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
For the fiscal year ended: December 31, 1996
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OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _________________ to ________________
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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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. [ ]
On January 1, 1997 the aggregate market value of the voting stock held by
nonaffiliates of the Registrant was approximately $742.2 million.
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, 38,851,464.
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 16, 1997.
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 12
Item 3 Legal Proceedings 14
Item 4 Submission of Matters to a Vote of Security Holders 14
Item 4-A Executive Officers of the Registrant 14
Part II
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Item 5 Market for the Registrant's Common Equity and
Related Stockholder Matters 16
Item 6 Selected Financial Data 17
Item 7 Management's Discussion and Analysis of Financial
Condition and Results of Operations 20
Item 8 Financial Statements and Supplementary Data 33
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 63
Part III
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Item 10 Directors and Executive Officers of the Registrant 64
Item 11 Executive Compensation 64
Item 12 Security Ownership of Certain Beneficial Owners and
Management 64
Item 13 Certain Relationships and Related Transactions 64
Part IV
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Item 14 Exhibits, Financial Statement Schedules and Reports
on Form 8-K 65
Signatures 70
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 7
Coal 8
Environmental Quality Control 8
Research and Development 9
Operating Statistics 10
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, 1996 the Company had 1,960 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
discussion of the causes of significant changes in revenues is presented in Item
2
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:
1996 1995 1994
------ ------ ------
Electric 67.1% 71.1% 67.4%
Gas 32.9% 28.9% 32.6%
----- ----- -----
100.0% 100.0% 100.0%
FINANCING AND CAPITAL REQUIREMENTS PROGRAM
A discussion of the Company's capital requirements, financial
objectives 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. 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, 1996 was 6.40.
(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, 1996 the amount of additional First Mortgage
Bonds which could be issued on that basis was approximately $398,265,000.
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, 1996, the Company
could issue $262,334,000 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, 1996, the
coverage ratio under (b) above (the more restrictive provision) was 2.67.
Under more restrictive financing provisions by the PSC the Company is
currently limited to the issuance of not more than $200 million of long-term
debt and common stock.
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, 1996 were:
First
Mortgage Preferred
Bonds Stock
-------- ---------
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 and operator of nuclear facilities, the
Company is also subject to regulation by the Nuclear Regulatory Commission
(NRC). Regulatory matters permeate all of the Company's activities and the
impact of regulation is discussed throughout this report.
In August 1995, a negotiated settlement was 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 in October 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 and the 1996 Rate
Settlement.
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 flexible tariff provisions, the Company
as of year-end 1996 had negotiated long-term electric supply contracts with 46
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
On December 13, 1996 the NRC fined the Company $100,000 as operator of
the Ginna nuclear power plant. The fine was for concerns about the function of
motor operated valves under a certain set of conditions. The Company has taken
corrective measures and did not contest the fine.
COMPETITION
The Company is operating in a rapidly changing competitive marketplace
for electric and gas service. This competitive environment includes a federal
and State trend toward deregulation and promotion of open-market choices for
consumers.
Regarding the Company's electric business, in early 1996 the FERC
issued new rules to facilitate the development of competitive wholesale markets.
At the State level, the PSC is currently investigating the establishment of an
efficient wholesale competitive market, and various issues relating to retail
electric service competition.
With the unbundling of services as directed by FERC Order 636, primary
responsibility for reliable natural gas has shifted from interstate pipeline
companies to local distribution companies, such as the Company. The Company has
implemented two new service classifications that will ultimately provide all gas
customers with gas supply choice.
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 is responding to those challenges.
ELECTRIC OPERATIONS
The total net generating capacity of the Company's electric system is
1,242,000 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 1991-1996 are as follows:
1996 1995 1994 1993 1992
------ ------ ------ ------ ------
Sources of Generated Energy:
Nuclear 49.9% 52.8% 55.3% 57.6% 52.1%
Fossil-Coal 18.2 18.6 16.9 18.2 24.4
-Oil 0.2 - 1.2 1.3 2.9
Hydro and Other 3.0 2.0 2.7 2.6 3.5
----- ----- ----- ----- -----
Total Generated Net 71.3 73.4 76.1 79.7 82.9
Purchased 28.7 26.6 23.9 20.3 17.1
----- ----- ----- ----- -----
Total Electric Energy 100.0% 100.0% 100.0% 100.0% 100.0%
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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
5
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 27%, 28% and 24% for the years 1997,
1998 and 1999, 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
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.
See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations under Competition - Nuclear Operating
Company regarding plans of the Company and Niagara to form a joint nuclear
operating company to support and manage the operations of Nine Mile Units One
and Two and the Company's Ginna Plant described below.
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 FERC, therefore, issued annual licenses that essentially extend
the terms of the old licenses year-to year until processing of the new ones can
be completed. The Company received final licenses for Stations 2 and 5 in
February of 1996. The license for Station 26 is expected to be issued sometime
in 1997. Overly stringent environmental conditions or other governmental
requirements may nullify the economic viability of the fourth station, number
160 (less than one megawatt net capacity).
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 in June 1996.
The gross and net book cost of the Ginna Plant as of December 31, 1996
are $559 million and $313 million, respectively. From time to time the NRC
issues
6
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 at the Ginna Plant, including the cost of
these modifications, are estimated to be $7.1 million, $11.2 million and $5.0
million for the years 1997, 1998 and 1999, 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.
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 $3.3 million and $11.3 million in the event of losses under the
replacement power and property damage coverages, respectively.
GAS OPERATIONS
The total daily transportation capacity contracted and owned by the
Company prior to November 1, 1996 was 5,230,000 Therms (one Therm is equivalent
to 100,000 British Thermal Units). In 1996, the Company renegotiated pipeline
contracts in an effort to more closely align its contractual assets with the
system requirements. As of November 1, 1996 the Company's transportation
capacity is 4,480,000 Therms. On January 19, 1994, the Company experienced its
maximum daily throughput of approximately 3,735,690 Therms, excluding 1,000,000
Therms of transportation customers' gas.
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. See Item 7 -
Management's Discussion and Analysis of Financial Condition and Results of
Operations under the caption "Energy Management and Costs - Gas" for a
discussion of that topic.
7
The Company continues to provide new and additional gas service. Of
240,685 residential gas spaceheating customers at December 31, 1996, 2,058 were
added during 1996.
Approximately 29% of the gas delivered to customers by the Company
during 1996 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)/
----------- ------------------
Uranium Concentrate 2000/(3)/ 2002/(2)/
Conversion 2000/(4)/ 2002/(2)/
Enrichment (5) (6)
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 1997, 70% of requirements in 1998 and 1999, and 100%
in 2000. Thirty percent of requirements remain to be purchased for 1998.
(5) 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 through 1999. A second enrichment contract is
in place which assures 30% of the Ginna Plant's requirements through 1999
and 100% of requirements in 2000 and 2001.
(6) Nine Mile Two is covered for 100% of requirements through 1998 and for
75% (with an option to increase to 100%) from 1999 through 2003.
With appropriate lead times, the Company will pursue 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.
8
The average annual cost of nuclear fuel per million BTU used for electric
generation for the last five years is as follows:
1996 1995 1994 1993 1992
----- ----- ----- ----- -----
Ginna Plant $.424 $.410 $.403 $.400 $.359
Nine Mile Two $.512 $.503 $.481 $.515 $.558
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
610,000 tons. In 1996 100% of its requirements were purchased under contract.
The Company is meeting its requirements during early 1997 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:
1996 1995 1994 1993 1992
---- ---- ---- ---- ----
Per Million BTU $1.34 $1.31 $1.38 $1.42 $1.48
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 1996.
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-2001. Efforts will be pursued
to extend storage capacity beyond mid-2001, 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
9
under cost of service rate regulation. Capital expenditures for meeting various
federal, State and local environmental standards are estimated to be $2.5
million for the year 1997, $6.7 million for the year 1998 and $1.5 million for
the year 1999. 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 1996, 1995 and
1994 were $4.9 million, $5.2 million, and $7.3 million, respectively. These
expenditures represent the Company's contribution to research administered by
Electric Power Research Institute, Empire State Electric Energy Research
Corporation and an assessment for state government sponsored research by the New
York State Energy Research and Development Authority, as well as internal
research projects.
10
Electric Department Statistics
Year Ended December 31 1996 1995 1994 1993 1992 1991
------------ ------------ ------------ ------------ ------------ ------------
Electric Revenue (000's)
Residential $ 254,885 $ 256,294 $ 243,961 $ 234,866 $ 222,210 $ 212,980
Commercial 215,763 215,696 206,545 196,100 187,262 181,553
Industrial 153,337 157,464 150,372 148,084 141,507 142,857
Other 66,898 67,128 57,270 59,905 57,288 51,540
---------- ---------- ---------- ---------- ---------- ----------
Electric revenue from our
customers 690,883 696,582 658,148 638,955 608,267 588,930
Other electric utilities 16,885 25,883 16,605 16,361 25,541 28,612
---------- ---------- ---------- ---------- ---------- ----------
Total electric revenue 707,768 722,465 674,753 655,316 633,808 617,542
---------- ---------- ---------- ---------- ---------- ----------
Electric Expense (000's)
Fuel used in electric
generation 40,938 44,190 44,961 45,871 48,376 65,105
Purchased electricity 46,484 54,167 37,002 31,563 29,706 27,683
Other operation 202,091 195,181 187,594 188,684 183,118 168,610
Maintenance 41,429 44,032 47,295 52,464 53,714 57,032
Depreciation and
amortization 92,615 78,812 75,211 72,326 73,213 72,746
Taxes - local, state and
other 95,010 102,380 97,919 96,043 94,841 86,925
---------- ---------- ---------- ---------- ---------- ----------
Total electric expense 518,567 518,762 489,982 486,951 482,968 478,101
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 189,201 203,703 184,771 168,365 150,840 139,441
Federal income tax 61,901 59,500 52,842 43,845 38,046 31,390
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Electric Operations (000's) $ 127,300 $ 144,203 $ 131,929 $ 124,520 $ 112,794 $ 108,051
---------- ---------- ---------- ---------- ---------- ----------
Electric Operating Ratio % 46.8 46.7 47.0 48.6 49.7 51.6
Electric Sales - KWH
(000's)
Residential 2,132,902 2,144,718 2,117,168 2,123,277 2,084,705 2,087,910
Commercial 2,061,625 2,064,813 2,028,611 1,986,100 1,938,173 1,931,024
Industrial 2,010,963 1,964,975 1,860,833 1,892,700 1,929,720 1,920,075
Other 520,885 531,311 513,675 504,987 503,388 508,368
---------- ---------- ---------- ---------- ---------- ----------
Total customer sales 6,726,375 6,705,817 6,520,287 6,507,064 6,455,986 6,447,377
Other electric utilities 994,842 1,484,196 1,021,733 743,588 1,062,738 1,034,370
---------- ---------- ---------- ---------- ---------- ----------
Total electric sales 7,721,217 8,190,013 7,542,020 7,250,652 7,518,724 7,481,747
---------- ---------- ---------- ---------- ---------- ----------
Electric Customers at
December 31
Residential 307,181 306,601 304,494 302,219 300,344 298,440
Commercial 30,620 30,426 29,984 29,635 29,339 28,856
Industrial 1,325 1,347 1,361 1,382 1,386 1,388
Other 2,688 2,711 2,670 2,638 2,605 2,558
---------- ---------- ---------- ---------- ---------- ----------
Total electric customers 341,814 341,085 338,509 335,874 333,674 331,242
---------- ---------- ---------- ---------- ---------- ----------
Electricity Generated and
Purchased - KWH (000's)
Fossil 1,512,513 1,631,933 1,478,120 1,520,936 2,197,757 2,146,664
Nuclear 4,094,272 4,645,646 4,527,178 4,495,457 4,191,035 4,391,480
Hydro 248,990 171,886 218,129 199,239 278,318 174,239
Pumped storage 246,726 237,904 247,550 233,477 226,391 240,206
Less energy for pumping (370,097) (361,144) (371,383) (355,725) (344,245) (364,520)
Other 936 1,565 1,245 2,559 811 1,269
---------- ---------- ---------- ---------- ---------- ----------
Total generated - net 5,733,340 6,327,790 6,100,839 6,095,943 6,550,067 6,589,338
Purchased 2,353,841 2,343,484 1,998,882 1,646,244 1,389,875 1,451,208
---------- ---------- ---------- ---------- ---------- ----------
Total electric energy 8,087,181 8,671,274 8,099,721 7,742,187 7,939,942 8,040,546
---------- ---------- ---------- ---------- ---------- ----------
System Net Capability -
KW at December 31
Fossil 529,000 529,000 532,000 541,000 541,000 541,000
Nuclear 638,000 640,000 617,000 620,000 617,000 622,000
Hydro 47,000 47,000 47,000 47,000 47,000 47,000
Other 28,000 28,000 29,000 29,000 29,000 29,000
Purchased 375,000 375,000 375,000 347,000 348,000 354,000
---------- ---------- ---------- ---------- ---------- ----------
Total system net capability 1,617,000 1,619,000 1,600,000 1,584,000 1,582,000 1,593,000
---------- ---------- ---------- ---------- ---------- ----------
Net Peak Load - KW 1,305,000 1,425,000 1,374,000 1,333,000 1,252,000 1,297,000
Annual Load Factor - Net % 61.9 57.6 58.8 59.1 62.5 61.7
11
Gas Department Statistics
