SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[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, 1995
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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
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Commission file number: 1-672-2
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Rochester Gas and Electric Corporation
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(Exact name of registrant as specified in its charter)
New York 16-0612110
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(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (716) 546-2700
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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First Mortgage 8 3/8% Bonds due
September 15, 2007, Series CC New York Stock Exchange
Common Stock, $5 par value New York Stock Exchange
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
Securities registered pursuant to Section 12(g) of the Act:
Preferred Stock, $100 par value
4% Series F 4.95% Series K
4.10% Series H 4.55% Series M
4.75% Series I 7.50% Series N
4.10% Series J
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]
On January 1, 1996 the aggregate market value of the voting stock held by
nonaffiliates of the Registrant was $869,248,744.
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
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Indicate the number of shares outstanding of each of the registrant's
classes of common stock as of the latest practicable date.
Common Stock, $5 par value, at January 1, 1996, 38,453,163.
Documents Incorporated by Reference Part of Form 10-K
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Definitive proxy statement in connection III
with annual meeting of shareholders to be
held April 24, 1996.
ROCHESTER GAS AND ELECTRIC CORPORATION
Information Required on Form 10-K
Item
Number Description Page
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Part I
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Item 1 Business 1
Item 2 Properties 11
Item 3 Legal Proceedings 13
Item 4 Submission of Matters to a Vote of Security Holders 13
Item 4-A Executive Officers of the Registrant 13
Part II
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Item 5 Market for the Registrant's Common Equity and
Related Stockholder Matters 15
Item 6 Selected Financial Data 16
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 19
Item 8 Financial Statements and Supplementary Data 35
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 68
Part III
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Item 10 Directors, Executive Officers, Promoters and
Control Persons of the Registrant 69
Item 11 Executive Compensation 69
Item 12 Security Ownership of Certain Beneficial Owners and
Management 69
Item 13 Certain Relationships and Related Transactions 69
Part IV
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Item 14 Exhibits, Financial Statement Schedules and Reports
on Form 8-K 72
Signatures 75
1
PART I
Item 1. BUSINESS
The following are discussed under the general heading of "Business".
Reference is made to the various other Items as applicable.
CAPTION PAGE
- ------- ----
General 1
Financing and Capital Requirements Program 2
Regulatory Matters 3
Competition 4
Electric Operations 4
Gas Operations 6
Fuel Supply
Nuclear 6
Coal 7
Environmental Quality Control 7
Research and Development 8
Operating Statistics 9
GENERAL
Incorporated in 1904 in the State of New York, the Company supplies
electric and gas service wholly within that State. It produces and distributes
electricity and distributes gas in parts of nine counties centering about the
City of Rochester. At December 31, 1995 the Company had 2,046 employees.
The Company's service area has a population of approximately one
million and is well diversified among residential, commercial and industrial
consumers. In addition to the City of Rochester, which is the third largest city
and a major industrial center in New York State, it includes a substantial
suburban area with commercial growth and a large and prosperous farming area. A
majority of the industrial firms in the Company's service area manufacture
consumer goods. Many of the Company's industrial customers are nationally
known, such as Xerox Corporation, Eastman Kodak Company, General Motors
Corporation, and Bausch & Lomb Incorporated.
The business of the Company is seasonal. With respect to electricity,
winter peak loads are attained due to spaceheating sales and shorter daylight
hours and summer peak loads are reached due to the use of air-conditioning and
other cooling equipment. With respect to gas, the greatest sales occur in the
winter months due to spaceheating usage.
In each of the communities in which it renders service, the Company,
with minor exceptions, holds the necessary municipal franchises, none of which
contains burdensome restrictions. The franchises are non-exclusive, and are
either unlimited as to time or run for terms of years. The Company anticipates
renewing franchises as they expire on a basis substantially the same as at
present.
Information concerning revenues, operating profits and identifiable
assets for significant industry segments is set forth in Note 4 of the Notes to
the Company's financial statements under Item 8. Information relating to the
principal classes of service from which electric and gas revenues are derived
and other operating data are included herein under "Operating Statistics". A
2
discussion of the causes of significant changes in revenues is presented in Item
7 - Management's Discussion and Analysis of Financial Condition and Results of
Operations. Percentages of the Company's operating revenues derived from
electric and gas operations for each of the last three years are as follows:
1995 1994 1993
------ ------ ------
Electric 71.1% 67.4% 69.1%
Gas 28.9% 32.6% 30.9%
----- ----- -----
100.0% 100.0% 100.0%
FINANCING AND CAPITAL REQUIREMENTS PROGRAM
A discussion of the Company's capital requirements and the resources
available to meet such requirements may be found in Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of Operations. In
addition to those issues discussed in Item 7, the sale of additional securities
depends on regulatory approval and the Company's ability to meet certain
requirements contained in its mortgage and Restated Certificate of
Incorporation.
Under the New York State Public Service Law, the Company is required
to secure authorization from the Public Service Commission of the State of New
York (PSC) prior to issuance of any stock or any debt having a maturity of more
than one year.
The Company's First Mortgage Bonds are issued under a General Mortgage
dated September 1, 1918, between the Company and Bankers Trust Company, as
Trustee, which has been amended and supplemented by thirty-nine supplemental
indentures. Before additional First Mortgage Bonds are issued, the following
financial requirements must be satisfied:
(a) The First Mortgage prohibits the issuance of additional First Mortgage
Bonds unless earnings (as defined) for a period of twelve months ending not
earlier than sixty days prior to the issue date of the additional bonds are
at least 2.00 times the annual interest charges on First Mortgage Bonds,
both those outstanding and those proposed to be outstanding. The ratio
under this test for the twelve months ended December 31, 1995 was 5.39.
(b) The First Mortgage also provides that, if additional First Mortgage Bonds
are being issued on the basis of property additions (as defined), the
principal amount of the bonds may not exceed 60% of available property
additions. As of December 31, 1995 the amount of additional First Mortgage
Bonds which could be issued on that basis was approximately $375,124,000.
In addition to issuance on the basis of property additions, First Mortgage
Bonds may be issued on the basis of 100% of the principal amount of other
First Mortgage Bonds which have been redeemed, paid at maturity, or
otherwise reacquired by the Company. As of December 31, 1995, the Company
could issue $195,334,000 of Bonds against Bonds that have matured or been
redeemed.
The Company's Restated Certificate of Incorporation (Charter) provides
that, without consent by two-thirds of the votes entitled to be cast by the
preferred stockholders, the Company may not issue additional preferred stock
unless in a 12-month period within the preceding 15 months: (a) net earnings
applicable to payment of dividends on preferred stock, after taxes, have been at
least 2.00 times the annual dividend requirements on preferred stock, including
the shares both outstanding and proposed to be issued, and (b) net earnings
available for interest on indebtedness, after taxes, have been at least 1.50
times the annual interest requirements on indebtedness and annual dividend
requirements on preferred stock, including the shares both outstanding and
3
proposed to be issued. For the twelve months ended December 31, 1995, the
coverage ratio under (b) above (the more restrictive provision) was 2.31.
For information with respect to short-term borrowing arrangements and
limitations see Item 8, Note 9 - Short-Term Debt.
The Company's Charter does not contain any financial tests
for the issuance of preference or common stock.
The Company's securities ratings at December 31, 1995 were:
First
Mortgage Preferred
Bonds Stock
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Standard & Poor's Corporation BBB+ BBB
Moody's Investors Service Baa1 baa2
Duff & Phelps BBB+ BBB
The securities ratings set forth in the table are subject to revision
and/or withdrawal at any time by the respective rating organizations and should
not be considered a recommendation to buy, sell or hold securities of the
Company.
REGULATORY MATTERS
The Company is subject to PSC regulation of rates, service, and sale
of securities, among other matters. The Company is also regulated by the
Federal Energy Regulatory Commission (FERC) on a limited basis, in the areas of
interstate sales and exchanges of electricity, intrastate sales of electricity
for resale, transmission wheeling service for other utilities, and licensing of
hydroelectric facilities. As a licensee of nuclear facilities, the Company is
also subject to regulation by the Nuclear Regulatory Commission.
On August 17, 1995, the Company announced that a negotiated settlement
had been reached with the Staff of the PSC and other parties which resolved
various proceedings relative to its gas costs. The settlement was approved by
the PSC on October 18, 1995. See Item 8, Note 10 under the heading "Gas Cost
Recovery" for further information related to the 1995 Gas Settlement.
See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations under the heading "Rates and Regulatory
Matters" for summaries of recent PSC rate decisions, the 1993 Rate Agreement and
the 1995 Rate Proposal.
Under its flexible pricing tariff for major industrial and commercial
electric customers, the Company may negotiate competitive electric rates at
discount prices to compete with alternative power sources, such as customer-
owned generation facilities. Under the terms of the 1993 Rate Agreement, the
Company would absorb 30 percent of any net revenues lost as a result of such
discounts through June 1996, while the remaining 70 percent would be recovered
from other customers. The Company has not sought recovery of that 70 percent
from other customers. The portion recoverable after June 1996 is expected to be
determined by the PSC as it considers the 1995 Rate Proposal. Under the
flexible tariff provisions, the Company as of year-end 1995 had negotiated long-
term electric supply contracts with twenty of its large industrial and
commercial electric customers at discounted rates. The Company is negotiating
long-term electric supply contracts with other large customers as the need and
opportunity arise. The Company has not experienced any customer loss due to
competitive alternative arrangements.
4
The United States Department of Justice, Antitrust Division, has
issued a Civil Investigative Demand calling for the production of documents and
answers to interrogatories concerning the electric industry and competititon.
The Company has been informed that the Antitrust Division has not concluded that
there is an antitrust violation, and that it is not a target of this
investigation, since there are no targets. The Company is cooperating with the
investigation.
COMPETITION
The Company is operating in an increasingly competitive environment.
See Item 7 - Management's Discussion and Analysis of Financial Condition and
Results of Operations under the heading "Competition" for information on the
competitive challenges the Company faces in its electric and gas business and
how it proposes to respond to those challenges.
ELECTRIC OPERATIONS
The total net generating capacity of the Company's electric system is
1,244,000 Kw. In addition the Company purchases 120,000 Kw of firm power under
contract and 35,000 Kw of non-contractual peaking power from the Power
Authority, 150,000 Kw of a 1,000,000 Kw pumped storage plant owned by the Power
Authority in Schoharie County, New York, 50,000 Kw of firm power from the Power
Authority's 821,000 Kw FitzPatrick Nuclear Power Plant near Oswego, New York and
20,000 Kw of firm power from Hydro-Quebec purchased through the Power Authority.
The Company's net peak load of 1,425,000 Kw occurred on August 15, 1995
The percentages of electricity actually generated and purchased for the
years 1991-1995 are as follows:
1995 1994 1993 1992 1991
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Sources of Generated Energy:
Nuclear 52.8% 55.3% 57.6% 52.1% 53.8%
Fossil-Coal* 18.6 16.9 18.2 24.4 23.0
-Oil - 1.2 1.3 2.9 3.3
Hydro and Other 2.0 2.7 2.6 3.5 2.1
----- ----- ----- ----- -----
Total Generated Net 73.4 76.1 79.7 82.9 82.2
Purchased 26.6 23.9 20.3 17.1 17.8
----- ----- ----- ----- -----
Total Electric Energy 100.0% 100.0% 100.0% 100.0% 100.0%
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* Beginning in 1996 Russell Station, Unit 1 (47Mw) is on cold standby.
The Company, six other New York utilities and the Power Authority are
members of the New York Power Pool. The primary purposes of the Power Pool are
to coordinate inter-utility sales of bulk power, long range planning of
generation and transmission facilities, and inter-utility operating and
emergency procedures in order to better assure reliable, adequate and economic
electric service throughout the State. By agreement with the other members of
the New York Power Pool, the Company is required to maintain a reserve
generating capacity equal to at least 18% of its forecasted peak load. The
Company expects to have reserve margins, which include purchased energy under
long-term firm contractual arrangements, of 22%, 21% and 20% for the years 1996,
1997 and 1998, respectively.
The Company's five major generating facilities are two nuclear units,
the Ginna Nuclear Plant (Ginna Plant) and the Company's 14% share of Nine Mile
Point Nuclear Plant Unit No. 2 (Nine Mile Two), and three fossil fuel generating
5
stations, the Russell and Beebee Stations and the Company's 24% share of Oswego
Unit Six. In terms of capacity these comprise 39%, 13%, 21%, 6% and 15%,
respectively, of the Company's current electric generating system.
Nine Mile Two, a nuclear generating unit in Oswego County, New York
with a capability of 1,143 megawatts (Mw)as estimated by Niagara Mohawk Power
Corporation (Niagara), was completed and entered commercial service in Spring
1988. Niagara is operating the Unit on behalf of all owners pursuant to a full
power operating license which the NRC issued on July 2, 1987 for a 40-year term
beginning October 31, 1986. Under arrangements dating from September 1975,
ownership, output and cost of the project are shared by the Company (14%),
Niagara (41%) Long Island Lighting Company (18%), New York State Electric & Gas
Corporation (18%) and Central Hudson Gas & Electric Corporation (9%). Under the
operating Agreement, Niagara serves as operator of Nine Mile Two, but all five
cotenant owners share certain policy, budget and managerial oversight functions.
The base term of the Operating Agreement is 24 months from its effective date,
with automatic extension, unless terminated by written notice of one or more of
the cotenant owners to the other cotenant owners; such termination becomes
effective six months from the receipt of any such notice of termination by all
the cotenant owners receiving such notice.
The Company has four licensed hydroelectric generating stations with
an aggregate capability of 47 megawatts. Although applications for renewal of
those licenses were timely made in 1991, the FERC was unable to complete
processing of many such applications by the December 31, 1993 license
expiration. The Company and many other hydro project owners are thus operating
under FERC annual licenses that essentially extend the terms of the old licenses
year-to-year until processing of new ones can be completed. Overly stringent
environmental conditions or other governmental requirements could nullify or
seriously impair the economic viability of one or more of these stations.
The Company's Ginna Plant, which has been in commercial operation
since July 1, 1970, provides 480 Mw of the Company's electric generating
capacity. In August 1991 the NRC approved the Company's application for
amendment to extend the Ginna Plant operating license expiration date from April
25, 2006 to September 18, 2009. See Item 7 - Management's Discussion and
Analysis of Financial Condition and Results of Operations under the Liquidity
and Capital Resources section for a discussion of the replacement of the steam
generators at the Ginna Plant.
The gross and net book cost of the Ginna Plant as of December 31, 1995
are $503 million and $260 million, respectively. From time to time the NRC
issues directives requiring all or a certain group of reactor licensees to
perform analyses as to their ability to meet specified criteria, guidelines or
operating objectives and where necessary to modify facilities, systems or
procedures to conform thereto. Typically, these directives are premised on the
NRC's obligation to protect the public health and safety. The Company reviews
such directives and implements a variety of modifications based on these
directives and resulting analyses. Expenditures, including AFUDC, at the Ginna
Plant (including the cost of these modifications and $51.0 million in 1996 for
steam generator replacement) are estimated to be $60.2 million, $7.6 million and
$5.2 million for the years 1996, 1997 and 1998, respectively, and are included
in the capital expenditure amounts presented under Item 7 - Management's
Discussion and Analysis of Financial Condition and Results of Operations.
See Item 8, Note 10 - Commitments and Other Matters, "Nuclear-Related
Matters", for a discussion relating to nuclear insurance including information
on coverages and maximum assessments.
6
GAS OPERATIONS
The total daily capacity of the Company's gas system, reflecting the
maximum demand which the transmission system can accept without a deficiency, is
5,230,000 Therms (one Therm is equivalent to 1,000,000 British Thermal Units).
On January 19, 1994, the Company experienced its maximum daily throughput of
approximately 4,735,690 Therms.
As a result of the implementation of FERC Order 636, and the
commencement of operation of the Empire State Pipeline (Empire), the Company now
purchases all of its required gas supply from numerous producers and marketers
under contracts containing varying terms and conditions. The Company
anticipates no problem with obtaining reliable, competitively priced natural gas
in the future. See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations under the captions "Energy Management and
Costs - Gas" for a discussion of that topic and "Capital Requirements and Gas
Operations" for a discussion of Empire.
The Company continues to provide new and additional gas service. Of
238,267 residential gas spaceheating customers at December 31, 1995, 2,954 were
added during 1995, and 25% of those were conversions from other fuels.
Approximately 28% of the gas delivered to customers by the Company
during 1995 was purchased directly by commercial, industrial and municipal
customers from brokers, producers and pipelines. The Company provided the
transportation of gas on its system to these customers' premises.
FUEL SUPPLY
Nuclear. Generally, the nuclear fuel cycle consists of the following:
(1) the procurement of uranium concentrate (yellowcake), (2) the conversion of
uranium concentrate to uranium hexafluoride, (3) the enrichment of the uranium
hexafluoride, (4) the fabrication of fuel assemblies, (5) the utilization of the
nuclear fuel in generating station reactors and (6) the appropriate storage or
disposition of spent fuel and radioactive wastes. Arrangements for nuclear fuel
materials and services for the Ginna Plant and Nine Mile Two have been made to
permit operation of the units through the years indicated:
Ginna Plant Nine Mile Two/(1)/
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Uranium Concentrate 2000/(3)/ 2002/(2)/
Conversion 2000/(4)/ 2002/(2)/
Enrichment (5) (5)
Fabrication 2001 2003
(1) Information was supplied by Niagara Mohawk Power Corporation.
(2) Arrangements have been made for procuring the majority of the uranium and
conversion requirements through 2002, leaving the remaining portion of the
requirements uncommitted.
(3) A contract is in place with flexibility to supply from 20 to 80 percent of
the annual Ginna Plant uranium requirements. A second contract is in place
to supply about 30% of the annual requirements for 1996 through 1999, and
100% of requirements in 2000. The remaining requirements are uncommitted.
(4) Seventy percent of the conversion requirements have been procured through
1997 under one contract. A second contract is in place covering 30% of
requirements through 1999 and 100% in 2000. Seventy percent of
requirements remain to be purchased for 1998.
7
(5) Thirty years from 1984 or life of reactor, whichever is less. See the
following discussion.
The Company has a contract with United States Enrichment Corporation
(USEC) for nuclear fuel enrichment services which assures provision of 70% of
the Ginna Plant's requirements throughout its service life or 30 years,
whichever is less. For further information concerning this contract see Item 8,
Note 10 under the heading "Nuclear Fuel Enrichment Services".
The Company is pursuing arrangements for the supply of uranium
requirements and related services beyond those years for which arrangements have
been made as shown above. The prices and terms of any such arrangements cannot
be predicted at this time.
The average annual cost of nuclear fuel per million BTU used for electric
generation for the last five years is as follows:
1995 1994 1993 1992 1991
----- ----- ----- ----- -----
Ginna Plant $.410 $.403 $.400 $.359 $.442
Nine Mile Two $.503 $.481 $.515 $.558 $.714
See Note 10 of the Notes to Financial Statements under Item 8 for
additional information regarding nuclear fuel disposal costs, nuclear plant
decommissioning and DOE uranium enrichment facility decontamination and
decommissioning.
Coal. The Company's present annual coal requirement is approximately
560,000 tons. In 1995 approximately 70% of its requirements were purchased
under contract and the balance on the open market. The Company is meeting its
requirements during early 1996 through contract purchases. Normally, the Company
maintains a reserve supply of coal ranging from a 30 to a 60 day supply at
maximum burn rates.
The sulfur content of the coal utilized in the Company's existing
coal-fired facilities ranges from 1.0 to 1.9 pounds per million BTU. Under
existing New York State regulations, the Company's coal-fired facilities may not
burn coal which exceeds 2.5 pounds per million BTU, which averages more than 1.9
pounds per million BTU over a three-month period or which averages more than 1.7
pounds per million BTU over a 12-month period.
The average annual delivered cost of coal used for electric generation was
as follows:
1995 1994 1993 1992 1991
---- ---- ---- ---- ----
Per Million BTU $1.31 $1.38 $1.42 $1.48 $1.61
ENVIRONMENTAL QUALITY CONTROL
Operations at the Company's facilities are subject to various Federal,
state and local environmental standards. To assure the Company's compliance
with these requirements, the Company expended approximately $3.6 million on a
variety of projects and facility additions during 1995.
The Company is monitoring a public concern tending to associate health
effects with electromagnetic fields from power lines. Together with other New
York utilities, the Company funded some of the earliest governmentally-directed
8
research on the question and it continues, with other electric utilities
nationwide, to underwrite a broad program of industry-sponsored research in this
area. The Company also participated with other New York utilities in compiling
information on the state's existing high voltage lines in an initiative which
served as a basis for PSC adoption of field limits applicable to the
construction of new high voltage lines. The Company has no definitive plans to
construct new high voltage lines for its system, but, in connection with Clean
Air Act compliance and planning of generation resources, it is considering
possible transmission reinforcements; at least one option could require such
construction. On request, the Company performs surveys of electromagnetic fields
on customer premises. None of its lines have been found to exceed the State
field limits applicable to new construction.
The federal Low Level Radioactive Waste Policy Act (Act), as amended
in 1985, provides for states to join compacts or individually develop their own
low level radioactive waste disposal sites. The portion of the Act that
requires a state which fails to provide access to a licensed disposal site by
1996 to take title to such waste was declared unconstitutional by the United
States Supreme Court on June 19, 1992, but the court upheld other provisions of
the Act enabling sited states to increase charges on shipments from non-sited
states and ultimately to refuse such shipments altogether. The Company can
provide no assurance as to what disposal arrangements, if any, New York will
have in place. The State has not passed legislation that would designate a site
for the disposal of low level radioactive waste. The Company has interim
storage capacity at the Ginna Plant through mid-1999. Efforts will be pursued
to extend storage capacity beyond mid-1999, if necessary, at this plant. A low
level radioactive waste management and contingency plan is currently ongoing to
provide assurance that Nine Mile Two will be properly prepared to handle interim
storage of low level radioactive waste for the next ten years.
The Company believes that additional expenditures and costs made necessary
by environmental regulations will be fully allowable for ratemaking purposes.
Expenditures for meeting various federal, State and local environmental
standards are estimated to be $4.4 million for the year 1996 $6.2 million for
the year 1997 and $4.3 million for the year 1998. These expenditures are
included under Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations, in the table entitled "Capital
Requirements".
See Item 7 - Management's Discussion and Analysis of Financial Condition
and Results of Operations and Item 8, Note 10 - Commitments and Other Matters,
with respect to other environmental matters.
RESEARCH AND DEVELOPMENT
The Company's research activities are designed to improve existing
energy technologies and to develop new technologies for the production,
distribution, utilization and conservation of energy while preserving
environmental quality. Research and development expenditures in 1995, 1994 and
1993 were $5.2 million, $7.3 million, and $8.3 million, respectively. These
expenditures represent the Company's contribution to research administered by
Electric Power Research Institute and Empire State Electric Energy Research
Corporation, the Company's share of research related to Nine Mile Two, an
assessment for state government sponsored research by the New York State Energy
Research and Development Authority, as well as internal research projects.
