<PAGE>
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, 1997
-----------------
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
-----------------------------------------------------
(Exact name of registrant as specified in its charter)
New York 16-0612110
------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) identification No.)
89 East Avenue, Rochester, NY 14649
--------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (716) 546-2700
--------------
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ---------------------
Common Stock, $5 par value New York Stock Exchange
<PAGE>
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934
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
4.10% Series J
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
On January 1, 1998 the aggregate market value of the voting stock held by
nonaffiliates of the Registrant was approximately $1,312,000,000.
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
--- ---
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, 1998, 38,862,347.
Documents Incorporated by Reference Part of Form 10-K
----------------------------------- -----------------
Definitive proxy statement in connection III
with annual meeting of shareholders to be
held April 15, 1998.
<PAGE>
ROCHESTER GAS AND ELECTRIC CORPORATION
Information Required on Form 10-K
Item
Number Description Page
- ------ ----------- ----
Part I
- ------
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 4A Executive Officers of the Registrant 14
Part II
- -------
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 34
Item 9 Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure 68
Part III
- --------
Item 10 Directors and Executive Officers of the Registrant 69
Item 11 Executive Compensation 69
Item 12 Security Ownership of Certain Beneficial Owners and
Management 69
Item 13 Certain Relationships and Related Transactions 69
Part IV
- -------
Item 14 Exhibits, Financial Statement Schedules and
Reports on Form 8-K 70
Signatures 75
<PAGE>
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
Regulatory Matters 2
Electric Operations 3
Gas Operations 5
Fuel Supply 6
Financing and Capital Requirements Program 7
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, 1997 the Company had 1,958 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. The Company also plans to enter into
unregulated businesses that will bring energy products and services to the
marketplace both within and outside the Company's franchise area.
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
7 - Management's Discussion and Analysis of Financial Condition and Results of
<PAGE>
2
Operations. Percentages of the Company's operating revenues derived from
electric and gas operations for each of the last three years are as follows:
<TABLE>
<CAPTION>
1997 1996 1995
----- ----- -----
<S> <C> <C> <C>
Electric 67.6% 67.1% 71.1%
Gas 32.4% 32.9% 28.9%
----- ----- -----
100.0% 100.0% 100.0%
</TABLE>
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. In November 1997 the New York State Public Service Commission (PSC)
approved a Settlement Agreement among the Company, PSC staff and other parties
which sets the framework for the introduction and development of open
competition in the electric energy marketplace in New York State over the next
five years.
Regarding the Company's electric business, in early 1996 the Federal
Energy Regulatory Commission (FERC) issued new rules to facilitate the
development of competitive wholesale markets. In 1997 the Company together with
other New York utilities filed with FERC a "Comprehensive Proposal to
Restructure the New York Wholesale Market" and requested approval of their
restructuring plan in early 1998. At the State level, the PSC endorsed a
fundamental restructuring of the electric utility industry in the State in its
"Competitive Opportunities Proceeding". The Company's Competitive Opportunities
Settlement in 1997, including its proposed retail access program called "Energy
Choice", allows for a phase-in to open electric markets while lowering customer
prices and establishing an opportunity for competitive returns on shareholder
investments. Although the Company is just beginning to receive applications from
potential competitors under its distribution tariff, it expects more to be
filed, particularly from companies with strong retailing and customer service
capabilities and wholesale power trading expertise.
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. All gas
customers have a choice of suppliers since November 1996, subject to certain
phase-in limitations through 1998 for loss of gas commodity sales. Some of
these companies are large, nationally known, publicly held marketers or
suppliers. In 1997 the Company commenced negotiations with the staff of the PSC
and other parties with the objective of developing a multi-year settlement of
issues pertaining to the Company's gas business.
See Item 7 - Management's Discussion and Analysis of Financial
Condition and Results of Operations under the heading "Competition" for further
information on the Competitive Opportunities Settlement and the competitive
challenges the Company faces in its electric and gas business and how it is
responding to those challenges.
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 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
<PAGE>
3
Nuclear Regulatory Commission (NRC). The impact of regulation is discussed
throughout this report.
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 its flexible pricing
tariff for major industrial and commercial electric customers.
ELECTRIC OPERATIONS
Electric System. The total net generating capacity of the Company's
electric system is 1,239,000 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 New York 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 1993-1997 are as follows:
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C>
Sources of Generated Energy:
Nuclear 61.6% 49.4% 52.8% 55.3% 57.6%
Fossil 20.0 18.2 18.6 18.1 19.5
Hydro and Other 2.7 3.0 2.0 2.7 2.6
----- ----- ----- ----- -----
Total Generated Net 84.3 70.6 73.4 76.1 79.7
Purchased 15.7 29.4 26.6 23.9 20.3
----- ----- ----- ----- -----
Total Electric Energy 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
</TABLE>
The Company, six other New York utilities and the Power Authority are
members of the New York Power Pool (NYPP). The primary purposes of the NYPP are
to coordinate inter-utility sales of bulk power, long range planning of
generation and transmission facilities, and inter-utility operating and
emergency procedures in order to better assure reliable, adequate and economic
electric service throughout the State. For a discussion on potential changes to
the NYPP, see Item 7, Management's Discussion and Analysis of Financial
Condition and Results of Operations - "FERC Open Transmission Orders and
Company filings".
Generating Facilities. 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%, 20%, 7% and 15%, respectively, of the Company's current electric
generating system.
On December 1, 1997 Niagara Mohawk Power Corporation (Niagara)
announced a plan to sell its fossil-fueled and hydroelectric generating stations
by auction in 1998. This plan was agreed to as part of Niagara's Power Choice
Settlement currently under review by the PSC. The Company intends to include
its 24 percent share of Niagara's Oswego Steam Station Unit 6 (Oswego 6) for
sale as part of Niagara's auction. Any gains or losses realized by the Company
from the sale of its share of Oswego 6 would be treated in accordance with the
terms of the Settlement under the Competitive Opportunities Proceeding. The
Company would
<PAGE>
4
include its share of Oswego 6 in these efforts as well. The gross and net book
cost of the Company's share of Oswego 6 as of December 31, 1997 are $99 million
and $58 million, respectively
On January 21, 1998 the Company decided to retire Beebee Station by
mid-1999. Factors such as the plant's age, location in an area no longer
consistent with the surrounding development, lack of a rail/coal delivery system
and more stringent clean air regulations made the plant uneconomical in the
developing competitive generation business. The retirement of Beebee Station is
not expected to have a material effect on the Company's financial position or
results of operations. The plant will be fully depreciated at the time of
retirement. The Settlement provides that all prudently incurred incremental
costs associated with the shut down and decommissioning of the plant are
recoverable through the Company's distribution access tariff. The electric
capability and energy currently provided by the plant is expected to be replaced
by purchased power as needed.