Year Ended December 31 1996 1995 1994 1993 1992 1991
---------- ----------- ----------- ---------- ---------- -----------
Gas Revenue (000's)
Residential $ 6,010 $ 4,081 $ 5,935 $ 5,526 $ 6,456 $ 6,354
Residential spaceheating 246,945 230,934 215,974 201,129 186,710 162,334
Commercial 52,073 51,117 49,115 46,321 44,395 41,261
Industrial 6,175 6,686 7,088 6,368 6,284 7,050
Municipal and other 35,076 1,045 47,949 34,364 17,879 18,729
---------- ---------- ---------- ---------- ---------- ----------
Total gas revenue 346,279 293,863 326,061 293,708 261,724 235,728
---------- ---------- ---------- ---------- ---------- ----------
Gas Expense (000's)
Gas purchased for resale 202,297 167,762 194,390 166,884 141,291 129,779
Other operation 60,725 58,727 48,302 46,697 43,506 39,830
Maintenance 5,634 5,194 7,774 9,229 9,006 8,383
Depreciation 12,999 12,781 12,250 11,851 11,815 11,435
Taxes - local, state and other 31,858 31,514 31,859 30,849 29,411 26,724
---------- ---------- ---------- ---------- ---------- ----------
Total gas expense 313,513 275,978 294,575 265,510 235,029 216,151
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 32,766 17,885 31,486 28,198 26,695 19,577
Federal income tax 7,600 6,715 8,403 5,485 5,545 2,869
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Gas Operations (000's) $ 25,166 $ 11,170 $ 23,083 $ 22,713 $ 21,150 $ 16,708
---------- ---------- ---------- ---------- ---------- ----------
Gas Operating Ratio % 77.6 79.7 76.8 75.9 74.1 75.5
Gas Sales - Therms (000's)
Residential 6,455 7,167 6,535 6,871 8,780 9,151
Residential spaceheating 299,085 280,763 283,039 295,093 287,623 255,988
Commerical 70,543 68,380 72,410 78,887 78,996 72,167
Industrial 9,334 9,560 11,420 12,030 12,438 13,120
Municipal 8,086 8,219 10,230 12,188 11,410 10,677
---------- ---------- ---------- ---------- ---------- ----------
Total gas sales 393,503 374,089 383,634 405,069 399,247 361,103
Transportation of customer-owned gas 167,779 146,149 136,372 124,436 126,140 109,835
---------- ---------- ---------- ---------- ---------- ----------
Total gas sold and transported 561,282 520,238 520,006 529,505 525,387 470,938
---------- ---------- ---------- ---------- ---------- ----------
Gas Customers at December 31
Residential 16,718 17,443 17,836 18,389 19,114 21,448
Residential spaceheating 240,685 238,267 235,313 231,937 228,096 222,918
Commercial 19,045 18,978 18,742 18,636 18,378 18,151
Industrial 857 879 905 924 932 921
Municipal 961 981 988 1,001 1,010 983
Transportation 744 655 558 466 424 423
---------- ---------- ---------- ---------- ---------- ----------
Total gas customers 279,010 277,203 274,342 271,353 267,954 264,844
---------- ---------- ---------- ---------- ---------- ----------
Gas - Therms (000's)
Purchased for resale 280,435 237,728 262,267 347,778 360,493 384,643
Gas from storage 122,843 152,852 134,802 76,378 53,757 16,755
Other 1,082 1,800 2,959 1,039 1,061 1,617
---------- ---------- ---------- ---------- ---------- ----------
Total gas available 404,360 392,380 400,028 425,195 415,311 403,015
---------- ---------- ---------- ---------- ---------- ----------
Cost of gas per therm (cents) 52.30c 45.80c 50.00c 36.79c 35.35c 32.96c
Total Daily Capacity -
Therms at December 31* 4,480,000 5,230,000 5,625,000 5,625,000 4,485,000 4,485,000
---------- ---------- ---------- ---------- ---------- ----------
Maximum daily throughput - Therms 4,022,600 3,980,000 4,735,690 3,864,850 3,768,470 3,539,260
Degree Days (Calendar Month)
For the period 7,099 6,535 6,699 7,044 6,981 6,146
Percent colder (warmer) than normal 4.8 (3.0) (0.6) 4.4 3.4 (8.4)
* Method for determining daily capacity, based on current network
analysis, reflects the maximum demand which the transmission systems can
accept without a deficiency.
12
Item 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of the Company's electric generating plants in operation as
of December 31, 1996 the net generation of each plant for the year ended
December 31, 1996, 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 80 400,081
Beebee Station
(Gas Turbine) Oil 1969 14 448
Russell Station
(Steam) Coal 1949-1957 260 1,098,660
Ginna Station
(Steam) Nuclear 1970 480 2,882,041
Oswego Unit 6/(1)/
(Steam) Oil 1980 189 13,772
Nine Mile Point
Unit No. 2/(2)/
(Steam) Nuclear 1988 158 1,212,231
Station No. 9
(Gas Turbine) Gas 1969 14 488
Station 5
(Hydro) Water 1917 39 199,489
5 Other Stations
(Hydro) Water 1906-1960 8 49,501
-------- ---------
5,856,711
Pumped Storage /(3)/ 246,726
Less: energy for pumping (370,097)
---------
1,242 5,733,340
======== =========
(1) Represents 24% share of jointly-owned facility.
(2) Represents 14% share of jointly-owned facility.
(3) Owned and operated by the Power Authority.
13
The Company owns 147 distribution substations having an aggregate
rated transformer capacity of 2,104,854 Kva, of which 138, having an aggregate
rated capacity of 1,925,688 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 74,527 line
transformers with a capacity of 2,960,843 Kva. The Company also owns 24
transmission substations having an aggregate rated capacity of 3,052,017 Kva of
which 23, having an aggregate rated capacity of 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 716 circuit miles of overhead lines and approximately 400 circuit
miles of underground lines. The distribution system consists of approximately
16,287 circuit miles of overhead lines, approximately 3,777 circuit miles of
underground lines and 351,247 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 4,191 miles of gas mains and
289,778 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 credit
agreements with a domestic bank under which short-term borrowings are secured by
the Company's accounts receivable.
14
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, 1996.
Item 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT
Age Positions, Offices and Business Experience
Name 12/31/96 1992 to date
- ----------------------------- -------- ---------------------------------------------
Roger W. Kober 63 Chairman of the Board and Chief Executive
Officer - March 1996 to date.
Chairman of the Board, President and Chief
Executive Officer - January 1992 to March 1996.
President and Chief Executive Officer - 1991
to January 1992.
Thomas S. Richards 53 President and Chief Operating Officer - March
1996 to date.
Senior Vice President, Energy Services -
August 1995 to March 1996.
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.
Michael J. Bovalino 41 Senior Vice President, Energy Services -
January 20, 1997 to date.
Vice President, Retail Services for Plum
Street Enterprises (a wholly owned subsidiary
of Niagara Mohawk Power Corporation, 300 Erie
Boulevard West, Syracuse, NY 13202) prior to
joining the Company.
15
Age Positions, Offices and Business Experience
Name 12/31/96 1992 to date
- ----------------------------- -------- ---------------------------------------------
Robert E. Smith 59 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.
J. Burt Stokes 53 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.
David C. Heiligman 56 Vice President and Corporate Secretary - April 1996 to Date.
Vice President, Finance and Corporate Secretary - August
1994 to April 1996.
Vice President, Secretary and Treasurer 1992 to August, 1994.
Robert C. Mecredy 51 Vice President, Nuclear Operations - August, 1994 to Date.
Vice President, Ginna Nuclear Production - 1992 to August,
1994.
Wilfred J. Schrouder, Jr. 55 Vice President, Customer Development - August, 1994 to Date.
Vice President, Employee Relations, Public Affairs and
Materials Management - 1992 to August, 1994.
Daniel J. Baier 50 Controller - August, 1994 to Date.
Assistant Controller - 1992 to August, 1994.
Mark Keogh 51 Treasurer - August, 1994 to Date.
Manager, Treasury Department - 1992 to August, 1994.
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.
16
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
COMMON STOCK AND DIVIDENDS
- ---------------------------------------------------- ----------------------------------------------------
Earnings/Dividends 1996 1995 1994 Shares/Shareholders 1996 1995 1994
- -------------------------- -------- ------- ------- -------------------- ------ ------ -------
Earnings per weighted Number of shares (000's)
average share $ 2.32 $ 1.69 $ 1.79 Weighted average 38,762 38,113 37,327
Dividends paid Actual number at
per share $ 1.80 $ 1.80 $ 1.76 December 31 38,851 38,453 37,670
Number of shareholders
at December 31 33,675 35,356 37,212
- ---------------------------------------------------- ----------------------------------------------------
TAX STATUS OF CASH DIVIDENDS
Cash dividends paid in 1996, 1995 and 1994 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 1997, the Company paid a cash
dividend of $.45 per share on its Common Stock. The January 1997 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 1996 1995 1994
- ---------------------------- ------ ------ ------
High
1st quarter 23 3/4 23 26 3/8
2nd quarter 21 7/8 22 5/8 25 1/8
3rd quarter 21 3/8 24 1/8 23 3/4
4th quarter 19 5/8 24 1/8 21 3/8
Low
1st quarter 21 1/4 20 3/8 23 3/8
2nd quarter 19 7/8 20 1/8 20 1/2
3rd quarter 18 20 19 3/4
4th quarter 17 7/8 22 3/8 20 1/8
At December 31 19 1/8 22 5/8 20 7/8
17
Item 6. SELECTED FINANCIAL DATA
CONSOLIDATED SUMMARY OF OPERATIONS
(Thousands of Dollars) Year Ended December 31 1996 1995 1994 1993 1992 1991
- ---------------------------------------------------------------- ------------ ------------ ------------- ------------ ------------
Operating Revenues
Electric $690,883 $696,582 $658,148 $638,955 $608,267 $588,930
Gas 346,279 293,863 326,061 293,708 261,724 235,728
------------ ----------- ------------ ------------- ------------ ------------
1,037,162 990,445 984,209 932,663 869,991 824,658
Electric sales to other utilities 16,885 25,883 16,605 16,361 25,541 28,612
------------ ---------- ------------ ------------ ------------ ------------
Total Operating Revenues 1,054,047 1,016,328 1,000,814 949,024 895,532 853,270
------------ ---------- ------------ ------------ ------------ ------------
Operating Expenses
Fuel Expenses
Fuel for electric generation 40,938 44,190 44,961 45,871 48,376 65,105
Purchased electricity 46,484 54,167 37,002 31,563 29,706 27,683
Gas purchased for resale 202,297 167,762 194,390 166,884 141,291 129,779
------------ ---------- ------------ ------------ ------------ ------------
Total Fuel Expenses 289,719 266,119 276,353 244,318 219,373 222,567
------------ ---------- ------------ ------------ ------------ ------------
Operating Revenues Less Fuel Expenses 764,328 750,209 724,461 704,706 676,159 630,703
------------ ---------- ------------ ------------ ------------ ------------
Other Operating Expenses
Operations excluding fuel expenses 262,816 253,907 235,896 235,381 226,624 208,440
Maintenance 47,063 49,226 55,069 61,693 62,720 65,415
Depreciation and amortization 105,614 91,593 87,461 84,177 85,028 84,181
Taxes - local, state and other 126,868 133,895 129,778 126,892 124,252 113,649
Federal income tax - current 65,757 65,368 35,658 33,453 36,101 28,766
- deferred 3,744 847 25,587 15,877 7,490 5,493
------------ ---------- ------------ ------------ ------------ ------------
Total Other Operating Expenses 611,862 594,836 569,449 557,473 542,215 505,944
------------ ---------- ------------ ------------ ------------ ------------
Operating Income 152,466 155,373 155,012 147,233 133,944 124,759
Other Income and Deductions
Allowance for other funds used during
construction 684 585 396 153 164 675
Federal income tax 3,450 16,948 16,259 9,827 4,195 4,580
Regulatory disallowances - (26,866) (600) (1,953) (8,215) (10,000)
Pension Plan Curtailment - - (33,679) (8,179) - -
Other, net (2,566) (14,931) (4,853) (7,074) 6,155 6,078
------------ ---------- ------------ ------------ ------------ ------------
Total Other Income and (Deductions) 1,568 (24,264) (22,477) (7,226) 2,299 1,333
------------ ---------- ------------ ------------ ------------ ------------
Interest Charges
Long term debt 48,618 53,026 53,606 56,451 60,810 63,918
Short term debt 21 398 1,808 1,487 1,950 2,623
Other, net 9,307 8,658 4,758 5,220 5,228 4,459
Allowance for borrowed funds used during
construction (1,423) (2,901) (2,012) (1,714) (2,184) (2,905)
------------ ---------- ------------ ------------ ------------ ------------
Total Interest Charges 56,523 59,181 58,160 61,444 65,804 68,095
------------ ---------- ------------ ------------ ------------ ------------
Net Income 97,511 71,928 74,375 78,563 70,439 57,997
------------ ---------- ------------ ------------ ------------ ------------
Dividends on Preferred Stock
at required rates 7,465 7,465 7,369 7,300 8,290 6,963
------------ ----------- ------------ ------------ ------------ -----------
Earnings Applicable to Common Stock $ 90,046 $ 64,463 $ 67,006 $ 71,263 $ 62,149 $ 51,034
------------ ---------- ----------- ------------ ------------ ------------
Weighted average number of shares for period (000's) 38,762 38,113 37,327 35,599 33,258 31,794
Earnings per Common Share $2.32 $1.69 $1.79 $2.00 $1.86 $1.60
Cash Dividends Declared per Common Share $1.80 $1.800 $1.77 $1.73 $1.69 $1.635
18
CONDENSED CONSOLIDATED BALANCE SHEET
-----------------------------------------------------------------------------
(Thousands of Dollars) At December 31, 1996 1995* 1994* 1993* 1992* 1991*
- ----------------------------------------------------------------------------------------------------------------------------------
Assets
Utility Plant $3,159,759 $3,068,103 $2,981,151 $2,890,799 $2,798,581 $2,706,554
Less: Accumulated depreciation and
amortization 1,569,078 1,518,878 1,423,098 1,335,083 1,253,117 1,178,649
---------- ---------- ---------- ---------- ---------- ----------
1,590,681 1,549,225 1,558,053 1,555,716 1,545,464 1,527,905
Construction work in progress 69,711 121,725 128,860 112,750 83,834 76,848
---------- ---------- ---------- ---------- ---------- ----------
Net utility plant 1,660,392 1,670,950 1,686,913 1,668,466 1,629,298 1,604,753
Current Assets 250,461 292,596 236,519 248,589 209,621 189,009
Investment in Empire - 38,879 38,560 38,560 9,846 -
Deferred Debits and Regulatory Assets 450,623 453,726 484,962 488,527 181,434 140,792
---------- ---------- ---------- ---------- ---------- ----------
Total Assets $2,361,476 $2,456,151 $2,446,954 $2,444,142 $2,030,199 $1,934,554
========== ========== ========== ========== ========== ==========
CAPITALIZATION AND LIABILITIES
Capitalization
Long term debt $646,954 $716,232 $735,178 $747,631 $658,880 $672,322
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 45,000 55,000 55,000 42,000 54,000 60,000
Common shareholders' equity:
Common stock 696,019 687,518 670,569 652,172 591,532 529,339
Retained earnings 90,540 70,330 74,566 75,126 66,968 61,515
---------- ---------- ---------- ---------- ---------- ----------
Total common shareholders' equity 786,559 757,848 745,135 727,298 658,500 590,854
---------- ---------- ---------- ---------- ---------- ----------
Total Capitalization 1,545,513 1,596,080 1,602,313 1,583,929 1,438,380 1,390,176
---------- ---------- ---------- ---------- ---------- ----------
Long Term Liabilities (Department
of Energy) 93,752 90,887 87,826 89,804 94,602 63,626
Current Liabilities 158,217 182,338 181,327 234,530 267,276 267,601
Deferred Credits and Other Liabilities 563,994 586,846 575,488 535,879 229,941 213,151
---------- ---------- ---------- ---------- ---------- ----------
Total Capitalization and Liabilities $2,361,476 $2,456,151 $2,446,954 $2,444,142 $2,030,199 $1,934,554
========== ========== ========== ========== ========== ==========
* Reclassified for comparative purposes.