9
Electric Department Statistics
Year Ended December 31 1995 1994 1993 1992 1991 1990
------------ ------------ ------------ ------------ ----------- -----------
Electric Revenue (000's)
Residential $ 254,292 $ 243,593 $ 235,286 $ 220,866 $ 212,327 $ 197,612
Commercial 214,491 206,910 196,456 184,815 181,561 165,445
Industrial 157,496 150,690 147,396 142,392 141,001 130,012
Other (includes unbilled
revenue) 70,302 56,955 59,817 60,194 54,041 58,861
---------- ---------- ---------- ---------- ---------- ----------
Electric revenue from our
customers 696,581 658,148 638,955 608,267 588,930 551,930
Other electric utilities 25,884 16,605 16,361 25,541 28,612 42,465
---------- ---------- ---------- ---------- ---------- ----------
Total electric revenue 722,465 674,753 655,316 633,808 617,542 594,395
---------- ---------- ---------- ---------- ---------- ----------
Electric Expense (000's)
Fuel used in electric
generation 44,190 44,961 45,871 48,376 65,105 76,420
Purchased electricity 54,167 37,002 31,563 29,706 27,683 34,264
Other operation 195,181 187,594 188,684 183,118 168,610 155,289
Maintenance 44,032 47,295 52,464 53,714 57,032 53,880
Depreciation and
amortization 78,812 75,211 72,326 73,213 72,746 67,302
Taxes - local, state and
other 102,380 97,919 96,043 94,841 86,925 77,323
---------- ---------- ---------- ---------- ---------- ----------
Total electric expense 518,762 489,982 486,951 482,968 478,101 464,478
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 203,703 184,771 168,365 150,840 139,441 129,917
Federal income tax 59,500 52,842 43,845 38,046 31,390 30,670
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Electric Operations (000's) $ 144,203 $ 131,929 $ 124,520 $ 112,794 $ 108,051 $ 99,247
---------- ---------- ---------- ---------- ---------- ----------
Electric Operating Ratio % 46.7 47.0 48.6 49.7 51.6 53.8
Electric Sales - KWH (000's)
Residential 2,144,718 2,117,168 2,123,277 2,084,705 2,087,910 2,066,859
Commercial 2,064,813 2,028,611 1,986,100 1,938,173 1,931,024 1,890,029
Industrial 1,964,975 1,860,833 1,892,700 1,929,720 1,920,075 1,923,935
Other 531,311 513,675 504,987 503,388 508,368 488,121
---------- ---------- ---------- ---------- ---------- ----------
Total customer sales 6,705,817 6,520,287 6,507,064 6,455,986 6,447,377 6,368,944
Other electric utilities 1,484,196 1,021,733 743,588 1,062,738 1,034,370 1,316,379
---------- ---------- ---------- ---------- ---------- ----------
Total electric sales 8,190,013 7,542,020 7,250,652 7,518,724 7,481,747 7,685,323
---------- ---------- ---------- ---------- ---------- ----------
Electric Customers at
December 31
Residential 306,601 304,494 302,219 300,344 298,440 296,110
Commercial 30,426 29,984 29,635 29,339 28,856 28,804
Industrial 1,347 1,361 1,382 1,386 1,388 1,428
Other 2,711 2,670 2,638 2,605 2,558 2,553
---------- ---------- ---------- ---------- ---------- ----------
Total electric customers 341,085 338,509 335,874 333,674 331,242 328,895
---------- ---------- ---------- ---------- ---------- ----------
Electricity Generated and
Purchased - KWH (000's)
Fossil 1,631,933 1,478,120 1,520,936 2,197,757 2,146,664 2,505,110
Nuclear 4,645,646 4,527,178 4,495,457 4,191,035 4,391,480 4,016,721
Hydro 171,886 218,129 199,239 278,318 174,239 244,539
Pumped storage 237,904 247,550 233,477 226,391 240,206 269,966
Less energy for pumping (361,144) (371,383) (355,725) (344,245) (364,520) (405,966)
Other 1,565 1,245 2,559 811 1,269 20,408
---------- ---------- ---------- ---------- ---------- ----------
Total generated - net 6,327,790 6,100,839 6,095,943 6,550,067 6,589,338 6,650,778
Purchased 2,343,484 1,998,882 1,646,244 1,389,875 1,451,208 1,498,089
---------- ---------- ---------- ---------- ---------- ----------
Total electric energy 8,671,274 8,099,721 7,742,187 7,939,942 8,040,546 8,148,867
---------- ---------- ---------- ---------- ---------- ----------
System Net Capability -
KW at December 31
Fossil 529,000 532,000 541,000 541,000 541,000 541,000
Nuclear 640,000 617,000 620,000 617,000 622,000 621,000
Hydro 47,000 47,000 47,000 47,000 47,000 47,000
Other 28,000 29,000 29,000 29,000 29,000 29,000
Purchased 375,000 375,000 347,000 348,000 354,000 356,000
---------- ---------- ---------- ---------- ---------- ----------
Total system net
capability 1,619,000 1,600,000 1,584,000 1,582,000 1,593,000 1,594,000
---------- ---------- ---------- ---------- ---------- ----------
Net Peak Load - KW 1,425,000 1,374,000 1,333,000 1,252,000 1,297,000 1,208,000
Annual Load Factor - Net % 57.6 58.8 59.1 62.5 61.7 64.6
10
Gas Department Statistics
Year Ended December 31 1995 1994 1993 1992 1991 1990
----------- ----------- ---------- ---------- ----------- -----------
Gas Revenue (000's)
Residential $ 4,081 $ 5,935 $ 5,526 $ 6,456 $ 6,354 $ 6,508
Residential spaceheating 226,946 221,927 196,411 183,405 157,458 159,501
Commercial 48,938 50,318 45,620 44,274 40,196 43,534
Industrial 6,293 7,254 6,346 6,418 6,761 9,674
Municipal and other
(Includes unbilled revenue) 7,605 40,627 39,805 21,171 24,959 17,279
---------- ---------- ---------- ---------- ---------- ----------
Total gas revenue 293,863 326,061 293,708 261,724 235,728 236,496
---------- ---------- ---------- ---------- ---------- ----------
Gas Expense (000's)
Gas purchased for resale 167,762 194,390 166,884 141,291 129,779 132,512
Other operation 58,727 48,302 46,697 43,506 39,830 39,307
Maintenance 5,194 7,774 9,229 9,006 8,383 8,510
Depreciation 12,781 12,250 11,851 11,815 11,435 10,465
Taxes - local, state and other 31,514 31,859 30,849 29,411 26,724 23,711
---------- ---------- ---------- ---------- ---------- ----------
Total gas expense 275,978 294,575 265,510 235,029 216,151 214,505
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 17,885 31,486 28,198 26,695 19,577 21,991
Federal income tax 6,715 8,403 5,485 5,545 2,869 3,820
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Gas Operations (000's) $ 11,170 $ 23,083 $ 22,713 $ 21,150 $ 16,708 $ 18,171
---------- ---------- ---------- ---------- ---------- ----------
Gas Operating Ratio % 79.7 76.8 75.9 74.1 75.5 76.3
Gas Sales - Therms (000's)
Residential 7,167 6,535 6,871 8,780 9,151 9,067
Residential spaceheating 280,763 283,039 295,093 287,623 255,988 246,749
Commerical 68,380 72,410 78,887 78,996 72,167 72,971
Industrial 9,560 11,420 12,030 12,438 13,120 17,427
Municipal 8,219 10,230 12,188 11,410 10,677 12,551
---------- ---------- ---------- ---------- ---------- ----------
Total gas sales 374,089 383,634 405,069 399,247 361,103 358,765
Transportation of customer-owned gas 146,149 136,372 124,436 126,140 109,835 101,985
---------- ---------- ---------- ---------- ---------- ----------
Total gas sold and transported 520,238 520,006 529,505 525,387 470,938 460,750
---------- ---------- ---------- ---------- ---------- ----------
Gas Customers at December 31
Residential 17,443 17,836 18,389 19,114 21,448 22,410
Residential spaceheating 238,267 235,313 231,937 228,096 222,918 219,242
Commercial 18,978 18,742 18,636 18,378 18,151 17,920
Industrial 879 905 924 932 921 960
Municipal 981 988 1,001 1,010 983 984
Transportation 655 558 466 424 423 401
---------- ---------- ---------- ---------- ---------- ----------
Total gas customers 277,203 274,342 271,353 267,954 264,844 261,917
---------- ---------- ---------- ---------- ---------- ----------
Gas - Therms (000's)
Purchased for resale 237,728 262,267 347,778 360,493 384,643 366,684
Gas from storage 152,852 134,802 76,378 53,757 16,755 -
Other 1,800 2,959 1,039 1,061 1,617 2,525
---------- ---------- ---------- ---------- ---------- ----------
Total gas available 392,380 400,028 425,195 415,311 403,015 369,209
---------- ---------- ---------- ---------- ---------- ----------
Cost of gas per therm (cents) 45.80c 50.00c 36.79c 35.35c 32.96c 36.03c
Total Daily Capacity - Therms
at December 31* 5,230,000 5,625,000 5,625,000 4,485,000 4,485,000 4,485,000
---------- ---------- ---------- ---------- ---------- ----------
Maximum daily throughput - Therms 3,980,000 4,735,690 3,864,850 3,768,470 3,539,260 3,539,820
Degree Days (Calendar Month)
For the period 6,535 6,699 7,044 6,981 6,146 5,924
Percent colder (warmer) than normal (3.0) (0.6) 4.4 3.4 (8.4) (11.8)
* Method for determining daily capacity, based on current network analysis,
reflects the maximum demand which the transmission systems can accept without
a deficiency.
11
Item 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of the Company's electric generating plants in
operation as of December 31, 1995, the net generation of each plant for the year
ended December 31, 1995, and the year each plant was placed in service are as
set forth below:
Electric Generating Plants
Net
Year Unit Net Generation
Placed in Capability thousands
Type of Fuel Service (Mw) (kwh)
------------ --------- ---------- ----------
Beebee Station
(Steam) Coal 1959 80 431,524
Beebee Station
(Gas Turbine) Oil 1969 14 145
Russell Station*
(Steam) Coal 1949-1957 260 1,200,409
Ginna Station
(Steam) Nuclear 1970 480 3,633,282
Oswego Unit 6/(1)/
(Steam) Oil 1980 189 1,311
Nine Mile Point
Unit No. 2/(2)/
(Steam) Nuclear 1988 160** 1,012,364
Sation No. 9
(Gas Turbine) Gas 1969 14 109
Station 5
(Hydro) Water 1917 39 119,260
5 Other Stations
(Hydro) Water 1906-1960 8 52,626
----- ---------
6,451,030
Pumped Storage /(3)/ 237,904
Less: energy for pumping (361,144)
---------
1,244 6,327,790
===== =========
(1) Represents 24% share of jointly-owned facility.
(2) Represents 14% share of jointly-owned facility.
(3) Owned and operated by the Power Authority.
* Beginning in 1996 Unit 1 (47Mw) on cold standby.
** As estimated by Niagara Mohawk Power Corporation.
12
The Company owns 147 distribution substations having an aggregate
rated transformer capacity of approximately 2,092,354 Kva, of which 138, having
an aggregate rated capacity of 1,913,188 Kva, were located on lands owned in
fee, and nine of which, having an aggregate rated capacity of 179,166 Kva, were
located on land under easements, leases or license agreements. The Company also
has 75,131 line transformers with a capacity of 2,967,809 Kva. The Company also
owns 24 transmission substations having an aggregate rated capacity of
approximately 3,052,017 Kva of which 23, having an aggregate rated capacity of
approximately 2,977,350 Kva, were located on land owned in fee and one, having a
rated capacity of 74,667 Kva, was located on land under easements. The
Company's transmission system consists of approximately 710 circuit miles of
overhead lines and 399 circuit miles of underground lines. The distribution
system consists of approximately 16,160 circuit miles of overhead lines,
approximately 3,649 circuit miles of underground lines and 348,980 installed
meters. The electric transmission and distribution system is entirely
interconnected and, in the central portion of the City of Rochester, is
underground. The electric system of the Company is directly interconnected with
other electric utility systems in New York and indirectly interconnected with
most of the electric utility systems in the United States and Canada. (See Item
1 - Business, "Electric Operations".)
GAS PROPERTIES
The gas distribution systems consists of 4,195 miles of gas mains and
286,807 installed meters. (See Item 1 - Business, "Gas Operations" and "Gas
Department Statistics".
OTHER PROPERTIES
The Company owns a ten-story office building centrally located in
Rochester and other structures and property. The Company also leases
approximately 485,000 square feet of facilities for administrative offices and
operating activities in the Rochester area.
The Company has good title in fee, with minor exceptions, to its
principal plants and important units, except rights of way and flowage rights,
subject to restrictions, reservations, rights of way, leases, easements,
covenants, contracts, similar encumbrances and minor defects of a character
common to properties of the size and nature of those of the Company. The
electric and gas transmission and distribution lines and mains are located in
part in or upon public streets and highways and in part on private property,
either pursuant to easements granted by the apparent owner containing in some
instances removal and relocation provisions and time limitations, or without
easements but without objection of the owners. The First Mortgage securing the
Company's outstanding bonds is a first lien on substantially all the property
owned by the Company (except cash and accounts receivable). A mortgage securing
the Company's revolving credit agreement is also a lien on substantially all the
property owned by the Company (except cash and accounts receivable) subject and
subordinate to the lien of the First Mortgage. The Company has a credit
agreement with a domestic bank under which short-term borrowings are secured by
the Company's accounts receivable.
13
Item 3. LEGAL PROCEEDINGS
See Item 8, Note 10 - Commitments and Other Matters.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
There were no matters submitted to a vote of security holders during
the fourth quarter of the fiscal year ended December 31, 1995.
Item 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT
Age Positions, Offices and Business Experience
Name 12/31/95 1991 to date
- ---- -------- ----------------------------------------------
Roger W. Kober 62 Chairman of the Board, President and
Chief Executive Officer - January 1992
to date.
President and Chief Executive Officer -
1991 to January 1992.
J. Burt Stokes 52 Senior Vice President, Corporate
Services and Chief Financial Officer -
January 1, 1996 to date.
Chief Financial Officer and acting
Chief Executive Officer for General
Railway Signal Corporation, 150
Sawgrass Dr., Rochester, NY 14692 prior
to joining the Company.
Thomas S. Richards 52 Senior Vice President, Energy
Services - August 1995 to date.
Senior Vice President, Corporate
Services and General Counsel - August,
1994 to August 1995.
Senior Vice President, Finance and
General Counsel - October 1993 to
August, 1994.
General Counsel - October, 1991 to
October, 1993.
Partner at the law firm of Nixon,
Hargrave, Devans & Doyle, Clinton
Square, P.O. Box 1051, Rochester, NY
14603 prior to joining the Company.
Robert E. Smith 58 Senior Vice President, Energy
Operations -August 1995 to date.
Senior Vice President, Customer
Operations -August, 1994 to August,
1995.
Senior Vice President, Production and
Engineering - 1991 to August, 1994.
14
Age Positions, Offices and Business Experience
Name 12/31/95 1991 to date
- ---- -------- ----------------------------------------------
David C. Heiligman 55 Vice President, Finance and Corporate
Secretary - August 1994 to Date.
Vice President, Secretary and Treasurer
1991 to August, 1994.
Robert C. Mecredy 50 Vice President, Nuclear Operations -
August, 1994 to Date.
Vice President, Ginna Nuclear
Production -1991 to August, 1994.
Wilfred J. Schrouder, Jr. 54 Vice President, Customer Development -
August, 1994 to Date.
Vice President, Employee Relations,
Public Affairs and Materials
Management - 1991 to August, 1994.
Daniel J. Baier 49 Controller - August, 1994 to Date.
Assistant Controller - 1991 to August, 1994.
Mark Keogh 50 Treasurer - August, 1994 to Date.
Manager, Treasury Department - March
1992 to August, 1994.
Manager, Corporate Administration -
1991 to March 1992.
The term of office of each officer extends to the meeting of the Board
of Directors following the next annual meeting of shareholders and until his or
her successor is elected and qualifies.
15
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
COMMON STOCK AND DIVIDENDS
- ------------------------------------------------------ ------------------------------------------------------
Earnings/Dividends 1995 1994 1993 Shares/Shareholders 1995 1994 1993
- --------------------------- ------- ------- ------- --------------------------- ------- ------- -------
Earnings per weighted Number of shares (000's)
average share $ 1.69 $ 1.79 $ 2.00 Weighted average 38,113 37,327 35,599
Dividends paid Actual number at
per share $ 1.80 $ 1.76 $ 1.72 December 31 38,453 37,670 36,911
Number of shareholders
at December 31 35,356 37,212 38,102
- ------------------------------------------------------ ------------------------------------------------------
TAX STATUS OF CASH DIVIDENDS
Cash dividends paid in 1995, 1994 and 1993 were 100 percent taxable for
federal income tax purposes.
DIVIDEND POLICY
The Company has paid cash dividends quarterly on its Common Stock without
interruption since it became publicly held in 1949. The Company believes that
future dividend payments will need to be evaluated in the context of maintaining
the financial strength necessary to operate in a more competitive and uncertain
business environment. This will require consideration, among other things, of a
dividend payout ratio that is lower over time, reevaluating assets and managing
greater fluctuation in revenues. While the Company does not presently expect
the impact of these factors to affect the Company's ability to pay dividends at
the current rate, future dividends may be affected. The Company's Certificate
of Incorporation provides for the payment of dividends on Common Stock out of
the surplus net profits (retained earnings) of the Company.
Quarterly dividends on Common Stock are generally paid on the twenty-fifth
day of January, April, July and October. In January 1996, the Company paid a
cash dividend of $.45 per share on its Common Stock. The January 1996 dividend
payment is equivalent to $1.80 on an annual basis.
COMMON STOCK TRADING
Shares of the Company's Common Stock are traded on the New York Stock
Exchange under the symbol "RGS".
Common Stock - Price Range 1995 1994 1993
- ---------------------------- ------ ------ ------
High
1st quarter 23 26 3/8 28 3/8
2nd quarter 22 5/8 25 1/8 28
3rd quarter 24 1/8 23 3/4 29 3/4
4th quarter 24 1/8 21 3/8 29 1/4
Low
1st quarter 20 3/8 23 3/8 24 1/8
2nd quarter 20 1/8 20 1/2 25 1/2
3rd quarter 20 19 3/4 27 3/8
4th quarter 22 3/8 20 1/8 24 3/4
At December 31 22 5/8 20 7/8 26 1/4
16
Item 6
SELECTED FINANCIAL DATA
CONSOLIDATED SUMMARY OF OPERATIONS
(Thousands of Dollars) At December 31, 1995 1994 1993 1992 1991 1990
- ------------------------------------------------------------------------------------------------------------------------------
Operating Revenues
Electric $696,582 $658,148 $638,955 $608,267 $588,930 $551,930
Gas 293,863 326,061 293,708 261,724 235,728 236,496
------------ ------------ ------------ ------------ ------------ ------------
990,445 984,209 932,663 869,991 824,658 788,426
Electric sales to other utilities 25,883 16,605 16,361 25,541 28,612 42,465
------------ ------------ ------------ ------------ ------------ ------------
Total Operating Revenues 1,016,328 1,000,814 949,024 895,532 853,270 830,891
Operating Expenses
Fuel Expenses
Fuel for electric generation 44,190 44,961 45,871 48,376 65,105 76,420
Purchased electricity 54,167 37,002 31,563 29,706 27,683 34,264
Gas purchased for resale 167,762 194,390 166,884 141,291 129,779 132,512
------------ ------------ ------------ ------------ ------------ ------------
Total Fuel Expenses 266,119 276,353 244,318 219,373 222,567 243,196
------------ ------------ ------------ ------------ ------------ ------------
Operating Revenues Less Fuel Expenses 750,209 724,461 704,706 676,159 630,703 587,695
Other Operating Expenses
Operations excluding fuel expenses 253,907 235,896 235,381 226,624 208,440 194,594
Maintenance 49,226 55,069 61,693 62,720 65,415 62,391
Depreciation and amortization 91,593 87,461 84,177 85,028 84,181 77,767
Taxes - local, state and other 133,895 129,778 126,892 124,252 113,649 101,035
Federal income tax - current 65,368 35,658 33,453 36,101 28,766 20,661
- deferred 847 25,587 15,877 7,490 5,493 13,829
------------ ------------ ------------ ------------ ------------ ------------
Total Other Operating Expenses 594,836 569,449 557,473 542,215 505,944 470,277
------------ ------------ ------------ ------------ ------------ ------------
Operating Income 155,373 155,012 147,233 133,944 124,759 117,418
Other Income and Deductions
Allowance for other funds used during
construction 585 396 153 164 675 2,689
Federal income tax 16,948 16,259 9,827 4,195 4,580 2,459
Regulatory disallowances (26,866) (600) (1,953) (8,215) (10,000) -
Pension Plan Curtailment - (33,679) (8,179) - - -
Other, net (14,931) (4,853) (7,074) 6,155 6,078 4,062
------------ ------------ ------------ ------------ ------------ ------------
Total Other Income and (Deductions) (24,264) (22,477) (7,226) 2,299 1,333 9,210
Interest Charges
Long term debt 53,026 53,606 56,451 60,810 63,918 64,873
Short term debt 398 1,808 1,487 1,950 2,623 1,070
Other, net 8,658 4,758 5,220 5,228 4,459 3,523
Allowance for borrowed funds used during
construction (2,901) (2,012) (1,714) (2,184) (2,905) (2,719)
------------ ------------ ------------ ------------ ------------ ------------
Total Interest Charges 59,181 58,160 61,444 65,804 68,095 66,747
Net Income 71,928 74,375 78,563 70,439 57,997 59,881
Dividends on Preferred Stock
at required rates 7,465 7,369 7,300 8,290 6,963 6,025
------------ ------------ ------------ ------------ ------------ ------------
Earnings Applicable to Common Stock $64,463 $67,006 $71,263 $62,149 $51,034 $53,856
============ ============ ============ ============ ============ ============
Weighted average number of shares
outstanding in each period (000's) 38,113 37,327 35,599 33,258 31,794 31,293
Earnings per Common Share $1.69 $1.79 $2.00 $1.86 $1.60 $1.72
Cash Dividends Declared per Common Share $1.800 $1.770 $1.730 $1.690 $1.635 $1.575
17
CONDENSED CONSOLIDATED BALANCE SHEET
---------------------------------------------------------------------------------
(Thousands of Dollars) At December 31 1995 1994 1993 1992 1991 1990
- ---------------------------------------------------------------------------------------------------------------------------------
Assets
Utility Plant $3,068,103 $2,981,151 $2,890,799 $2,798,581 $2,706,554 $2,310,294
Less: Accumulated depreciation and
amortization 1,518,878 1,423,098 1,335,083 1,253,117 1,178,649 812,994
----------- ----------- ----------- ----------- ----------- -----------
1,549,225 1,558,053 1,555,716 1,545,464 1,527,905 1,497,300
Construction work in progress 121,725 128,860 112,750 83,834 76,848 82,663
----------- ----------- ----------- ----------- ----------- -----------
Net utility plant 1,670,950 1,686,913 1,668,466 1,629,298 1,604,753 1,579,963
Current Assets 292,596 236,519 248,589 209,621 189,009 176,045
Investment in Empire 38,879 38,560 38,560 9,846 - -
Deferred Debits and Regulatory Assets 472,968 504,204 507,769 200,676 160,034 108,451
----------- ----------- ----------- ----------- ----------- -----------
Total Assets $2,475,393 $2,466,196 $2,463,384 $2,049,441 $1,953,796 $1,864,459
- ------------------ =========== =========== =========== =========== =========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization
Long term debt $716,232 $735,178 $747,631 $658,880 $672,322 $721,612
Preferred stock redeemable at option
of Company 67,000 67,000 67,000 67,000 67,000 67,000
Preferred stock subject to mandatory
redemption 55,000 55,000 42,000 54,000 60,000 30,000
Common shareholders' equity:
Common stock 687,518 670,569 652,172 591,532 529,339 516,388
Retained earnings 70,330 74,566 75,126 66,968 61,515 62,542
----------- ----------- ----------- ----------- ----------- -----------
Total common shareholders' equity 757,848 745,135 727,298 658,500 590,854 578,930
----------- ----------- ----------- ----------- ----------- -----------
Total Capitalization 1,596,080 1,602,313 1,583,929 1,438,380 1,390,176 1,397,542
----------- ----------- ----------- ----------- ----------- -----------
Long Term Liabilities (Department
of Energy) 90,887 87,826 89,804 94,602 63,626 59,989
Current Liabilities 182,338 181,327 234,530 267,276 267,601 183,720
Deferred Credits and Other Liabilities 606,088 594,730 555,121 249,183 232,393 223,208
----------- ----------- ----------- ----------- ----------- -----------
Total Capitalization and Liabilities $2,475,393 $2,466,196 $2,463,384 $2,049,441 $1,953,796 $1,864,459
- ------------------------------------------ =========== =========== =========== =========== =========== ===========
18
FINANCIAL DATA
At December 31 1995 1994 1993 1992 1991 1990
------ ------ ------ ------ ------ ------
Capitalization Ratios (a) (percent)
Long-term debt 47.4 48.2 49.4 48.2 50.6 53.6
Preferred Stock 7.3 7.3 6.6 8.0 8.7 6.7
Common shareholders' equity 45.3 44.5 44.0 43.8 40.7 39.7
------ ------ ------ ------ ------ ------
Total 100.0 100.0 100.0 100.0 100.0 100.0
Book Value per Common Share - Year End $19.71 $19.78 $19.70 $18.92 $18.41 $18.42
Rate of Return on Average Common Equity (b)
(percent) 8.37 8.92 10.25 9.94 8.60 9.29
Embedded Cost of Senior Capital (percent)
Long-term debt 7.38 7.40 7.36 7.91 8.32 8.59
Preferred stock 6.26 6.26 6.69 6.98 6.97 6.72
Effective Federal Income Tax Rate (percent) 40.7 37.7 33.5 35.9 33.9 34.8
Depreciation Rate (percent) - Electric 2.76 2.69 2.62 2.69 3.05 3.33
- - Gas 2.59 2.62 2.60 2.78 2.94 2.94
Interest Coverages
Before federal income taxes (incld. AFUDC) 2.95 2.98 2.87 2.62 2.23 2.32
(excld. AFUDC) 2.90 2.94 2.84 2.58 2.18 2.25
After federal income taxes (incld. AFUDC) 2.16 2.24 2.24 2.04 1.82 1.86
(excld. AFUDC) 2.10 2.20 2.21 2.00 1.77 1.78
Interest Coverages Excluding Non-Recurring
Items (c)
Before federal income taxes (incld. AFUDC) 3.66 3.55 3.03 2.74 2.38 2.32
(excld. AFUDC) 3.61 3.51 3.00 2.70 2.33 2.25
After federal income taxes (incld. AFUDC) 2.62 2.61 2.35 2.12 1.91 1.86
(excld. AFUDC) 2.57 2.57 2.32 2.08 1.86 1.78
(a) Includes Company's long-term liability to the Department of Energy (DOE)
for nuclear waste disposal. Excludes DOE long-term liability for uranium
enrichment decommissioning and amounts due or redeemable within one year.