Nine Mile Two, a nuclear generating unit in Oswego County, New York
with a designed capability of 1,143 megawatts (Mw) as estimated by Niagara, was
completed and entered commercial service in Spring 1988. Niagara is operating
the Unit on behalf of all owners pursuant to a full power operating license
which the NRC issued on July 2, 1987 for a 40-year term beginning October 31,
1986. Under arrangements dating from September 1975, ownership, output and cost
of the project are shared by the Company (14%), Niagara (41%) Long Island
Lighting Company (18%), New York State Electric & Gas Corporation (18%) and
Central Hudson Gas & Electric Corporation (9%). Under the operating Agreement,
Niagara serves as operator of Nine Mile Two, but all five cotenant owners share
certain policy, budget and managerial oversight functions. The base term of the
Operating Agreement is 24 months from its effective date, with automatic
extension, unless terminated by written notice of one or more of the cotenant
owners to the other cotenant owners; such termination becomes effective six
months from the receipt of any such notice of termination by all the cotenant
owners receiving such notice. The gross and net book cost of the Company's
share of Nine Mile Two including $374 million of disallowed costs previously
written off, as of December 31, 1997 are $879 million and $399 million,
respectively.
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.
The gross and net book cost of the Ginna Plant as of December 31, 1997
are $560 million and $309 million, respectively. From time to time the NRC
issues directives requiring all or a certain group of reactor licensees to
perform analyses as to their ability to meet specified criteria, guidelines or
operating objectives and where necessary to modify facilities, systems or
procedures to conform thereto. Typically, these directives are premised on the
NRC's obligation to protect the public health and safety. The Company reviews
such directives and implements a variety of modifications based on these
directives and resulting analyses. Expenditures at the Ginna Plant, including
the cost of these modifications, are estimated to be $10.1 million, $10.4
million and $6.4 million for the years 1998, 1999 and 2000, 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 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
<PAGE>
5
Company received final licenses for Stations 2 and 5 in February of 1996. The
license for Station 26 was received in October, 1997. Overly stringent
environmental conditions, governmental requirements and high property taxes have
nullified the economic viability of the fourth station, number 160 (less than
one megawatt net capacity). It will not be relicensed.
Joint Nuclear Operating Company. See Item 7 - Management's Discussion
and Analysis of Financial Condition and Results of Operations under Competition
- -Nuclear Operating Company regarding formation of a joint nuclear operating
company to support and manage the operations of nuclear plants in New York State
including Nine Mile Two and the Company's Ginna Plant described below.
Insurance. 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.
As a licensee of a commercial nuclear power plant in the United
States, the Company is required to have and maintain financial protection to
cover radiation injury claims of certain nuclear workers. The Company purchases
primary insurance to meet this requirement. On January 1, 1998, a new insurance
policy was issued that applies to claims first reported on or after January 1,
1998. This policy has a limit of $200 million (reinstated annually if certain
conditions are met) for radiation injury claims against the Company, or against
other licensees who are insured by this policy. If these claims exceed the $200
million limit of primary coverage, the provisions of the Price-Anderson Act
(discussed above) would apply. Since reserves for outstanding claims under
former policies could be insufficient and certain claims may still be made under
former policies due to a discovery period, the Company could be assessed under
these former policies along with the other policyholders. The Company's share
could be up to $3.0 million in any one year.
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 $3.0 million and $10.9 million in the event of losses under the
replacement power and property damage coverages, respectively.
GAS OPERATIONS
As of December 31, 1997 the Company's daily city gate resource
capability is 4,380,000 therms and its daily contracted transportation capacity
is 4,080,000 therms (where one Therm is equivalent to 100,000 British Thermal
Units). The Company optimizes its assets by contracting for gas resources that
align with its system requirements. The Company experienced on January 19,
1994, its maximum daily throughput of approximately 4,740,000 therms, (3,910,000
therms sold to retail customers and 830,000 therms delivered for transportation
customers).
The Company purchases all of its required gas supply from numerous
marketers and producers under contracts containing various terms and conditions.
<PAGE>
6
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.
The Company continues to provide new and additional gas service. Of
243,264 residential gas spaceheating customers at December 31, 1997, 2,579 were
added during 1997.
Approximately 31% of the gas delivered to customers by the Company
during 1997 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:
<TABLE>
<CAPTION>
Ginna Plant Nine Mile Two/(1)/
----------- ------------------
<S> <C> <C>
Uranium Concentrate 2000/(3)/ 2002/(2)/
Conversion 2000/(4)/ 2002/(2)/
Enrichment (5) (6)
Fabrication 2001 2003
</TABLE>
(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) The Company has a contract under which it may procure up 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 1998 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 70% of
requirements in 1998 and 1999, and 100% in 2000. Twenty percent of
requirements for 1998 are covered by a contract for delivery of UF6
(uranium plus conversion). Ten percent of requirements for 1998 will be
filled from inventory.
(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.
<PAGE>
7
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 average annual cost of nuclear fuel per million BTU used for
electric generation for the last five years is as follows:
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C>
Ginna Plant $.461 $.424 $.410 $.403 $.400
Nine Mile Two $.485 $.512 $.503 $.481 $.515
</TABLE>
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 1998 coal requirements are expected to be
approximately 800,000 tons. In 1997 100% of its requirements were purchased
under contract. To meet the additional coal burn requirements and meet its
current reserve supply of coal ranging from 30-60 days supply at maximum burn
rates, it is anticipated that the Company will purchase spot market coal to
supplement it contract supply.
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, and must average no higher
than 1.7 pounds per million BTU over a 12-month period or 1.9 pounds per million
BTU over a three-month period.
The average annual delivered cost of coal used for electric
generation was as follows:
<TABLE>
<CAPTION>
1997 1996 1995 1994 1993
----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C>
Per Million BTU $1.34 $1.34 $1.31 $1.38 $1.42
</TABLE>
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:
<PAGE>
8
(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, 1997 was 6.99.
(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, 1997 the amount of additional First Mortgage
Bonds which could be issued on that basis was approximately $398,393,000.
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, 1997, the Company
could issue $321,669,000 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
proposed to be issued. For the twelve months ended December 31, 1997, the
coverage ratio under (b) above (the more restrictive provision) was 2.83.
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, 1997 were:
<TABLE>
<CAPTION>
First
Mortgage Preferred
Bonds Stock
-------- ---------
<S> <C> <C>
Standard & Poor's Corporation BBB+ BBB
Moody's Investors Service Baa1 baa2
Duff & Phelps BBB+ BBB
</TABLE>
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.
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 $0.6 million on a
variety of projects and facility additions during 1997.
<PAGE>
9
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 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 2002. Efforts are being pursued to extend storage capacity beyond
2002, 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 and beyond, if necessary.
The Company has wastewater discharge permits from NYSDEC for its Ginna,
Beebee and Russell Stations, which were renewed in July 1997, February 1994, and
June 1994, respectively. These permits are each effective for a period of five
years. Consistent with these permits, no significant changes to the wastewater
discharge treatment systems are currently required, nor anticipated.
The Company believes that additional expenditures and costs made necessary
by mandated environmental protection programs will be fully allowable for
ratemaking purposes under cost of service rate regulation. Capital expenditures
for meeting various federal, State and local environmental standards are
estimated to be $9 million for the year 1998, $2 million for the year 1999 and
$1 million for the year 2000. 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 1997, 1996 and 1995 were $4.5 million,
$4.9 million, and $5.2 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.