19
FINANCIAL DATA
At December 31 1996 1995 1994 1993 1992 1991
------ ------ ------ ------ ------ ------
Capitalization Ratios (a) (percent)
Long-term debt 44.7 47.4 48.2 49.4 48.2 50.6
Preferred Stock 6.9 7.3 7.3 6.6 8.0 8.7
Common shareholders' equity 48.4 45.3 44.5 44.0 43.8 40.7
------ ------ ------ ------ ------ ------
Total 100.0 100.0 100.0 100.0 100.0 100.0
Book Value per Common Share - Year End $20.24 $19.71 $19.78 $19.70 $18.92 $18.41
Rate of Return on Average Common Equity (b)
(percent) 11.41 8.37 8.92 10.25 9.94 8.60
Embedded Cost of Senior Capital (percent)
Long-term debt 7.33 7.38 7.40 7.36 7.91 8.32
Preferred stock 6.26 6.26 6.26 6.69 6.98 6.97
Effective Federal Income Tax Rate (percent) 40.4 40.7 37.7 33.5 35.9 33.9
Depreciation Rate (percent) - Electric 2.99 2.76 2.69 2.62 2.69 3.05
- Gas 2.60 2.59 2.62 2.60 2.78 2.94
Interest Coverages
Before federal income taxes (incld. AFUDC) 3.82 2.95 2.98 2.87 2.62 2.23
(excld. AFUDC) 3.79 2.90 2.94 2.84 2.58 2.18
After federal income taxes (incld. AFUDC) 2.68 2.16 2.24 2.24 2.04 1.82
(excld. AFUDC) 2.65 2.10 2.20 2.21 2.00 1.77
Interest Coverages Excluding Non-Recurring
Items (c)
Before federal income taxes (incld. AFUDC) 3.82 3.66 3.55 3.03 2.74 2.38
(excld. AFUDC) 3.79 3.61 3.51 3.00 2.70 2.33
After federal income taxes (incld. AFUDC) 2.68 2.62 2.61 2.35 2.12 1.91
(excld. AFUDC) 2.65 2.57 2.57 2.32 2.08 1.86
(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).
20
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following is Management's assessment of certain significant
factors affecting the financial condition and operating results of the Company.
This assessment contains forward-looking statements which are subject to various
risks and uncertainties. The Company's actual results could differ from those
anticipated in such forward-looking statements as a result of numerous factors
which may be beyond the Company's control. Shown below is a listing of the
principal items discussed.
Earnings Summary Page 20
Competition Page 21
PSC Competitive Opportunities Case
FERC Open Transmission Orders
PSC Gas Restructuring Case
Prospective Financial Position
Business Strategy
Nuclear Operating Company
Rates and Regulatory Matters Page 25
1996 Rate Settlement
1995 Gas Settlement
Liquidity and Capital Resources Page 26
Capital and Other Requirements
Redemption of Securities
Financing
Capital Structure
Results of Operations Page 29
Operating Revenues and Sales
Operating Expenses
Dividend Policy Page 32
EARNINGS SUMMARY
Operating earnings were higher in 1996 due to a good winter heating season
and lower interest expense on long-term debt, coupled with savings resulting
from cost control efforts by the Company. Partially offsetting the increase
were a decrease in electric rates effective July 1 and an increase in certain
amortization expenses. For a summary of the earnings effect of changes in
revenues and expenses, see the table under Results of Operations.
Earnings per share were $2.32 in 1996. Earnings per share of $1.69
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 discussed below) 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 degree of success in remarketing its
excess gas capacity as set under the terms of the 1995 Gas Settlement and in
controlling its local gas distribution costs. The Company believes it will be
successful in meeting the 1995 Gas Settlement targets over the remaining term of
the Settlement period, although no assurance may be given.
Earnings per share of $1.79 reported in 1994 reflect charges for work force
reduction programs completed in that year. In addition to the cost of the work
force reduction programs, earnings as reported in 1994 include a charge of $.01
per share for purchased gas undercharges.
21
Earnings Per Share - Summary
- -----------------------------------------------------------------------------
(Dollars per Share) 1996 1995 1994
- -----------------------------------------------------------------------------
Earnings per Share Before Non-recurring Items $2.32 $ 2.44 $2.39
Non-recurring Items
1995 Gas Cost Settlement ( .75)*
Purchased Gas Undercharges (.01)
Retirement Enhancement Programs (.59)
----- ------ -----
Total Non-recurring Items $ _ $ (.75) $(.60)
----- ------ -----
Reported Earnings per Share $2.32 $ 1.69 $1.79
===== ====== =====
* $.46 per share charged to earnings, plus $.29 of foregone revenues
Uncollectible expense in 1996 was $20 million, which included an
increase of $5 million in the reserve for doubtful accounts. In 1995,
uncollectible expense was $23 million, including an increase of $15 million in
the reserve for doubtful accounts. The Company is taking more aggresive steps to
improve its collection efforts, as discussed under the heading Operating
Expenses, Excluding Fuel.
The impact of developing competition in the energy marketplace,
including the ultimate resolution of the PSC Competitive Opportunities Case (see
Competition) will also affect future earnings.
COMPETITION
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 and resulted in the approval of flexible rate discounts for
non-residential electric customers who have competitive alternatives.
In May 1996 the PSC issued an order which purports to have required
the electric utilities in New York State to file plans to implement competition
at the wholesale level by 1997 and at the retail level by 1998. The PSC Order
required the Company and four other New York investor-owned utilities to file a
restructuring plan by October 1, 1996.
Certain aspects of the restructuring envisioned by the PSC --
particularly the PSC's apparent determinations that it can deny a reasonable
opportunity to recover prudent investments made on behalf of the public, order
retail wheeling, require divestiture of generation assets and deregulate certain
sectors of the energy market -- could, if implemented, have a negative impact on
the operations of New York's investor-owned electric utilities, including the
Company. The Company therefore joined in a lawsuit filed by the Energy
Association of New York State and the State's other electric utilities against
the PSC on September 18, 1996, in the New York Supreme Court for Albany County.
The utilities requested that the Court declare that the May 20 Order is unlawful
or, in the alternative, that the Court clarify that the May 20 Order is a policy
statement which has no binding legal effect. On November 26 the Court denied the
utilities' motion, however, the Court agreed with their view that the PSC Order
was not a binding rule, but only a policy statement which, until an attempt is
made to implement it, is not suscepitible to judicial review. Nevertheless, the
court decision contains language that suggests the PSC may have authority to,
among other things, deny recovery of prudent costs. Because the Court decision
seems internally inconsistent and contains adverse language, a notice of appeal
was filed by the utilities in December 1996. The litigation is ongoing and the
Company is unable at this time to predict the impact of the litigation on the
Company's operations.
The Company's October 1 submission to the PSC explains that certain
issues, in addition to the litigation discussed above, need to be addressed
satisfactorily before the Company can proceed. These prerequisites to
restructuring include: assurance of the recovery of investment made to provide
public service; a consistent Statewide treatment of nuclear plants that
recognizes the need to treat them as must-run units subject to cost-based rate
22
regulation; assurance of recovery of costs associated with the Kamine/Besicorp
Allegheny L.P. project (Kamine)(see Purchased Power Requirement); assurance of
recovery of regulatory assets (i.e., generally current costs that have been
deferred and/or spread over time to minimize current rate impact); collection of
the cost of public policy programs through a Public Policy Charge; and provision
of a fair opportunity for the Company to participate in the competitive market-
place. Because of the importance of resolving these issues before the Company
can voluntarily commit to any major restructuring effort, the Company made its
submission subject to the foregoing reservations.
On a number of the important issues referenced above, the PSC is
taking a position contrary to that of the Company and the Company's submission.
Although the Company is prepared to proceed on the basis of its submission,
changes are certain to arise before the conclusion of the proceeding. The
Company is unable to predict how these numerous issues will be resolved, if at
all.
In summary, highlights of the Company's position documented in its
submission to the PSC filed on October 1, 1996 are:
- - Overview. Subject to the the foregoing legal proceedings and
prerequisites, the Company would propose to move toward full
competition at the retail level. A regulated distribution company
which would also own the Company's generating assets(DISCO/GENCO)
would receive electricity purchased in the unregulated wholesale
market by unregulated Load Serving Entities (LSEs), and deliver that
electricity to the customers of the LSEs. The Company would operate
its own unregulated LSE. Before arriving at this final stage, two
transition phases would be required.
- - Phase I - Functional Reorganization.First, the Company would create
a wholesale entity (DISCO/GENCO) comprised of the transmission and
distribution functions, together with existing generation and certain
contracts. At the same time, the Company would establish a regulated
LSE which would handle all retail functions. The DISCO/GENCO would
provide electric transmission service to the regulated LSE under a
federal-regulated transmission tariff. It might also provide energy
distribution service to the regulated LSE under a state-regulated
tariff.
Instead of identifying a specific value of stranded costs, the Company
would recover through the LSE the difference between traditional
revenue requirements and the revenues received from electric power
sales which the Company is able to make into the wholesale market.
- - Phase II - Retail Access. The second phase, movement to retail access
would begin after an Independent System Operator (ISO) is functioning
in a manner sufficient to enable multiple LSEs to operate on the
system and after completion of a major pilot program. Under the full-
scale access scenario, the Company would, through its unregulated
affiliated LSE, continue to compete for customers.
- - Treatment of Incumbent Generation. Under the submission, the Company
would retire or otherwise remove all of its wholly-owned fossil
generating plants from rate base by the year 2009, when the license
for the Ginna nuclear plant expires. Prior to retirement, the Company
would run those units as needed to support the Company's system and
when the wholesale price exceeds their variable cost of operation. Any
revenues received from those sales would be used to offset the costs
associated with these units.