(b) The return on average common equity for 1995 excluding effects of the 1995
Gas Settlement is 12.10%. The rate of return on average common equity
excluding effects of retirement enhancement programs recognized by the
Company in 1994 and 1993 is 11.90% and 11.20%, respectively.
(c) The recognition by the Company in 1991 of a fuel procurement audit approved
by the New York State Public Service Commission (PSC) has been excluded
from 1991 coverages. Likewise, recognition by the Company in 1992 of
disallowed ice storm costs as approved by the PSC has been excluded from
1992 coverages. Coverages for 1994 and 1993 exclude the effects of
retirement enhancement programs recognized by the Company during each year
and certain gas purchase undercharges written off in 1994 and 1993.
Coverages in 1995 exclude the economic effect of the 1995 Gas Settlement
($44.2 million, pretax).
19
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The following is Management's assessment of significant factors which
affect the Company's financial condition and operating results.
EARNINGS SUMMARY
A good summer cooling season, a modest increase in electric rates, and
savings from prior years' work force reduction programs, together with other
cost control efforts by the Company helped to boost operating earnings for 1995.
Presented below is a table which summarizes the Company's Common Stock
earnings on a per-share basis. Earnings per share, before non-recurring items,
were $2.44 in 1995. Non-recurring items and their effect on earnings per share
have been identified. Earnings per share as reported in 1995 were reduced by an
aggregate pretax amount of $44.2 million, or $.75 per share net-of-tax, in
connection with a negotiated settlement (see 1995 Gas Settlement) reached
between the Company, Staff of the New York State Public Service Commission (PSC)
and other parties resolving various proceedings to review issues affecting the
Company's gas costs.
Future earnings will be affected, in part, by the Company's ability to
control certain costs and its ability to remarket excess gas capacity as set
under the terms of the 1995 Gas Settlement, which is discussed under Rates and
Regulatory Matters.
The final outcome of a rate proposal submitted by the Company and
currently pending before the PSC as well as the impact of developing competition
in the energy marketplace are anticipated to affect future earnings.
To provide for increases in past due accounts, an additional expense
accrual for doubtful accounts was recognized by the Company in 1995, reducing
1995 pretax earnings by $15.0 million, or $.26 per share.
Earnings per share as reported in 1994 and 1993 reflect charges for
work force reduction programs completed in 1994. By the end of 1994, a total of
572 persons, or about 22 percent of the work force, elected to participate in
one of three programs which were offered. The overall after-tax savings of
these programs are estimated to be about $61 million through 1998. In addition
to the cost of the work force reduction programs, earnings as reported include a
charge of $.01 per share in 1994 and $.04 per share in 1993 for purchased gas
undercharges (see Rates and Regulatory Matters).
Earnings Per Share - Summary
- --------------------------------------------------------------------------------
(Dollars per Share) 1995 1994 1993
- --------------------------------------------------------------------------------
Earnings per Share Before Non-recurring Items $2.44 $ 2.39 $ 2.19
Non-recurring Items
1995 Gas Cost Settlement (.75)
Purchased Gas Undercharges ( .01) ( .04)
Retirement Enhancement Programs (.59) (.15)
----- ------ ------
Total Non-recurring Items $(.75) $ (.60) $ (.19)
----- ------ ------
Reported Earnings per Share $1.69 $ 1.79 $ 2.00
===== ====== ======
COMPETITION
Overview. The Company is operating in a rapidly changing competitive
marketplace for electric and gas service. In its electric business, this
competitive environment includes a federal and State trend toward deregulation.
The passage of the National Energy Policy Act of 1992 (Energy Act) encourages
competition in the electric power industry at the wholesale level and promotes
access to utility-owned transmission facilities upon payment of appropriate
20
prices. At the State level, the PSC is currently investigating the
establishment of an efficient wholesale electric competitive market, and various
issues relating to retail electric service competition.
Competition in the Company's gas business was accelerated with the
passage in April 1992 of the Federal Energy Regulatory Commission's (FERC) Order
No. 636. In essence, FERC Order 636 requires interstate natural gas pipeline
companies to offer customers "unbundled", or separately-priced, sale and
transportation services.
ELECTRIC UTILITY COMPETITION. Cost pressures on major customers,
excess electric capacity in the region, and new technology have created
incentives for customers to investigate different electric supply options.
Those options have included various forms of self generation, but may eventually
include customer access to the transmission system in order to purchase
electricity from suppliers other than the Company.
PSC Competitive Opportunities Case. Phase I of a PSC proceeding to
address various issues related to increasing competition in the New York State
electric energy markets (the Competitive Opportunities Case) was completed in
the summer of 1994. The PSC approved flexible rate discounts for non-
residential electric customers who have competitive alternatives and adopted
specific guidelines for such rates.
Under Phase II of the Competitive Opportunities Case, the PSC issued
an Opinion in June 1995 establishing nine principles to guide the transition to
competition in the electric industry. Among other things, the PSC endorsed
increased emphasis on market-based approaches to research, environmental
protections and energy efficiency, and it supported the concept that utilities
should have a reasonable opportunity to recover expenditures and commitments
made pursuant to historical obligations. The PSC also indicated that the
current vertically integrated industry structure must be thoroughly examined to
ensure that it does not impede effective wholesale or retail competition. In
October 1995, formal submissions were made in support of, or opposition to, the
various proposals being considered for restructuring the electric industry in
New York State. The majority of submissions supported the concept that
competition should extend to the level of individual retail customers. The
Staff of the PSC endorsed the idea that existing utility companies should be
required to separate generation from transmission and distribution facilities
(including the possible divestiture of generating assets) to foster greater
competition. The PSC Staff position also encouraged electric wholesale
competition by 1997, retail competition by 1998, and stated that the New York
investor-owned utilities should absorb a portion of any stranded investment.
The Company does not support the PSC Staff position, but does agree with the
spirit underlying the PSC's guiding principles as presented in June 1995. As
discussed below, in October 1995 the Company, along with other New York
utilities, presented a consensus position to the PSC under Phase II of the
Competitive Opportunities Case through the Energy Association of New York State
(the Energy Association), an electric utility industry association which is
representing the Company and other utilities in the Competitive Opportunities
Case.
In summary, the Energy Association endorses the following:
- - the creation of a pool market mechanism through which all electricity
producers would compete,
- - creation of an independent system operator to coordinate bulk power
transmission and the pool market mechanism,
- - regulatory and tax reform that would reduce taxes paid by utilities and
limit any increases in the price of electricity and,
- - creation of a mechanism for generators to recover investments made pursuant
to legal obligations to provide universal service.
The Energy Association stopped short of endorsing increased competition at
the retail level, citing several unresolved issues created by different
obligations to serve customers when more than one supplier is selling energy in
a single area. The Company cannot predict if this proposal will be adopted by
the
21
PSC in its Competitive Opportunities Case or its effect on the Company because
potential business risks faced by the Company will depend on the specific
details of any plan ultimately adopted by the PSC.
On December 21, 1995 a Recommended Decision was issued by the
Administrative Law Judge presiding over this proceeding. In summary, it
provides:
- - Competition in the generation or production section of the electric
industry should be pursued, as long as steps are taken to ensure that
unregulated monopoly does not result and that reliability is not impaired.
A preferred competitive model, which includes, among other things, the
establishment of an independent system operator to perform a variety of
essential functions to ensure the reliable operation of the system was
presented.
- - Retail competition has the potential to benefit all customers by providing
greater choice among their electricity providers as well as increased
pricing and reliability options. But retail access brings with it
significant risks and requires considerable caution, and should be provided
only if it is in the best interests of all consumers.
- - In order to ensure reliability, effective competition at the wholesale
level should be established first, with an eye toward adding retail access
as rapidly as possible once a market is established and reliability is
ensured.
- - Strandable costs must be determined to be prudent, verifiable, and
incapable of being reduced before recovery is allowed. Recovery of
strandable costs generally should be accomplished by a non-bypassable
access charge or wires charge imposed by the distribution company. There
must also be a "reasonable opportunity" for consumers to realize savings
and receive reasonable prices. This requires a careful balancing of
interests and expectations, and the level of recovery may vary utility by
utility.
- - In any model under which the production of electricity is deregulated, this
function must be separated from transmission and distribution systems in
order to limit the exercise of market power. Utilities should make
individual proposals regarding preferable corporate structures, explaining
how market power will be alleviated.
A final ruling by the PSC on Phase II of the Competitive Opportunities
Case is expected in the Spring of 1996. The Company is not able to predict what
policies or guidelines may ultimately be adopted by the PSC under this
proceeding. The nature and magnitude of the potential impact of any proposals
ultimately adopted by the PSC on the business of the Company will depend on the
specific details of any plan for increased competition and resolution of the
complex issues related to competition at the retail level.
FERC Open Transmission Proposals. In March 1995 FERC proposed new
rules which would facilitate the development of competitive wholesale markets by
requiring electric utilities to offer "open-access" transmission service on a
non-discriminatory basis. A final rule would define the non-discriminatory
terms and conditions under which unregulated generators, neighboring utilities,
and other suppliers could gain access to a utility's transmission grid to
deliver power to wholesale customers. A supplementary release by FERC states
the principle that utilities are entitled to full recovery of "legitimate,
prudent and verifiable" strandable costs at the state and federal level. This
supplementary release concludes that FERC should be the principal forum for
addressing wholesale strandable costs, while suggesting state regulatory
authorities should address the recovery of strandable costs which may result
from retail competition. The FERC sought comments on its proposals in August
and October. The Company responded individually and as a member the New York
Power Pool (NYPP). The NYPP is actively evaluating the requirements for
implementing wholesale competition within the framework of the FERC proposals.
Significant changes to NYPP pricing procedures are expected, but their projected
effects on the Company's operations and financial performance are not
substantial assuming continued vertical integration of the utility industry in
New York State. FERC
22
is continuing to solicit public comments and elicit public involvement on these
proposals. A final ruling from FERC is not anticipated before mid-1996. At the
present time, the Company cannot predict what effects regulations ultimately
adopted by FERC will have, if any, on future operations or the financial
condition of the Company.
GAS UTILITY COMPETITION. Competition in the Company's gas business
has existed for some time, as larger customers have had the option of obtaining
their own gas supply and transporting it through the Company's distribution
system. FERC Order 636 enables the Company and other gas utilities to negotiate
directly with gas producers for supplies of natural gas. With the unbundling of
services, primary responsibility for reliable natural gas has shifted from
interstate pipeline companies to local distribution companies, such as the
Company.
PSC Gas Restructuring Case. In October 1993 the PSC initiated a
proceeding to address issues involving the restructuring of gas utility services
to respond to competition. Subsequently, in December 1994, the PSC issued an
order which presented regulatory policies and guidelines for natural gas
distributors. Requirements having the greatest impact on the Company are:
- - The Company must offer its customers unbundled access to upstream
facilities such as storage and transportation capacity on the interstate
pipelines with which the Company does business.
- - The Company may offer to package an individual supply of gas to an
individual customer in cases that would lower the Company's overall cost of
supplying gas.
- - The Company must offer an aggregation program whereby individual customers
could join together in a pool for the purpose of purchasing gas from a
supplier, in such cases the Company would still provide the service of
distributing gas on the Company's system.
- - The PSC allows full recovery of the transition costs resulting from FERC
Order 636 and requires that a share of these costs be borne by firm
transportation customers.
In November 1995 the Company filed its response to this order. The
Company's filing focused on setting transportation rates for an aggregation of
all gas customers, reviewing the necessity for minimum gas transportation
volumes, providing for the recovery of transition costs associated with FERC
Order 636, and establishing requirements for the use of automatic recording
meters. The impact on the Company's gas business as a result of this
proceeding, however, will depend upon the guidelines and regulations ultimately
approved by the PSC. At this time, the Company is unable to predict what
regulations will ultimately be adopted by the PSC.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. It has
been suggested that certain New York State utilities should write down certain
regulatory or generating assets in anticipation of the impact of competitive and
regulatory changes. The Company currently believes its regulatory and
generating assets are probable of recovery in rates, but industry trends have
moved more toward competition, and in a purely competitive environment, it is
not clear to what extent, if any, writeoffs of such assets may ultimately be
necessary (see Note 10 of the Notes to Financial Statements).
Regulatory Assets. The Company has deferred certain costs rather than
recognize them on its books when incurred. Such deferred costs are then
recognized as expenses when they are included in rates and recovered from
customers. Such deferral accounting is permitted by Statement of Financial
Accounting Standards No. 71 (SFAS-71). These deferred costs are shown as
Regulatory Assets on the Company's Balance Sheet and a discussion and
summarization of such Regulatory Assets is presented in Note 10 of the Notes to
Financial Statements. Such cost deferral is appropriate under traditional
regulated cost-of-service rate setting, where all prudently incurred costs are
recovered through rates. In a purely competitive pricing environment, such
costs might not have been incurred and could not have been deferred.
Accordingly, if the Company's rate setting was changed from a cost-of-service
approach, and it was no longer allowed to defer these costs under SFAS-71, these
assets would be
23
adjusted for any impairment to recovery (see discussion under Financial
Accounting Standards No. 121). In certain cases, the entire amount could be
written off.
Strandable Assets. In a competitive electric market, strandable
assets would arise when investments are made in facilities, or costs are
incurred to service customers, and such costs are not fully recoverable in
market-based rates. Examples include purchase power contracts (e.g., the
Kamine/Besicorp Allegany L.P. contract, see Projected Capital and Other
Requirements) or high cost generating assets. Estimates of strandable assets
are highly sensitive to the competitive wholesale market price assumed in the
estimation. The amount of potentially strandable assets at December 31, 1995
cannot be determined at this time, but could be significant.
Financial Accounting Standards No. 121. In March 1995, the Financial
Accounting Standards Board (FASB) issued Financial Accounting Standards No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of " (SFAS-121). SFAS-121 amends SFAS-71 to require write-off of a
regulatory asset or strandable asset if it is no longer probable that future
revenues will cover the cost of the asset. SFAS-121 also requires a company to
recognize a loss whenever events or circumstances occur which indicate that the
carrying amount of an asset may not be fully recoverable. At December 31, 1995
the Company's regulatory assets totaled $311.2 million. At the current time,
the Company believes its regulatory assets are probable of recovery, and,
accordingly, the adoption of this accounting standard will not have a material
impact on the financial position or results of operations of the Company.
THE COMPANY'S RESPONSE. The growing pace of competition in the energy
industry has been a primary focus of management over the past three years. The
Company accepts the challenges of this new environment and is responding to the
impact of increased competition.
Business Strategy. In May 1995 the Company set a new strategic
business direction for the future. Highlights of that strategy include:
- - the focus of the Company will be retail energy services,
- - the Company's goal in that business is market leadership, and
- - the Company will achieve that goal through operational excellence.
The Company's core business will be the marketing and providing of
electricity, natural gas, transmission and distribution services, and other
energy-related services to retail customers. A closely-aligned business will be
providing gas transmission and gas and electric distribution services to other
energy services companies.
The Company is continuously assessing various strategies which may
enhance its ability to respond to competitive forces and regulatory change.
These strategies are assessed in an effort to provide the greatest possible
value to the Company's shareholders and customers giving consideration to
changing economic, regulatory, and political circumstances. Such strategies may
include business partnerships or combinations with other companies, internal
restructuring involving a separation of some or all of the Company's wholesale
or retail businesses, and acquisitions of related businesses. No assurances can
be given as to whether any of these potential strategies will be pursued, or as
to the corresponding results on the financial condition or competitive position
of the Company.
RATES AND REGULATORY MATTERS
OVERVIEW. The Company is subject to PSC regulation of rates, service,
and sale of securities, among other matters. The Company is also regulated by
FERC on a limited basis, in the areas of interstate sales and exchanges of
electricity, intrastate sales of electricity for resale, transmission wheeling
service for other utilities, and licensing of hydroelectric facilities. As a
licensee of nuclear facilities, the Company is also subject to regulation by the
Nuclear Regulatory Commission.
24
1995 Gas Settlement. The Company's purchased gas expense charged to
customers was higher during the 1994-95 heating season compared with prior
years, generating substantial customer concern. The action the Company took to
reduce rates included refunding the weather normalization adjustment charged to
customers in January 1995 and discontinuation of those charges through the
remainder of the heating season ending in May 1995. The weather normalization
adjustment provides for recovery of fixed charges by producing higher unit rates
when the weather is warm and usage is low. Conversely, it would provide lower
unit rates during colder periods of high usage.
In December 1994, the PSC instituted a proceeding to review the
Company's practices regarding acquisition of pipeline capacity, the deferred
costs of the capacity and the Company's recovery of those costs.
In April 1995, the PSC issued a Department of Public Service staff
report on the Company's 1994-1995 billing practices and procedures which
presented recommendations regarding changes in the Company's natural gas
purchasing, billing, meter reading and communication activities.
On August 17, 1995, the Company announced that a negotiated settlement
had been reached with the Staff of the PSC and other parties which would resolve
various PSC proceedings affecting the Company's gas costs. On October 18, 1995,
the PSC approved, effective November 1, 1995, (1) the settlement discussed
below, (2) elimination of the weather normalization clause in gas rates and (3)
the Company's plan for improving its gas billing procedures (the 1995 Gas
Settlement). This settlement affects the rate treatment of various gas costs
through October 31, 1998.
Highlights of the 1995 Gas Settlement are:
- - The Company will forego, for three years, gas rate increases exclusive of
the cost of natural gas and certain cost increases imposed by interstate
pipelines.
- - The Company has agreed not to charge customers for pipeline capacity costs
in 1996, 1997 and 1998 of $22.5 million, $24.5 million, and $27.2 million,
respectively. Under FERC rules, the Company may sell its excess
transportation capacity in the market. The value of those sales can be used
to offset the capacity costs that will not be charged to customers. These
amounts that the Company will not be permitted to charge are subject to
increase in the event of major increases in the overall cost of pipeline
capacity during these years. The foregoing amounts include the cost of
capacity to be purchased by replacement shippers. As discussed below, a
substantial portion of this capacity is expected to be released and sold in
the market pursuant to a marketing agreement with CNG Transmission
Corporation (CNG), a supply agreement with MidCon Gas Services Corporation
(MGSC), and other individual agreements.
- - The Company agreed to write off excess gas pipeline capacity costs incurred
through 1995.
- - As part of a separate decision, the PSC agreed with the Company's request
to eliminate the weather normalization clause effective November 1, 1995.
The weather normalization clause had adjusted gas customer billing for
abnormal weather variations.
25
The economic effect of the 1995 Gas Settlement on the Company's 1995
results of operations may be summarized as follows:
Millions of Earnings per
Description Dollars Share Effect
- ----------------------------------------- ------------ -------------
(Pretax)
Elimination of weather
normalization charges $ 5.8 $(.10)
Foregone gas rate increase scheduled
for July 1, 1995 2.8 (.04)
Foregone gas pipeline capacity
costs for 1995 8.8 (.15)
Gas pipeline capacity and other costs
which were written off in October 1995 23.2 (.40)
Provision for retroactive pipeline
charges pending before FERC 3.6 (.06)
----- -----
Total $44.2 $(.75)
===== =====
Under provisions of the 1995 Gas Settlement, the Company faces an
economic risk of remarketing $74.2 million of excess gas capacity through 1998.
The Company has entered into a marketing agreement with CNG that is expected to
result in the release of approximately $29 million of this capacity through the
period. CNG will assist the Company in obtaining permanent replacement
customers for transportation capacity the Company will not require. To help
manage the balance of the excess capacity costs at risk, the Company has
retained MGSC which will work with the Company to identify and implement
opportunities for temporary and permanent release of surplus pipeline capacity
and advise in the management of the Company's gas supply, transportation and
storage assets consistent with the goal of providing reliable service and
reducing the cost of gas.
The ultimate financial impact of the 1995 Gas Settlement on the
Company's business in 1996 and subsequent years will be largely determined by
the degree of success achieved by the Company in remarketing its excess gas
capacity and in controlling its local gas distribution costs.
1995 Rate Proposal. With the current three-year electric and gas rate
plan expiring in July 1996 (see 1993 Rate Agreement below), the Company in July
1995 filed a request with the PSC for new electric rate tariffs commencing in
August 1996. Higher electric rates have been requested to cover increases in
capital and operating costs that are not provided for in present rates and are
not expected to be offset by increased revenues from sales. Highlights of the
1995 Rate Proposal filing are as follows:
- - A request for electric rates to be increased by approximately $17.1 million
or 2.4 percent annually (based on forecasted retail sales volumes).
- - A requested 11.75 percent rate of return on equity.
PSC Staff has proposed that electric rates be decreased 3.5 percent in each of
the next two years based on a rate of return on equity of 10.50 percent.
Although the Company's rate application is being litigated before a
PSC Administrative Law Judge, the Company has been working with the PSC Staff
and others to develop an agreement that could lead to a settlement of the
Company's filing, replacing the Company's current rate agreement with a new
agreement. The goal is to stabilize customer rates at as low a level as
possible and establish guidelines that will allow the Company to assume more
risk to take actions that could create increased earnings for shareholders.
The Company is unable to predict whether any settlement will be
achieved, or what effect any ultimate PSC decision in this proceeding will have
on the
26
Company's results of operation or its financial position. A PSC decision on the
Company's rate filing is expected by August 1996. Negotiations were suspended
late in 1995 after the various participants failed to reach a preliminary
settlement. While the Company continues to believe a settlement of these issues
would be in the best interest of all parties, it cannot predict the future
course of negotiations.
1993 Rate Agreement. In August 1993 the PSC approved a settlement
agreement (1993 Rate Agreement) which determined the Company's rates through
June 30, 1996 and includes certain incentive arrangements providing for both
rewards and penalties. Under the 1993 Rate Agreement, the PSC approved an
electric rate increase of 2.5% ($18.3 million) effective July 1, 1995. Recovery
of approximately $20 million of incentive awards earned by the Company has been
delayed for future consideration given the competitive environment and the
Company's desire to minimize price impacts on its customers. A summary of
recent PSC rate decisions under this agreement is included in the table titled
Rate Increases.
