPU Service Corporation
(Exhibit 10(f)-2 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1991)
10(g)-1 - Copy of Capacity and Energy
Sales Agreement, dated January 28, 1988,
between the Company and Baltimore Gas and
Electric Company (Exhibit 10(e)-7 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1987)
10(g)-2 - Copy of First Supplement,
effective November 1, 1988, to said
Capacity and Energy Sales Agreement
(Exhibit 10(i)-2 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1989)
10(g)-3 - Copy of Second Supplement,
effective June 1, 1989, to said Capacity
and Energy Sales Agreement (Exhibit 10(i)-3
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1989)
10(g)-4 - Copy of Third Supplement,
effective June 1, 1991, to said Capacity
and Energy Sales Agreement between the
Company and Baltimore Gas & Electric
Company (Exhibit 10(g)-4 to the Company's
Form 10-K Report (File No. 1-905) for the
year ended December 31, 1991)
#10(h)-1 - Copy of Amended and Restated Directors
Deferred Compensation Plan, effective
January 1, 1990 (Exhibit 10(q) to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1990)
#10(h)-2 - Copy of Amendment No. 1 to said
Directors Deferred Compensation Plan,
effective January 1, 1991 (Exhibit 10(h)-2
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1991)
#10(h)-3 - Copy of Amendment No. 2 to said
Directors Deferred Compensation Plan,
effective October 23, 1991 (Exhibit 10(h)-3
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1991)
#10(h)-4 - Copy of Amendment No. 3 to said Directors
Deferred Compensation Plan, effective
January 1, 1992 and April 1, 1992 (Exhibit
10(h)-4 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1991)
#10(i)-1 - Copy of Directors Retirement Plan, effective
January 1, 1988 (Exhibit 10(f)-2 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1988)
#10(i)-2 - Copy of Amendment No. 1 to said Directors
Retirement Plan, effective January 1, 1991
(Exhibit 10(i)-2 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1991)
#10(i)-3 - Copy of Amendment No. 2 to said Directors
Retirement Plan, effective October 23, 1991
(Exhibit 10(i)-3 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1991)
#10(i)-4 - Copy of Amendment No. 3 to said Directors
Retirement Plan, effective January 1, 1992
(Exhibit 10(i)-4 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1991)
#10(j)-1 - Copy of Amended and Restated Deferred
Compensation Plan for Executive Officers,
effective January 1, 1990 (Exhibit 10(s) to
the Company's Form 10-K Report (File No. 1-
905) for the year ended December 31, 1990)
#10(j)-2 - Copy of Amendment No. 1 to said Officers
Deferred Compensation Plan, effective
January 1, 1991 (Exhibit 10(j)-2 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1991)
#10(j)-3 - Copy of Amendment No. 2 to said Officers
Deferred Compensation Plan, effective
October 23, 1991 (Exhibit 10(j)-3 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1991)
#10(j)-4 - Copy of Amendment No. 3 to said Officers
Deferred Compensation Plan, effective
January 1, 1992 and April 1, 1992 (Exhibit
10(j)-4 to the Company's Form 10-K Report
(File No. 1-905) for the year ended
December 31, 1991)
*#10(j)-5 - Copy of Amendment No. 4 to said Officers
Deferred Compensation Plan, effective
January 1, 1995
#l0(k)-1 - Copy of Supplemental Executive
Retirement Plan, effective January 1, 1987
(Exhibit 10(f)-3 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1986)
#10(k)-2 - Copy of Amendment No. 1 to said
Supplemental Executive Retirement Plan,
effective January 1, 1987 (Exhibit 10(f)-4
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1987)
#10(k)-3 - Copy of Amendment No. 2 to said
Supplemental Executive Retirement Plan,
effective January 1, 1990 (Exhibit 10(t)-3
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1990)
#10(k)-4 - Copy of Amendment No. 3 to said
Supplemental Executive Retirement Plan,
effective November 1, 1990 (Exhibit 10(t)-4
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1990)
#10(k)-5 - Copy of Amendment No. 4 to said
Supplemental Executive Retirement Plan,
effective January 1, 1991 (Exhibit 10(k)-5
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1991)
#10(k)-6 - Copy of Amendment No. 5 to said
Supplemental Executive Retirement Plan,
effective October 23, 1991 (Exhibit 10(k)-6
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1991)
#10(k)-7 - Copy of Amendment No. 6 to said
Supplemental Executive Retirement Plan,
effective January 1, 1992 (Exhibit 10(k)-7
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1991)
#10(k)-8 - Copy of Amendment No. 7 to said
Supplemental Executive Retirement Plan,
effective July 1, 1992 (Exhibit 10(k)-8 to
the Company's Form 10-K Report (File No. 1-
905) for the year ended December 31, 1992)
#10(k)-9 - Copy of Amendment No. 8 to said
Supplemental Executive Retirement Plan,
effective January 1, 1993 (Exhibit 10(k)-9
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1993)
*#10(k)-10- Copy of Amendment No. 9 to said Supplemental
Executive Retirement Plan, effective July
1, 1994
*#10(k)-11- Copy of Amendment No. 10 to said Supplemental
Executive Retirement Plan, effective
January 1, 1995
#10(l)-1- Copy of Executive Retirement Security Plan,
effective January 1, 1987 (Exhibit 10(f)-4
to the Company's Form 10-K Report (File No.