Until retirement, Ginna would be operated as a must-run, base load
unit and its output would be sold into the wholesale market.
Nine Mile Two, a nuclear unit which is co-owned with four other
utilities, requires a Statewide solution. At least until that time,
costs not otherwise recovered in the market would need to be recovered
in charges to customers.
- - Corporate Structure. Under the Company's suggested approach,
implementation of wholesale and retail access would not require
divestiture of generation or formation of separate subsidiaries to own
and/or operate the Company's generating plants.
23
- - Rate Plan. The Company's current electric rates are governed by a
1996 Settlement that extends through June 1999; gas rates are set
pursuant to a 1995 Settlement that remains in effect through October
1998. After the expiration of the settlement periods, the regulated
LSE would operate under a multi-year plan based upon cost-of-service
regulation. The DISCO's rates for distribution service would be set
through a performance-based system that would include price caps
subject to an index that would be adjusted downward for presumed
productivity gains.
Stranded costs of generation and other assets that are not mitigated
through wholesale power sales would be collected through charges by
the DISCO applicable to all customers.
The Company has participated in extensive settlement discussions with
respect to its submission. Although these discussions could result in changes
in the ultimate outcome from the Company's position as filed in October, it is
too early to determine if any settlement can be achieved. Reply Briefs for this
case are due to the Administrative Law Judge on April 17, 1997. As this
proceeding does not have a stated suspension period, it is unknown when the PSC
will issue a final order.
The Company is not able to predict the outcome of 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 involved, especially those related to competition at the retail level.
FERC Open Transmission Orders. In early 1996 FERC issued new rules to
facilitate the development of competitive wholesale markets by requiring
electric utilities to offer "open-access" transmission service on a non-
discriminatory basis in tariffs to be filed by July 9, 1996. A FERC release
states that utilities are entitled to full recovery of "legitimate, prudent and
verifiable" strandable costs at the state and federal level. This 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 Company filed its required transmission service tariff on July 9,
1996. The new tariff would apply to wholesale purchases and sales made by the
Company and the financial impact will depend on prevailing energy prices in the
wholesale market. The near-term impacts of this tariff are not expected to be
significant. Hearings on the rates and term in the Company's tariff filing have
been set for September 1997. The Company plans to proceed with the case
independent of the New York Power Pool (NYPP) filings discussed below until such
time as those filings are accepted and effectively supersede the Company's
filing.
In December 1996 the NYPP member companies submitted a compliance
filing with FERC in accordance with the requirements of the FERC's "open access"
order. The NYPP filing indicates the intention to restructure the power pool
using an ISO structure, as endorsed by FERC. At the present time, member
companies of the NYPP continue to participate in collaborative efforts with
State regulators and other interested parties to develop and implement a new
pool-wide pricing system for both wholesale energy products and transmission
service. It is anticipated that a formal NYPP tariff filing with FERC will
occur by the end of January 1997.
In order to support the FERC's "open access" order, the NYPP member
companies have established a centralized transmission service information
network, which went on-line in early January 1997. This "open access same-time
information system" (OASIS) will enable all wholesale customers of New York
State's bulk power system to obtain timely information regarding transmission
service availability and pricing via the Internet.
Significant changes to NYPP pricing procedures are expected, but their
projected effects on the Company's operations and financial performance are
currently not expected to be substantial;but, it is unclear what effect these
changes may have once other regulatory changes in New York State are
implemented. At the present time, the Company cannot predict what effects
regulations
24
ultimately adopted by FERC will have, if any, on future operations or the
financial condition of the Company.
PSC Gas Restructuring Case. In March 1996 the PSC issued an Order and
approved utility restructuring plans designed to open up the local natural gas
market to competition and thereby allow residential, small business and
commercial/industrial users the same ability to purchase their gas supplies from
a variety of sources, other than the local utility, that larger industrial
customers already have. Under two new gas transportation tariffs, gas customers
have a choice of suppliers beginning November 1, 1996. The Company will
distribute the gas and charge for the distribution as well as associated
services. The Company believes its position in the market is such that it will
maintain its distribution system margins. Under a phase-in limitation, loss of
gas commodity sales may be limited to five percent of the Company's annual gas
volume the first year, and then five additional percent for each of the
following two years. The phase-in will be reviewed as experience is gained with
the program. The Company anticipates that the use of transportation gas service
will increase; however, through year-end 1996 no customers were being served
under this new service.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. It is
possible that New York State utilities may be unable to recover all of their
regulatory and generating assets in a competitive market brought about by
regulatory changes, and thus may need to write down the value of those assets.
Further, in the PSC Competitive Opportunities Case discussed above, the PSC has
asserted it lawfully may disallow recovery of some or all of such costs in
rates, and the Supreme Court, Albany County, has indicated its concurrence in
that position. The Company currently believes its regulatory and generating
assets are probable of recovery in rates. However, given industry trends toward
competition, and the position of the PSC, no assurance can be given as to the
extent, if any, writeoffs of such assets may ultimely be necessary (see Note 10
of the Notes to Financial Statements).
Regulatory and Strandable Assets. With PSC approval, 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. 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. If the Company's rate setting were to be changed from a
cost-of-service approach, and it were no longer allowed to defer these costs,
these assets would be written down for any impairment to recovery. In certain
cases, the entire amount could be written off.
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 contract), or high cost
generating assets. Estimates of strandable assets are highly sensitive to the
competitive wholesale market price assumed in the estimation. As discussed in
Note 10 to the Financial Statements, the amount of potentially strandable assets
at December 31, 1996 cannot be determined at this time, but could be
significant. Strandable assets, if any, would be written down for impairment of
recovery in the same manner as deferred costs discussed above.
At December 31, 1996 the Company believes that its Regulatory and
Strandable Assets, if any, are not impaired and are probable of recovery,
although no such assurance can be given.
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. The focus of the Company will be retail energy
services. The Company's core business will be the marketing and providing of
electricity, natural gas, transmission and distribution services, and other
25
energy-related services to retail customers. A closely-aligned future business
may be providing gas transmission and gas and electric distribution services to
other energy services companies. In addition, the Company anticipates that
energy-related services will be developed and provided by an unregulated entity
to markets and areas within and beyond its current regulated franchise service
territory.
The Company is continuously assessing various strategies which may
enhance its ability to respond to competitive forces and regulatory change. Such
strategies may include business partnerships 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. In its October 1,
1996 submission to the PSC under the Competitive Opportunities Case, the Company
envisioned functional separation among generation, distribution and retailing
elements of the Company's electric energy business as part of its move toward
implementing this business strategy.
Nuclear Operating Company. In mid-October the Company and Niagara
Mohawk Power Corporation (Niagara) announced plans to form a joint nuclear
operating company to support and manage the operations of the Company's Ginna
Nuclear Plant and two plants operated by Niagara, Nine Mile Point One and Two.
The plan includes the initial formation of a nuclear services entity to provide
support services to the plants.
RATES AND REGULATORY MATTERS
1996 Rate Settlement. The PSC approved a Settlement Agreement (1996
Rate Settlement) among the Company, PSC Staff and several other parties which
set rates for a three-year period, commencing July 1, 1996 and concluding June
30, 1999. Under the 1996 Rate Settlement base electric rates for the first year
(commencing July 1, 1996) are decreased to a level that reduces revenues in an
amount equal to 1.0 percent ($7.1 million). In each of the second and third
years, base rates will be decreased by an additional amount equal to 0.5 percent
($3.5 million) of the revenues that were produced by the rates in effect in the
immediately preceding year. In addition, the 1996 Rate Settlement reduces and
holds constant fuel cost recoveries for the three-year period. This provision,
combined with the base rate decreases, is expected to produce effective overall
rate decreases of 3.5% for residential customers and 5.0% to 6.0% for non-
residential customers over the three-year period.
The 1996 Rate Settlement provides that, if the Company achieves a
return in excess of 11.2 percent over the entire three-year period, the Company
can retain 50 percent of the excess as earnings and shall use the remaining 50
percent to write down its investment in nuclear assets. If the return on equity
in any rate year falls below 8.5 percent or rises above 14.5 percent, or pre-tax
cash interest coverage falls below 2.5 times, or fuel cost changes (other than
Kamine costs), result in a swing of more than 10 percent in electric common
earnings, then either the Company or any other party can petition the PSC for a
change in the rates.
The PSC failed to approve provisions of the 1996 Rate Settlement
related to Kamine which would have permitted immediate recovery of increases in
Kamine costs, subject to subsequent PSC review and failed to approve other
provisions related to certain gas costs. On October 28, 1996, the Company
sought judicial review of the PSC's decision to exclude these two items from the
1996 Rate Settlement. The Company and the PSC have agreed to delay this
proceeding until there are further developments on these matters.
1995 Gas Settlement. In October of 1995, a settlement of various gas
rate and management issues was finalized (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.
26
- - 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 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 was to reduce earnings by $.75 per share. The 1995 Gas
Settlement is fully reflected in 1996 results.
The Company has entered into several agreements to help manage its
pipeline capacity costs and has successfully met settlement targets for capacity
remarketing for the twelve months ending October 31, 1996, thereby avoiding
negative financial impacts for that period. The Company believes that it will
also be successful in meeting the Settlement targets in the remaining two years
of the Settlement period, although no assurance may be given.
For additional information about the effects of the 1995 Gas
Settlement on the Company's financial condition and results of operations, see
Note 10 of the Notes to Financial Statements.
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
1996 Rate Settlement, the Company will absorb, as it has done since the
inception of these rates, the difference between the discounted rates paid under
these individual contracts and the rates that would otherwise apply.
Approximately 27 percent of all electric sales (KWHs) to customers are made
under long-term contracts, primarily to large industrial customers. These sales
represent approximately 65 percent of the Company's revenues from customers who
purchase $500,000 of electricity or more per year. The Company has not
experienced any customer loss due to competitive alternative arrangements.
Rate Increases (Decreases)
- -----------------------------------------------------------------------------------------------
Effective Amount of Increase (Decrease) Authorized
Class of Date of Increase (Annual Basis) Rate of Return on
Service (Decrease) (000's) Percent Rate Base Equity
- -----------------------------------------------------------------------------------------------
Electric 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
July 1, 1996 (7,072) (1.0) 9.22 11.20
Gas 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
LIQUIDITY AND CAPITAL RESOURCES
Cash flow, mainly from operations, provided the funds for the debt
reductions, as well as funds for construction expenditures during 1996 (see
Consolidated Statement of Cash Flows). Capital requirements during 1997 are
anticipated to be satisfied primarily from a combination of internally generated
funds and the use of short-term credit arrangements.
CAPITAL AND OTHER REQUIREMENTS. The Company's capital requirements
relate primarily to expenditures for electric generation, transmission and
distribution
27
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.
Ginna Steam Generator Replacement. In 1996 the Company completed
replacement of the two steam generators at the Ginna Nuclear Plant. Improved
plant efficiency has allowed the plant to recapture output capacity that had
been lost due to the declining performance of the former generators. Cost of
the replacement was approximately $107 million, about $40 million for the steam
generators, about $50 million for the installation and the remainder for Company
engineering, radiation protection, plant support, other services and finance
charges. During 1996, the Company spent $45.7 million on this project. The
project was completed within a PSC-approved cost of $115 million and savings
under that amount will be shared between the Company and its customers.
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 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 could 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.
Sale of Interest in Empire State Pipeline. In September 1996 the
Company's wholly-owned subsidiary, Energyline Corporation, sold its 20%
ownership interest in the Empire State Pipeline (Empire) to the other co-
tenants, subsidiaries of The Coastal Corporation and Westcoast Energy Inc. The
Company will remain a customer of Empire. The sale of Empire did not have a
material impact on the Company's financial condition.
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 $24.5 million in 1994, $1 million
in 1995, and $49 million in 1996.
CAPITAL REQUIREMENTS - SUMMARY. Capital requirements for the three-
year period 1994 to 1996 and the current estimate of capital requirements
through 1999 are summarized in the Capital Requirements table.
The Company's capital expenditures program is under continuous review
and could be revised for any number of issues. The Company also may consider,
as conditions warrant, the redemption or refinancing of certain long-term
securities.
28
Capital Requirements
- ---------------------------------------------------------------------------------
Actual Projected
1994 1995 1996 1997 1998 1999
Type of Facilities (Millions of Dollars)
- ---------------------------------------------------------------------------------
Electric Property
Production $ 42 $ 48 $ 57 $ 15 $ 22 $ 13
Energy Delivery 27 25 23 31 57 45
---- ---- ---- ---- ---- ----
Subtotal 69 73 80 46 79 58
Nuclear Fuel 16 17 16 21 16 16
---- ---- ---- ---- ---- ---
Total Electric 85 90 96 67 95 74
Gas Property 20 14 17 19 21 21
Common Property 12 4 6 15 14 7
---- ---- ---- ---- ---- ---
Total 117 108 119 101 130 102
Carrying Costs
Allowance for Funds Used During
Construction 2 3 2 1 1 1
---- ---- ---- ---- ---- ---
Total Construction Requirements 119 111 121 102 131 103
Securities Redemptions, Maturities
and Sinking Fund Obligations* 52 1 67 30 40 40
---- ---- ---- ---- ---- ---
Total Capital Requirements $171 $112 $188 $132 $171 $143
---- ---- ---- ---- ---- ----
* Excludes prospective refinancings.