<PAGE>
10
Electric Department Statistics
<TABLE>
<CAPTION>
Year Ended December 31 1997 1996* 1995* 1994* 1993* 1992
------------ ------------ ------------ ------------ ------------ -----------
<S> <C> <C> <C> <C> <C> <C>
Electric Revenue (000's)
Residential $ 252,464 $ 254,885 $ 256,294 $ 243,961 $ 234,866 $ 222,210
Commercial 210,643 215,763 215,696 206,545 196,100 187,262
Industrial 144,305 153,337 157,464 150,372 148,084 141,507
Municipal and Other 72,061 66,898 67,128 57,270 59,905 57,288
---------- ---------- ---------- ---------- ---------- ----------
Electric revenue from our customers 679,473 690,883 696,582 658,148 638,955 608,267
Other electric utilities 20,856 16,885 25,883 16,605 16,361 25,541
---------- ---------- ---------- ---------- ---------- ----------
Total electric revenue 700,329 707,768 722,465 674,753 655,316 633,808
---------- ---------- ---------- ---------- ---------- ----------
Electric Expense (000's)
Fuel used in electric generation 47,665 40,938 44,190 44,961 45,871 48,376
Purchased electricity 28,347 46,484 54,167 37,002 31,563 29,706
Other operation 205,058 204,746 199,524 192,360 192,749 183,118
Maintenance 41,217 41,429 44,032 47,295 52,464 53,714
Depreciation and amortization 103,395 92,615 78,812 75,211 72,326 73,213
Taxes - local, state and other 91,111 95,010 102,380 97,919 96,043 94,841
---------- ---------- ---------- ---------- ---------- ----------
Total electric expense 516,793 521,222 523,105 494,748 491,016 482,968
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 183,536 186,546 199,360 180,005 164,300 150,840
Federal income tax 61,837 61,901 59,500 52,842 43,845 38,046
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Electric Operations (000's) $ 121,699 $ 124,645 $ 139,860 $ 127,163 $ 120,455 $ 112,794
---------- ---------- ---------- ---------- ---------- ----------
Electric Operating Ratio % 46.0 47.1 47.3 47.7 49.2 49.7
Electric Sales - KWH (000's)
Residential 2,139,064 2,132,902 2,144,718 2,117,168 2,123,277 2,084,705
Commercial 2,118,991 2,061,625 2,064,813 2,028,611 1,986,100 1,938,173
Industrial 2,010,613 2,010,963 1,964,975 1,860,833 1,892,700 1,929,720
Municipal and Other 537,051 520,885 531,311 513,675 504,987 503,388
---------- ---------- ---------- ---------- ---------- ----------
Total customer sales 6,805,719 6,726,375 6,705,817 6,520,287 6,507,064 6,455,986
Other electric utilities 1,218,794 994,842 1,484,196 1,021,733 743,588 1,062,738
---------- ---------- ---------- ---------- ---------- ----------
Total electric sales 8,024,513 7,721,217 8,190,013 7,542,020 7,250,652 7,518,724
---------- ---------- ---------- ---------- ---------- ----------
Electric Customers at December 31
Residential 308,909 307,181 306,601 304,494 302,219 300,344
Commercial 30,940 30,620 30,426 29,984 29,635 29,339
Industrial 1,300 1,325 1,347 1,361 1,382 1,386
Municipal and Other 2,824 2,688 2,711 2,670 2,638 2,605
---------- ---------- ---------- ---------- ---------- ----------
Total electric customers 343,973 341,841 341,085 338,509 335,874 333,674
---------- ---------- ---------- ---------- ---------- ----------
Electricity Generated and
Purchased - KWH (000's)
Fossil 1,664,914 1,512,513 1,631,933 1,478,120 1,520,936 2,197,757
Nuclear 5,119,544 4,094,272 4,645,646 4,527,178 4,495,457 4,191,035
Hydro 227,867 248,990 171,886 218,129 199,239 278,318
Pumped storage 238,900 246,726 237,904 247,550 233,477 226,391
Less energy for pumping (358,350) (370,097) (361,144) (371,383) (355,725) (344,245)
Other 890 936 1,565 1,245 2,559 811
---------- ---------- ---------- ---------- ---------- ----------
Total generated - net 6,893,765 5,733,340 6,327,790 6,100,839 6,095,943 6,550,067
Purchased 1,301,636 2,437,433 2,343,484 1,998,882 1,646,244 1,389,875
---------- ---------- ---------- ---------- ---------- ----------
Total electric energy 8,195,401 8,170,773 8,671,274 8,099,721 7,742,187 7,939,942
---------- ---------- ---------- ---------- ---------- ----------
System Net Capability -
KW at December 31
Fossil 526,000 529,000 529,000 532,000 541,000 541,000
Nuclear 638,000 638,000 640,000 617,000 620,000 617,000
Hydro 47,000 47,000 47,000 47,000 47,000 47,000
Other 28,000 28,000 28,000 29,000 29,000 29,000
Purchased 375,000 375,000 375,000 375,000 347,000 348,000
---------- ---------- ---------- ---------- ---------- ----------
Total system net capability 1,614,000 1,617,000 1,619,000 1,600,000 1,584,000 1,582,000
---------- ---------- ---------- ---------- ---------- ----------
Net Peak Load - KW 1,421,000 1,305,000 1,425,000 1,374,000 1,333,000 1,252,000
Annual Load Factor - Net % 56.1 61.9 57.6 58.8 59.1 62.5
</TABLE>
* Reclassified for comparative purposes.