1-905) for the year ended December 31,
1986)
#10(l)-2 - Copy of Amendment No. 1 to said Executive
Retirement Security Plan, effective
January 1, 1987 (Exhibit 10(f)-6 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1987)
#10(l)-3 - Copy of Amendment No. 2 to said Executive
Retirement Security Plan, effective
January 1, 1990 (Exhibit 10(u)-3 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1990)
#10(l)-4 - Copy of Amendment No. 3 to said Executive
Retirement Security Plan, effective
November 1, 1990 (Exhibit 10(u)-4 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1990)
#10(l)-5 - Copy of Amendment No. 4 to said Executive
Retirement Security Plan, effective
January 1, 1991 (Exhibit 10(l)-5 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1991)
#10(l)-6 - Copy of Amendment No. 5 to said Executive
Retirement Security Plan, effective
October 23, 1991 (Exhibit 10(l)-6 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1991)
#10(l)-7 - Copy of Amendment No. 6 to said Executive
Retirement Security Plan, effective
January 1, 1992 (Exhibit 10(l)-7 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1991)
#10(l)-8 - Copy of Amendment No. 7 to said Executive
Retirement Security Plan, effective
January 1, 1993 (Exhibit 10(l)-8 to the
Company's Form 10-K Report (File No. 1-905)
for the year ended December 31, 1994)
*#10(l)-9 - Copy of Amendment No. 8 to said Executive
Retirement Security Plan, effective July 1,
1994
*#10(l)-10 - Copy of Amendment No. 9 to said Executive
Retirement Security Plan, effective
January 1, 1995 and upon the effectiveness
of the Agreement and Plan of Exchange
between the Company and PP&L Resources,
Inc.
*#10(l)-11 - Copy of Amendment No. 10 to said Executive
Retirement Security Plan, effective
January 1, 1995
#10(m)-1 - Copy of Amended and Restated Incentive
Compensation Plan, effective July 1, 1992
(Exhibit 10(m)-4 to the Company's Form 10-K
Report (File No. 1-905) for the year ended
December 31, 1992)
*#10(n) - Description of Executive Compensation
Incentive Award Program, effective
January 1, 1995 (Footnote 1/)
10(o) - Conformed copy of Nuclear Fuel Lease, dated
as of February 1, 1982, between the Com
pany, as lessee, and Newton I. Waldman, not
in his individual capacity, but solely as
Cotrustee of the Pennsylvania Power & Light
Energy Trust, as lessor (Exhibit 10(g) to
the Company's Form l0-K Report (File No. 1-
905) for the year ended December 31, 1981)
*12 - Computation of Ratio of Earnings to
Fixed Charges
*16 - Letter re: Change in Certifying Accountants
(Exhibit 16 to the Company's Form 8-K Report
(File No. 1-905) dated February 1, 1995)
*23 - Consent of Deloitte & Touche
*24 - Power of Attorney
*27 - Financial Data Schedule
*99 - Schedule of Property, Plant and
Equipment
________________________
Certain long-term debt instruments of the Company's
consolidated subsidiaries have been omitted from this filing
pursuant to 17 C.F.R. Section 229.601(b)(4)(iii)(A). The
Company will furnish a copy of any such instrument to the
Commission upon request.
_______________________________
Footnote 1/ This description is provided pursuant to 17
C.F.R. Section 229.601(b)(10)(iii)(A).
(PP&L LOGO
Appears Here)
Pennsylvania Power & Light Company
Two North Ninth Street - Allentown, PA 18101