FINANCING AND CAPITAL STRUCTURE. Capital requirements in 1996 were
satisfied primarily with internally generated funds and the Company had no
public issuance of securities during the year. The Company had $14.0 million of
short-term debt outstanding at December 31, 1996. Energyline Corporation, a
wholly-owned subsidiary of the Company, had temporary cash investments of $17.5
million at year-end 1996 resulting primarily from the sale of its share of the
Empire project. The Company foresees modest near-term financing requirements.
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.
Financing. For information with respect to short-term borrowing
arrangements and limitations, see Note 9 of the Notes to Financial Statements.
During 1996 approximately 398,000 new shares of Common Stock were sold
through the Company's Automatic Dividend Reinvestment and Stock Purchase Plan
(ADR Plan) and an employee stock purchase plan, providing $8.6 million to help
finance its capital expenditures program. In July 1996 the Company began
providing for ADR Plan and employee stock plan shares on the open market. These
plans permit the Company to issue new shares to participants or to purchase
outstanding shares on the open market.
Capital Structure. Common equity (including retained earnings)
comprised 48.4 percent of the Company's capitalization at December 31, 1996,
with the balance being comprised of 6.9 percent preferred equity and 44.7
percent long-term debt. As presented, these percentages are based on the
Company's capitalization exclusive of securities due within one year and
inclusive of the Company's 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.
29
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing 1996 to 1995 and 1995
to 1994. The Notes to Financial Statements contain additional information. A
summary of changes in Electric and Gas Department revenues and expenses is
presented in the Operating Revenues and Expenses table.
Operating Revenues and Expenses (Millions of Dollars)
Twelve Months Twelve Months
1996 1995
----------- -------------
Prior Year Earnings $ 64.5 $ 67.0
Increase (decrease) in earnings:
Electric revenue changes (14.7) 47.7
- - Includes effect of rate changes
- - Consumption changes including weather
- - Changes in sales to other electric utilities
Electric fuel cost changes 10.9 (16.4)
Gas margin (revenue less fuel) 17.9 (5.6)
- - Consumption changes including weather
- - 1995 Gas Settlement effects
Uncollectible Expense 3.1 (14.1)
Payroll changes (6.5) (0.9)
- - Amortization of early retirement program
- - Ongoing outplacement program
- - Improved employee performance
Miscellaneous non-fuel operating and maintenance (3.3) 2.8
Depreciation and amortization (14.0) (4.1)
Net federal income tax effects (16.8) (4.3)
Local and state tax effects 7.0 (4.1)
Change in Regulatory Disallowances 26.9 (26.3)
Pension Plan Curtailment effect ---- 33.7
Other income and deductions effects 12.4 (9.9)
Interest Expense 2.6 (1.0)
- - Redeemed 8 3/8% Series CC bonds 3/7/96
- - Matured 5.3% Series V bonds 5/1/96
------ ------
Current Year Earnings $ 90.0 $ 64.5
OPERATING REVENUES AND SALES. Operating revenues in 1996 were higher due to
the effect of an extended period of cold weather on electric and gas sales,
compared to the revenue effect of unusually warm weather in the first quarter of
1995. In addition, higher revenues in 1996 resulted from recovery of higher
purchased gas costs offset in part by lower electric fuel and purchased
electricity costs, an electric rate decrease effective July 1, 1996, and cooler
1996 summer weather.
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 1996 was 4.8 percent colder than normal and 8.6 percent
30
colder than last year on a calendar month heating degree day basis. In
contrast, weather during 1995 was warmer than normal, with the weather during
1995 being 2.4 percent warmer than 1994. With elimination of the weather
normalization clause in the Company's gas tariff effective November 1, 1995,
abnormal weather variations may have a more pronounced effect on gas revenues.
Warmer than normal summer weather during 1995 boosted electric energy sales to
meet the demand for air conditioning usage, while summer weather during 1996 was
43 percent cooler than 1995 and, accordingly, hampered such sales.
Compared with a year earlier, kilowatt-hour sales of energy to retail
customers were up less than one percent in 1996, following a 2.8 percent
increase in 1995. Sales to industrial customers led the increase in both 1996
and 1995 compared to a year earlier. 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 1995 and 1996.
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 1995, revenues from sales to
other electric utilities declined in 1996 reflecting decreased kilowatt-hour
sales to such utilities, lower average rates, less generation from the Company's
Ginna Nuclear Plant, and increased retail sales. Electric sales for resale
generally result in low profit margin contribution to the Company due to
regulatory sharing mechanisms and relatively low prices caused by excess supply.
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 16.8 million dekatherms in 1996 and 14.6
million dekatherms in 1995. These purchases by eligible customers have caused
decreases in Company revenues, with offsetting decreases in purchased gas
expenses and, 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.
Therms of gas sold and transported, including unbilled sales, were up 7.9
percent in 1996, after being nearly flat in 1995. 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 decreased less than one percent in 1996 over 1995, while non-
residential sales, including gas transported, would have increased approximately
three percent in 1996. The average use per residential gas customer, when
adjusted for normal weather conditions, was down in 1996, following a modest
increase in 1995.
OPERATING EXPENSES.
Energy Costs - Electric. For the 1996 comparison period, lower electric
fuel costs resulted from less electric generation. 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 over 1994. The average cost of nuclear
fuel was up slightly in 1995 and 1996. The fuel cost adjustment clause has been
eliminated effective July 1, 1996. Company shareholders will assume the full
benefits and detriments realized from actual electric fuel costs and generation
mix compared with PSC-approved forecast amounts.
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
31
total price of $16.6 million in 1995. The Kamine facility has been out of
service since the middle of February 1996 which helped to lower the unit cost
for purchased electricity in 1996. Electric purchased power expense was down in
1996 despite an increase in kilowatt-hours purchased.
Energy Management and Costs - Gas. 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 Transmission Corporation (CNG) pipeline system, as well as to
upstream pipeline transportation and storage services. The combined CNG and
Empire transportation capacity is comparable to the Company's current
requirements.
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
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.
Fluctuations in gas purchased for resale expense for both the 1996 and 1995
comparison periods were driven by changes in the cost of purchased gas. The
commodity cost of gas was higher in 1996 after dropping in 1995.
Operating Expenses, Excluding Fuel. For the 1996 comparison period, the
increase in other operating expenses excluding fuel reflects mainly higher
payroll costs and an increase in amortization expense beginning July 1, 1996 for
customer information system enhancements. Higher payroll costs for this period
reflects amortization of additional early retirement costs for programs
concluded in October 1994 and greater employee redeployment/outplacement costs.
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 Company is taking more aggressive steps to improve its collection
efforts. These include additional field collectors, the centralization of all
collection functions, and the implementation of several calling programs that
target customers in arrears. Further, the Company now utilizes collection
agencies to perform additional collection activities. The Company has also
initiated more legal activity against certain accounts, both commercial and
residential. Given these initiatives, the Company anticipates its allowance for
doubtful accounts may decline in 1997, although no assurance may be given.
The increase in depreciation expense for 1996 over 1995 primarily results
from depreciation of the new Ginna Nuclear Plant steam generators (approximately
$800,000 additional expense per month) and recovery of increased nuclear
decommissioning expense of approximately $3.2 million per quarter beginning July
1, 1996. For the 1995 comparison periods, the increase in depreciation expense
is due mainly to an increase in depreciable plant.
Taxes Charged To Operating Expenses. The decrease in local, state and
other taxes in 1996 reflects mainly lower property taxes due to decreases in
assessments. For the 1995 comparision period, the increase in local, state and
other taxes reflects certain assessments for prior years' taxes.
OTHER STATEMENT OF INCOME ITEMS. Variations in non-operating federal
income tax reflect mainly accounting adjustments related to retirement
enhancement programs, 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 and
which were completed in the third quarter of 1994.
32
For the 1996 comparison period, Other Income and Deductions, Other -- net
increased mainly due to the elimination in 1996 of two accrued expenses in 1995
related to depreciation expense for the Empire State Pipeline and amortization
of certain employee early retirement costs. In addition, both comparision
periods reflect changes in the expense of an employee performance incentive
program. These programs recognize employees' achievements in meeting corporate
goals and reducing expenses.
Both mandatory redemptions and the optional redemptions of certain higher-
cost first mortgage bonds have helped to reduce long-term debt interest expense
over the three-year period 1994-1996. The average short-term debt outstanding
decreased in 1995 and 1996.
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 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.
33
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
A. FINANCIAL STATEMENTS
Report of Independent Accountants
Consolidated Statement of Income for each of the three years ended December
31, 1996.
Consolidated Statement of Retained Earnings for each of the three years
ended December 31, 1996.
Consolidated Balance sheet at December 31, 1996 and 1995.
Consolidated Statement of Cash Flows for each of the three years ended
December 31, 1996.
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.
34
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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1996, in conformity with generally accepted accounting principles.
These financial statements are the responsibility of the Company's management;
our responsibility is to express an opinion on these financial statements based
on our audits. We conducted our audits of these statements in accordance with
generally accepted auditing standards which require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are
free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements,
assessing the accounting principles used and significant estimates made by
management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for the opinion expressed
above.
/s/ PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
Rochester, New York
January 17, 1997
35
CONSOLIDATED STATEMENT OF INCOME
(Thousands of Dollars) Year Ended December 31, 1996 1995 1994
Operating Revenues
Electric $690,883 $696,582 $658,148
Gas 346,279 293,863 326,061
---------- ---------- ----------
1,037,162 990,445 984,209
Electric sales to other utilities 16,885 25,883 16,605
---------- ---------- ----------
Total Operating Revenues 1,054,047 1,016,328 1,000,814
---------- ---------- ----------
Operating Expenses
Fuel Expenses
Fuel for electric generation 40,938 44,190 44,961
Purchased electricity 46,484 54,167 37,002
Gas purchased for resale 202,297 167,762 194,390
---------- ---------- ----------
Total Fuel Expenses 289,719 266,119 276,353
---------- ---------- ----------
Operating Revenues Less Fuel Expenses 764,328 750,209 724,461
---------- ---------- ----------
Other Operating Expenses
Operations excluding fuel expenses 262,816 253,907 235,896
Maintenance 47,063 49,226 55,069
Depreciation and amortization 105,614 91,593 87,461
Taxes - local, state and other 126,868 133,895 129,778
Federal income tax 69,501 66,215 61,245
Total Other Operating Expenses 611,862 594,836 569,449
---------- ---------- ----------
Operating Income 152,466 155,373 155,012
Other Income and Deductions
Allowance for other funds used during construction 684 585 396
Federal income tax 3,450 16,948 16,259
Regulatory disallowances - (26,866) (600)
Pension Plan Curtailment - - (33,679)
Other, net (2,566) (14,931) (4,853)
---------- ---------- ----------
Total Other Income and (Deductions) 1,568 (24,264) (22,477)
---------- ---------- ----------
Interest Charges
Long term debt 48,618 53,026 53,606
Other, net 9,328 9,056 6,566
Allowance for borrowed funds used during construction (1,423) (2,901) (2,012)
---------- ---------- ----------
Total Interest Charges 56,523 59,181 58,160
---------- ---------- ----------
Net Income 97,511 71,928 74,375
---------- ---------- ----------
Dividends on Preferred Stock 7,465 7,465 7,369
---------- ---------- ----------
Earnings Applicable to Common Stock $ 90,046 $ 64,463 $ 67,006
---------- ---------- ----------
Weighted Average Number of Shares for Period (000's) 38,762 38,113 37,327
Earnings per Common Share $2.32 $1.69 $1.79
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
(Thousands of Dollars) Year Ended December 31, 1996 1995 1994
Balance at Beginning of Period $70,330 $74,566 $75,126
Add
Net Income 97,511 71,928 74,375
Adjustment Associated with Stock Redemption - - (1,398)
---------- ---------- ----------
Total 167,841 146,494 148,103
---------- ---------- ----------
Deduct
Dividends declared on capital stock
Cumulative preferred stock - at required rates
(Note 7) 7,465 7,465 7,369
Common Stock 69,836 68,699 66,168
---------- ---------- ----------
Total 77,301 76,164 73,537
---------- ---------- ----------
Balance at End of Period $ 90,540 $ 70,330 $ 74,566
---------- ---------- ----------
Cash Dividends Declared per Common Share $1.80 $1.80 $1.77
The accompanying notes are an integral part of the financial statements.