<PAGE>
11
Gas Department Statistics
<TABLE>
<CAPTION>
Year Ended December 31 1997 1996* 1995* 1994* 1993* 1992
----------- ----------- ----------- ----------- ----------- ----------
<S> <C> <C> <C> <C> <C> <C>
Gas Revenue (000's)
Residential $ 5,852 $ 6,010 $ 4,081 $ 5,935 $ 5,526 $ 6,456
Residential spaceheating 249,101 246,945 230,934 215,974 201,129 186,710
Commercial 51,893 52,073 51,117 49,115 46,321 44,395
Industrial 5,800 6,175 6,686 7,088 6,368 6,284
Municipal and other 23,663 35,076 1,045 47,949 34,364 17,879
---------- ---------- ---------- ---------- ---------- ----------
Total gas revenue 336,309 346,279 293,863 326,061 293,708 261,724
---------- ---------- ---------- ---------- ---------- ----------
Gas Expense (000's)
Gas purchased for resale 196,579 202,297 167,762 194,390 166,884 141,291
Other operation 63,416 61,348 59,684 49,312 47,593 43,506
Maintenance 5,418 5,634 5,194 7,774 9,229 9,006
Depreciation 13,127 12,999 12,781 12,250 11,851 11,815
Taxes - local, state and other 30,685 31,858 31,514 31,859 30,849 29,411
---------- ---------- ---------- ---------- ---------- ----------
Total gas expense 309,225 314,136 276,935 295,585 266,406 235,029
---------- ---------- ---------- ---------- ---------- ----------
Operating Income before
Federal Income Tax 27,084 32,143 16,928 30,476 27,302 26,695
Federal income tax 3,442 7,600 6,715 8,403 5,485 5,545
---------- ---------- ---------- ---------- ---------- ----------
Operating Income from
Gas Operations (000's) $ 23,642 $ 24,543 $ 10,213 $ 22,073 $ 21,817 $ 21,150
---------- ---------- ---------- ---------- ---------- ----------
Gas Operating Ratio % 78.9 77.8 79.2 77.1 76.2 74.1
Gas Sales - Therms (000's)
Residential 5,773 6,455 7,167 6,535 6,871 8,780
Residential spaceheating 285,395 299,085 280,763 283,039 295,093 287,623
Commercial 65,675 70,543 68,380 72,410 78,887 78,996
Industrial 7,828 9,334 9,560 11,420 12,030 12,438
Municipal 7,331 8,086 8,219 10,230 12,188 11,410
---------- ---------- ---------- ---------- ---------- ----------
Total gas sales 372,002 393,503 374,089 383,634 405,069 399,247
Transportation of customer-owned gas 166,060 167,779 146,149 136,372 124,436 126,140
---------- ---------- ---------- ---------- ---------- ----------
Total gas sold and transported 538,062 561,282 520,238 520,006 529,505 525,387
---------- ---------- ---------- ---------- ---------- ----------
Gas Customers at December 31
Residential 16,265 16,718 17,443 17,836 18,389 19,114
Residential spaceheating 243,264 240,685 238,267 235,313 231,937 228,096
Commercial 19,118 19,045 18,978 18,742 18,636 18,378
Industrial 829 857 879 905 924 932
Municipal 1,117 961 981 988 1,001 1,010
Transportation 836 744 655 558 466 424
---------- ---------- ---------- ---------- ---------- ----------
Total gas customers 281,429 279,010 277,203 274,342 271,353 267,954
---------- ---------- ---------- ---------- ---------- ----------
Gas - Therms (000's)
Purchased for resale 274,430 279,353 237,728 262,267 347,778 360,493
Gas from storage 104,317 122,843 152,852 134,802 76,378 53,757
Other 1,410 1,082 1,800 2,959 1,039 1,061
---------- ---------- ---------- ---------- ---------- ----------
Total gas available 380,157 403,278 392,380 400,028 425,195 415,311
---------- ---------- ---------- ---------- ---------- ----------
Cost of gas per therm 51.70(cent) 52.30(cent) 45.80(cent) 50.00(cent) 36.79(cent) 35.35(cent)
Total Daily Capacity -
Therms at December 31** 4,380,000 4,480,000 5,230,000 5,625,000 5,625,000 4,485,000
---------- ---------- ---------- ---------- ---------- ----------
Maximum daily throughput - Therms 4,114,290 4,022,600 3,980,000 4,735,690 3,864,850 3,768,470
Degree Days (Calendar Month)
For the period 6,921 6,998 6,535 6,699 7,044 6,981
Percent colder (warmer) than normal 2.8 3.9 (3.0) (0.6) 4.4 3.4
</TABLE>
* Reclassified for comparative purposes.
** Method for determining daily capacity, based on current network analysis,
reflects the maximum demand which the transmission systems can accept
without a deficiency.
<PAGE>
12
Item 2. PROPERTIES
ELECTRIC PROPERTIES
The net capability of the Company's electric generating plants in
operation as of December 31, 1997 the net generation of each plant for the year
ended December 31, 1997, and the year each plant was placed in service are as
set forth below:
<TABLE>
<CAPTION>
Electric Generating Plants
Net
Year Unit Net Generation
Placed in Capability thousands
Type of Fuel Service (Mw) (kwh)
------------ --------- ---------- ----------
<S> <C> <C> <C> <C>
Beebee Station
(Steam) Coal 1959 80 418,139
Beebee Station
(Gas Turbine) Oil 1969 14 425
Russell Station
(Steam) Coal 1949-1957 257 1,237,958
Ginna Station
(Steam) Nuclear 1970 480 3,894,652
Oswego Unit 6/(1)/
(Steam) Oil 1980 189 8,817
Nine Mile Point
Unit No. 2/(2)/
(Steam) Nuclear 1988 158 1,224,892
Station No. 9
(Gas Turbine) Gas 1969 14 465
Station 5
(Hydro) Water 1917 39 173,487
5 Other Stations
(Hydro) Water 1906-1960 8 54,380
-------- ---------
7,013,215
Pumped Storage /(3)/ 238,900
Less: energy for pumping (358,350)
---------
1,239 6,893,765
======== =========
</TABLE>
(1) Represents 24% share of jointly-owned facility.
(2) Represents 14% share of jointly-owned facility.
(3) Owned and operated by the Power Authority.
<PAGE>
13
The Company owns 147 distribution substations having an aggregate
rated transformer capacity of 2,149,754 Kva, of which 138, having an aggregate
rated capacity of 1,970,588 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 72,881 line
transformers with a capacity of 2,903,304 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
16,262 circuit miles of overhead lines, approximately 3,857 circuit miles of
underground lines and 353,220 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 4,257 miles of gas mains and
292,392 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 475,000 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.
<PAGE>
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, 1997.
Item 4-A. EXECUTIVE OFFICERS OF THE REGISTRANT
Age Positions, Offices and Business Experience
Name 1/1/98 1993 to date
- ---- ------ --------------------------------------------
Thomas S. Richards 54 Chairman of the Board, President and Chief
Executive Officer - January 1998 to date.
President and Chief Operating Officer - March
1996 to December 1997.
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 - January, 1993 to October, 1993.
Michael J. Bovalino 42 President, Energetix, Inc (a wholly owned subsidiary
of the Company) January 1998 to date.
Senior Vice President, Energy Services - January 1997
to December 1997.
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.
Robert E. Smith 60 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 -
1993 to August, 1994.
<PAGE>
15
Age Positions, Offices and Business Experience
Name 1/1/98 1993 to date
- ---- ------ -------------------------------------------
J. Burt Stokes 54 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.
Michael T. Tomaino 60 Senior Vice President and General Counsel - October,
1997 to Date.
Vice President, General Counsel and Secretary
for Goulds Pumps, Inc., 300 Willowbrook Office Park,
Fairport, NY 14450 prior to joining the Company.
William J. Reddy 50 Controller - May, 1997 to Date.
Group Manager, Public Affairs Services - January
1995 to April 1997.
Division Manager, Public Affairs Services - October
1994 to January 1995.
Department Manager, Forecasts and Budgets -
1993 to September 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.