Flexible Pricing Tariff. Under its flexible pricing tariff for major
industrial and commercial electric customers, the Company may negotiate
competitive electric rates at discount prices to compete with alternative power
sources, such as customer-owned generation facilities. Under the terms of the
1993 Rate Agreement, the Company would absorb 30 percent of any net revenues
lost as a result of such discounts through June 1996, while the remaining 70
percent would be recovered from other customers. The Company has not sought
recovery of that 70 percent from other customers. The portion recoverable after
June 1996 is expected to be determined by the PSC as it considers the 1995 Rate
Proposal. Under the flexible tariff provisions, the Company as of year-end 1995
had negotiated long-term electric supply contracts with twenty of its large
industrial and commercial electric customers at discounted rates. The Company
is negotiating long-term electric supply contracts with other large customers as
the need and opportunity arise. The Company has not experienced any customer
loss due to competitive alternative arrangements.
Purchased Gas Undercharges. In March 1994 the PSC approved a December
1993 settlement among the Company, PSC Staff and another party regarding the
Company's accounting for certain gas purchases for the period August 1990-August
1992 which resulted in undercharges to gas customers of approximately $7.5
million. The Company wrote off $2.0 million of the undercharges as of December
31, 1993, reducing 1993 earnings by four cents per share, net of tax. In April
1994, the Company wrote off an additional one cent per share, net of tax. Under
the 1993 settlement, the Company was to collect $2.6 million from customers over
a three-year period. Due to rate increase limitations established in the
Company's 1993 Rate Agreement and certain provisions under the 1995 Gas
Settlement; however, the Company is precluded from collecting the $2.6 million,
and, accordingly, this amount was written off in 1995 and is reflected in Other
Deductions on the Statement of Income.
Rate Increases
- ----------------------------------------------------------------------------------
Granted
Amount of Increase Authorized
Class of Effective (Annual Basis) Percent Rate of Return on
Service Date of Increase (000's) Increase Rate Base Equity
- ----------------------------------------------------------------------------------
Electric July 1, 1992 $32,220 5.2% 9.31% 11.00%
July 1, 1993 18,500 2.8 9.46 11.50
July 1, 1994 20,900 3.0 9.23 11.50
July 1, 1995 18,300 2.5 9.30 11.50
Gas July 1, 1992 12,316 4.1 9.31 11.00
July 1, 1993 2,600 1.1 9.46 11.50
July 1, 1994 7,400 3.0 8.90 11.50
July 1, 1995 - - 9.30 11.50
27
LIQUIDITY AND CAPITAL RESOURCES
During 1995 cash flow from operations, together with proceeds from
external financing activity (see Consolidated Statement of Cash Flows), provided
the funds for construction expenditures and the retirement of all outstanding
short-term borrowings. At December 31, 1995 the Company had cash and cash
equivalents of $44.1 million. Capital requirements during 1996 are anticipated
to be satisfied primarily from the combination of internally generated funds and
temporary cash investments.
PROJECTED CAPITAL AND OTHER REQUIREMENTS. The Company's capital
requirements relate primarily to expenditures for electric generation, including
the 1996 replacement of its Ginna steam generators, transmission and
distribution facilities, and gas mains and services as well as the repayment of
existing debt. The Company has no current plans to install additional baseload
generation.
Integrated Resource Plan. The Company's 1992 Integrated Resource Plan
(IRP) and 1993 IRP update explored options for complying with the 1990 Clean Air
Act Amendments. Future options with regard to generating resources and
alternative methods of meeting electric capacity requirements were also
examined. Activities have been completed or are currently under way to:
- - Modify Units 2, 3, and 4 at Russell Station and Unit 12 at Beebee Station
(all coal-fired facilities) to meet federal Environmental Protection Agency
standards and Clean Air Act requirements, and
- - Replace the two steam generators at the Ginna Nuclear Plant.
As the future of the electric competitive marketplace becomes more
clear with the conclusion of the PSC Competitive Opportunities Case, the Company
anticipates addressing a new full-scale planning review.
Ginna Steam Generator Replacement. Preparation for replacement of the
two steam generators at the Ginna Nuclear Plant began in 1993 and will continue
until the replacement in 1996. Much of the preliminary preparation has been
done during the normal annual refueling and maintenance outages. The Company
anticipates that the 1996 outage for refueling and replacement will begin in
April and take about 70 days. Cost of the replacement is estimated at $115
million; about $40 million for the units, about $50 million for installation and
the remainder for engineering and other services. Refueling is expected to take
place on an 18-month cycle once the new steam generators are installed. The PSC
order regarding this project provides that certain costs over $115 million, and
savings under that amount, will be shared between the Company and its customers
but the Company does not expect to exceed that amount.
Purchased Power Requirement. Under federal and New York State laws
and regulations, the Company is required to purchase the electrical output of
unregulated cogeneration facilities which meet certain criteria (Qualifying
Facilities). The Company was compelled by regulators to enter into a contract
with Kamine/Besicorp Allegheny L.P. (Kamine) for approximately 55 megawatts of
capacity, the circumstances of which are discussed in Note 10 of the Notes to
Financial Statements. The Kamine contract and the outcome of related litigation
will have an important impact on the Company's electric rates and its ability to
function effectively in a competitive environment. The Company has no other
long-term obligations to purchase energy from Qualifying Facilities.
Capital Requirements and Electric Operations. Electric production
plant expenditures in 1995 included $41 million of expenditures made at the
Company's Ginna Nuclear Plant, of which $29 million was incurred for preparation
to replace the steam generators. The Company spent $16 million on this project
in 1994 and $15 million in 1993. In addition, nuclear fuel expenditures of $16
million were incurred at Ginna during 1995.
Exclusive of fuel costs, the Company's 14 percent share of electric
production plant expenditures at the Nine Mile Two nuclear facility totaled $6
million in 1995. Expenditures of $1 million during 1995 were also made for the
Company's share of nuclear fuel at Nine Mile Two. On April 8, 1995 Nine Mile
Two was taken out of service for a scheduled refueling outage and resumed full
28
operation on June 2, 1995, the shortest refueling in the plant's history. The
next refueling outage for Nine Mile Two is scheduled for late 1996.
Electric transmission and distribution expenditures, as presented in
the Capital Requirements table, totaled $22 million in 1995, of which $20.4
million was for the upgrading of electric distribution facilities to meet the
energy requirements of new and existing customers.
Capital Requirements and Gas Operations. The Empire State Pipeline
(Empire), an intrastate natural gas pipeline between Grand Island and Syracuse,
New York is subject to PSC regulation and commenced operation in November 1993.
The Company is participating as an equity owner of Empire through its wholly-
owned subsidiary, Energyline Corporation (Energyline), along with subsidiaries
of Coastal Corporation and Westcoast Energy Inc. Energyline has a total
obligation of $20 million in Empire, made up of a $10.3 million equity
investment, and $9.7 million in commitments under a credit agreement.
Construction requirements for gas property totaled $14 million in 1995
and were principally for the replacement of older cast iron mains with longer-
lasting and less expensive plastic and coated steel pipe, the relocation of gas
mains for highway improvement, and the installation of gas services for new
load.
ENVIRONMENTAL ISSUES. The production and delivery of energy are
necessarily accompanied by the release of by-products subject to environmental
controls. The Company has taken a variety of measures (e.g., self-auditing,
recycling and waste minimization, training of employees in hazardous waste
management) to reduce the potential for adverse environmental effects from its
energy operations. A more detailed discussion concerning the Company's
environmental matters, including a discussion of the federal Clean Air Act
Amendments, can be found in Note 10 of the Notes to Financial Statements.
REDEMPTION OF SECURITIES. In addition to first mortgage bond
maturities and mandatory sinking fund obligations over the past three years,
discretionary redemption of securities totaled $120 million in 1993, $24.5
million in 1994, and $1 million in 1995. There was no mandatory redemption of
securities in 1995.
CAPITAL REQUIREMENTS - SUMMARY. The Company's capital program is
designed to maintain reliable and safe electric and natural gas service, to
improve the Company's competitive position, and to meet future customer service
requirements. Capital requirements for the three-year period 1993 to 1995 and
the current estimate of capital requirements through 1998 are summarized in the
Capital Requirements table.
The Company's capital expenditures program is under continuous review
and will be revised depending upon the progress of construction projects,
customer demand for energy, rate relief, government mandates and other factors.
In addition to its projected construction requirements, the Company may
consider, as conditions warrant, the redemption or refinancing of certain long-
term securities.
29
Capital Requirements
- ---------------------------------------------------------------------------------------------------------
Actual Projected
1993 1994 1995 1996 1997 1998
Type of Facilities (Millions of Dollars)
- ---------------------------------------------------------------------------------------------------------
Electric Property
Production $ 54 $ 42 $ 48 $ 68 $ 18 $ 19
Transmission and Distribution 29 26 22 30 28 26
Street Lighting and Other 2 1 3 1 1 1
---- ---- ---- ---- ---- ----
Subtotal 85 69 73 99 47 46
Nuclear Fuel 16 16 17 20 20 15
---- ---- ---- ---- ---- ----
Total Electric 101 85 90 119 67 61
Gas Property 20 20 14 16 18 18
Common Property 21 12 4 13 13 14
---- ---- ---- ---- ---- ----
Total 142 117 108 148 98 93
Carrying Costs
Allowance for Funds Used During
Construction (AFUDC) 2 2 3 2 1 1
Deferred Financing Charges
Included in Other Income 1 - - - - -
---- ---- ---- ---- ---- ----
Total Construction Requirements 145 119 111 150 99 94
Securities Redemptions, Maturities
and Sinking Fund Obligations* 212 52 1 18 30 40
---- ---- ---- ---- ---- ----
Total Capital Requirements $357 $171 $112 $168 $129 $134
---- ---- ---- ---- ---- ----
* Excludes prospective refinancings.
FINANCING AND CAPITAL STRUCTURE. The Company had no debt maturity or
sinking fund obligations in 1995 and had no public issuance of securities during
the year. Capital requirements in 1995 were satisfied primarily by a
combination of internally generated funds and proceeds from the issuance of new
shares of Common Stock through its Automatic Dividend Reinvestment and Stock
Purchase Plan (ADR Plan). The Company foresees modest near-term financing
requirements. Investments in short-term securities were approximately $37.5
million at December 31, 1995. Depending upon economic and market conditions at
the time, the Company could use proceeds from these securities to meet
construction requirements, undertake debt and/or preferred stock redemptions, or
consider investments in unregulated businesses. With an increasingly
competitive environment, the Company believes maintaining a high degree of
financial flexibility is critical. In this regard, the Company's long-term
objective is to control capital expenditures and to move to a less leveraged
capital structure.
The Company anticipates utilizing its credit agreements and unsecured
lines of credit to meet any interim external financing needs prior to issuing
any long-term securities. As financial market conditions warrant, the Company
may, from time to time, redeem higher cost senior securities. The Company's
financing program is under continuous review and may be revised depending upon
the level of construction, financial market conditions, and other factors.
Financing. For information with respect to short-term borrowing
arrangements and limitations, see Note 9 of the Notes to Financial Statements.
During 1995 approximately 783,000 new shares of Common Stock were sold
through the Company's ADR Plan and an employee stock purchase plan, providing
$17.1 million to help finance its capital expenditures program. New shares
issued in 1995 and 1994 were purchased from the Company at a market price above
the book value per share at the time of purchase. These plans permit the
Company to issue new shares to participants or to purchase outstanding shares on
the open market.
Capital Structure. The Company's retained earnings at December 31,
1995 were $70.3 million, a decrease of approximately $4.2 million compared with
a year
30
earlier. Retained earnings were reduced by approximately $15 million in October
1995 resulting from a writeoff of certain gas costs, as discussed under the
heading 1995 Gas Settlement. Common equity (including retained earnings)
comprised 45.3 percent of the Company's capitalization at December 31, 1995,
with the balance being comprised of 7.3 percent preferred equity and 47.4
percent long-term debt. Capitalization at December 31, 1995, including $18.0
million of long-term debt due within one year, was comprised of 44.9 percent
common equity, 7.2 percent preferred equity, and 47.9 percent long-term debt.
As presented, these percentages are based on the Company's capitalization
inclusive of its long-term liability to the United States Department of Energy
(DOE) for nuclear waste disposal as explained in Note 10 of the Notes to
Financial Statements. As financial market conditions warrant, the Company may,
from time to time, issue securities to permit early redemption of higher-cost
senior securities. The Company is reviewing its financing strategies as they
relate to debt and equity structures in the context of the new competitive
environment and the ability of the Company to shift from a fully regulated to a
more competitive organization.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing 1995 to 1994 and 1994
to 1993. The Notes to Financial Statements contain additional information.
OPERATING REVENUES AND SALES. Compared with a year earlier, operating
revenues were nearly unchanged in 1995 after rising five percent in 1994. Gas
operating revenues declined in 1995 due to the milder weather during the first
quarter of the year and as a result of the 1995 Gas Settlement discussed
earlier. Customer electric revenue increased, reflecting higher kilowatt-hour
sales and recovery of higher fuel costs. Revenues from the sale of electric
energy to other utilities were up due, in part, to a new FERC-approved tariff
which has greatly facilitated the Company's participation in two-party sales, or
sales which are independent of the New York Power Pool. Details of the revenue
changes are presented in the Operating Revenues table. As presented in this
table, the base cost of fuel has been excluded from customer consumption and is
included under fuel costs, revenue taxes and deferred fuel costs are included as
a part of other revenues, and unbilled revenues are included in each caption as
appropriate.
Operating Revenues
- ---------------------------------------------------------------------------------------------------------
Increase or (Decrease) from Prior Year Electric Department Gas Department
(Thousands of Dollars) 1995 1994 1995 1994
- ---------------------------------------------------------------------------------------------------------
Customer Revenues (Estimated) from:
Rate Increases $15,704 $18,647 $ 1,883 $ 4,155
Fuel Costs 16,393 3,171 (26,505) 29,989
Weather Effects (Heating & Cooling) 1,397 (1,166) (1,525) (3,362)
Customer Consumption 8,968 1,726 8,433 (2,406)
Other (4,028) (3,185) (14,484) 3,977
------- ------- -------- -------
Total Change in Customer Revenues 38,434 19,193 (32,198) 32,353
Electric Sales to Other Utilities 9,278 244 - -
------- ------- -------- -------
Total Change in Operating Revenues $47,712 $19,437 $(32,198) $32,353
Changes in fuel cost revenues, which include purchased power revenues,
normally have been earnings neutral in the past. Under the 1993 Rate Agreement,
however, fuel clause provisions currently provide that customers and
shareholders will share, generally on a 50%/50% basis subject to certain
incentive limits, the benefits and detriments realized from actual electric fuel
costs, generation mix, sales of gas to dual-fuel customers and sales of
electricity to other utilities compared with PSC-approved forecast amounts. As
a result of these sharing arrangements, discussed further in Note 1 of the Notes
to Financial Statements, pretax earnings were increased by $3.9 million in 1994
and $6.6 million in 1995, reflecting, in part, actual experience in both
electric fuel costs and generation mix compared with rate assumptions. Deferred
costs associated with the DOE's assessment for future uranium enrichment
decontamination are also being recovered
31
through the Company's electric fuel adjustment clauses. Certain transition
costs incurred by gas supply pipeline companies and billed to the Company are
recovered through the Company's gas fuel adjustment provisions.
A reconciliation of gas costs incurred and gas costs billed to
customers is done annually, as of August 31, and the excess or deficiency is
normally refunded to or recovered from customers during a subsequent period. As
part of the 1995 Gas Settlement, the Company agreed not to collect from
customers and to write off $23.2 million of gas costs which had previously been
incurred.
The effect of weather variations on operating revenues is most
measurable in the Gas Department, where revenues from spaceheating customers
comprise about 90 to 95 percent of total gas operating revenues. Weather in the
Company's service area during 1994 and 1995 was warmer than normal, with the
weather during 1995 being 2.4 percent warmer than 1994 on a calendar-month
heating degree day basis. With elimination of the weather normalization clause
in the Company's gas tariff, abnormal weather variations may have a more
pronounced effect on future gas revenues. Warmer than normal summer weather
during 1995 and 1994 boosted electric energy sales to meet the demand for air
conditioning usage.
Compared with a year earlier, kilowatt-hour sales of energy to retail
customers were up 2.8 percent in 1995, after remaining nearly flat in 1994.
Sales to industrial customers led the increase. This gain was driven by one
large industrial customer who is purchasing more electric power as an
alternative to power produced at its own plant. Electric demand for air
conditioning usage had a significant impact on kilowatt-hour sales in 1994 and
1995. The Company had a net gain of nearly 2,600 new electric customers during
1995, including over 400 new commercial customers.
Fluctuations in revenues from electric sales to other utilities are
generally related to the Company's customer energy requirements, New York Power
Pool energy market and transmission conditions and the availability of electric
generation from Company facilities. In contrast to 1994, revenues from sales to
other electric utilities grew in 1995 reflecting increased kilowatt-hour sales
and higher rates. In addition to sales through the New York Power Pool, the
Company increased its participation in two-party sales, as discussed earlier.
With the possibility of more open access to transmission services as provided
for under the Energy Act, the Company is examining alternative markets and
procedures to meet what it believes will be increased competition for the sale
of electric energy to other utilities.
The transportation of gas for large-volume customers who are able to
purchase natural gas from sources other than the Company is an important
component of the Company's marketing mix. Company facilities are used to
distribute this gas, which amounted to 14.6 million dekatherms in 1995 and 13.6
million dekatherms in 1994. These purchases have caused decreases in customer
revenues, with offsetting decreases in purchased gas expenses, but in general do
not adversely affect earnings because transportation customers are billed at
rates which, except for the cost of buying and transporting gas to the Company's
city gate, approximate the rates charged the Company's other gas service
customers. Gas supplies transported in this manner are not included in Company
therm sales, depressing reported gas sales to non-residential customers. The
Company's objective is eventually to make gas transportation a viable option for
every customer on its system. Under two new gas transportation tariffs
currently pending before the PSC in its Gas Restructuring Case, minimum
throughput levels to qualify for such service would be totally eliminated by
July 1998, thereby allowing all customers to qualify for gas transportation
service and to choose their own sources of gas supply. If approved by the PSC,
these tariffs will be in place by July 1996.
Therms of gas sold and transported, including unbilled sales, were
nearly flat in 1995, after dropping two percent in 1994. These changes reflect,
primarily, the effect of weather variations on therm sales to customers with
spaceheating. If adjusted for normal weather conditions, residential gas sales
would have increased about 1.7 percent in 1995 over 1994, while nonresidential
sales, including gas transported, would have increased approximately 2.0 percent
in 1995. The average use per residential gas customer, when adjusted for normal
weather conditions, was slightly up in 1995, following a modest decrease in
1994.
32
Fluctuations in "Other" customer revenues shown in the Operating
Revenues table for both comparison periods are largely the result of revenue
taxes, deferred fuel costs, and miscellaneous revenues.
OPERATING EXPENSES. Operating expenses in 1995 reflect the first
complete year of savings associated with the Company's early retirement programs
in 1993 and 1994. The Company's continuing efforts to curtail increases in
maintenance and other operation expenses are also reflected in 1995 results.
Operating expenses are summarized in the table titled Operating Expenses.
Operating Expenses
- ---------------------------------------------------------------------------------------------------------
Increase or (Decrease) from Prior Year
(Thousands of Dollars) 1995 1994
- ---------------------------------------------------------------------------------------------------------
Fuel for Electric Generation $ (771) $ (910)
Purchased Electricity 17,165 5,439
Gas Purchased for Resale (26,628) 27,506
Other Operation 18,011 515
Maintenance (5,843) (6,624)
Depreciation and Amortization 4,132 3,284
Taxes Charged to Operating Expenses
Local, State and Other Taxes 4,117 2,886
Federal Income Tax 4,970 11,915
-------- -------
Total Change in Operating Expenses $ 15,153 $44,011
Energy Costs - Electric. Lower fuel expense for electric generation
in 1995 compared with a year earlier reflects primarily a drop in the average
cost of coal used to generate power. Total Company electric generation was up
4.5 percent in 1995. For the 1994 comparison period, an electric generation mix
favoring less expensive nuclear fuel, compared with the cost of coal or oil,
resulted in fuel expenses not increasing at the same rate as electric
generation. The average cost of nuclear fuel decreased in 1994 and was up
slightly in 1995.
The Company normally purchases electric power to supplement its own
generation when needed to meet load or reserve requirements, and when such power
is available at a cost lower than the Company's production cost. Under a
contract with Kamine, however, the Company has been required to purchase
unneeded energy at uneconomical rates (see Note 10 of the Notes to Financial
Statements). The Company purchased 337 thousand megawatt-hours of energy from
Kamine at a total price of $16.6 million in 1995. For the 1994 comparison
period, the increase in purchased electricity expense was caused by an increase
in kilowatt-hours purchased. Average rates for purchased electricity were up in
1995 after declining in 1994.
Energy Management and Costs - Gas. The Company purchases all of its
required gas supply directly from numerous producers and marketers under
contracts containing varying terms and conditions. The Company currently holds
firm transportation capacity on ten major natural gas pipelines, giving the
Company access to the major gas-producing regions of North America. In addition
to firm pipeline capacity, the Company also has obtained contracts for firm
storage capacity on the CNG system (7.2 billion cubic feet) and on the ANR
Pipeline system (8.4 billion cubic feet) which is used to help satisfy its
customers' winter demand requirements.
The Company acquires gas supply and transportation capacity based on
its requirements to meet peak loads which occur in the winter months. The
Company is committed to transportation capacity on Empire and the CNG pipeline
system, as well as to upstream pipeline transportation and storage services.
The combined CNG and Empire transportation capacity exceeds the Company's
current requirements. This temporary excess has occurred largely due to the
Company's initiatives to diversify its supply of gas and the industry changes
and increasing competition resulting from the implementation of FERC Order 636.
As a result of the restructuring of the gas transportation industry by
FERC pursuant to Order No. 636 and related decisions, there have been and will
be a number of changes in the gas portion of the Company's business over the
next
33
several years. These changes will require the Company to pay a share of certain
transition costs incurred by the pipelines as a result of the FERC-ordered
industry restructuring. For additional information with respect to these
transition costs, see Note 10 of the Notes to Financial Statements.
Gas purchased for resale expense declined in 1995 driven by a reduced
volume of purchased gas resulting from a warmer than normal heating season. In
addition, average purchased gas rates declined in 1995 compared with a year
earlier, primarily due to lower commodity costs. Despite a decrease in the
volume of gas purchased, gas purchased for resale expense was up in 1994
reflecting higher average purchased gas rates compared with 1993.
Operating Expenses, Excluding Fuel. Other operation expense increased
approximately $18.0 million in 1995, after remaining nearly flat in 1994. An
additional expense accrual for doubtful accounts increased operating expenses by
$15.0 million in 1995. This expense was partially offset by lower costs for
payroll, employee welfare, and materials and supplies due, in part, to Company
cost control efforts and the work reduction programs undertaken in 1994. The
additional reserve in 1995 for doubtful accounts was recognized to provide for
increases in past due accounts. The change in other operation expenses for the
1994 comparison period reflects increased demand side management and
uncollectible expenses offset by lower payroll and welfare expense.
Lower maintenance expense in both comparison periods reflects reduced
payroll and contractor costs.
For both comparison periods, the increase in depreciation expense
reflects an increase in depreciable plant. When completed, replacement of the
steam generators at the Ginna Nuclear Plant is anticipated to increase
depreciation expense by approximately $11 million annually.
Taxes Charged To Operating Expenses. The increase in local, state and
other taxes in the 1995 comparison period reflects certain assessments for prior
years' taxes. The 1994 comparison period reflects primarily an increase in
revenues combined with increased property tax rates and generally higher
property assessments.
See Note 2 of the Notes to Financial Statements for an analysis of federal
income taxes.
OTHER STATEMENT OF INCOME ITEMS. Variations in non-operating federal
income tax reflect mainly accounting adjustments related to retirement
enhancement programs (see Earnings Summary), regulatory disallowances, and
employee performance incentive programs (discussed below in this section).