36
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars) At December 31, 1996 1995*
- --------------------------------------------------------------------------------------------------------------
Assets
Utility Plant
Electric $2,413,881 $2,342,981
Gas 391,231 382,071
Common 129,946 135,526
Nuclear fuel 224,701 207,525
---------- ----------
3,159,759 3,068,103
Less: Accumulated depreciation 1,381,908 1,345,552
Nuclear fuel amortization 187,170 173,326
---------- ----------
1,590,681 1,549,225
Construction work in progress 69,711 121,725
---------- ----------
Net Utility Plant 1,660,392 1,670,950
---------- ----------
Current Assets
Cash and cash equivalents 21,301 44,121
Accounts receivable, net of allowance for doubtful accounts:
1996 - $ 17,500; 1995 - $ 11,950 112,908 121,123
Unbilled revenue receivable 53,261 64,169
Materials, supplies and fuels, at average cost 39,888 38,650
Prepayments 23,103 24,533
---------- ----------
Total Current Assets 250,461 292,596
---------- ----------
Investment in Empire - 38,879
Deferred Debits
Nuclear generating plant decommissioning fund 91,195 71,540
Nine Mile Two deferred costs 31,360 32,411
Unamortized debt expense 14,820 16,712
Other deferred debits 28,759 21,857
Regulatory assets (Note 10) 284,489 311,206
---------- ----------
Total Deferred Debits 450,623 453,726
---------- ----------
Total Assets $2,361,476 $2,456,151
---------- ----------
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds $555,054 $624,332
- promissory notes 91,900 91,900
Preferred stock redeemable at option of Company 67,000 67,000
Preferred stock subject to mandatory redemption 45,000 55,000
Common shareholders' equity:
Common stock 696,019 687,518
Retained earnings 90,540 70,330
---------- ----------
Total Common Shareholders' Equity 786,559 757,848
---------- ----------
Total Capitalization 1,545,513 1,596,080
---------- ----------
Long Term Liabilities (Department of Energy)
Nuclear waste disposal 79,057 75,077
Uranium enrichment decommissioning 14,695 15,810
---------- ----------
Total Long Term Liabilities 93,752 90,887
---------- ----------
Current Liabilities
Long term debt due within one year 20,000 18,000
Preferred stock redeemable within one year 10,000 -
Short term debt 14,000 -
Note Payable - Empire - 29,600
Accounts payable 49,462 52,578
Dividends payable 19,349 19,170
Taxes accrued 4,694 18,638
Interest accrued 10,317 12,844
Other 30,395 31,508
---------- ----------
Total Current Liabilities 158,217 182,338
---------- ----------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 370,028 377,652
Pension costs accrued 69,806 71,580
Other 124,160 137,614
---------- ----------
Total Deferred Credits and Other Liabilities 563,994 586,846
---------- ----------
Commitments and Other Matters (Note 10) - -
---------- ----------
Total Capitalization and Liabilities $2,361,476 $2,456,151
---------- ----------
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
37
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
(Thousands of Dollars) Year Ended December 31 1996 1995 * 1994 *
- --------------------------------------------------------------------------------------------------------------
CASH FLOW FROM OPERATIONS
Net income $ 97,511 $ 71,928 $ 74,375
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 121,824 109,575 105,509
Deferred fuel (6,501) 3,432 (30,658)
Deferred income taxes 6,391 (8,047) 13,193
Allowance for funds used during construction (2,107) (3,486) (2,408)
Unbilled revenue, net 10,908 (9,899) 7,060
Nuclear generating plant decommissioning fund (11,732) (8,837) (8,594)
Pension costs accrued (2,494) 6,280 43,942
Post employment benefit internal reserve 6,626 4,636 5,287
Regulatory disallowance - 26,866 600
Changes in certain current assets and liabilities:
Accounts receivable 8,215 (10,706) (5,664)
Materials, supplies and fuels (1,238) 6,837 13,129
Taxes accrued (13,944) 15,167 (3,001)
Accounts payable (3,116) 9,644 (9,662)
Other current assets and liabilities, net (5,186) 9,639 (671)
Other, net (3,931) 28,762 13,144
----------- ---------- ---------
Total Operating 201,226 251,791 215,581
- -------------------------------------------------------- ----------- ---------- ---------
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (114,274) (109,547) (117,219)
Other, net 9,204 11,124 (150)
----------- ---------- ---------
Total Investing (105,070) (98,423) (117,369)
- -------------------------------------------------------- ----------- ---------- ---------
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issuance of common stock 8,612 17,074 17,369
Sale of preferred stock - - 25,000
Short term borrowings 14,000 (51,600) (16,500)
Retirement of long term debt (67,332) (1,000) (33,750)
Retirement of preferred stock - - (18,000)
Dividends paid on preferred stock (7,465) (7,465) (7,328)
Dividends paid on common stock (69,657) (68,347) (65,457)
Other, net 2,866 (719) 937
----------- ---------- ---------
Total Financing (118,976) (112,057) (97,729)
----------- ---------- ---------
Increase (Decrease) in cash and cash equivalents $ (22,820) $ 41,311 $ 483
Cash and cash equivalents at beginning of year $ 44,121 $ 2,810 $ 2,327
----------- ---------- ---------
Cash and cash equivalents at end of year $ 21,301 $ 44,121 $ 2,810
- -------------------------------------------------------- ----------- ---------- ---------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
(Thousands of Dollars) Year Ended December 31 1996 1995 1994
- ---------------------------------------------------------------------------------------------------------------
Cash Paid During the Year
Interest paid (net of capitalized amount) $ 55,545 $ 56,592 $ 57,186
Income taxes paid $ 76,890 $ 43,500 $ 28,411
----------- ---------- ---------
* Reclassified for comparative purposes.
The accompanying notes are an integral part of the financial statements.
38
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 was formed as a gas pipeline corporation to fund the Company's
investment in the Empire State Pipeline project. 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 had 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. In late 1996, Energyline sold its investment in the
Empire State Pipeline.
The Roxdel activity was insignificant to the Company's financial position
and results of operation.
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.
Through June 30, 1996, tariffs for electric service included fuel cost
adjustment clauses which adjusted the rates monthly to reflect changes in the
actual average cost of fuels. Beginning July 1, 1996, the electric fuel
adjustment clause was eliminated in connection with a rate settlement agreement
with the PSC.
In prior years, retail customers who used 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 by
approximately $1.2 million. On January 25, 1995, the Company 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 continues to use 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
39
Company capitalizes an Allowance for Funds Used During Construction (AFUDC)
approximately equivalent to the cost of capital devoted to plant under
construction that is not included in its rate base. 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, 1996.
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 3.0% in the three-year period
ended December 31, 1996.
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, 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.
GAS SUPPLY. The Company periodically enters into agreements to minimize
price risks for natural gas in storage. Gains or losses resulting from these
agreements are deferred until the corresponding gas is withdrawn from storage
and delivered to customers.
RESEARCH AND DEVELOPMENT COST. Research and Development charged to expense
for the years 1996, 1995, and 1994 was $4.9 million, $5.2 million and $7.3
million respectively.
SALE OF PROPERTY. During 1995, the Company sold property at the location
of its former operations center for approximately $11.5 million and entered into
a 3-year lease-back arrangement with the buyer.
STOCK-BASED COMPENSATION. SFAS-123, Accounting for Stock-Based
Compensation, was adopted by the Company in the first quarter of 1996. It
recommends the use of a fair value based method of accounting for compensation
costs associated with stock-based compensation. The Company currently has Stock
Appreciation Rights plans covering certain employees and directors. For these
plans, the Company's accounting policy has been to use a fair value method of
computing periodic compensation expense; accordingly, the application of SFAS-
123 has no significant impact on the Company's financial position or results of
operations. The aggregate amount charged to expense as a result of these plans
approximates $1.0 million annually.
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.
40
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)
-----------------------------
1996 1995 1994
Charged to operating expense:
Current $65,757 $ 65,368 $ 35,658
Deferred 3,744 847 25,587
------- -------- --------
Total 69,501 66,215 61,245
Charged (Credited) to other income:
Current (6,097) (9,996) (7,419)
Deferred 5,079 (4,520) (6,408)
Deferred investment tax credit (2,432) (2,432) (2,432)
------- -------- --------
Total (3,450) (16,948) (16,259)
Total federal income tax expense $66,051 $ 49,267 $ 44,986
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)
---------------------------------------------------------
1996 1995 1994
% of % of % of
Pretax Pretax Pretax
Amount Income Amount Income Amount Income
-------- ------ -------- ------ ------ ------
Net Income $ 97,511 $ 71,928 $ 74,375
Add: federal income tax expense 66,051 49,267 44,986
-------- -------- --------
Income before federal income tax $163,562 $121,195 $119,361
Computed tax expense $ 57,247 35.0 $ 42,418 35.0 $ 41,776 35.0
Increases (decreases) in tax resulting from:
Difference between tax depreciation
and amount deferred 10,796 6.6 7,197 6.0 6,685 5.6
Deferred investment tax credit (2,432) (1.5) (2,432) (2.0) (2,432) (2.0)
Miscellaneous items, net 440 0.3 2,084 1.7 (1,043) (0.9)
Total federal income tax expense $ 66,051 40.4 $ 49,267 40.7 $ 44,986 37.7
A summary of the components of the net deferred tax liability is as follows:
(Thousands of Dollars)
-----------------------------
1996 1995 1994
Nuclear decommissioning $(17,880) $(14,797) $(13,390)
Alternative minimum tax (4,183) 0 (9,584)
Accelerated depreciation 213,907 197,952 184,941
Deferred investment tax credit 29,562 31,143 32,723
Deferred ice storm charges 3,142 4,035 4,930
Depreciation previously flowed through 169,562 183,077 200,956
Gas storage demand charges (4,316) (6,076) 0
Pension (24,570) (24,241) (11,690)
Other 4,804 6,559 14,008
-------- -------- --------
Total $370,028 $377,652 $402,894
41
SFAS-109 "Accounting for Income Taxes" 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, 1996 and 1995 was $175
million and $189 million, respectively. In conjunction with the recognition of
this liability, a corresponding regulatory asset was also recognized.
As of December 31, 1996, the regulatory asset recognized by the Company as a
result of adopting SFAS-109 is attributable to $153 million in depreciation, $21
million to property taxes, $17 million of deferred finance charges - Nine Mile
Two and $3 million of miscellaneous items offset by $16 million attributable to
deferred investment tax credits and $3 million of revenue taxes.
42
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)
1996 1995
-------- -------
Accumulated benefit obligation, including
vested benefits of $374.6 in 1996 and
$407.8 in 1995 $ (392.6)* $(424.5)*
======== =======
Projected benefit obligation for service
rendered to date $ (480.2)* $(515.9)*
Less: Plan assets at fair value, primarily
listed stocks and bonds 567.1 520.0
-------- -------
Plan assets in excess of projected benefits 86.9 4.1
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions ( 170.7) (91.1)
Prior service cost not yet recognized in
net periodic pension cost 11.6 12.5
Unrecognized net obligation at December 31 2.4 2.9
-------- -------
Pension costs accrued $ ( 69.8) $( 71.6)
======== =======
* Actuarial present value.
Net pension cost included the following components:
(Millions)
1996 1995 1994
------ ------- ------
Service cost - benefits earned during the period $ 7.4 $ 6.0 $ 8.2
Interest cost on projected benefit obligation 33.4 35.4 32.2
Actual return on plan assets (80.8) (101.1) 0.8
Net amortization and deferral 39.0 56.1 (40.0)
------ ------- ------
Net periodic pension (credit) cost $ (1.0) $ (3.6) $ 1.2
====== ======= ======
During 1994, the Company offered to its employees an early retirement
program. A total of 399 employees elected to participate in this program
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, 1996 and December 31,
1995 assumed discount rates of 7.25% and 6.75%, respectively, and a long-term
rate of increase in future compensation levels of 5.00%. 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.
43
The 1996, 1995, and 1994 pension costs reflect adoption of PSC
prescribed 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 1996, 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.
SFAS-106, "Accounting for Postretirement Benefits Other than
Pensions", allows the Company to amortize the initial unrecognized, unfunded
Accumulated Postretirement Benefit Obligation at January 1992 estimated at $56
million over twenty years. 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)
1996 1995
------ ------
Accumulated postretirement benefit obligation:
Retired employees $(65.6) $(68.3)
Active employees (13.5) (14.0)
------ ------
$(79.1) $(82.3)
Less - Plan assets at fair value 0.0 0.0
------ ------
Accumulated postretirement benefit
obligation (in excess of) less than
fair value of assets (79.1) (82.3)
Unrecognized net loss (gain) from past experience
different from that assumed and effects
of changes in assumptions 3.7 10.3
Prior service cost not yet recognized in
net periodic pension cost 7.1 7.5
Unrecognized net obligation at December 31 42.3 45.1
------ ------
Accrued postretirement benefit cost $(26.0) $(19.4)
====== ======
44
Net periodic postretirement benefit cost included the following
components:
(Millions)
1996 1995
----- -----
Service cost - benefits attributed to the period $ 1.0 $ 0.7
Interest cost on accumulated postretirement
benefit obligation 5.4 5.5
Actual return on plan assets 0.0 0.0
Net amortization and deferral 4.2 2.9
----- -----
Net periodic postretirement benefit cost $10.6 $ 9.1
===== =====
The Accumulated Postretirement Benefit Obligation at December 31, 1996
and 1995 assumed discount rates of 7.25% and 6.75%, respectively, and long-term
rate of increase in future compensation levels of 5.00%.
SFAS-112, "Employers' Accounting for Postemployment Benefits",
requires the Company to recognize the obligation to provide postemployment
benefits to former or inactive employees after employment but before retirement.