<PAGE>
16
PART II
Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
COMMON STOCK AND DIVIDENDS
<TABLE>
<CAPTION>
- ------------------------------------------------------ --------------------------------------------------
Earnings/Dividends 1997 1996 1995 Shares/Shareholders 1997 1996 1995
- ------------------ ------- ------- ------- ------------------- ------ ------ ------
<S> <C> <C> <C> <C> <C> <C> <C>
Earnings per share Number of shares (000's)
- basic $ 2.30 $ 2.32 $ 1.69 Weighted average - basic 38,853 38,762 38,113
- diluted $ 2.30 $ 2.32 $ 1.69 - diluted 38,909 38,762 38,113
Dividends paid Actual number at
per share $ 1.80 $ 1.80 $ 1.80 December 31 38,862 38,851 38,453
Number of shareholders
at December 31 31,337 33,675 35,356
- ------------------------------------------------------ --------------------------------------------------
</TABLE>
TAX STATUS OF CASH DIVIDENDS
Cash dividends paid in 1997, 1996 and 1995 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 level of future cash
dividend payments will be dependent upon the Company's future earnings, its
financial requirements and other factors. 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 1998, the Company paid a
cash dividend of $.45 per share on its Common Stock. The January 1998 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".
<TABLE>
<CAPTION>
Common Stock - Price Range 1997 1996 1995
- -------------------------- -------- ------ ------
<S> <C> <C> <C>
High
1st quarter 20 3/8 23 3/4 23
2nd quarter 21 7/16 21 7/8 22 5/8
3rd quarter 24 15/16 21 3/8 24 1/8
4th quarter 34 1/2 19 5/8 24 1/8
Low
1st quarter 18 7/8 21 1/4 20 3/8
2nd quarter 18 19 7/8 20 1/8
3rd quarter 20 5/8 18 20
4th quarter 23 3/4 17 7/8 22 3/8
At December 31 34 19 1/8 22 5/8
</TABLE>
<PAGE>
17
ITEM 6 - SELECTED FINANCIAL DATA
CONSOLIDATED SUMMARY OF OPERATIONS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1997 1996* 1995* 1994*
- --------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Operating Revenues
Electric $679,473 $690,883 $696,582 $658,148
Gas 336,309 346,279 293,863 326,061
------------ ------------ ------------ ------------
1,015,782 1,037,162 990,445 984,209
Electric sales to other utilities 20,856 16,885 25,883 16,605
------------ ------------ ------------ ------------
Total Operating Revenues 1,036,638 1,054,047 1,016,328 1,000,814
Operating Expenses
Fuel Expenses
Fuel for electric generation 47,665 40,938 44,190 44,961
Purchased electricity 28,347 46,484 54,167 37,002
Gas purchased for resale 196,579 202,297 167,762 194,390
------------ ------------ ------------ ------------
Total Fuel Expenses 272,591 289,719 266,119 276,353
------------ ------------ ------------ ------------
Operating Revenues Less Fuel Expenses 764,047 764,328 750,209 724,461
Other Operating Expenses
Operations excluding fuel expenses 268,474 266,094 259,207 241,672
Maintenance 46,635 47,063 49,226 55,069
Depreciation and amortization 116,522 105,614 91,593 87,461
Taxes - local, state and other 121,796 126,868 133,895 129,778
Federal income tax - current 69,812 65,757 65,368 35,658
- deferred (4,533) 3,744 847 25,587
------------ ------------ ------------ ------------
Total Other Operating Expenses 618,706 615,140 600,136 575,225
------------ ------------ ------------ ------------
Operating Income 145,341 149,188 150,073 149,236
Other (Income) and Deductions
Allowance for other funds used during
construction (351) (684) (585) (396)
Federal income tax (3,704) (3,450) (16,948) (16,259)
Regulatory disallowances - - 26,866 600
Pension Plan Curtailment - - - 33,679
Other, net 3,308 (712) 9,631 (923)
------------ ------------ ------------ ------------
Total Other (Income) and Deductions (747) (4,846) 18,964 16,701
Interest Charges
Long term debt 44,615 48,618 53,026 53,606
Short term debt 47 21 398 1,808
Other, net 6,629 9,307 8,658 4,758
Allowance for borrowed funds used during
construction (563) (1,423) (2,901) (2,012)
------------ ------------ ------------ ------------
Total Interest Charges 50,728 56,523 59,181 58,160
Net Income 95,360 97,511 71,928 74,375
Dividends on Preferred Stock
at required rates 5,805 7,465 7,465 7,369
------------ ------------ ------------ ------------
Earnings Applicable to Common Stock $89,555 $90,046 $64,463 $67,006
============ ============ ============ ============
Earnings per Common Share - Basic $2.30 $2.32 $1.69 $1.79
Earnings per Common Share - Diluted $2.30 $2.32 $1.69 $1.79
Cash Dividends Declared per Common Share $1.80 $1.80 $1.80 $1.77
</TABLE>
* Reclassified for comparative purposes.
ITEM 6 - SELECTED FINANCIAL DATA
CONSOLIDATED SUMMARY OF OPERATIONS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1993* 1992
- ---------------------------------------------------------------------------------------------------
<S> <C> <C>
Operating Revenues
Electric $638,955 $608,267
Gas 293,708 261,724
------------ ------------
932,663 869,991
Electric sales to other utilities 16,361 25,541
------------ ------------
Total Operating Revenues 949,024 895,532
Operating Expenses
Fuel Expenses
Fuel for electric generation 45,871 48,376
Purchased electricity 31,563 29,706
Gas purchased for resale 166,884 141,291
------------ ------------
Total Fuel Expenses 244,318 219,373
------------ ------------
Operating Revenues Less Fuel Expenses 704,706 676,159
Other Operating Expenses
Operations excluding fuel expenses 240,342 226,624
Maintenance 61,693 62,720
Depreciation and amortization 84,177 85,028
Taxes - local, state and other 126,892 124,252
Federal income tax - current 33,453 36,101
- deferred 15,877 7,490
------------ ------------
Total Other Operating Expenses 562,434 542,215
------------ ------------
Operating Income 142,272 133,944
Other (Income) and Deductions
Allowance for other funds used during
construction (153) (164)
Federal income tax (9,827) (4,195)
Regulatory disallowances 1,953 8,215
Pension Plan Curtailment 8,179 -
Other, net 2,113 (6,155)
------------ ------------
Total Other (Income) and Deductions 2,265 (2,299)
Interest Charges
Long term debt 56,451 60,810
Short term debt 1,487 1,950
Other, net 5,220 5,228
Allowance for borrowed funds used during
construction (1,714) (2,184)
------------ ------------
Total Interest Charges 61,444 65,804
Net Income 78,563 70,439
Dividends on Preferred Stock
at required rates 7,300 8,290
------------ ------------
Earnings Applicable to Common Stock $71,263 $62,149
============ ============
Earnings per Common Share - Basic $2.00 $1.86
Earnings per Common Share - Diluted $2.00 $1.86
Cash Dividends Declared per Common Share $1.73 $1.69
</TABLE>
* Reclassified for comparative purposes.