Recorded under the caption Other Income and Deductions is the
recognition of retirement enhancement programs designed to reduce overall labor
costs which were implemented by the Company during the third and fourth quarters
of 1993 and the third quarter of 1994. These programs are discussed under
Earnings Summary.
Other--Net Income and Deductions for 1993 and 1994 result mainly from
the recognition of employee performance incentive programs in each of those
years. These programs recognize employees' achievements in meeting corporate
goals and reducing expenses. For the 1995 comparison period, Other--Net Income
and Deductions also reflects recognition of the employee incentive program, and
additional depreciation of the Empire project to recognize the difference
between a rateable method of computation versus a lesser amount currently
included in rates.
Both mandatory and optional redemptions of certain higher-cost first
mortgage bonds have helped to reduce long-term debt interest expense over the
three-year period 1993-1995. The average short-term debt outstanding decreased
in 1994 and 1995.
DIVIDEND POLICY. The current annual dividend rate on the Company's
Common Stock is $1.80 per share. The Company's Certificate of Incorporation
provides for the payment of dividends on Common Stock out of the surplus net
profits (retained earnings) of the Company. The Company believes that future
dividend payments will need to be evaluated in the context of maintaining the
financial
34
strength necessary to operate in a more competitive and uncertain business
environment. This will require consideration, among other things, of a dividend
payout ratio that is lower over time, reevaluating assets and managing greater
fluctuation in revenues. While the Company does not presently expect the impact
of these factors to affect the Company's ability to pay dividends at the current
rate, future dividends may be affected.
35
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. FINANCIAL STATEMENTS
Report of Independent Accountants
Consolidated Statements of Income and Retained Earnings for each of the
three years ended December 31, 1995.
Consolidated Balance sheets at December 31, 1995 and 1994.
Consolidated Statement of Cash Flows for each of the three years ended
December 31, 1995.
Notes to Consolidated Financial Statements.
Financial Statement Schedules:
The following Financial Statement Schedule is submitted as part of Item 14,
Exhibits, Financial Statement Schedules and Reports on Form 8-K, of this
Report. (All other Financial Statement Schedules are omitted because they
are not applicable, or the required information appears in the Financial
Statements or the Notes thereto.)
Schedule II - Valuation and Qualifying Accounts.
B. SUPPLEMENTARY DATA
Interim Financial Data.
36
REPORT OF INDEPENDENT ACCOUNTANTS
To the Shareholders and
Board of Directors of
Rochester Gas and Electric Corporation
In our opinion, the consolidated financial statements listed under
Item 8A in the index appearing on the preceding page present fairly, in all
material respects, the financial position of Rochester Gas and Electric
Corporation and its subsidiaries at December 31, 1995 and 1994, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1995, in conformity with generally accepted accounting
principles. These financial statements are the responsibility of the Company's
management; our responsibility is to express an opinion on these financial
statements based on our audits. We conducted our audits of these statements in
accordance with generally accepted auditing standards which require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for the opinion expressed
above.
As discussed in Note 3 to the financial statements, the Company
adopted the provisions of Statement of Financial Accounting Standards No. 112,
"Employers' Accounting for Postemployment Benefits" in 1994.
PRICE WATERHOUSE LLP
Rochester, New York
January 19, 1996
37
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars) At December 31, 1995 1994 1993
- -----------------------------------------------------------------------------------------
Operating Revenues
Electric $696,582 $658,148 $638,955
Gas 293,863 326,061 293,708
---------- ---------- ----------
990,445 984,209 932,663
Electric sales to other utilities 25,883 16,605 16,361
---------- ---------- ----------
Total Operating Revenues 1,016,328 1,000,814 949,024
Operating Expenses
Fuel Expenses
Fuel for electric generation 44,190 44,961 45,871
Purchased electricity 54,167 37,002 31,563
Gas purchased for resale 167,762 194,390 166,884
---------- ---------- ----------
Total Fuel Expenses 266,119 276,353 244,318
---------- ---------- ----------
Operating Revenues Less Fuel Expenses 750,209 724,461 704,706
Other Operating Expenses
Operations excluding fuel expenses 253,907 235,896 235,381
Maintenance 49,226 55,069 61,693
Depreciation and amortization 91,593 87,461 84,177
Taxes - local, state and other 133,895 129,778 126,892
Federal income tax 66,215 61,245 49,330
---------- ---------- ----------
Total Other Operating Expenses 594,836 569,449 557,473
---------- ---------- ----------
Operating Income 155,373 155,012 147,233
Other Income and Deductions
Allowance for other funds used during construction 585 396 153
Federal income tax 16,948 16,259 9,827
Regulatory disallowances (26,866) (600) (1,953)
Pension Plan Curtailment - (33,679) (8,179)
Other, net (14,931) (4,853) (7,074)
---------- ---------- ----------
Total Other Income and (Deductions) (24,264) (22,477) (7,226)
Interest Charges
Long term debt 53,026 53,606 56,451
Other, net 9,056 6,566 6,707
Allowance for borrowed funds used during construction (2,901) (2,012) (1,714)
---------- ---------- ----------
Total Interest Charges 59,181 58,160 61,444
Net Income 71,928 74,375 78,563
Dividends on Preferred Stock 7,465 7,369 7,300
---------- ---------- ----------
Earnings Applicable to Common Stock $64,463 $67,006 $71,263
========== ========== ==========
Weighted Average Number of Shares for Period (000's) 38,113 37,327 35,599
Earnings per Common Share $1.69 $1.79 $2.00
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(Thousands of Dollars) At December 31, 1995 1994 1993
- -----------------------------------------------------------------------------------------
Balance at Beginning of Period $74,566 $75,126 $66,968
Add
Net Income 71,928 74,375 78,563
Adjustment Associated with Stock Redemption - (1,398) (933)
---------- ---------- ----------
Total 146,494 148,103 144,598
---------- ---------- ----------
Deduct
Dividends declared on capital stock
Cumulative preferred stock - at required rates
(Note 7) 7,465 7,369 7,300
Common Stock 68,699 66,168 62,172
---------- ---------- ----------
Total 76,164 73,537 69,472
---------- ---------- ----------
Balance at End of Period $70,330 $74,566 $75,126
========== ========== ==========
Cash Dividends Declared per Common Share $1.80 $1.77 $1.73
The accompanying notes are an integral part of the financial statements.
38
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars) At December 31 1995 1994
- ------------------------------------------------------------------------------
Assets
Utility Plant
Electric $2,342,981 $2,284,634
Gas 382,071 370,205
Common 135,526 135,975
Nuclear fuel 207,525 190,337
------------ ------------
3,068,103 2,981,151
Less: Accumulated depreciation 1,345,552 1,263,637
Nuclear fuel amortization 173,326 159,461
------------ ------------
1,549,225 1,558,053
Construction work in progress 121,725 128,860
------------ ------------
Net Utility Plant 1,670,950 1,686,913
------------ ------------
Current Assets
Cash and cash equivalents 44,121 2,810
Accounts receivable, net of allowance for
doubtful accounts:
1995 - $ 11,950; 1994 - $ 950 121,123 110,417
Unbilled revenue receivable 64,169 54,270
Materials and supplies, at average cost:
Fossil fuel 8,101 7,908
Construction and other supplies 10,223 13,264
Gas stored underground 20,326 24,315
Prepayments 24,533 23,535
------------ ------------
Total Current Assets 292,596 236,519
------------ ------------
Investment in Empire 38,879 38,560
Deferred Debits
Unamortized debt expense 16,712 18,343
Nuclear generating plant decommissioning fund 71,540 49,011
Nine Mile Two deferred costs 32,411 33,462
Deferred finance charges - Nine Mile Two 19,242 19,242
Other deferred debits 21,857 19,214
Regulatory assets:
Income taxes 188,599 205,794
Uranium enrichment decommissioning deferral 18,707 20,169
Deferred ice storm charges 16,553 19,111
FERC 636 transition costs 40,965 32,479
Demand side management costs 14,759 19,807
Deferred fuel costs - gas - 33,845
Other regulatory assets 31,623 33,727
------------ ------------
Total Regulatory Assets 311,206 364,932
------------ ------------
Total Deferred Debits 472,968 504,204
------------ ------------
Total Assets 2,475,393 2,466,196
============ ============
The accompanying notes are an integral part of the financial statements.
39
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars) At December 31 1995 1994
- ------------------------------------------------------------------------------
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $624,332 $643,278
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 55,000 55,000
Common shareholders' equity:
Common stock 687,518 670,569
Retained earnings 70,330 74,566
------------ ------------
Total Common Shareholders' Equity 757,848 745,135
------------ ------------
Total Capitalization 1,596,080 1,602,313
------------ ------------
Long Term Liabilities (Department of Energy)
Nuclear waste disposal 75,077 70,895
Uranium enrichment decommissioning 15,810 16,931
------------ ------------
Total Long Term Liabilities 90,887 87,826
------------ ------------
Current Liabilities
Long term debt due within one year 18,000 -
Short term debt - 51,600
Note Payable - Empire 29,600 29,600
Accounts payable 52,578 42,934
Dividends payable 19,170 18,818
Taxes accrued 18,638 3,471
Interest accrued 12,844 11,967
Other 31,508 22,937
------------ ------------
Total Current Liabilities 182,338 181,327
------------ ------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 377,652 402,894
Deferred finance charges - Nine Mile Two 19,242 19,242
Pension costs accrued 71,580 75,912
Other 137,614 96,682
------------ ------------
Total Deferred Credits and
Other Liabilities 606,088 594,730
------------ ------------
Commitments and Other Matters (Note 10) - -
------------ ------------
Total Capitalization and Liabilities $2,475,393 $2,466,196
============ ============
The accompanying notes are an integral part of the financial statements.
40
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars) Year Ended December 31 1995 1994 * 1993 *
- ----------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS
Net income $ 71,928 $ 74,375 $ 78,563
Adjustments to reconcile net income to net cash
provided from operating activities:
Depreciation and amortization 91,593 87,461 84,177
Amortization of nuclear fuel 17,982 18,048 18,861
Deferred fuel - electric (7,213) (1,967) (2,072)
Deferred fuel - gas 10,645 (28,691) (13,453)
Deferred income taxes (8,047) 13,193 15,232
Allowance for funds used during construction (3,486) (2,408) (1,867)
Unbilled revenue, net (9,899) 7,060 (5,107)
Deferred ice storm costs 2,558 2,510 2,576
Nuclear generating plant decommissioning fund (8,837) (8,594) (8,558)
Pension costs accrued 6,280 43,942 11,641
Post employment benefit internal reserve 4,636 5,287 4,174
Research and development amortization 2,860 183 105
Rate settlement amortizations 9,521 8,943 -
Regulatory disallowance 26,866 600 1,953
Changes in certain current assets and liabilities:
Accounts receivable (10,706) (5,664) (12,461)
Materials and supplies - gas stored underground 3,989 14,674 (28,991)
- other, net 2,848 (1,545) 5,776
Taxes accrued 15,167 (3,001) (7,271)
Accounts payable 9,644 (9,662) 12,018
Interest accrued 877 (988) (2,506)
Other current assets and liabilities, net 8,762 317 6,113
Other, net 13,823 1,508 (13,686)
------------ ------------ ------------
Total Operating $ 251,791 $ 215,581 $ 145,217
- --------------------------------------- ------------ ------------ ------------
CASH FLOW FROM INVESTING ACTIVITIES
Utility Plant
Plant additions $ (95,911) $ (103,737) $ (125,744)
Nuclear fuel additions (17,122) (15,890) (15,530)
Less: Allowance for funds used during construction 3,486 2,408 1,867
------------ ------------ ------------
Additions to Utility Plant (109,547) (117,219) (139,407)
Proceeds from retirement of plant 11,477 - -
Investment in Empire - net (319) - 884
Other, net (34) (150) (1,907)
------------ ------------ ------------
Total Investing $ (98,423) $ (117,369) $ (140,430)
- --------------------------------------- ------------ ------------ ------------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issue of common stock $ 17,074 $ 17,369 $ 61,254
Sale of preferred stock - 25,000 -
Sale of long term debt, mortgage bonds - - 200,000
Short term borrowings (51,600) (16,500) 17,300
Retirement of long term debt (1,000) (33,750) (200,249)
Retirement of preferred stock - (18,000) (12,000)
Capital stock expense (125) 1,028 (615)
Dividends paid on preferred stock (7,465) (7,328) (7,548)
Dividends paid on common stock (68,347) (65,457) (60,893)
Other, net (594) (91) (1,468)
------------ ------------ ------------
Total Financing $ (112,057) $ (97,729) $ (4,219)
------------ ------------ ------------
Increase in cash and cash equivalents $ 41,311 $ 483 $ 568
Cash and cash equivalents at begining
of year $ 2,810 $ 2,327 $ 1,759
------------ ------------ ------------
Cash and cash equivalents at end of year $ 44,121 $ 2,810 $ 2,327
- --------------------------------------- ============ ============ ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars) Year Ended December 31 1995 1994 1993
- ----------------------------------------------------------------------------------------------
Cash Paid During the Period
Interest paid (net of capitalized amount) $ 56,592 $ 57,186 $ 60,852
Income taxes paid $ 43,500 $ 28,411 $ 32,779
- --------------------------------------- ============ ============ ============
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
41
NOTES TO FINANCIAL STATEMENTS
Note 1. SUMMARY OF ACCOUNTING PRINCIPLES
GENERAL. The Company supplies electric and gas services wholly within
the State of New York. It produces and distributes electricity and distributes
gas in parts of nine counties centering about the City of Rochester. The
Company is subject to regulation by the Public Service Commission of the State
of New York (PSC) under New York statutes and by the Federal Energy Regulatory
Commission (FERC) as a licensee and public utility under the Federal Power Act.
The Company's accounting policies conform to generally accepted accounting
principles as applied to New York State public utilities giving effect to the
ratemaking and accounting practices and policies of the PSC. The preparation of
financial statements requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities at the date of the
financial statements and the reported amounts of revenues and expenses during
the reporting period. Actual results could differ from those estimates.
A description of the Company's principal accounting policies follows.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements
include the accounts of the Company and its wholly-owned subsidiaries Roxdel and
Energyline. All intercompany balances and transactions have been eliminated.
Energyline Corporation, which is a wholly-owned subsidiary, was
incorporated in July 1992. Energyline was formed as a gas pipeline corporation
to fund the Company's investment in the Empire State Pipeline project. On
November 1, 1993 Empire commenced service. The Company has authority to make a
net investment of up to $20 million in Empire. In June 1993 Empire secured a
$150 million credit agreement, a portion of the proceeds of which were used to
finance approximately 75% of the total construction cost and initial operating
expenses. Energyline has a total obligation of $20 million in the Empire State
Pipeline, made up of a $10.3 million equity investment, and $9.7 million in
commitments under the credit agreement.
RATES AND REVENUE. Revenue is recorded on the basis of meters read.
In addition, the Company records an estimate of unbilled revenue for service
rendered subsequent to the meter-read date through the end of the accounting
period.
Tariffs for electric and gas service include fuel cost adjustment
clauses which adjust the rates monthly to reflect changes in the actual average
cost of fuels. The electric fuel adjustment provides that customers and the
Company will share the effects of any variation from forecast monthly unit fuel
costs on a 50%/50% basis up to 60 basis points of common equity or approximately
a $7.0 million cumulative annual gain or loss to the Company. Thereafter, 100%
of additional fuel clause adjustment amounts are assigned to customers. The
electric fuel cost adjustment also provides that any variation from forecast
margins below $4.1 million or above $7.1 million on sales to electric utilities
be shared with retail customers on a 50%/50% basis.
In addition, there is a similar 80%/20% sharing process of variances
from forecasted margins derived from sales and the transportation of privately
owned gas to large customers that can use alternate fuels.
Under the Company's Electric Revenue Assurance Mechanism (ERAM), which was
established in the 1993 multi-year rate settlement, any variations between
actual margins and the established targets may be recovered from or returned to
customers. The December 31, 1995 balance recoverable from customers is $9.3
million. The company is not currently recognizing ERAM amounts as part of
income. The ultimate recognition, if any, will be determined as a part of the
current rate filing with the PSC.
In prior years, retail customers who use gas for spaceheating were
subject to a weather normalization adjustment to reflect the impact of
variations from normal weather on a billing month basis for the months of
October through May, inclusive. Weather normalization adjustments lowered gas
revenues in 1994 and 1993 by approximately $1.2 million in each year. On
January 25, 1995 the Company
42
suspended the weather normalization adjustment in an effort to mitigate high
billings due to the warm weather, and as discussed in Note 10, the suspension
became permanent. This decreased 1995 pre-tax earnings from gas operations by
$5.8 million.
The Company practices gas cost deferral accounting. A reconciliation
of recoverable gas costs with gas revenues is done annually as of August 31, and
the excess or deficiency is refunded to or recovered from the customers during a
subsequent period.
UTILITY PLANT, DEPRECIATION AND AMORTIZATION. The cost of additions
to utility plant and replacement of retirement units of property is capitalized.
Cost includes labor, material, and similar items, as well as indirect charges
such as engineering and supervision, and is recorded at original cost. The
Company capitalizes an Allowance for Funds Used During Construction
approximately equivalent to the cost of capital devoted to plant under
construction that is not included in its rate base. Replacement of minor items
of property is included in maintenance expenses. Costs of depreciable units of
plant retired are eliminated from utility plant accounts, and such costs, plus
removal expenses, less salvage, are charged to the accumulated depreciation
reserve.
Depreciation in the financial statements is provided on a straight-
line basis at rates based on the estimated useful lives of property, which have
resulted in an annual depreciation provision of 2.9% in the three year period
ended December 31, 1995. Reported other income deductions includes an additional
charge of approximately $5 million to recognize the difference between a
rateable method of computation versus a lesser amount currently included in
rates for the Empire Pipeline.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION. The Company capitalizes
an Allowance for Funds Used During Construction (AFUDC) based upon the cost of
borrowed funds for construction purposes, and a reasonable rate upon the
Company's other funds when so used. AFUDC is segregated into two components and
classified in the Consolidated Statement of Income as Allowance for Borrowed
Funds Used During Construction, an offset to Interest Charges, and Allowance for
Other Funds used During Construction, a part of Other Income.
The rates approved by the PSC for purposes of computing AFUDC ranged
from 5.0% to 3.9% during the three-year period ended December 31, 1995.
The Company did not accrue AFUDC on a portion of its investment in
Nine Mile Two for which a cash return was allowed. Instead amounts were
accumulated in deferred debit and credit accounts for use in conjunction with a
rate phase-in plan equal to the amount of AFUDC which was no longer accrued.
FEDERAL INCOME TAX. Statement of Financial Accounting Standards
(SFAS) 109, Accounting for Income Taxes, was adopted by the Company during the
first quarter of 1993 (see Note 2).
CASH AND CASH EQUIVALENTS. Cash and cash equivalents consist of cash
and short-term commercial paper. These investments have original maturity not
exceeding three months. Such investments are stated at cost, which approximates
fair value, and are considered cash equivalents for financial statement
purposes.
INVESTMENTS IN DEBT AND EQUITY SECURITIES. SFAS-115, Accounting for
Certain Investments in Debt and Equity Securities, was adopted by the Company in
1994 and requires that debt and equity securities not held to maturity or held
for trading purposes be recorded at fair value with unrealized gains and losses
excluded from earnings and recorded as a separate component of shareholders'
equity. The Company's accounting policy, as prescribed by the PSC, with respect
to its nuclear decommissioning trusts is to reflect the trusts' assets at market
value and reflect unrealized gains and losses as a change in the corresponding
accrued decommissioning liability.
FUTURE CONTRACTS. The Company periodically hedges natural gas in storage
against possible changes in price. Hedges are always backed by gas commodity in
storage, and gains or losses resulting from these transactions are deferred
until the corresponding gas is withdrawn from storage and delivered to
customers. The Company had no open hedge contracts outstanding at December 31,
1995.
43
ALLOWANCE FOR DOUBTFUL ACCOUNTS. The Company's practice is to reserve an
amount for doubtful accounts that corresponds to its write-off history.
Recently, the Company experienced an increase in write-offs and extended
collection periods. Accordingly, an additional $11 million was reserved in
1995.
RESEARCH AND DEVELOPMENT COST. Research and Development charged to expense
for the years 1995, 1994, and 1993 was $5.2 million, $7.3 million, and $8.3
million respectively.
SALE OF PROPERTY. During 1995, the Company sold property at the location
of its former operation center for approximately $11.5 million and entered into
a 3 year lease-back arrangement with the buyer. The gain on the sale of the
property has been deferred pending disposition by the PSC.
EARNINGS PER SHARE. Earnings applicable to each share of common stock are
based on the weighted average number of shares outstanding during the respective
years.
44
Note 2. FEDERAL INCOME TAXES
The provision for federal income taxes is distributed between operating
expense and other income based upon the treatment of the various components of
the provision in the rate-making process. The following is a summary of income
tax expense for the three most recent years.
(Thousands of Dollars)
------------------------------
1995 1994 1993
Charged to operating expense:
Current $ 65,368 $ 35,658 $33,453
Deferred 847 25,587 15,877
-------- -------- -------
Total 66,215 61,245 49,330
Charged (Credited) to other income:
Current (9,996) (7,419) (9,182)
Deferred (4,520) (6,408) 1,787
Investment tax credit (2,432) (2,432) (2,432)
-------- -------- -------
Total (16,948) (16,259) (9,827)
Total federal income tax expense $ 49,267 $ 44,986 $39,503
The following is a reconciliation of the difference between the amount
of federal income tax expense reported in the Consolidated Statement of Income
and the amount computed by multiplying the income by the statutory tax rate.
(Thousands of Dollars)
---------------------------------------------
1995 1994 1993
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
------ ------ ------ ------ ------ ------
Net Income $ 71,928 $ 74,375 $ 78,563
Add: federal income tax expense 49,267 44,986 39,503
-------- -------- --------
Income before federal income tax $121,195 $119,361 $118,066
Computed tax expense $ 42,418 35.0 $ 41,776 35.0 $ 41,323 35.0
Increases (decreases) in tax resulting from:
Difference between tax depreciation
and amount deferred 7,197 6.0 6,685 5.6 6,337 5.4
Investment tax credit (2,432) (2.0) (2,432) (2.0) (2,432) (2.1)
Miscellaneous items, net 2,084 1.7 (1,043) (0.9) (5,725) (4.8)
Total federal income tax expense $ 49,267 40.7 $ 44,986 37.7 $ 39,503 33.5
A summary of the components of the net deferred tax liability is as
follows:
(Thousands of Dollars)
-------------------------------
1995 1994 1993
Nuclear decommissioning $(14,797) $(13,390) $(11,518)
Nine Mile disallowance (5,351) (10,276) (15,200)
Alternate minimum tax 0 (9,584) (27,908)
Accelerated depreciation 197,952 184,941 164,821
Investment tax credit 31,143 32,723 34,305
Deferred ice storm charges 4,035 4,930 5,642
Depreciation previously flowed through 183,077 200,956 246,127
Gas storage demand charges (6,076) 0 0
Other (12,331) 12,594 29,379
-------- -------- --------
Total $377,652 $402,894 $425,648
The Company adopted SFAS-109 "Accounting for Income Taxes" in 1993. SFAS-
109 requires that a deferred tax liability must be recognized on the balance
sheet for tax differences previously flowed through to customers. Substantially
all of these flow-through adjustments relate to property plant and equipment and
related investment tax credits and will be amortized consistent with the
depreciation of these accounts. The net amount of the additional liability at
December 31, 1995 and 1994 was $189 million and $206 million, respectively. In
conjunction with the recognition of this liability, a corresponding regulatory
asset was also recognized.
As of December 31, 1995, the regulatory asset recognized by the Company as
a result of adopting SFAS-109 is attributed to $166 million in depreciation, $21
million to property taxes, $18 million of deferred finance charges - Nine Mile
Two and $4 million of Miscellaneous items offset by $17 million attributed to
investment tax credits and $3 million of revenue taxes.