The Company has been allowed to recover this cost in rates.
45
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)
----------------------------------
1996 1995 1994
---------- ---------- ----------
Electric
Operating Information
Operating revenues $ 707,768 $ 722,465 $ 674,753
Operating expenses, excluding
provision for income taxes 518,567 518,762 489,982
---------- ---------- ----------
Pretax operating income 189,201 203,703 184,771
Provision for income taxes 61,901 59,500 52,842
---------- ---------- ----------
Net operating income $ 127,300 $ 144,203 $ 131,929
---------- ---------- ----------
Other Information
Depreciation and amortization $ 92,615 $ 78,812 $ 75,211
Nuclear fuel amortization $ 16,209 $ 17,982 $ 18,048
Capital expenditures $ 95,334 $ 93,634 $ 93,477
Investment Information,
Identifiable assets (a) $1,877,224 $1,913,762 $1,901,262
Gas
Operating Information
Operating revenue $ 346,279 $ 293,863 $ 326,061
Operating expenses, excluding
provision for income taxes 313,513 275,978 294,575
---------- ---------- ----------
Pretax operating income 32,766 17,885 31,486
Provision for income taxes 7,600 6,715 8,403
---------- ---------- ----------
Net operating income $ 25,166 $ 11,170 $ 23,083
---------- ---------- ----------
Other Information
Depreciation $ 12,999 $ 12,781 $ 12,250
Capital expenditures $ 18,940 $ 15,913 $ 23,742
Investment Information
Identifiable assets (a) $ 447,865 $ 477,758 $ 487,333
(a) Excludes cash, unamortized debt expense, and other common items.
46
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 capability (summer) 788 1,128
RG&E's share - megawatts 189 158
- percent 24 14
Year of completion 1980 1988
Millions of Dollars
at December 31, 1996
-------------------------
Plant In Service Balance $98.6 $874.7
Accumulated Provision For Depreciation $39.2 $465.0
Plant Under Construction $ 0.9 $ 4.6
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.
47
Note 6. LONG-TERM DEBT
FIRST MORTGAGE BONDS
(Thousands of Dollars)
Principal Amount
December 31
% Series Due 1996 1995
- -----------------------------------------------------------------------------
5.30 V May 1, 1996 $ - $ 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 29,668 30,000
8 3/8 CC Sept. 15, 2007 - 49,000
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
-------- --------
$575,668 $643,000
Net bond discount (614) (668)
Less: Due within one year 20,000 18,000
------- --------
Total $555,054 $624,332
======== ========
(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 (NYSERDA) 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 depositing cash with the Trustee. The 1996 requirement was met with funds
deposited with the Trustee, and these funds were used for redemption of
48
outstanding bonds of Series Y. The 1995 requirement was met by certification of
additional property.
On March 7, 1996 the Company redeemed all its outstanding $49 million
principal amount of First Mortgage 8 3/8% Bonds, Series CC, due September 15,
2007 at a price of 103.18%.
Sinking fund requirements and bond maturities for the next five years are:
(Thousands of Dollars)
1997 1998 1999 2000 2001
-------------------------------------------------------
Series W $20,000
Series X $30,000
Series Y $29,668
Series EE $ 270 $ 285
7% Series 30,000
-------------------------------------------------------
$20,000 $30,000 $29,668 $30,270 $ 285
PROMISSORY NOTES
(Thousands of Dollars)
December 31
Issued Due 1996 1995
- ----------------------------------------------------------------
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, 1999. 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 3.38% for 1996, 3.68% for 1995 and 2.82% for 1994. 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, 1999. The annual
interest rate was adjusted to 4.40% effective November 15, 1994, to 3.75%
effective November 15, 1995 and to 3.60% effective November 15, 1996. 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 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.
Based on an estimated borrowing rate at year-end 1996 of 7.30% 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 $670 million at December 31, 1996.
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.
49
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, 1996 1996 1995 (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, 1996 1996 1995 (per share)
- ------- ------- ----------------- ------- ------------- -----------------
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
Less: Due within o ne year 100,000 10,000 --
------- ------- -------
Total 450,000 $45,000 $55,000
======= ======= =======
+ Thereafter at $100.00
50
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 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 1996 of 6.50% for
Preferred Stock, subject to mandatory redemption, with similar terms and average
maturities (5.66 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $57 million at December 31,
1996.
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.
51
Note 8. COMMON STOCK
At December 31, 1996, there were 50,000,000 shares of $5 par value
Common Stock authorized, of which 38,851,464 were outstanding. No shares of
Common Stock are reserved for options, warrants, conversions, or other rights.
There were 1,026,840 shares of Common Stock reserved and unissued for
shareholders under the Automatic Dividend Reinvestment and Stock Purchase Plan
and 129,664 shares reserved and unissued for employees under the RG&E Savings
Plus Plan.
COMMON STOCK
Per Shares Amount
Share Outstanding (Thousands)
---------- ------------ -----------
Balance, January 1, 1994 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
Net issuance/redemption costs 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
Net issuance/redemption costs (125)
---------- --------
Balance, December 31, 1995 38,453,163 $687,518
Automatic Dividend Reinvestment 20.375-
and Stock Purchase Plan 23.250 342,222 7,409
Savings Plus Plan 20.313-
23.438 56,079 1,203
Net issuance/redemption costs (111)
--------- -------
Balance, December 31, 1996 38,851,464 $696,019
52
Note 9. SHORT-TERM DEBT
On December 31, 1996, the Company had short-term debt outstanding of
$14.0 million. At December 31, 1995 the Company had no short-term debt
outstanding. For 1996, the weighted average interest rate on short-term debt
outstanding at year end was 7.25% and was 5.86% for borrowings during the year.
The weighted average interest rate on short-term debt borrowed during 1995 was
6.14%.
In December 1996 the Company's $90 million revolving credit agreement
was amended extending its term to five years, terminating December 31, 2001.
Commitment fees related to this facility amounted to $113,000 in 1996, $165,000
in 1995 and $169,000 in 1994.
The Company's Charter provides that the Company may not issue
unsecured debt if immediately after such issuance the total amount of unsecured
debt outstanding would exceed 15 percent of the Company's total secured
indebtedness, capital, and surplus without the approval of at least a majority
of the holders of outstanding Preferred Stock. As of December 31, 1996, the
Company would be able to incur $ 55.1 million of additional unsecured debt under
this provision. The Company has unsecured lines of credit totaling $72 million
available from several banks, at their discretion.
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 $10 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, 1996, borrowings outstanding were $9.1 million of 636
Notes (recorded on the Balance Sheet as a deferred credit).
53
Note 10. COMMITMENTS AND OTHER MATTERS
CAPITAL EXPENDITURES
The Company's 1997 construction expenditures program is currently
estimated at $101 million. 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 amounts in its
electric rates 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 $94.2 million through December
31, 1996 and is authorized to collect approximately $22 million annually through
June 30, 1999 for decommissioning, covering both nuclear units. The amount
allowed in rates is based on estimated ultimate decommissioning costs of $296.3
million for Ginna and $112.8 million for the Company's 14% share of Nine Mile
Two (1995 dollars). These estimates are based on site specific cost studies for
each plant completed in 1995. 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 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 $66.1 million to this fund and, including realized
and unrealized investment returns, the fund has a balance of $91.2 million as of
December 31, 1996. 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, 1996 is $28.1 million.
The NRC is currently considering proposals which may impact financial
funding requirements for decommissioning of nuclear power plants. Under current
NRC regulations electric utilities provide for decommissioning funds annually
over the estimated life of a plant. If state regulatory authorities were to
adopt a program to remove electric generation (including nuclear plants) from
cost-based rate regulation, an action which the New York PSC is currently
considering, such plants would operate in a competitive electric market and
would have no assured source of revenue from energy sales. Under current
regulations, the NRC can require the owners of nuclear plants lacking such
assured revenue streams to provide assurance that the full estimated cost of
decommissioning will ultimately be available through some guarantee mechanism.
The NRC is seeking public comment on a number of questions, including
the likely timetable for utility restructuring and deregulation and to what
extent costs will be recoverable if a large baseload plant is deemed to be non-
competitive because of high construction costs and what funding sources will be
used to shut down a plant prematurely and safely.
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 accounts could be increased and trust fund income from
the external decommissioning trusts could be reported as investment income
rather than as a reduction to decommissioning expense.
54
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 enacted in October 1992, utilities with nuclear
generating facilities are assessed an annual fee payable over 15 years 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. Installments aggregating approximately $7.7
million have been paid through 1996. The Company is seeking a return of
approximately $5.6 million as part of a civil action against the United States
Department of Energy (DOE) filed in the United States Court of Federal Claims in
July. 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, 1996 is $16.4 million ($14.7 million as a long-term liability
and $1.7 million as a current liability). The Company is recovering costs
through base rates of fuel.
NUCLEAR FUEL DISPOSAL COSTS. The Nuclear Waste Policy Act (Nuclear
Waste Act) of 1982, as amended, requires the 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. In December 1996 the DOE notified the
Company that the DOE will not start acceptance of Ginna spent fuel in 1998. In
January 1997 the DOE released a draft request for proposal outlining a process
for private firms to accept and transport waste from reactors until a federal
facility is operational. 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 $79.1 million at December 31,
1996. The Company is allowed by the PSC to recover these costs in rates. The
estimated fees are classified as a long-term liability and interest is accrued
at the current three-month Treasury bill rate, adjusted quarterly. The Nuclear
Waste Act also requires the DOE to provide for the disposal of nuclear fuel
irradiated after April 6, 1983, for a charge of one mill ($.001) per KWH of
nuclear energy generated and sold. This charge (approximately $3.5 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 will 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 seeking a declaration that DOE is
violating its obligation to begin accepting and disposing of such waste,
requiring DOE to report progress thereon and requesting other relief. In a July
1996 decision, the court upheld the utilities' position that DOE is obligated to
accept and dispose of the utilities' SNF beginning not later than January 31,
55
1998. DOE had contended in effect that it could defer the disposal until the
availability of a suitable SNF repository. The court rejected this DOE reading
of the Nuclear Waste Act, but stopped short of providing the utilities a remedy
since DOE has not yet defaulted on its obligations.
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
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 "six-cent"
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 judgment
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.
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 damages in the amount of $420,000,000, when trebeled,
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.
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
56
Agreement. The Company filed such a petition and Kamine filed papers in
opposition.
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's motion for rehearing was denied.
The Company filed a petition for review with the U.S. Court of Appeals for the
District of Columbia Circuit but that court denied the request for review.
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 Agreement. Kamine
filed a motion to compel the Company to pay what would be due under Kamine's
view of the terms of the 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. On appeal the Bankruptcy Court was reversed and the case sent
back to the Bankruptcy Court to decide where the contract issues in the
Adversary Proceeding should be adjudicated. Numerous other procedural motions
have been presented in the Bankruptcy Court. While these procedural issues are
pending, the Company would pay approximately two cents per kilowatt hour when
the plant operates and it is not operating at the present time.
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 investor-owned utilities and State officials to resolve
the problem. The Company is litigating the Kamine matter vigorously while it
continues to work to resolve this particular dispute in a fashion that is fair
and equitable to all parties. However, it 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 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,
1996 of $4.3 million.
* Voluntary agreement signed.
57
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 1996 of less than $1.0
PAS of Oswego* Oswego, NY million.
* 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 four of
these sites are in various stages of planning or completion and the Company is
conducting a program to restore the other two sites. The Company has recorded a
total liability of approximately $12.8 million, $12.0 million of which it
anticipates spending on SIR efforts at the six Company-owned sites listed in
Table I above. Concurrently, the Company recorded a similar amount in its
Regulatory Assets.
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
cleanup. 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. Cleanup activities which were previously suspended, resumed on a portion of
the West Station site and were concluded in July 1996 under a voluntary
agreement with the NYSDEC. The Company expects to receive a release from future
liability and a covenant not to sue from the NYSDEC for this work. There remain
other portions of the property where additional remedial work is expected,
however, only a preliminary scope and schedule have been determined. 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. Subsequent data evaluation indicate a wider array of potential sources
of coal gassification related materials than previously thought suggesting
significant remedial work 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. The matter was reported to the NYSDEC and, in
September 1990, the Company also provided the agency with a risk assessment.
The report of the results of this study and the NYSDEC's response to the
recommendations made
58
therein will influence the future remediation costs. The Company has signed a
voluntary agreement to perform limited additional investigation at the site to
determine whether certain remedial actions are necessary prior to development.
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 investigative work continues. 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 (Brewer Street), 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 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
investigation of this area, 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.
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. It is estimated
that further investigative work into this problem may cost up to $100,000.
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 $.8 million.
In one site, known as the Quanta Resources Site, the Company signed a
consent order with the Environmental Protection Agency (EPA) and paid its
$27,500 share of remedial cost. The Company was again contacted by EPA in late
August, 1996. The EPA informed the Company that it believed certain additional
work was required, including a study to determine the extent to which additional
removal of waste materials was required. The EPA's list of PRPs had grown to
about 80. The Company, along with most of those PRPs, has agreed (through an
Administrative Order on Consent) to conduct the required study. The Company
anticipates its obligation through this phase will be less than $10,000.