<PAGE>
18
CONDENSED CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
(Thousands of Dollars) At December 31 1997 1996 1995 * 1994 *
<S> <C> <C> <C> <C>
Assets
Utility Plant $3,234,077 $3,159,759 $3,068,103 $2,981,151
Less: Accumulated depreciation and
amortization 1,714,368 1,569,078 1,518,878 1,423,098
---------- ----------- ----------- -----------
1,519,709 1,590,681 1,549,225 1,558,053
Construction work in progress 74,018 69,711 121,725 128,860
---------- ----------- ----------- -----------
Net utility plant 1,593,727 1,660,392 1,670,950 1,686,913
Current Assets 242,371 250,461 292,596 236,519
Investment in Empire - - 38,879 38,560
Deferred Debits 432,191 450,623 453,726 484,962
---------- ----------- ----------- -----------
Total Assets $2,268,289 $2,361,476 $2,456,151 $2,446,954
========== =========== =========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization
Long term debt $587,334 $646,954 $716,232 $735,178
Preferred stock redeemable at option
of Company 47,000 67,000 67,000 67,000
Preferred stock subject to mandatory
redemption 35,000 45,000 55,000 55,000
Common shareholders' equity:
Common stock 699,031 696,019 687,518 670,569
Retained earnings 109,313 90,540 70,330 74,566
---------- ----------- ----------- -----------
Total common shareholders' equity 808,344 786,559 757,848 745,135
---------- ----------- ----------- -----------
Total Capitalization 1,477,678 1,545,513 1,596,080 1,602,313
---------- ----------- ----------- -----------
Long Term Liabilities (Department
of Energy) 96,726 93,752 90,887 87,826
Current Liabilities 189,317 158,217 182,338 181,327
Deferred Credits and Other Liabilities 504,568 563,994 586,846 575,488
---------- ----------- ----------- -----------
Total Capitalization and Liabilities $2,268,289 $2,361,476 $2,456,151 $2,446,954
========== =========== =========== ===========
</TABLE>
CONDENSED CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
(Thousands of Dollars) At December 31 1993 * 1992 *
<S> <C> <C>
Assets
Utility Plant $2,890,799 $2,798,581
Less: Accumulated depreciation and
amortization 1,335,083 1,253,117
----------- -----------
1,555,716 1,545,464
Construction work in progress 112,750 83,834
----------- -----------
Net utility plant 1,668,466 1,629,298
Current Assets 248,589 209,621
Investment in Empire 38,560 9,846
Deferred Debits 488,527 181,434
----------- -----------
Total Assets $2,444,142 $2,030,199
=========== ===========
CAPITALIZATION AND LIABILITIES
Capitalization
Long term debt $747,631 $658,880
Preferred stock redeemable at option
of Company 67,000 67,000
Preferred stock subject to mandatory
redemption 42,000 54,000
Common shareholders' equity:
Common stock 652,172 591,532
Retained earnings 75,126 66,968
----------- -----------
Total common shareholders' equity 727,298 658,500
----------- -----------
Total Capitalization 1,583,929 1,438,380
----------- -----------
Long Term Liabilities (Department
of Energy) 89,804 94,602
Current Liabilities 234,530 267,276
Deferred Credits and Other Liabilities 535,879 229,941
----------- -----------
Total Capitalization and Liabilities $2,444,142 $2,030,199
=========== ===========
</TABLE>
* Reclassified for comparative purposes.
<PAGE>
19
FINANCIAL DATA
<TABLE>
<CAPTION>
At December 31 1997 1996 1995 1994 1993 1992
------ ------ ------ ------ ------ ------
<S> <C> <C> <C> <C> <C> <C>
Capitalization Ratios (a) (percent)
Long-term debt 43.0 44.7 47.4 48.2 49.4 48.2
Preferred Stock 5.2 6.9 7.3 7.3 6.6 8.0
Common shareholders' equity 51.8 48.4 45.3 44.5 44.0 43.8
------ ------ ------ ------ ------ ------
Total 100.0 100.0 100.0 100.0 100.0 100.0
Book Value per Common Share - Year End $20.80 $20.24 $19.71 $19.78 $19.70 $18.92
Rate of Return on Average Common Equity (b)
(percent) 11.00 11.41 8.37 8.92 10.25 9.94
Embedded Cost of Senior Capital (percent)
Long-term debt 7.32 7.33 7.38 7.40 7.36 7.91
Preferred stock 5.80 6.26 6.26 6.26 6.69 6.98
Effective Federal Income Tax Rate (percent) 39.2 40.4 40.7 37.7 33.5 35.9
Depreciation Rate (percent) - Electric 3.12 2.99 2.76 2.69 2.62 2.69
- Gas 2.60 2.60 2.59 2.62 2.60 2.78
Interest Coverages
Before federal income taxes (incld. AFUDC) 4.06 3.82 2.95 2.98 2.87 2.62
(excld. AFUDC) 4.04 3.79 2.90 2.94 2.84 2.58
After federal income taxes (incld. AFUDC) 2.86 2.68 2.16 2.24 2.24 2.04
(excld. AFUDC) 2.84 2.65 2.10 2.20 2.21 2.00
Interest Coverages Excluding Non-Recurring
Items (c)
Before federal income taxes (incld. AFUDC) 4.06 3.82 3.66 3.55 3.03 2.74
(excld. AFUDC) 4.04 3.79 3.61 3.51 3.00 2.70
After federal income taxes (incld. AFUDC) 2.86 2.68 2.62 2.61 2.35 2.12
(excld. AFUDC) 2.84 2.65 2.57 2.57 2.32 2.08
</TABLE>
(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) 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).
<PAGE>
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 by reason of factors such as electric
and gas utility restructuring, future economic conditions, and developments in
the legislative, regulatory and competitive environments in which the Company
operates. Shown below is a listing of the principal items discussed.
Earnings Summary Page 20
Competition Page 21
PSC Competitive Opportunities Case Settlement
Business and Financial Strategy
PSC Position Paper on Nuclear Generation
FERC Open Transmission Orders
Gas Restructuring and PSC Negotiations
Prospective Financial Position
Rates and Regulatory Matters Page 27
1996 Electric Rate Settlement
1995 Gas Settlement
Flexible Pricing Tariff
Liquidity and Capital Resources Page 27
Capital and Other Requirements
Redemption of Securities
Financing
Results of Operations Page 30
Operating Revenues and Sales
Fossil Unit Ratings and Status
Operating Expenses
Dividend Policy Page 33
EARNINGS SUMMARY
Despite rate reductions in July 1996 and 1997, earnings applicable to
Common Stock were nearly unchanged in 1997 due, in part, to the increased
availability of the Company's Ginna nuclear generating facility following the
1996 refueling and steam generator replacement outage. Increased Company
generation allowed the Company to reduce purchased electric expense , while
increasing available power for customer consumption and resale. A decrease in
financing costs as a result of discretionary redemptions and refinancing
activities during the year also helped to increase earnings. In addition to
rate reductions, offsetting a gain in 1997 earnings were a warmer heating season
during the first quarter of the year coupled with a cooler summer which affected
air conditioning load.