45
Note 3. PENSION PLAN AND OTHER POST EMPLOYMENT BENEFITS
The Company has a defined benefit pension plan covering substantially all
of its employees. The benefits are based on years of service and the employee's
compensation. The Company's funding policy is to contribute annually an amount
consistent with the requirements of the Employee Retirement Income Security Act
and the Internal Revenue Code. These contributions are intended to provide for
benefits attributed to service to date and for those expected to be earned in
the future.
The plan's funded status and amounts recognized on the Company's balance
sheet are as follows:
(Millions)
1995 1994
----------- ------------
Accumulated benefit obligation, including
vested benefits of $407.8 in 1995 and
$330.5 in 1994 $(424.5)* $ (354.8)*
======= ==========
Projected benefit obligation for service
rendered to date $(515.9)* $ (433.5)*
Less: Plan assets at fair value, primarily
listed stocks and bonds 520.0 451.7
------- ----------
Plan assets in excess of projected benefits 4.1 18.2
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions ( 91.1) (110.9)
Prior service cost not yet recognized in
net periodic pension cost 12.5 13.4
Unrecognized net obligation at December 31 2.9 3.4
------- ----------
Pension costs accrued $( 71.6) $ ( 75.9)**
======= ==========
* Actuarial present value.
** Includes $43.3 million pension plan curtailment charge.
Net pension cost included the following components:
(Millions)
1995 1994 1993
---------- ------- -------
Service cost - benefits earned during the period $ 6.0 $ 8.2 $ 8.7
Interest cost on projected benefit obligation 35.4 32.2 30.0
Actual return on plan assets (101.1) 0.8 (60.2)
Net amortization and deferral 56.1 (40.0) 24.3
------- ------ ------
Net periodic pension (credit) cost $ (3.6) $ 1.2 $ 2.8
======= ====== ======
During 1994, the Company offered to its employees a Temporary
Retirement Enhancement Program (TREP 3). A total of 399 employees elected to
participate in TREP 3 resulting in a net curtailment charge of $43.3 million
($9.6 million deferred for collection from customers), including $71.1 million
cost of the enhanced benefit offset by a curtailment gain of $27.8 million. In
connection with the curtailment, the Company revalued the projected benefit
obligation as of September 30, 1994 utilizing a current discount rate of 8.25%.
The projected benefit obligation at December 31, 1995 and December 31,
1994 assumed discount rates of 6.75% and 8.50%, respectively, and a long-term
rate of increase in future compensation levels of 5.00% and 6.00%, respectively.
The assumed long-term rate of return on plan assets was 8.50%. The unrecognized
net obligation is being amortized over 15 years beginning January 1986.
46
In September 1993, the PSC issued a "Statement of Policy Concerning
the Accounting and Ratemaking Treatment for Pensions and Postretirement Benefits
Other than Pensions" (Statement). The 1995, 1994, and 1993 pension cost
reflects adoption of the Statement's provisions which, among other things,
requires ten-year amortization of actuarial gains and losses and deferral of
differences between actual costs and rate allowances.
In addition to providing pension benefits, the Company provides
certain health care and life insurance benefits to retired employees and health
care coverage for surviving spouses of retirees. Substantially all of the
Company's employees are eligible provided that they retire as employees of the
Company. In 1995, the health care benefit consisted of a contribution of up to
$200 per retiree per month towards the cost of a group health policy provided by
the Company. The life insurance benefit consists of a Basic Group Life benefit,
covering substantially all employees, providing a death benefit equal to one-
half of the retiree's final pay. In addition, certain employees and retirees,
employed by the Company at December 31, 1982, are entitled to a Special Group
Life benefit providing a death benefit equal to the employee's December 31, 1982
pay.
The Company adopted SFAS-106, "Accounting for Postretirement Benefits
Other than Pensions", in 1992. The Company has elected to amortize the
unrecognized, unfunded Accumulated Postretirement Benefit Obligation at January
1, 1992 over twenty years as provided by SFAS-106. The Company intends to
continue funding these benefits as the benefit becomes due.
The plan's funded status reconciled with the Company's balance sheet is as
follows:
(Millions)
1995 1994
---------- -------
Accumulated postretirement benefit obligation:
Retired employees $(68.3) $(42.4)
Active employees (14.0) (26.4)
------ ------
$(82.3) $(68.8)
Less - Plan assets at fair value 0.0 0.0
------ ------
Accumulated postretirement benefit
obligation (in excess of) less than
fair value of assets (82.3) (68.8)
Unrecognized net loss (gain) from past experience
different from that assumed and effects
of changes in assumptions 10.3 0.8
Prior service cost not yet recognized in
net periodic pension cost 7.5 5.6
Unrecognized net obligation at December 31 45.1 47.9
------ ------
Accrued postretirement benefit cost $(19.4) $(14.5)
====== ======
Net periodic postretirement benefit cost included the following components:
(Millions)
1995 1994
---------- -----
Service cost - benefits attributed to the period $ 0.7 $ 0.9
Interest cost on accumulated postretirement
benefit obligation 5.5 4.9
Actual return on plan assets 0.0 0.0
Net amortization and deferral 2.9 3.4
----- -----
Net periodic postretirement benefit cost $ 9.1 $ 9.2
===== =====
The Accumulated Postretirement Benefit Obligation at December 31, 1995
and 1994 assumed discount rates of 6.75% and 8.50%, respectively, and long-term
rate of increase in future compensation levels of 5.00% and 6.00%, respectively.
47
SFAS-112, "Employers' Accounting for Postemployment Benefits", was
adopted by the Company in 1994. SFAS-112 requires the Company to recognize the
obligation to provide postemployment benefits to former or inactive employees
after employment but before retirement. The additional postemployment
obligation at the time of the accounting change was approximately $11 million
and is being deferred on the balance sheet.
Note 4. DEPARTMENTAL FINANCIAL INFORMATION
The Company's records are maintained by operating departments, in
accordance with PSC accounting policies. The following is the operating data for
each of the Company's departments, and no interdepartmental adjustments are
required to arrive at the operating data included in the Consolidated Statement
of Income.
(Thousands of Dollars)
----------------------------------
1995 1994 1993
---------- ---------- ----------
Electric
Operating Information
Operating revenues $ 722,465 $ 674,753 $ 655,316
Operating expenses, excluding
provision for income taxes 518,762 489,982 486,951
---------- ---------- ----------
Pretax operating income 203,703 184,771 168,365
Provision for income taxes 59,500 52,842 43,845
---------- ---------- ----------
Net operating income $ 144,203 $ 131,929 $ 124,520
---------- ---------- ----------
Other Information
Depreciation and amortization $ 78,812 $ 75,211 $ 72,326
Nuclear fuel amortization $ 17,982 $ 18,048 $ 18,861
Capital expenditures $ 93,634 $ 93,477 $ 112,022
Investment Information
Identifiable assets (a) $2,228,056 $1,920,504 $1,978,009
Gas
Operating Information
Operating revenue $ 293,863 $ 326,061 $ 293,708
Operating expenses, excluding
provision for income taxes 275,978 294,575 265,510
---------- ---------- ----------
Pretax operating income 17,885 31,486 28,198
Provision for income taxes 6,715 8,403 5,485
---------- ---------- ----------
Net operating income $ 11,170 $ 23,083 $ 22,713
---------- ---------- ----------
Other Information
Depreciation and amortization $ 12,781 $ 12,250 $ 11,815
Capital expenditures $ 15,913 $ 23,742 $ 27,385
Investment Information
Identifiable assets (a) $ 477,758 $ 487,333 $ 491,563
(a) Excludes cash, unamortized debt expense, and other common items.
48
Note 5. JOINTLY-OWNED FACILITIES
The following table sets forth the jointly-owned electric generating
facilities in which the Company is participating. Both Oswego Unit No. 6 and
Nine Mile Point Nuclear Plant Unit No. 2 have been constructed and are operated
by Niagara Mohawk Power Corporation. Each participant must provide its own
financing for any additions to the facilities. The Company's share of direct
expenses associated with these two units is included in the appropriate
operating expenses in the Consolidated Statement of Income. Various
modifications will be made throughout the lives of these plants to increase
operating efficiency or reliability, and to satisfy changing environmental and
safety regulations.
Oswego Nine Mile Point
Unit No. 6 Nuclear Unit No. 2
---------- ------------------
Net megawatt capacity
as estimated by
Niagara Mohawk Power Corporation 850 1,143
RG&E's share - megawatts 204 160
- percent 24 14
Year of completion 1980 1988
Millions of Dollars
at December 31, 1995
------------------------------
Plant In Service Balance $98.6 $880.0
Accumulated Provision For Depreciation $36.8 $457.8
Plant Under Construction $ 0.4 $ 3.2
The Plant in Service and Accumulated Provision for Depreciation
balances for Nine Mile Point Nuclear Unit No. 2 shown above include disallowed
costs of $374.3 million. Such costs, net of income tax effects, were previously
written off in 1987 and 1989.
49
Note 6. LONG-TERM DEBT
FIRST MORTGAGE BONDS
(Thousands of Dollars)
Principal Amount
December 31
% Series Due 1995 1994
- ------- ------ --- -------- --------
5.30 V May 1, 1996 $ 18,000 $ 18,000
6 1/4 W Sept. 15, 1997 20,000 20,000
6.7 X July 1, 1998 30,000 30,000
8.00 Y Aug. 15, 1999 30,000 30,000
8 3/8 CC Sept. 15, 2007 49,000 50,000
6 1/2 EE/(a)/ Aug. 1, 2009 10,000 10,000
8 3/8 OO/(a)/ Dec. 1, 2028 25,500 25,500
9 3/8 PP Apr. 1, 2021 100,000 100,000
8 1/4 QQ/(b)/ Mar. 15, 2002 100,000 100,000
6.35 RR/(a)/ May 15, 2032 10,500 10,500
6.50 SS/(a)/ May 15, 2032 50,000 50,000
7.00 (b)(c) Jan. 14, 2000 30,000 30,000
7.15 (b)(c) Feb. 10, 2003 39,000 39,000
7.13 (b)(c) Mar. 3, 2003 1,000 1,000
7.64 (c) Mar. 15, 2023 33,000 33,000
7.66 (c) Mar. 15, 2023 5,000 5,000
7.67 (c) Mar. 15, 2023 12,000 12,000
6.375 (b)(c) July 30, 2003 40,000 40,000
7.45 (c) July 30, 2023 40,000 40,000
-------- --------
$643,000 $644,000
Net bond discount (668) (722)
Less: Due within one year 18,000 -
-------- --------
Total $624,332 $643,278
======== ========
(a) The Series EE, Series OO, Series RR and Series SS First Mortgage Bonds
equal the principal amount of and provide for all payments of principal,
premium and interest corresponding to the Pollution Control Revenue Bonds,
Series A, Series C, and Pollution Control Refunding Revenue Bonds, Series
1992 A, Series 1992 B (Rochester Gas and Electric Corporation Projects),
respectively, issued by the New York State Energy Research and Development
Authority through a participation agreement with the Company. Payment of
the principal of, and interest on the Series 1992 A and Series 1992 B Bonds
are guaranteed under a Bond Insurance Policy by Municipal Bond Investors
Assurance Corporation. The Series EE Bonds are subject to a mandatory
sinking fund beginning August 1, 2000 and each August 1 thereafter. Nine
annual deposits aggregating $3.2 million will be made to the sinking fund,
with the balance of $6.8 million principal amount of the bonds becoming due
August 1, 2009.
(b) The Series QQ First Mortgage Bonds and the 7%, 7.15%, 7.13% and 6.375%
medium-term notes described below are generally not redeemable prior to
maturity.
(c) In 1993 the Company issued $200 million under a medium-term note program
entitled "First Mortgage Bonds, Designated Secured Medium-Term Notes,
Series A" with maturities that range from seven years to thirty years.
The First Mortgage provides security for the bonds through a first lien on
substantially all the property owned by the Company (except cash and accounts
receivable).
Sinking and improvement fund requirements aggregate $333,540 per annum
under the First Mortgage, excluding mandatory sinking funds of individual
series. Such requirements may be met by certification of additional property or
by
50
depositing cash with the Trustee. The 1995 and 1994 requirements were met by
certification of additional property.
On February 15, 1994 the Company redeemed $2.75 million principal amount of
its First Mortgage 10.95% Bonds, Series FF, pursuant to a sinking fund
provision. On June 15, 1994 the Company redeemed all of its outstanding $15
million principal amount of First Mortgage 13 7/8% Bonds, Series JJ, due June
15, 1999. Of the $15 million total, $2.5 million was redeemed through a
mandatory sinking fund provision, and the remaining $12.5 million was redeemed
at the Company's option.
There are no sinking fund requirements for the next five years. Bond
maturities for the next five years are:
(Thousands of Dollars)
1996 1997 1998 1999 2000
------- ------- ------- ------- -------
Series V $18,000
Series W $20,000
Series X $30,000
Series Y $30,000
7% Series $30,000
------- ------- ------- ------- -------
$18,000 $20,000 $30,000 $30,000 $30,000
PROMISSORY NOTES
(Thousands of Dollars)
December 31
Issued Due 1995 1994
- ------ --- ---- ----
November 15, 1984/(d)/ October 1, 2014 $51,700 $51,700
December 5, 1985/(e)/ November 15, 2015 40,200 40,200
------- -------
Total $91,900 $91,900
======= =======
(d) The $51.7 million Promissory Note was issued in connection with NYSERDA's
Floating Rate Monthly Demand Pollution Control Revenue Bonds (Rochester Gas
and Electric Corporation Project), Series 1984. This obligation is
supported by an irrevocable Letter of Credit expiring October 15, 1997. The
interest rate on this note for each monthly interest payment period will be
based on the evaluation of the yields of short-term tax-exempt securities
at par having the same credit rating as said Series 1984 Bonds. The average
interest rate was 3.68% for 1995, 2.82% for 1994 and 2.19% for 1993. The
interest rate will be adjusted monthly unless converted to a fixed rate.
(e) The $40.2 million Promissory Note was issued in connection with NYSERDA's
Adjustable Rate Pollution Control Revenue Bonds (Rochester Gas and Electric
Corporation Project), Series 1985. This obligation is supported by an
irrevocable Letter of Credit expiring November 30, 1998. The annual
interest rate was adjusted to 2.75% effective November 15, 1993, to 4.40%
effective November 15, 1994 and to 3.75% effective November 15, 1995. The
interest rate will be adjusted annually unless converted to a fixed rate.
The Company is obligated to make payments of principal, premium and
interest on each Promissory Note which correspond to the payments of principal,
premium, if any, and interest on certain Pollution Control Revenue Bonds issued
by the New York State Energy Research and Development Authority (NYSERDA) as
described above. These obligations are supported by certain bank Letters of
Credit discussed above. Any amounts advanced under such Letters of Credit must
be repaid, with interest, by the Company.
51
Based on an estimated borrowing rate at year-end 1995 of 6.69% for
long-term debt with similar terms and average maturities (14 years), the fair
value of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $780 million at December 31, 1995.
Based on an estimated borrowing rate at year-end 1994 of 8.62% for
long-term debt with similar terms and average maturities (13 years), the fair
value of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $667 million at December 31, 1994.
52
Note 7. PREFERRED AND PREFERENCE STOCK
Par Shares Shares
Type by Order of Seniority Value Authorized Outstanding
- ------------------------------ ----- ---------- ------------
Preferred Stock (cumulative) $100 2,000,000 1,220,000*
Preferred Stock (cumulative) 25 4,000,000 -
Preference Stock 1 5,000,000 -
* See below for mandatory redemption requirements.
No shares of preferred or preference stock are reserved for employees, or
for options, warrants, conversions, or other rights.
A. PREFERRED STOCK, NOT SUBJECT TO MANDATORY REDEMPTION:
Shares (Thousands) Optional
Outstanding December 31, Redemption
% Series December 31, 1995 1995 1994 (per share) #
- -------- ------ ----------------- ------- ------- -------------
4 F 120,000 $12,000 $12,000 $ 105
4.10 H 80,000 8,000 8,000 101
4 3/4 I 60,000 6,000 6,000 101
4.10 J 50,000 5,000 5,000 102.5
4.95 K 60,000 6,000 6,000 102
4.55 M 100,000 10,000 10,000 101
7.50 N 200,000 20,000 20,000 102
------- ------- -------
Total 670,000 $67,000 $67,000
======= ======= =======
# May be redeemed at any time at the option of the Company on 30 days minimum
notice, plus accrued dividends in all cases.
B. PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:
Shares (Thousands) Optional
Outstanding December 31, Redemption
% Series December 31, 1995 1995 1994 (per share)
- -------- ------ ----------------- ------- ------------- -------------------
8.25 R - $ - $ - Not applicable
7.45 S 100,000 10,000 10,000 Not applicable
7.55 T 100,000 10,000 10,000 Not applicable
7.65 U 100,000 10,000 10,000 Not applicable
6.60 V 250,000 25,000 25,000 Not Before 3/1/04+
------- ------- -------
Total 550,000 $55,000 $55,000
======= ======= =======
+ Thereafter at $100.00
53
MANDATORY REDEMPTION PROVISIONS
In the event the Company should be in arrears in the sinking fund
requirement, the Company may not redeem or pay dividends on any stock
subordinate to the Preferred Stock.
Series R. The Company redeemed the remaining 180,000 shares on March
1, 1994 at $100 per share. Capital stock expense of $1.4 million was charged
against retained earnings in connection with the redemption of the Series R
Preferred Stock in 1994.
Series S, Series T, Series U. All of the shares are subject to
redemption pursuant to mandatory sinking funds on September 1, 1997 in the case
of Series S, September 1, 1998 in the case of Series T and September 1, 1999 in
the case of Series U; in each case at $100 per share.
Series V. The Series V is subject to a mandatory sinking fund
sufficient to redeem on each March 1 beginning in 2004 to and including 2008,
12,500 shares at $100 per share and on March 1, 2009, the balance of the
outstanding shares. The Company has the option to redeem up to an additional
12,500 shares on the same terms and dates as applicable to the mandatory sinking
fund.
Based on an estimated dividend rate at year-end 1995 of 5.90% for
Preferred Stock, subject to mandatory redemption, with similar terms and average
maturities (6.66 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $59 million at December 31,
1995.
Based on an estimated dividend rate at year-end 1994 of 7.50% for
Preferred Stock, subject to mandatory redemption, with similar terms and average
maturities (8.65 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $54 million at December 31,
1994.
54
Note 8. COMMON STOCK
At December 31, 1995, there were 50,000,000 shares of $5 par value
Common Stock authorized, of which 38,453,163 were outstanding. No shares of
Common Stock are reserved for options, warrants, conversions, or other rights.
There were 1,369,062 shares of Common Stock reserved and unissued for
shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan
and 185,743 shares reserved and unissued for employees under the RG&E Savings
Plus Plan.
Capital stock expense increased in 1993 primarily due to expenses
associated with the public sale of Common Stock. Redemption of the Company's
8.25% Preferred Stock, Series R, decreased capital stock expense by $0.9 million
in 1993 and $1.4 million in 1994.
COMMON STOCK
Per Shares Amount
Share Outstanding (Thousands)
----------- ------------ -----------
Balance, January 1, 1993 34,796,659 $ 591,532
Sale of Stock 29.625 1,500,000 44,438
Automatic Dividend Reinvestment 25.475-
and Stock Purchase Plan 29.413 515,036 14,076
Savings Plus Plan 25.813-
29.250 99,570 2,741
Decrease (Increase) in
Capital Stock Expense (615)
---------- ----------
Balance, December 31, 1993 36,911,265 $ 652,172
Automatic Dividend Reinvestment 20.313-
and Stock Purchase Plan 25.088 644,478 14,797
Savings Plus Plan 20.313-
24.875 114,220 2,572
Decrease (Increase) in
Capital Stock Expense 1,028
---------- ----------
Balance, December 31, 1994 37,669,963 $ 670,569
Automatic Dividend Reinvestment 20.288-
and Stock Purchase Plan 23.625 680,073 14,803
Savings Plus Plan 20.438-
23.875 103,127 2,271
Decrease (Increase) in
Capital Stock Expense ( 125)
---------- ----------
Balance, December 31, 1995 38,453,163 $ 687,518
55
Note 9. SHORT-TERM DEBT
At December 31, 1995 the Company had no short-term debt outstanding.
On December 31, 1994, the Company had short-term debt outstanding of $51.6
million. The weighted average interest rate on short-term debt borrowed during
1995 was 6.14%. For 1994, the weighted average interest rate on short-term debt
outstanding at year end was 6.01% and was 4.50% for borrowings during the year.
The Company has a $90 million revolving credit agreement for a term of
three years. In December of 1995 the Company was granted a one-year extension
of the commitment termination date to December 31, 1998. Commitment fees
related to this facility amounted to $165,000 in 1995 and $169,000 per year in
1994 and 1993.
The Company's Charter provides that unsecured debt may not exceed 15
percent of the Company's total capitalization (excluding unsecured debt). As of
December 31, 1995, the Company would be able to incur $63.4 million of
additional unsecured debt under this provision. The Company has unsecured lines
of credit totaling $92 million available from several banks, at their
discretion. The aggregate borrowings outstanding at any time under these lines
of credit cannot exceed the 15% Charter limitation.
In order to be able to use its $90 million revolving credit agreement,
the Company has created a subordinate mortgage which secures borrowings under
its revolving credit agreement that might otherwise be restricted by this
provision of the Company's Charter. In addition, the Company has a Loan and
Security Agreement to provide for borrowings up to $20 million for the exclusive
purpose of financing Federal Energy Regulatory Commission Order 636 transition
costs(636 Notes) and up to $20 million as needed from time to time for other
working capital needs. Borrowings under this agreement, which can be renewed
annually, are secured by a lien on the Company's accounts receivable.
At December 31, 1995, borrowings outstanding were $13.9 million of 636
Notes (recorded on the Balance Sheet as a deferred credit).
56
Note 10. COMMITMENTS AND OTHER MATTERS
CAPITAL EXPENDITURES
The Company's 1996 construction expenditures program is currently
estimated at $150 million, including $51 million related to replacement of the
steam generators at the Ginna Nuclear Plant. The Company has entered into
certain commitments for purchase of materials and equipment in connection with
that program.
NUCLEAR-RELATED MATTERS
DECOMMISSIONING TRUST. The Company is collecting in its electric rates
amounts for the eventual decommissioning of its Ginna Plant and for its 14%
share of the decommissioning of Nine Mile Two. The operating licenses for these
plants expire in 2009 and 2026, respectively.
Under accounting procedures approved by the PSC, the Company has
collected decommissioning costs of approximately $78.9 million through December
31, 1995. In connection with the Company's rate settlement completed in August
1993, the PSC approved the collection during the rate year ending June 30, 1996
of an aggregate $8.9 million for decommissioning, covering both nuclear units.
The amount allowed in rates is based on estimated ultimate decommissioning costs
of $169.5 million for Ginna and $38.6 million for the Company's 14% share of
Nine Mile Two (January 1995 dollars). This estimate is based principally on the
application of a Nuclear Regulatory Commission (NRC) formula to determine
minimum funding with an additional allowance for removal of non-contaminated
structures. Site specific studies of the anticipated costs of actual
decommissioning are required to be submitted to the NRC at least five years
prior to the expiration of the license.
The Company completed a site specific cost analysis of decommissioning
at Ginna and incorporated the results of this study in its July 1995 rate filing
with the PSC. Based on the site specific study the estimated decommissioning
cost increased to $296.3 million (May 1995 dollars). The Company has received
Niagara Mohawk's estimate of a site specific cost estimate for Nine Mile Two
which indicates the Company's share of such costs could be as much as $113
million. This estimate is currently under review by the Company and the other
co-tenants and the staff of the PSC. The Company cannot predict the timing or
extent to which any additional estimates will be recognized in rates.
The NRC requires reactor licensees to submit funding plans that
establish minimum NRC external funding levels for reactor decommissioning. The
Company's plan, filed in 1990, consists of an external decommissioning trust
fund covering both its Ginna Plant and its Nine Mile Two share. Since 1990,
the Company has contributed $54.4 million to this fund and, including realized
and unrealized investment returns, the fund has a balance of $71.5 million as of
December 31, 1995. The amount attributed to the allowance for removal of non-
contaminated structures is being held in an internal reserve. The internal
reserve balance as of December 31, 1995 is $24.4 million.