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
59
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 of which the Company's share is not expected
to exceed $600,000. 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 that its share of the cost of investigation and remediation would
approximate $276,000.
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.
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. Based on the most recent strategy
developments a range of capital costs between $2.9 million and $3.5 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, as well as approximately $1.0 million per year in operating
expenses. These capital costs would be incurred between 1997 and 2000. Beyond
2000, the Company estimates that it could also incur approximately $2.5 million
of additional annual operating expenses, excluding fuel, to comply with the
Amendments. Capital costs after the year 2000 cannot be predicted until a
strategy is chosen.
CIVIL INVESTIGATIVE DEMAND
The United States Department of Justice, Antitrust Division
("Division"), has issued a Civil Investigative Demand calling for depositions
for the production of documents and answers to interrogatories concerning the
electric industry and competition. The Company believes that the Division is
interested in the transition of the electric industry from a regulated monopoly
to competition in order to ensure that electric utilities do not use their
existing lawful market position to gain an unfair competitive advantage if and
when wholesale and retail competition are a reality. The primary focus of the
Division appears to be on the flexible rate, long-term contracts entered between
the Company and a number of its large customers under the tariff approved by the
PSC, notwithstanding extensive PSC review and its express determination that the
Company may enter into such contracts. The Company has urged the Division to
address its concerns to the PSC in the Competitive Opportunities Proceeding
since the PSC intends to specifically manage the transition to competition.
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 $40.0 million of these costs were paid to various suppliers, of
which about $30.9 million has been included in purchased gas costs. At year-
end, $32.3 million remains deferred for future collection from customers. The
Company has a $10
60
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, 1996 the Company had $9.1 million of borrowings outstanding under the credit
agreement. The Company is collecting those costs through the Gas Cost
Adjustment clause 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 for a period extending to the year 2008. 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
is comparable to the Company's current requirements.
1995 GAS SETTLEMENT. The Company has entered into several agreements
to help manage its pipeline capacity costs and has successfully met settlement
targets for capacity remarketing for the twelve months ending October 31, 1996,
thereby avoiding negative financial impacts for that period. The Company
believes that it will also be successful in meeting the Settlement targets in
the remaining two years of the Settlement period, although no assurance may be
given.
The FERC approved a change in rate design for the Great Lakes Gas
Transmission Limited Partnership (Great Lakes) on which the Company holds
transportation capacity. This change resulted in a retroactive surcharge by
Great Lakes to the Company in the amount of approximately $8 million, including
interest. Under the terms of the 1995 Gas Settlement, the Company may recover
approximately one-half of the surcharge in rates charged to customers; but the
remainder may not be passed through and has been previously reserved. The
Company, which paid the Great Lakes assessment under protest, vigorously
contested it before the FERC, but on April 25, 1996, the FERC upheld this
determination that the charge to the Company is proper. The Company has filed a
petition for review with the U.S. Court of Appeals. The ultimate outcome of
judicial review cannot be predicted.
GAS RESTRUCTURING PROCEEDING. In the PSC's Proceeding on
Restructuring the Emerging Competitive Natural Gas Market, the PSC established a
three-year period (ending March 28, 1999) during which the State's gas utilities
would be permitted to require customers converting from sales service to take
associated pipeline capacity for which the utilities had originally contracted.
Prior to the beginning of the third year, the utilities would be required to
demonstrate their efforts to dispose of "excess" capacity. Pursuant to the
PSC's Orders, the cost of capacity defined as "excess" that the Company still
holds after March 28, 1999 may not be fully recoverable in rates. Accordingly,
the Company's ability to avoid absorbing this cost will depend on the success of
remarketing efforts, as described above, and, if such efforts do not result in
eliminating all "excess" capacity, on a satisfactory explanation as to why all
such capacity could not be remarketed.
The PSC's March 28, 1996 Order also required that the Company and
other gas utilities restructure their service offerings in a number of different
respects. The Company has made the necessary changes to its tariff and, as of
the end of 1996, had deferred an additional amount of approximately $1.8 million
to effect the required transition. The Company anticipates that the remaining
transition costs will occur in 1997 and that they will total approximately an
additional $1.5 million. On December 20, 1996, the Company petitioned the PSC
for authority to defer the 1996 expenditures for subsequent recovery. Because
of the potential impact of recovering these costs on gas rates established by
the 1995 Gas Settlement, it may be necessary for the Company to petition the PSC
for review of the operation of the Gas Settlement, as provided for therein. The
Company has not determined whether to file such a petition for review and,
therefore, the outcome of any request for recovery of the transition costs,
assuming deferred accounting is authorized, cannot be determined.
ASSERTION OF TAX LIABILITY
The Company's federal income tax returns have been examined by the
Internal Revenue Service (IRS) through the calendar year ended 1992. The one
outstanding issue, which has placed the years 1987 through 1992 in protest by
the Company,
61
pertains 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.
The Company believes its tax reserve is sufficient and that it will
reach an agreement with the IRS on the issue, in which the Company will
substantially prevail in the issues.
REGULATORY AND STRANDABLE ASSETS
With PSC approval 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 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
(pursuant to Financial Accounting Standards No. 121 (SFAS-121)). In certain
cases, the entire amount could be written off.
SFAS-121,"Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of", requires write-down of assets whenever
events or circumstances occur which indicate that the carrying amount of a long-
lived asset may not be fully recoverable.
Below is a summary of the Regulatory Assets as of December 31, 1996
and 1995 (Millions of Dollars):
1996 1995
------ ------
Income Taxes $174.6 $188.6
Uranium Enrichment Decommissioning Deferral 17.7 18.7
Deferred Ice Storm Charges 14.0 16.6
FERC 636 Transition Costs 32.3 41.0
Demand Side Management Costs Deferred 8.4 14.7
Other, net 37.5 31.6
------ ------
Total - Regulatory Assets $284.5 $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
through the year 2007. The recovery of these costs is through base rates of
fuel.
- - 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 by the year
2000.
62
- - 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
through the year 2000.
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, 1996
cannot be determined at this time, but could be significant. Strandable assets,
if any, would be written down for impairment of recovery in the same manner as
deferred cost discussed above.
At December 31, 1996 the Company believes that its Regulatory and
Strandable Assets, if any, are not impaired and are probable of recovery,
although no such assurance can be given.
LEASE AGREEMENTS
The Company leases five properties for administrative offices and
operating activities. The total lease expense charged to operations was $3.9
million in 1996. For the years 1997, 1998, 1999, 2000 and 2001 the estimated
lease expense charged to operations will be $5.9 million, $5.9 million, $4.0
million, $4.0 million and $4.0 million, respectively. Commitments under capital
leases were not significant to the accompanying financial statements.
63
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, 1996 $274,431 $36,326 $22,228 $20,362 $0.52
September 30, 1996 234,843 36,159 21,062 19,196 0.49
June 30, 1996 235,577 23,115 11,732 9,866 0.25
March 31, 1996 309,195 56,866 42,489 40,623 1.05
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 28,653 .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
/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.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
64
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS 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 16, 1997, 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".
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 4, 1997 will be filed with the
Securities and Exchange Commission prior to April 30, 1997. 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 16, 1997 is not deemed to be filed as part of this
Report.
65
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 Statement of Income for each of the three
years ended December 31, 1996.
Consolidated Statement of Retained Earnings for each of
the three years ended December 31, 1996.
Consolidated Balance sheet at December 31, 1996 and 1995.
Consolidated Statement of Cash Flows for each of the three
years ended December 31, 1996.
Notes to Consolidated Financial Statements.
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1996.
Schedule II - Valuation and Qualifying Accounts.
(a) 3. Exhibits - See List of Exhibits.
(b) Reports on Form 8-K - None.
66
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
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 0 736 736
FOR THE YEAR ENDED DECEMBER 31, 1996
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 $11,950 $5,552 $17,502
Materials and supplies
obsolescence 736 (375) 361
Beginning in 1992 the Company no longer charges uncollectible expenses
through the uncollectible reserve. The total amount written off directly to
expense in 1994 was $9,000, in 1995 was $12,063 and in 1996 was $15,016.
67
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 3-1
in May 1996 on Form 10-Q for the quarter ended March 31, 1996, SEC
File No. 1-672)
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 3-1
in May 1996 on Form 10-Q for the quarter ended March 31, 1996, SEC
File No. 1-672)
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.)
68
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* (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 10-9* (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 10-10* (A) Rochester Gas and Electric Corporation Deferred Stock Unit
Plan for Non-Employee Directors, effective as of December 31,
1995. (Filed as Exhibit 10-1 in May 1996 on Form 10-Q for the
quarter ended March 31, 1996, SEC File No. 1-672)
Exhibit 10-11 (A) 1996 Performance Stock Option Plan.
Exhibit 10-12* (A) Rochester Gas and Electric Corporation Executive Incentive
Plan, Restatement of January 1, 1995. (Filed as Exhibit 10-11
in February 1996 on Form 10-K for the year ended December 31,
1995, SEC File No. 1-672-2)
Exhibit 10-13* (A) RG&E Unfunded Retirement Income Plan Restatement as of
July 1, 1995. (Filed as Exhibit 10-12 in February 1996 on
Form 10-K for the year ended December 31, 1995, SEC File
No. 1-672-2)
Exhibit 10-14* (A) Severance Agreement dated August 17, 1995 between the Company
and Roger W. Kober, Chairman of the Board, President and
Chief Executive Officer. (Filed as Exhibit 10-13 in February
1996 on Form 10-K for the year ended December 31, 1995, SEC
File No. 1-672-2)
69
Exhibit 10-15* (A) Severance Agreement dated August 17, 1995 between the Company
and Thomas S. Richards, Senior Vice President, Energy
Services. (Filed as Exhibit 10-14 in February 1996 on Form
10-K for the year ended December 31, 1995, SEC File No.
1-672-2)
Exhibit 10-16* (A) Severance Agreement dated August 17, 1995 between the Company
and Robert E. Smith, Senior Vice President, Energy
Operations. (Filed as Exhibit 10-15 in February 1996 on Form
10-K for the year ended December 31, 1995, SEC File No.
1-672-2)
Exhibit 10-17* (A) Severance Agreement dated January 2, 1996 between the Company
and J. Burt Stokes, Senior Vice President, Corporate Services
and Chief Financial Officer. (Filed as Exhibit 10-16 in
February 1996 on Form 10-K for the year ended December 31,
1995, SEC File No. 1-672-2)
Exhibit 10-18 (A) Change of Control Agreement dated January 2, 1997 between the
Company and Michael J. Bovalino, Senior Vice President,
Energy Services.
Exhibit 23 Consent of Price Waterhouse LLP, 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.
70
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: /s/ ROGER W. KOBER
--------------------------------
Roger W. Kober
Chairman of the Board and
Chief Executive Officer
DATE: February 13, 1997
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.
SIGNATURE TITLE DATE
- --------- ----- ----
Principal Executive Officer:
/s/ ROGER W. KOBER Chairman of the Board and February 13, 1997
- ---------------------------- Chief Executive Officer
(Roger W. Kober)
Principal Financial Officer:
/s/ J. B. STOKES Senior Vice President February 13, 1997
- ---------------------------- Corporate Services and
(J. Burt Stokes) Chief Financial Officer
Principal Accounting Officer:
/s/ DANIEL J. BAIER Controller February 13, 1997
- -----------------------------
(Daniel J. Baier)
71
SIGNATURE TITLE DATE
- --------- ----- ----
Directors:
/s/ WILLIAM BALDERSTON III Director February 13, 1997
- -----------------------------
(William Balderston III)
/s/ ANGELO J. CHIARELLA Director February 13, 1997
- -----------------------------
(Angelo J. Chiarella)
/s/ ALLAN E. DUGAN Director February 13, 1997
- -----------------------------
(Allan E. Dugan)
/s/ JAY T. HOLMES Director February 13, 1997
- -----------------------------
(Jay T. Holmes)
/s/ SAMUEL T. HUBBARD,JR Director February 13, 1997
- -----------------------------
(Samuel T. Hubbard,Jr.)
/s/ ROGER W. KOBER Director February 13, 1997
- -----------------------------
(Roger W. Kober)
/s/ THEODORE L. LEVINSON Director February 13, 1997
- -----------------------------
(Theodore L. Levinson)
/s/ CONSTANCE M. MITCHELL Director February 13, 1997
- -----------------------------
(Constance M. Mitchell)
/s/ CORNELIUS J. MURPHY Director February 13, 1997
- -----------------------------
(Cornelius J. Murphy)
/s/ CHARLES I. PLOSSER Director February 13, 1997
- -----------------------------
(Charles I. Plosser)
/s/ THOMAS S. RICHARDS Director February 13, 1997
- -----------------------------
(Thomas S. Richards)
/s/ ARTHUR M. RICHARDSON Director February 13, 1997
- -----------------------------
(Arthur M. Richardson)
/s/ M. RICHARD ROSE Director February 13, 1997
- -----------------------------
(M. Richard Rose)
/s/ NANCY J. WOODHULL Director February 13, 1997
- -----------------------------
(Nancy J. Woodhull)