Basic and dilutive earnings per share of $2.30 in 1997 are down two cents
compared to a year ago. In February 1997, the Financial Accounting Standards
Board issued Statement of Financial Accounting Standards No. 128 ("SFAS-128"),
"Earnings per Share," which changes the methodology of calculating earnings per
share. The Company adopted SFAS No. 128 during the fourth quarter of 1997. The
impact on earnings per share for prior periods is not material. A discussion of
the calculation of earnings per share is presented in Note 1 to the Notes to
Financial Statements.
Basic and dilutive earnings per share of $1.69 reported in 1995 reflect a
pretax reduction of $44.2 million, or $.75 per share net-of-tax, in connection
<PAGE>
21
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.
The impact of developing competition in the energy marketplace will affect
future earnings. The Competitive Opportunities Case Settlement (the
"Settlement", see description below) allows for a phase-in to open electric
markets while lowering customer prices and establishing an opportunity for
competitive returns on shareholder investments. The nature and magnitude of the
potential impact of the Settlement on the business of the Company will depend on
the availability of qualified energy suppliers, the degree of customer
participation and ultimate selection of an alternative energy supplier, the
Company's ability to be competitive by controlling its operating expenses, and
the Company's ultimate success in development of its unregulated business
opportunities as permitted under the Settlement.
Future earnings will also 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 year of the Settlement period, although no assurance
may be given.
COMPETITION
Overview. During 1996 and 1997, the Company, the Staff of the PSC, and
several other parties negotiated an agreement which was approved by the PSC in
November 1997. This agreement sets the framework for the introduction and
development of open competition in the electric energy marketplace and lasts
through the year 2002. Over this time, the way electricity is delivered to
customers will fundamentally change. In phases, the Company will open its
electric system to other suppliers. The system will be fully open to
competitors by July of 2001. These suppliers will compete to package and sell
energy and related services to customers. The Company and its subsidiaries will
be among the supplier choices. Competing suppliers will pay the Company a fee
to use its electric distribution system and the Company will remain responsible
for maintaining it and responding to most emergencies.
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. Through its "Competitive
Opportunities Proceeding," the PSC has embarked on a fundamental restructuring
of the electric utility industry in the State. Among other elements, the PSC's
goals included lower rates for consumers and increased customer choice in
obtaining electricity and other energy services.
The Company's proceeding was completed on November 26, 1997 with the PSC
approval of a Settlement Agreement among the Company, the PSC Staff and other
parties. The PSC's November 26, 1997 order of approval was confirmed by a full
Opinion and Order (No. 98-1) issued January 14, 1998.
Summary. The Settlement provides for a transition to competition during
its five-year term (July 1, 1997 through June 30, 2002) and establishes the
Company's electric rates for each annual period. A Retail Access Program will
be phased in, allowing customers to purchase electricity, and later electricity
and capacity commitments, from sources other than the Company. The Company will
be provided a reasonable opportunity to recover prudently incurred costs,
including those pertaining to generation and purchased power.
The Settlement also requires the Company to functionally separate its
component operations: distribution, generation, and retailing. Any unregulated
retail operations must be structurally separate from the regulated utility
functions but may be funded with up to $100 million. In addition, the Company
would have the option after receiving the necessary regulatory approvals to
establish a holding company structure. Although the Settlement provides
incentives for the sale of generating assets, it requires neither divestiture of
generating or other assets, nor write off of "stranded costs" (the above-market
costs, presumed to result from competition).
<PAGE>
22
The Company believes that the Settlement will not adversely affect its
eligibility to continue to apply Statement of Financial Accounting Standards No.
71 ("SFAS-71"), with the exception of certain "to-go costs" associated with non-
nuclear generation. If, contrary to the Company's view, such eligibility were
adversely affected, a material write-down of assets, the amount of which is not
presently determinable, could be required.
Rate Plan. Over the five year term of the Settlement, the cumulative rate
reductions will be as follows: Rate Year 1: $3.5 million; Rate Year 2: $12.8
million; Rate Year 3: $27.6 million; Rate Year 4: $39.5 million; and Rate Year
5: $64.6 million.
The Rate Plan permits the Company to offset against the foregoing total
reductions certain inflation-related expenses, and certain amounts related to a
power purchase agreement with Kamine/Besicorp Allegany L.P.(Kamine), including
seven-eighths of any difference between Kamine costs currently included in rates
and any increased amount resulting from enforcement of such agreement with any
balance not recovered during the term of the Settlement subject to deferral for
recovery after such term. The agreement is subject to litigation, as discussed
in Note 10 of the Notes to Financial Statements. In the event of a settlement
of the Kamine matter, the Settlement permits the Company to offset against rate
reductions, the following amounts: Rate Year 2, $3.5 million; Rate Year 3, $8.4
million; Rate Year 4 and continuing until Settlement payments are complete or
July 1, 2002, whichever is later, $10.5 million.
In the event that the Company earns a return on common equity in excess of
an effective rate of 11.50 percent over the entire five-year term of the
Settlement, 50 percent of such excess will be used to write down deferred costs
accumulated during the term. The other 50 percent of the excess will be used to
write down accumulated deferrals or investment in electric plant or Regulatory
Assets (which are deferred costs whose classification as an asset on the balance
sheet is permitted by SFAS-71). If certain extraordinary events occur,
including a rate of return on common equity below 8.5 percent or above 14.5
percent, or a pretax interest coverage below 2.5 times, then either the Company
or any other party to the Settlement would have the right to petition the PSC
for review of the Settlement and appropriate remedial action.
Retail Access. RG&E's Energy Choice Program will be available to all of its
customers, without regard to customer class, on an equal basis up to certain
usage caps. On July 1, 1998, customers whose electric loads represent
approximately 10 percent of the Company's total annual retail sales will be
eligible to purchase electricity (but not capacity commitments) from alternative
suppliers. On July 1, 1999, customers with 20 percent of total sales will be
eligible and as of July 1, 2000, 30 percent of total sales will be eligible. As
of July 1, 2001, all retail customers will be eligible to purchase energy and
capacity from alternative suppliers.
During the initial, energy only stage of the Retail Access Program, the
Company's distribution rate will be set by deducting 2.3 cents per kilowatt hour
("KWH") from its full service ("bundled") rates and Load Serving Entities acting
as retailers in the Company's service area will be entitled to purchase
electricity from the Company at a rate of 1.9 cents per KWH. During the energy
and capacity stage, the rate will generally equal the bundled rate less the cost
of the electric commodity and the Company's non-nuclear generating capacity.
These commodity and capacity costs, generally referred to as "contestable
costs," are estimated to be 3.2 cents per KWH, inclusive of gross receipts
taxes.
Generating Assets. The Company will not be required to divest any of its
generation facilities. To the extent that the Company sells any generating
assets during the term of the Settlement, gains on such sales will be shared
between the Company and customers. With regard to losses on such sales, the
Settlement acknowledges an intent that the Company will be permitted to recover
such losses through distribution rates during the term of the Settlement.
Future rate treatment is to be consistent with the principle that the Company is
to have a reasonable opportunity to recover such costs.