The Company is aware of recent NRC activities related to upward
revisions to the required minimum funding levels. These activities, primarily
focused on disposition of low level radioactive waste, may require the Company
to further increase funding. The Company continues to monitor these activities
and although an increase in funding levels is likely, the Company cannot predict
what regulatory actions the NRC may ultimately take.
The Staff of the Securities and Exchange Commission and the Financial
Accounting Standards Board are currently studying the recognition, measurement
and classification of decommissioning costs for nuclear generating stations in
the financial statements of electric utilities. If current accounting practices
for such costs were changed, the annual provisions for decommissioning costs
could increase, the estimated cost for decommissioning could be reclassified as
a liability rather than as accumulated depreciation, the liability accounts and
corresponding plant asset carrying accounts could be increased and trust fund
57
income from the external decommissioning trusts could be reported as investment
income rather than as a reduction to decommissioning expense.
If annual decommissioning costs increased, the Company would expect to
defer the effects of such costs pending disposition by the PSC.
URANIUM ENRICHMENT DECONTAMINATION AND DECOMMISSIONING FUND. As part
of the National Energy Act (Energy Act) issued in October 1992, utilities with
nuclear generating facilities are assessed an annual fee payable over 15 years
to pay for the decommissioning of federally owned uranium enrichment facilities.
The assessments for Ginna and Nine Mile Two are estimated to total $22.1
million, excluding inflation and interest. The first three installments
aggregating approximately $6.2 million have been paid through 1995. A liability
has been recognized on the financial statements along with a corresponding
regulatory asset. For the two facilities the Company's liability at December
31, 1995 is $17.5 million ($15.8 million as a long-term liability and $1.7
million as a current liability). In October 1993, the Company began recovery of
this deferral through its fuel adjustment clause. The Company believes that the
full amount of the assessment will be recoverable in rates as described in the
Energy Act.
NUCLEAR FUEL DISPOSAL COSTS. The Nuclear Waste Policy Act (Nuclear
Waste Act) of 1982, as amended, requires the United States Department of Energy
(DOE) to establish a nuclear waste disposal site and to take title to nuclear
waste. A permanent DOE high-level nuclear waste repository is not expected to
be operational before the year 2010. The DOE is pursuing efforts to establish
an interim storage facility which may allow it to take title to and possession
of nuclear waste prior to the establishment of a permanent repository. The
Nuclear Waste Act provides for a determination of the fees collectible by the
DOE for the disposal of nuclear fuel irradiated prior to April 7, 1983 and for
three payment options. The option of a single payment to be made at any time
prior to the first delivery of fuel to the DOE was selected by the Company in
June 1985. The Company estimates the fees, including accrued interest, owed to
the DOE to be $75.1 million at December 31, 1995. The Company is allowed by the
PSC to recover these costs in rates. The estimated fees are classified as a
long-term liability and interest is accrued at the current three-month Treasury
bill rate, adjusted quarterly. The Nuclear Waste Act also requires the DOE to
provide for the disposal of nuclear fuel irradiated after April 6, 1983, for a
charge of one mill ($.001) per KWH of nuclear energy generated and sold. This
charge (approximately $2.7 million per year) is currently being collected from
customers and paid to the DOE pursuant to PSC authorization. The Company
expects to utilize on-site storage for all spent or retired nuclear fuel
assemblies until an interim or permanent nuclear disposal facility is
operational.
There are presently no facilities in operation in the United States
available for the reprocessing of spent nuclear fuel from utility companies. In
the Company's determination of nuclear fuel costs it has taken into account that
nuclear fuel would not be reprocessed and has provided for disposal costs in
accordance with the Nuclear Waste Act. The Company has completed a conceptual
study of alternatives to increase the capacity for the interim storage of spent
nuclear fuel at the Ginna Plant. The preferred alternative, based on cost and
safety criteria, is to install high-capacity spent fuel racks in the existing
area of the spent fuel pool. The additional storage capacity, scheduled to be
implemented prior to September 2000, would allow interim storage of all spent
fuel discharged from the Ginna Plant through the end of its Operating License in
the year 2009.
SPENT NUCLEAR FUEL LITIGATION. The Nuclear Waste Act obligates the
DOE to accept for disposal spent nuclear fuel (SNF) starting in 1998. Since the
mid-1980s the Company and other nuclear plant owners and operators have paid
substantial fees to the DOE to fund its obligations under the Nuclear Waste Act.
DOE has indicated that it may not be in a position to accept SNF in 1998. On
June 20, 1994, Northern States Power Company and other owners and operators of
nuclear power plants filed suit against DOE and the U.S. in the U.S. Court of
Appeals for the District of Columbia Circuit asking for a declaration that DOE
is not acting in accordance with law, seeking orders directing DOE to submit to
the Court a description of and progress reports on a program to begin acceptance
of SNF by 1998, and requesting other relief, including an order allowing
petitioners to pay fees into an escrow fund rather than to DOE. The Company has
joined Northern States and the other petitioners in this litigation. Petitioners
initial
58
and reply briefs were filed in October and November, 1995, respectively and oral
argument was completed in January, 1996. A decision is expected in the second
quarter of 1996.
NUCLEAR FUEL ENRICHMENT SERVICES. The Company has two contracts for
enrichment services, one with the United States Enrichment Corporation (USEC),
formerly part of the DOE, for nuclear fuel enrichment services which assures
provision for 70% of the Ginna Nuclear Plant's requirements throughout its
service life or 30 years, whichever is less. No payment obligation accrues
unless such enrichment services are needed. Annually, the Company is permitted
to decline USEC-furnished enrichment for a future year upon giving ten years'
notice. Consistent with that provision, the Company has terminated its
commitment to USEC for the years 2000, 2001 and 2002. The USEC waived, for an
interim period, the obligation to give ten years' notice for 2003, 2004 and
2005. Additionally, the Company will accept only 70% of its required enrichment
services from USEC in 1996 through 1999. A second enrichment service contract
has been placed with Urenco, Inc., with enrichment facilities in Europe, to
cover 30% of the Company's requirements from 1996 through 1999, and 100% of
requirements in 2000 and 2001. The Company plans to meet its enrichment
requirements for years beyond those already committed by making further
arrangements with USEC, Urenco or by contracting with third parties. The
estimated cost of enrichment services utilized every 18 months for the next
seven years is expected to range from $10 million to $13 million.
INSURANCE PROGRAM. The Price-Anderson Act establishes a federal
program insuring against public liability in the event of a nuclear accident at
a licensed U.S. reactor. Under the program, claims would first be met by
insurance which licensees are required to carry in the maximum amount available
(currently $200 million). If claims exceed that amount, licensees are subject
to a retrospective assessment up to $79.3 million per licensed facility for each
nuclear incident, payable at a rate not to exceed $10 million per year. Those
assessments are subject to periodic inflation-indexing and a surcharge for New
York State premium taxes. The Company's interests in two nuclear units could
thus expose it to a potential liability for each accident of $90.4 million
through retrospective assessments of $11.4 million per year in the event of a
sufficiently serious nuclear accident at its own or another U.S. commercial
nuclear reactor.
Claims alleging radiation-induced injuries to workers at nuclear
reactor sites are covered under a separate, industry-wide insurance program.
That program contains a retrospective premium assessment feature whereby
participants in the program can be assessed to pay incurred losses that exceed
the program's reserves. Under the plan as currently established, the Company
could be assessed a maximum of $3.0 million over the life of the insurance
coverage.
The Company is a member of Nuclear Electric Insurance Limited, which
provides insurance coverage for the cost of replacement power during certain
prolonged accidental outages of nuclear generating units and coverage for
property losses in excess of $500 million at nuclear generating units. If an
insuring program's losses exceeded its other resources available to pay claims,
the Company could be subject to maximum assessments in any one policy year of
approximately $3.8 million and $17.2 million in the event of losses under the
replacement power and property damage coverages, respectively.
LITIGATION WITH CO-GENERATOR
Under federal and New York State laws and regulations, the Company is
required to purchase the electrical output of unregulated cogeneration
facilities which meet certain criteria (Qualifying Facilities). Under these
statutes, a utility is required to pay for electricity from Qualifying
Facilities at a rate that equals the cost to the utility of power it would
otherwise produce itself or purchase from other sources (Avoided Cost). With
the exception of one contract which the Company was compelled by regulators to
enter into with Kamine/Besicorp Allegany L.P. (Kamine) for approximately 55
megawatts of capacity, the Company has no long-term obligations to purchase
energy from Qualifying Facilities.
Under State law and regulatory requirements in effect at the time the
contract with Kamine was negotiated, the Company was required to agree to pay
59
Kamine a price for power that is substantially greater than the Company's own
cost of production and other purchases. Since that time the State law mandating
a minimum price higher than the Company's own costs has been repealed and PSC
estimates of future costs on which the contract was based have declined
dramatically.
In September 1994, the Company commenced a lawsuit in New York State
Supreme Court, Monroe County, seeking to void or, alternatively, to reform a
Power Purchase Agreement with Kamine for the purchase of the electrical output
of a cogeneration facility in the Town of Hume, Allegany County, New York, for a
term of 25 years. The contract was negotiated pursuant to the specific pricing
requirement of a State statute that was later repealed, as well as estimates of
Avoided Costs by the PSC that subsequently were drastically reduced. As a
result, the contract requires the Company to pay prices for Kamine's electrical
output that dramatically exceed current Avoided Costs and current projections of
Avoided Costs. The Company's lawsuit seeks to avoid payments to Kamine that
exceed actual and currently projected Avoided Costs. Kamine answered the
Company's complaint, seeking to force the Company to take and pay for power at
the higher rates called for in the contract and claiming damages in an
unspecified amount alleged to have been caused by the Company's conduct. The
Company received test generation from the Kamine facility during the last
quarter of 1994. Kamine contends that the facility went into commercial
operation in December 1994 and that the Company is obligated to pay the full
contract rate for it. The Company disputes this contention and refuses to pay
the full contract rate. During 1995 Kamine filed a motion for summary judgement
dismissing the Company's complaint and directing it to perform the Power
Purchase Agreement. The court denied that motion and Kamine appealed. After
argument of that appeal Kamine filed for protection under the Bankruptcy laws
and sent to the Appellate Division a notice that all further proceedings were
stayed. The Company is unable to predict the ultimate outcome of this
litigation.
In addition, Kamine has filed a related complaint in the United States
District Court for the Western District of New York alleging that the conduct
which is the subject of the State court action violates the federal antitrust
laws. The complaint seeks treble damages in the amount of $420,000,000, as well
as preliminary and permanent injunctions. Subsequently, Kamine filed a motion
for a preliminary injunction in the federal action to enjoin the Company from
refusing to accept and purchase electric power from Kamine and enjoining the
Company from terminating during the pendency of this lawsuit its performance
under the contract. In November, 1995, the Court issued a decision denying
Kamine's motion for a preliminary injunction, finding, among other things, that
Kamine had not established the necessary likelihood of success on the merits of
its action. Kamine filed a notice of appeal from that decision but has
subsequently announced that it is withdrawing that appeal. The Company is
unable to predict the ultimate outcome of this litigation.
During 1995 the PSC invited the Company to file a petition requesting,
among other things, that the Commission commence an investigation to determine
whether at the time of claimed commercial operation the Hume plant was a
cogeneration facility under New York law as required by the Power Purchase
Agreement. The Company filed such a petition and Kamine filed papers in
opposition. The Company is unable to predict the ultimate outcome of this
proceeding.
Also during 1995 Kamine filed a petition before the FERC to waive
certain requirements for federal Qualified Facility status for 1994. The
Company and the PSC filed in opposition to the request. Subsequently FERC
issued an order granting the waiver request and the Company has filed a motion
for reconsideration.
In November 1995 Kamine filed in Newark, New Jersey for protection
under the Bankruptcy laws and filed a complaint in an adversary proceeding
seeking, among other things, specific performance of the Power Purchase
Agreement. Kamine filed a motion to compel the Company to pay under its view of
the terms of the Power Purchase Agreement during the pendency of the Adversary
Proceeding. After hearing, the Bankruptcy Court denied that motion. The Court
also denied various motions made by the Company to change the venue of the
proceedings to New York State and to lift the automatic stay of the pending New
York State Action. The Company has filed a notice of appeal to the District
Court for the denial of its
60
motions. The PSC has filed a motion to lift the stay to permit it to proceed
with its investigation of the Hume facility under New York State Law. General
Electric Credit Corporation which had provided financing to the Hume project,
has intervened in the Adversary Proceeding as a plaintiff. The Company has
filed an answer with affirmative defenses and counterclaims in the Adversary
Proceeding. The counterclaims seek, among other things, the relief sought in the
New York State Court action described above. The parties are now engaged in
discovery in connection with the Adversary Proceeding.
The existence of mandated high priced independent power purchase
agreements is a significant problem throughout the State of New York and there
are various efforts by State officials to resolve the problem. The Company
continues to work to resolve this particular dispute in a fashion that is fair
and equitable to all parties, however, we will continue to take aggressive
action on behalf of customers and the Company to assure that their interests are
respected in any resolution. The Company is unable to predict the ultimate
outcome of these efforts on the legal proceedings.
ENVIRONMENTAL MATTERS
The following tables list various sites where past waste handling and
disposal has or may have occurred that are discussed below:
TABLE I - COMPANY-OWNED SITES
Estimated
Site Name Location Company Cost
--------- -------- ------------
West Station Rochester, NY Ultimate costs have
East Station Rochester, NY not been determined.
Front Street Rochester, NY The Company has
Brewer Street Rochester, NY incurred aggregate
Brooks Avenue Rochester, NY costs for these sites
Canandaigua Canandaigua, NY through December 31,
1995 of $2.4 million.
TABLE II - SUPERFUND AND OTHER SITES
Estimated
Site Name Location Company Cost
--------- -------- ------------
Quanta Resources* Syracuse, NY Ultimate costs have
Frontier Chemical- not been determined.
Pendleton* Pendleton, NY The Company has
Maxey Flats* Morehead, KY incurred aggregate
Mexico Milk Mexico, NY costs for these sites
Byron Barrel and Drum Bergen, NY through December 31,
Fulton Terminals* Oswego, NY 1995 of $1.0 million.
PAS of Oswego* Oswego, NY
* Orders on consent signed.
COMPANY-OWNED WASTE SITE ACTIVITIES. As part of its commitment to
environmental excellence, the Company is conducting proactive Site Investigation
and/or Remediation (SIR) efforts at six Company-owned sites where past waste
handling and disposal may have occurred. Remediation activities at three of
these sites are in various stages of planning or completion and the Company is
conducting a program to restore, as necessary to meet environmental standards,
the other three sites. The Company has recorded a total liability of
approximately $11 million, $8 million of which it anticipates spending on SIR
efforts at the six Company-owned sites listed in Table I above where past waste
handling and disposal may have occurred. Concurrently, the Company recorded a
similar increase in its Regulatory Assets. Approximately $4.5 million has been
provided for in rates through June 1996 ($1.5 million annually) for recovery of
61
SIR costs. To the extent actual expenditures differ from this amount, they will
be deferred for future disposition and recovery as authorized by the PSC.
In mid-1995, the New York State Department of Environmental
Conservation (NYSDEC) developed a listing of sites called "The Hazardous
Substance Site Inventory". Under current New York State law, unless a site,
which is determined to pose a public health or environmental risk, contains
hazardous wastes, State "Superfund" monies cannot be used to assist in the
clean-up. The State wanted to have some sense of the scale of this problem
before the legislature considered other avenues of legal and financial redress
than those currently available. The NYSDEC's " Hazardous Substance Waste
Disposal Site Study" was developed to assess the number of and cost to
remediate sites where hazardous chemicals, but not hazardous wastes are present.
Of the six Company-owned sites listed in Table I above, three are listed in this
inventory. These are East Station, Front Street and Brooks Avenue. In addition
to these three sites, the inventory includes Ambrose Yard and Lindberg Heat
Treating. The Company does not believe that additional SIR work for which the
Company is responsible is required at either site, however the Company is unable
to predict what action will be necessitated as a result of the listing.
The Company and its predecessors formerly owned and operated three
manufactured gas facilities in the Rochester area. They are included in Table
I. In September 1991, the Company initiated a study of subsurface conditions in
the vicinity of retired facilities at its West Station manufactured gas property
and has since commenced the removal of soils containing hazardous substances in
order to minimize any potential long-term exposure risks. Cleanup efforts were
temporarily suspended while the Company investigated more cost effective
remedial technologies. Cleanup activities resumed in October 1995 and are
scheduled to be concluded in April 1996. At the second of the three
manufactured gas plant sites known as East Station, an interim remedial action
was undertaken in late 1993. Ground water monitoring wells were also installed
to assess the quality of the ground water at this location. The Company has
informed the NYSDEC of the results of the samples taken. These results may
indicate that some further action may be required.
At the third Rochester area property owned by the Company (Front
Street) where gas manufacturing took place, a boring placed in the Fall of 1988
for a sewer system project showed a layer containing a black viscous material.
The study of the layer found that some of the soil and ground water on-site had
been adversely impacted by the hazardous substance constituents of the black
viscous material, but evidence was inadequate to determine whether the material
or its constituents had migrated off-site. The matter was reported to the
NYSDEC and, in September 1990, the Company also provided the agency with a risk
assessment for its review. That assessment concluded that the findings
warranted no agency action and that site conditions posed no significant threat
to the environment. Although NYSDEC could require the Company to undertake
further investigation and/or remediation, the agency has taken no action since
the report's submittal. The Company is formulating plans for long-term
management of the site.
Another property owned by the Company where gas manufacturing took
place is located in Canandaigua, New York. Limited investigative work performed
there during the Summer of 1995 has shown evidence of both the former gas
manufacturing operations and leakage from fuel tanks. The NYSDEC was informed;
the fuel tanks removed; and additional work planned for 1996. The SIR costs
associated with these actions are included in Table I. The NYSDEC has not taken
any action against the Company as a result of these findings.
On another portion of the Company's property in the Rochester area
(Brewer Street), and elsewhere in the general area, the County of Monroe has
installed and operates sewer lines. During sewer installation, the County
constructed over Company property certain retention ponds which reportedly
received from the sewer construction area certain fossil-fuel-based materials
(the materials) found there. In July 1989, the Company received a letter from
the County asserting that activities of the Company left the County unable to
effect a regulatorily-approved closure of the retention pond area. The County's
letter takes the position that it intends to seek reimbursement for its
additional costs incurred with respect to the materials once the NYSDEC
identifies the generator thereof and that any further cleanup action which the
NYSDEC may require at the retention pond site is the Company's responsibility.
In the course of discussions over
62
this matter, the County has claimed, without offering any evidence, that the
Company was the original generator of the materials. It asserts that it will
hold the Company liable for all County costs -- presently estimated at $1.5
million -- associated both with the materials' excavation, treatment and
disposal and with effecting a regulatorily-approved closure of the retention
pond area. The Company could incur costs as yet undetermined if it were to be
found liable for such closure and materials handling, although provisions of an
existing easement afford the Company rights which may serve to offset all or a
portion of any such County claim. To date, the Company has agreed to pay a 20%
share of the County's most recent investigation of this area, which commenced in
September 1993 and which is estimated to cost no more than $150,000, but no
commitment has been made toward any remedial measures which may be recommended
by the investigation.
The NYSDEC did not include the site in its hazardous substance
inventory, presumably pending negotiations with the County to pursue appropriate
closure of the County's former retention pond area. The Company and the County
continue to negotiate to resolve the issue. The Company is unable to assess the
outcome of the negotiations or the implications of the NYSDEC's attempts to
secure proper closure.
Monitoring wells installed at another Company facility (Brooks Avenue)
in 1989 revealed that an undetermined amount of leaded gasoline had reached the
ground water. The Company has continued to monitor free product levels in the
wells, and has begun a modest free product recovery project, reports on both of
which are routinely furnished to the NYSDEC. Free product levels in the wells
have declined. It is estimated that further investigative work into this
problem may cost up to $100,000. In December 1994, the NYSDEC granted a permit
for the storage of hazardous wastes at this location. Conditions of the permit
require additional investigation and corrective action of the hazardous
constituents at the site. While the cost of corrective actions cannot be
determined until investigations are completed, preliminary estimates are in the
range of $160-180 thousand.
SUPERFUND AND OTHER SITES. The Company has been or may be associated
as a potentially responsible party (PRP) at seven sites not owned by it. The
Company has signed orders on consent for five of these sites and recorded
estimated liabilities totaling approximately $3 million.
In August 1990, the Company was notified of the existence of a federal
Superfund site located in Syracuse, NY, known as the Quanta Resources Site. The
federal Environmental Protection Agency (EPA) has included the Company in its
list of approximately 25 PRPs at the site, but no data has been produced showing
that any of its wastes were delivered to the site. In return for its release
from liability for that phase, the Company has joined other PRPs in agreeing to
divide among them, utilizing a two-tier structure, EPA's cost of a contractor-
performed removal action intended to stabilize the site and has signed a consent
order to that effect. The Company, in the lower tier of PRPs, paid its $27,500
share of such cost. Although the NYSDEC has not yet made an assessment for
certain response and investigation costs it has incurred at the site, nor is
there as yet any information on which to determine the cost to design and
conduct at the site any remedial measures which federal or State authorities may
require, the Company does not expect its costs to exceed $250,000.
On May 21, 1993, the Company was notified by NYSDEC that it was
considered a PRP for the Frontier Chemical Pendleton Superfund Site located in
Pendleton, NY. The Company has signed, along with other participating parties,
an Administrative Order on Consent with NYSDEC. The Order on Consent obligates
the parties to implement a work plan and remediate the site. The PRPs have
negotiated a work plan for site remediation and have retained a consulting firm
to implement the work plan. Preliminary estimates indicate site remediation
will be between $6 and $8 million. The Company is participating with the group
to allocate costs among the PRPs. Subsequent work has indicated that the final
cost is likely to be lower.
The Company is involved in the investigation and cleanup of the Maxey
Flats Nuclear Disposal Site in Morehead, Kentucky and has signed various consent
orders to that effect. The Company has contributed to a study of the site and
estimates
63
that its share of the cost of investigation and remediation would approximate
$205,000.
The Company has been named as a PRP at three other sites and has been
associated with another site for which the Company's share of total projected
costs is not expected to exceed $120,000. Actual Company expenditures for these
sites are dependent upon the total cost of investigation and remediation and the
ultimate determination of the Company's share of responsibility for such costs
as well as the financial viability of other identified responsible parties since
clean-up obligations are joint and several.
FEDERAL CLEAN AIR ACT AMENDMENTS. The Company is developing
strategies responsive to the federal Clean Air Act Amendments of 1990
(Amendments) which will primarily affect air emissions from the Company's
fossil-fueled electric generating facilities. A range of capital costs between
$15 million and $25 million has been estimated for the implementation of several
potential scenarios which would enable the Company to meet the foreseeable NOx
and sulphur dioxide requirements of the Amendments. These capital costs would
be incurred between 1996 and 2000. The Company estimates that it could also
incur up to $2.1 million of additional annual operating expenses, excluding
fuel, to comply with the Amendments.
GAS COST RECOVERY
FERC 636 TRANSITION COSTS. As a result of the restructuring of the
gas transportation industry by the FERC pursuant to Order No. 636 and related
decisions, there have been and will be a number of changes in this aspect of the
Company's business over the next several years. These changes will require the
Company to pay a share of certain transition costs incurred by the pipelines as
a result of the FERC-ordered industry restructuring. The final amounts of such
transition costs are subject to continuing negotiations with several pipelines
and ongoing pipeline filings requiring FERC approval. The Company, as a
customer, has estimated total costs of about $63.2 million which will be paid to
its suppliers. A regulatory asset and related deferred credit have been
established on the balance sheet to account for these estimated costs.
Approximately $36.2 million of these costs were paid to various suppliers, of
which about $22.2 million has been included in purchased gas costs. At year-
end, $41.0 million remains deferred for future collection from customers. The
Company entered into a $20 million credit agreement with a domestic bank to
provide funds for the Company's transition cost liability to CNG Transmission
Corporation (CNG). At December 31, 1995 the Company had $13.9 million of
borrowings outstanding under the credit agreement. The Company is collecting
those costs through the Gas Clause Adjustment in its rates.
The Company is committed to transportation capacity on the Empire
State Pipeline (Empire) as well as to upstream pipeline transportation and
storage services. The Company also has contractual obligations with CNG and
upstream pipelines whereby the Company is subject to charges for transportation
and storage services for a period extending to the year 2001. The combined CNG
and Empire transportation capacity exceeds the Company's current requirements.
This temporary excess has occurred largely due to the Company's initiatives to
diversify its supply of gas and the industry changes and increasing competition
resulting from the implementation of FERC Order 636.
1995 GAS SETTLEMENT. The Company's purchased gas expense charged to
customers was higher during the 1994-95 heating season compared with prior
years, generating substantial customer concern. The action the Company took to
reduce rates included refunding the weather normalization adjustment charged to
customers in January 1995 and discontinuation of those charges through the
remainder of the heating season ending in May 1995. The weather normalization
adjustment provides for recovery of fixed charges by producing higher unit rates
when the weather is warm and usage is low. Conversely, it would provide lower
unit rates during colder periods of high usage.
In December 1994, the PSC instituted a proceeding to review the
Company's practices regarding acquisition of pipeline capacity, the deferred
costs of the capacity and the Company's recovery of those costs.
64
In April 1995, the PSC issued a Department of Public Service staff
report on the Company's 1994-1995 billing practices and procedures which
presented recommendations regarding changes in the Company's natural gas
purchasing, billing, meter reading and communication activities.
On August 17, 1995, the Company announced that a negotiated settlement
had been reached with the Staff of the PSC and other parties which would resolve
various PSC proceedings affecting the Company's gas costs. On October 18, 1995,
the PSC approved, effective November 1, 1995, (1) the settlement discussed
below, (2) elimination of the weather normalization clause in gas rates and (3)
the Company's plan for improving its gas billing procedures (the 1995 Gas
Settlement). This settlement affects the rate treatment of various gas costs
through October 31, 1998.
Highlights of the 1995 Gas Settlement are:
- - The Company will forego, for three years, gas rate increases exclusive of
the cost of natural gas and certain cost increases imposed by interstate
pipelines.
- - The Company has agreed not to charge customers for pipeline capacity costs
in 1996, 1997 and 1998 of $22.5 million, $24.5 million, and $27.2 million,
respectively. Under FERC rules, the Company may sell its excess
transportation capacity in the market. The value of those sales can be used
to offset the capacity costs that will not be charged to customers. These
amounts that the Company will not be permitted to charge are subject to
increase in the event of major increases in the overall cost of pipeline
capacity during these years. The foregoing amounts include the cost of
capacity to be purchased by replacement shippers. As discussed below, a
substantial portion of this capacity is expected to be released and sold in
the market pursuant to a marketing agreement with CNG, a supply agreement
with MidCon Gas Services Corporation (MGSC), and other individual
agreements.
- - The Company agreed to write off excess gas pipeline capacity costs incurred
through 1995.
- - As part of a separate decision, the PSC agreed with the Company's request
to eliminate the weather normalization clause effective November 1, 1995.
The weather normalization clause had adjusted gas customer billing for
abnormal weather variations.
The economic effect of the 1995 Gas Settlement on the Company's 1995
results of operations may be summarized as follows:
Millions of
Dollars Earnings per
Description (Pretax) Share Effect
- ------------------------------------------ ------------- -------------
Elimination of weather
normalization charges $ 5.8 $(.10)
Foregone gas rate increase scheduled
for July 1, 1995 2.8 (.04)
Foregone gas pipeline capacity
costs for 1995 8.8 (.15)
Gas pipeline capacity and other costs
which were written off in October 1995 23.2 (.40)
Provision for retroactive
pipeline charges pending before FERC 3.6 (.06)
----- -----
Total $44.2 $(.75)
===== =====
Under provisions of the 1995 Gas Settlement, the Company faces an
economic risk of remarketing $74.2 million of excess gas capacity through 1998.
The
65
Company has entered into a marketing agreement with CNG that is expected to
result in the release of approximately $29 million of this capacity through the
period. CNG will assist the Company in obtaining permanent replacement
customers for transportation capacity the Company will not require. To help
manage the balance of the excess capacity costs at risk, the Company has
retained MGSC which will work with the Company to identify and implement
opportunities for temporary and permanent release of surplus pipeline capacity
and advise in the management of the Company's gas supply, transportation and
storage assets consistent with the goal of providing reliable service and
reducing the cost of gas.
The ultimate financial impact of the 1995 Gas Settlement on the
Company's business in 1996 and subsequent years will be largely determined by
the degree of success achieved by the Company in remarketing its excess gas
capacity and in controlling its local gas distribution costs.
PURCHASED GAS UNDERCHARGES
In March 1994 the PSC approved a December 1993 settlement among the
Company, PSC Staff and another party regarding the Company's accounting for
certain gas purchases for the period August 1990 - August 1992 which resulted in
undercharges to gas customers of approximately $7.5 million. The Company wrote
off $2.0 million of the undercharges as of December 31, 1993, reducing 1993
earnings by four cents per share, net of tax. In April 1994, the Company wrote
off an additional one cent per share, net of tax. Under the 1993 settlement,
the Company was to collect $2.6 million from customers over a three-year period.
Due to rate increase limitations established in the Company's 1993 Rate
Agreement and certain provisions under the 1995 Gas Settlement; however, the
Company is precluded from collecting the $2.6 million and accordingly, this
amount was written off in 1995 and is reflected in Other Deductions on the
Statement of Income.
ASSERTION OF TAX LIABILITY
The Company's federal income tax returns for 1987 and 1988 have been
examined by the Internal Revenue Service (IRS) which has proposed adjustments of
approximately $29 million.
The adjustments at issue generally pertain to the characterization and
treatment of events and relationships at the Nine Mile Two project and to the
appropriate tax treatment of investments made and expenses incurred at the
project by the Company and the other co-tenants. A principal issue is the year
in which the plant was placed in service.
The Company filed a protest of the IRS adjustments to its 1987-88 tax
liability. The Company believes it has sound bases for its protest, but cannot
predict the outcome thereof. Generally, the Company would expect to receive
rate relief to the extent it was unsuccessful in its protest except for that
part of the IRS assessment stemming from the Nine Mile Two disallowed costs,
although no such assurance can be given.
The IRS also completed in 1994 its audit of the Company's federal
income tax returns for 1989 and 1990, which has resulted in a proposed refund of
$600,000. Since this refund arises from the contentious issues from the prior
audit, the Company filed a protest with the IRS.
REGULATORY AND STRANDABLE ASSETS
The Company has deferred certain costs rather than recognize them on
its books when incurred. Such deferred costs are then recognized as expenses
when they are included in rates and recovered from customers. Such deferral
accounting is permitted by Statement of Financial Accounting Standards No. 71
(SFAS-71). These deferred costs are shown as Regulatory Assets on the Company's
Balance Sheet. Such cost deferral is appropriate under traditional regulated
cost-of-service rate setting, where all prudently incurred costs are recovered
through rates. In a purely competitive pricing environment, such costs might
not
66
have been incurred and could not have been deferred. Accordingly, if the
Company's rate setting was changed from a cost-of-service approach, and it was
no longer allowed to defer these costs under SFAS-71, these assets would be
adjusted for any impairment to recovery (see discussion under Financial
Accounting Standards No. 121). In certain cases, the entire amount could be
written off.
Below is a summarization of the Regulatory Assets as of December 31, 1995.
Millions
of Dollars
----------
Income Taxes $188.6
Uranium Enrichment Decommissioning Deferral 18.7
Deferred Ice Storm Charges 16.6
FERC 636 Transition Costs 41.0
Demand Side Management Costs Deferred 14.7
Other, net 31.6
------
Total - Regulatory Assets $311.2
======
- - Income Taxes: This amount represents the unrecovered portion of tax
benefits from accelerated depreciation and other timing differences which
were used to reduce tax expense in past years. The recovery of this
deferral is anticipated over the remaining life of the related property
when the effect of the past deductions reverses in future years.
- - Deferred Ice Storm Charges: These costs result from the non-capital storm
damage repair costs following the March 1991 ice storm. The recovery of
these costs has been approved by the PSC through the year 2002.
- - Uranium Enrichment Decommissioning Deferral: The Energy Policy Act of 1992
requires utilities to contribute such amounts based on the amount of
uranium enriched by DOE for each utility. This amount is mandated to be
paid to DOE over the next 13 years. The recovery of these costs is through
the Company's fuel adjustment clause, over a comparable period.
- - FERC 636 Transition Costs: These costs are payable to gas supply and
pipeline companies which are passing various restructuring and other
transition costs on to the Company, as ordered by FERC. The majority of
these costs will be recovered through the Company's gas cost adjustment
over the next three years.
- - Demand Side Management Costs Deferred: These costs are Demand Side
Management costs which relate to programs initiated to increase efficiency
with which electricity is used. These costs are recoverable by the Company
over the next five years.
In a competitive electric market, strandable assets would arise when
investments are made in facilities, or costs are incurred to service customers,
and such costs are not fully recoverable in market-based rates. Examples
include purchase power contracts (e.g., the Kamine/Besicorp Allegany L.P.
contract), or high cost generating assets. Estimates of strandable assets are
highly sensitive to the competitive wholesale market price assumed in the
estimation. The amount of potentially strandable assets at December 31, 1995
cannot be determined at this time, but could be significant.
FINANCIAL ACCOUNTING STANDARDS No. 121
In March 1995, the Financial Accounting Standards Board (FASB) issued
Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-
Lived Assets and for Long-Lived Assets to be Disposed Of" (SFAS-121). SFAS-121
amends SFAS-71 to require write-off of a regulatory asset or strandable asset if
it is no longer probable that future revenues will cover the cost of the asset.
SFAS-121 also requires a company to recognize a loss whenever events or
circumstances occur which indicate that the carrying amount of an asset may not
be fully recoverable. At December 31, 1995 the Company's regulatory assets
totaled $311.2 million. At the current time, the Company believes its
regulatory assets are probable of recovery, and, accordingly, the adoption of
this
67
accounting standard will not have a material impact on the financial position or
results of operations of the Company.
LEASE AGREEMENTS
The Company leases several buildings for administrative offices and
operating activities. The total lease expense charged to operations was $2.4
million in 1995. For the years 1996, 1997, 1998, 1999 and 2000 the estimated
lease expense charged to operations will be $4.1 million, $4.1 million, $4
million, $2.3 million and $2.3 million, respectively. Commitments under capital
leases were not significant to the accompanying financial statements.
68
INTERIM FINANCIAL DATA
In the opinion of the Company, the following quarterly information
includes all adjustments, consisting of normal recurring adjustments, necessary
for a fair statement of the results of operations for such periods. The
variations in operations reported on a quarterly basis are a result of the
seasonal nature of the Company's business and the availability of surplus
electricity.
(Thousands of Dollars)
------------------------------------------------------------
Earnings per
Operating Operating Net Earnings on Common Share
Quarter Ended Revenues Income Income Common Stock (in dollars)
December 31, 1995/1/ $270,518 $37,624 $ (387) $(2,253) $(.05)
September 30, 1995 245,145 41,738 26,934 25,068 .65
June 30, 1995 219,546 29,454 14,861 12,995 .34
March 31, 1995 281,119 46,557 30,520 28,65 .75
December 31, 1994 $243,697 $42,249 $25,618 $23,751 $ .63
September 30, 1994/2/ 229,982 41,007 4,912 3,046 .08
June 30, 1994 217,083 24,578 9,608 7,742 .20
March 31, 1994 310,052 47,178 34,237 32,467 .87
December 31, 1993/3/ $256,219 $43,756 $22,366 $20,541 $ .55
September 30, 1993/4/ 217,278 38,058 20,204 18,379 .51
June 30, 1993 203,252 21,295 6,909 5,084 .15
March 31, 1993 272,275 44,124 29,084 27,259 .78
/1/ Includes recognition of $28.7 million net-of-tax gas settlement adjustment.
/2/ Includes recognition of $21.9 million net-of-tax pension plan curtailment.
/3/ Includes recognition of $1.3 million net-of-tax pension plan curtailment.
/4/ Includes recognition of $5.3 million net-of-tax pension plan curtailment.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS AND FINANCIAL DISCLOSURE
None
69
PART III
Item 10. DIRECTORS, EXECUTIVE OFFICERS, PROMOTERS AND CONTROL PERSONS OF THE
REGISTRANT
The information required by Item 10 of Form 10-K relating to directors
who are nominees for election as directors at the Company's Annual Meeting of
Shareholders to be held on April 24, 1996, will be set forth under the heading
"Election of Directors" in the Company's Definitive Proxy Statement for such
Annual Meeting of Shareholders.
The information required by Item 10 of Form 10-K with respect to
executive officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of
Regulation S-K, set forth in Part I as Item 4-A of this Form 10-K under the
heading "Executive Officers of the Registrant".
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Form 10-K will be set forth
under the headings "Report of the Committee on Management on Executive
Compensation", "Executive Compensation" and "Pension Plan Table" in the
Company's Definitive Proxy Statement for the Annual Meeting of Shareholders.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 of Form 10-K will be set forth
under the headings "General" and "Security Ownership of Management" in the
Company's Definitive Proxy Statement for the Annual Meeting of Shareholders.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 of Form 10-K will be set forth
under the heading "Election of Directors" in the Company's Definitive Proxy
Statement for the Annual Meeting of Shareholders.
Pursuant to General Instruction G(3) to Form 10-K, Items 10 through 13
have not been answered because, within 120 days after the close of its fiscal
year, the Registrant will file with the Commission a definitive proxy statement
pursuant to Regulation 14A which involves the election of directors. Regis
trant's definitive proxy statement dated March 12, 1996 will be filed with the
Securities and Exchange Commission prior to April 30, 1996. The information
required in Items 10 through 13 under the headings set forth above is incorpo
rated by reference herein by this reference thereto. Except as specifically
referenced herein the proxy statement in connection with the annual meeting of
shareholders to be held April 24, 1996 is not deemed to be filed as part of this
Report.
70
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. The financial statements listed below are shown under Item 8 of
this Report.
Report of Independent Accountants.
Consolidated Statements of Income and Retained Earnings
for each of the three years ended December 31, 1995.
Consolidated Balance Sheets at December 31, 1995 and 1994.
Consolidated Statement of Cash Flows for each of the
three years ended December 31, 1995.
Notes to Consolidated Financial Statements.
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1995.
Schedule II - Valuation and Qualifying Accounts.
(a) 3. Exhibits - See List of Exhibits.
(b) Reports on Form 8-K - None.
71
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1993
Additions
----------
Balance at Charged to Charged Balance
Beginning Costs and To Other at End
Descriptions of Period Expenses Accounts Deductions of Period
- ------------------------ --------- ---------- ---------- ---------- ---------
Reserves for:
Uncollectible accounts $500 $100 $600
FOR THE YEAR ENDED DECEMBER 31, 1994
Additions
----------
Balance at Charged to Charged Balance
Beginning Costs and To Other at End
Descriptions of Period Expenses Accounts Deductions of Period
- ------------------------ --------- ---------- ---------- ---------- ---------
Reserves for:
Uncollectible accounts $600 $350 $950
FOR THE YEAR ENDED DECEMBER 31, 1995
Additions
----------
Balance at Charged to Charged Balance
Beginning Costs and To Other at End
Descriptions of Period Expenses Accounts Deductions of Period
- ------------------------ --------- ---------- ---------- ---------- ---------
Reserves for:
Uncollectible accounts $950 $11,000 $11,950
Materials and supplies
obsolescence 0 800 800
Beginning in 1992 the Company no longer charges uncollectible expenses
through the uncollectible reserve. The total amount written off directly to
expense in 1993 was $6,241, in 1994 was $9,000 and in 1995 was $12,063.
72
LIST OF EXHIBITS
Exhibit 3-1* Restated Certificate of Incorporation of Rochester Gas and
Electric Corporation under Section 807 of the Business
Corporation Law filed with the Secretary of State of the
State of New York on June 23, 1992. (Filed in Registration
No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 3-2* Certificate of Amendment of the Certificate of
Incorporation of Rochester Gas and Electric Corporation
Under Section 805 of the Business Corporation Law filed
with the Secretary of State of the State of New York on
March 18, 1994. (Filed as Exhibit 4 in May 1994 on Form
10-Q for the quarter ended March 31, 1994, SEC File No.
1-672.)
Exhibit 3-3* By-Laws of the Company, as amended to date. (Filed as
Exhibit 3-2 in February 1994 on Form 10-K for the year
ended December 31, 1993, SEC File No. 1-672-2)
Exhibit 4-1* Restated Certificate of Incorporation of Rochester Gas and
Electric Corporation under Section 807 of the Business
Corporation Law filed with the Secretary of State of the
State of New York on June 23, 1992. (Filed in Registration
No. 33-49805 as Exhibit 4-5 in July 1993)
Exhibit 4-2* Certificate of Amendment of the Certificate of
Incorporation of Rochester Gas and Electric Corporation
Under Section 805 of the Business Corporation Law filed
with the Secretary of State of the State of New York on
March 18, 1994. (Filed as Exhibit 4 in May 1994 on Form
10-Q for the quarter ended March 31, 1994, SEC File No.
1-672.)
Exhibit 4-3* By-Laws of the Company, as amended to date. (Filed as
Exhibit 3-2 in February 1994 on Form 10-K for the year
ended December 31, 1993, SEC File No. 1-672-2)
Exhibit 4-4* General Mortgage to Bankers Trust Company, as Trustee,
dated September 1, 1918, and supplements thereto, dated
March 1, 1921, October 23, 1928, August 1, 1932 and May 1,
1940. (Filed as Exhibit 4-2 in February 1991 on Form 10-K
for the year ended December 31, 1990, SEC File No. 1-672-2)
Exhibit 4-5* Supplemental Indenture, dated as of March 1, 1983 between
the Company and Bankers Trust Company, as Trustee (Filed as
Exhibit 4-1 on Form 8-K dated July 15, 1993, SEC File No.
1-672)
Exhibit 10-1* Basic Agreement dated as of September 22, 1975 among the
Company, Niagara Mohawk Power Corporation, Long Island
Lighting Company, New York State Electric & Gas Corporation
and Central Hudson Gas & Electric Corporation. (Filed in
Registration No. 2-54547, as Exhibit 5-P in October 1975.)
Exhibit 10-2* Letter amendment modifying Basic Agreement dated September
22, 1975 among the Company, Central Hudson Gas & Electric
Corporation, Orange and Rockland Utilities, Inc. and
Niagara Mohawk Power Corporation. (Filed in Registration
No. 2-56351, as Exhibit 5-R in June 1976.)
73
Exhibit 10-3* Agreement dated September 25, 1984 between the Company and
the United States Department of Energy, as amended. (Filed
as Exhibit 10-3 in February 1995 on Form 10-K for the year
ended December 31, 1994, SEC File No. 1-672-2)
Exhibit 10-4* Agreement dated February 5, 1980 between the Company and
the Power Authority of the State of New York. (Filed as
Exhibit 10-10 in February 1990 on Form 10-K for the year
ended December 31, 1989, SEC File No. 1-672-2)
Exhibit 10-5* Agreement dated March 9, 1990 between the Company and
Mellon Bank, N.A. (Filed as Exhibit 10-1 in May 1990 on
Form 10-Q for the quarter ended March 31, 1990, SEC File
No. 1-672)
Exhibit 10-6* Basic Agreement dated September 22, 1975 as amended and
supplemented between the Company and Niagara Mohawk Power
Corporation. (Filed as Exhibit 10-11 in February 1993 on
Form 10-K for the year ended December 31, 1992, SEC File
No. 1-672-2)
Exhibit 10-7* Operating Agreement effective January 1, 1993 among the
owners of the Nine Mile Point Nuclear Plant Unit No. 2.
(Filed as Exhibit 10-12 in February 1993 on Form 10-K for
the year ended December 31, 1992, SEC File No. 1-672-2)
Exhibit 10-8 Agreement dated July 1, 1995 between the Company and MidCon
Gas Services Corporation [not filed - subject to request
for confidential treatment]
Exhibit 10-9* (A) Rochester Gas and Electric Corporation Deferred
Compensation Plan. (Filed as Exhibit 10-14 in February 1994
on Form 10-K for the year ended December 31, 1993, SEC File
No. 1-672-2)
Exhibit 10-10* (A) Rochester Gas and Electric Corporation Long Term Incentive
Plan, Restatement of January 1, 1994. (Filed as Exhibit
10-10 in February 1995 on Form 10-K for the year ended
December 31, 1994, SEC File No. 1-672-2)
Exhibit 10-11 (A) Rochester Gas and Electric Corporation Executive Incentive
Plan, Restatement of January 1, 1995.
Exhibit 10-12 (A) RG&E Unfunded Retirement Income Plan Restatement as of
July 1, 1995.
Exhibit 10-13 (A) Severance Agreement dated August 17, 1995 between the
Company and Roger W. Kober, Chairman of the Board,
President and Chief Executive Officer.
Exhibit 10-14 (A) Severance Agreement dated August 17, 1995 between the
Company and Thomas S. Richards, Senior Vice President,
Energy Services.
Exhibit 10-15 (A) Severance Agreement dated August 17, 1995 between the
Company and Robert E. Smith, Senior Vice President, Energy
Operations.
74
Exhibit 10-16 (A) Severance Agreement dated January 2, 1996 between the
Company and J. Burt Stokes, Senior Vice President,
Corporate Services and Chief Financial Officer.
Exhibit 23 Consent of Price Waterhouse, independent accountants
Exhibit 27 Financial Data Schedule, pursuant to Item 601(c) of
Regulation S-K.
* Incorporated by reference.
(A) Denotes executive compensation plans and arrangements.
The Company agrees to furnish to the Commission, upon request, a copy of
all agreements or instruments defining the rights of holders of debt which do
not exceed 10% of the total assets with respect to each issue, including the
Supplemental Indentures under the General Mortgage and credit agreements in
connection with promissory notes as set forth in Note 6 of the Notes to
Financial Statements.
75
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.
ROCHESTER GAS AND ELECTRIC CORPORATION
By: ROGER W. KOBER
-----------------------------------
Roger W. Kober
Chairman of the Board, President
and Chief Executive Officer
DATE: February 15, 1996
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 in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- --------- ----- ----
Principal Executive Officer:
ROGER W. KOBER Chairman of the Board, February 15, 1996
- --------------------------- President and Chief
(Roger W. Kober) Executive Officer
Principal Financial Officer:
J. B. STOKES Senior Vice President February 15, 1996
- --------------------------- Corporate Services and
(J. Burt Stokes) Chief Financial Officer
Principal Accounting Officer:
DANIEL J. BAIER Controller February 15,1996
- ---------------------------
(Daniel J. Baier)
76
SIGNATURE TITLE DATE
- --------- ----- ----
Directors:
WILLIAM BALDERSTON III Director February 15, 1996
- ---------------------------
(William Balderston III)
ANGELO J. CHIARELLA Director February 15, 1996
- ---------------------------
(Angelo J. Chiarella)
ALLAN E. DUGAN Director February 15, 1996
- ---------------------------
(Allan E. Dugan)
JAY T. HOLMES Director February 15, 1996
- ---------------------------
(Jay T. Holmes)
ROGER W. KOBER Director February 15, 1996
- ---------------------------
(Roger W. Kober)
THEODORE L. LEVINSON Director February 15, 1996
- ---------------------------
(Theodore L. Levinson)
CONSTANCE M. MITCHELL Director February 15, 1996
- ---------------------------
(Constance M. Mitchell)
CORNELIUS J. MURPHY Director February 15, 1996
- ---------------------------
(Cornelius J. Murphy)
ARTHUR M. RICHARDSON Director February 15, 1996
- ---------------------------
(Arthur M. Richardson)
M. RICHARD ROSE Director February 15, 1996
- ---------------------------
(M. Richard Rose)