"To-go costs" of the Company's non-nuclear resources (i.e., capital costs
incurred after February 28, 1997, operation and maintenance expenses, and
property, payroll and other taxes) are to be recovered through the distribution
<PAGE>
23
access tariff. The fixed portion of To-Go Costs would be recovered in full
through the distribution access tariff until July 1, 1999 and subject to the
market thereafter in accordance with the phase-in schedule for the Retail Access
Program described above. The variable portion of non-nuclear to-go costs would
also be subject to the market in accordance with the phase-in Schedule described
above. Upon extension of eligibility for the Retail Access Program to all
retail customers on July 1, 2001, the Company would be authorized to modify its
distribution access rates, so as to hold constant the degree to which its to-go
costs are at risk for recovery through the market. Thus, while the recovery of
non-nuclear to-go Costs would continue to be through the market, recovery of
nuclear costs would remain recoverable through regulated rates. No change in
such treatment of nuclear facilities would be implemented prior to the PSC's
resolution of the issues raised in its Staff Report on nuclear generation (see
PSC Position Paper on Nuclear Generation). Shutdown and decommissioning costs
would be recovered during the term of the Settlement in a manner consistent with
past ratemaking treatment.
Pilot Program. Consistent with a PSC order issued June 23, 1997 in a
separate proceeding involving establishment of pilot programs for farmers and
food processors, the Settlement provides that the Company's Retail Access
Program will commence on February 1, 1998 for those groups within the Company's
service area.
Tariff Filing. On December 1, 1997, the Company submitted to the PSC its
proposed tariffs and a Distribution Operating Agreement to establish "Energy
Choice", the Company's proposed retail access program to implement the terms of
the Settlement. In an order issued January 21, 1998, the PSC approved certain
provisions of the December 1, 1997 tariff filing and required the Company to
revise others. In late January 1998 the Company filed revisions to the tariff
to incorporate the changes required by the PSC's order.
Miscellaneous. After approval of the Settlement becomes final and non-
appealable, the Company will withdraw legal appeals which challenge various PSC
Orders regarding the PSC Competitive Opportunities Proceeding, establishment of
a pilot program pursuant to those proceedings, and certain provisions of the
1996 Electric Rate Settlement.
The present Settlement supersedes the 1996 Rate Settlement. Various
incentive and penalty provisions in the 1996 Electric Rate Settlement are
eliminated.
BUSINESS AND FINANCIAL STRATEGY: THE COMPANY'S RESPONSE. Under the terms of
the Settlement, the Company will functionally separate its generation,
distribution, and regulated energy services businesses. As permitted by the
Settlement, the Company has established a separate unregulated subsidiary called
Energetix which will be able to compete for energy, energy services and products
both in and outside the Company's existing franchise service territory. The
Company has also developed an integrated financial strategy which includes new
business development initiatives and a Common Stock share repurchase program.
Energy Choice. Within the framework of the Energy Choice Program, the
Company will unbundle traditional utility services. Retail electric customers
in the Company's service territory will have the opportunity to purchase energy,
capacity, and retailing services from competitive energy service companies,
referred to as Load Serving Entities (LSEs). They may also continue to purchase
fully-bundled electric service from the Company under existing retail tariffs.
General Structure. Energy Choice adopts the "single-retailer" model for
the relationship between RG&E, the LSEs, and retail customers. Under the
"single-retailer" model the regulated utility's customer is the LSE, whose
customers are the retail customers. The relationship between the regulated
utility and retail customers is substantially eliminated. The LSE assumes
responsibility for providing its retail customers with bundled energy and
delivery services, and for virtually all related retailing functions, including
direct contact and communications with retail customers. With the exception of
transmission and distribution service, the LSE will procure for its customers,
or will itself create and provide them with, all necessary components of fully
bundled service on a competitive basis.
<PAGE>
24
Throughout the term of the Settlement, RG&E will continue to provide
regulated and fully bundled electric service under its retail service tariff to
customers who choose to continue with or return to such service, and to
customers to whom no competitive alternative is offered.
Until the development of a wholesale market for generating capacity, there
will be no suitable mechanism for the reallocation, from the regulated utility
to the LSE, of responsibility for ensuring adequate installed reserve capacity.
Accordingly, during the initial "Energy Only" stage of the Energy Choice
Program (July 1, 1998 to July 1, 1999), LSEs will be able to choose their own
sources of energy supply, while RG&E will provide to LSEs, and will be
compensated for, the generating capacity (installed reserve) needed to serve
their retail customers reliably. During the "Energy and Capacity" stage
commencing July 1, 1999, the LSEs will be able to select, and will be
responsible for procuring, generating capacity, as well as energy, to serve the
loads of their retail customers, and distribution charges will be accordingly
reduced as hereinafter described. If by July 1, 1998 there is not a functioning
Statewide energy and capacity market (see discussion under FERC Open
Transmission Orders), the Company may petition the PSC for deferral of the
scheduled commencement of the Energy and Capacity stage.
Summary. The availability of LSEs to serve eligible customers and how
quickly they decide to become involved cannot be determined. Likewise, the
Company is not able to predict the number of customers that may chose to no
longer be served under the Company's regulated tariffs.
The proposed tariffs for Energy Choice as filed by the Company are expected
to become effective February 1, 1998 for the pilot program. The PSC has not set
a decision-making date for the full-scale program. The Company is unable to
predict what final rules or regulations will ultimately be adopted by the PSC
for this program.
Unregulated Energy Services Company. It is part of the Company's financial
strategy to stimulate growth by entering into unregulated businesses. The first
step in this direction was the formation and operation of Energetix effective
January 1, 1998. Energetix is an unregulated subsidiary of the Company that will
bring energy products and services to the marketplace both within and outside
the Company's franchise area.
The Settlement approved by the PSC in November allows for the investment of
up to $100 million in unregulated businesses during the next five years. During
1998, the Company expects to determine the actual level of the initial
investments to be made in unregulated business opportunities.
On July 1, 1997 the Company and Energetix filed with the Federal Energy
Regulatory Commission (FERC) seeking authorization to engage in the wholesale
sale of electric energy and capacity at market-based rates. These applications
were accepted by FERC on September 12, 1997. The Company must seek separate
authorization in order to sell electric energy to Energetix at market-based
rates.
Stock Repurchase Plan. In December 1997 the Company's Board of Directors
approved a Stock Repurchase Plan. This plan, which is subject to approval by
the PSC, provides for the repurchase over the next three years of up to 4.5
million shares of Common Stock, representing approximately 11.5 percent of the
Company's outstanding shares of Common Stock at December 31, 1997. The Company
expects a PSC decision in early 1998.
Nuclear Operating Company. In October 1996, the Company and Niagara Mohawk
Power Corporation (Niagara) announced plans to establish a nuclear operating
company to be known as the New York Nuclear Operating Company (NYNOC). Since
that time NYNOC has been organized as a New York Limited Liability Company and
the Consolidated Edison Company of New York and New York Power Authority have
announced their desire to move forward with the Company and Niagara with plans
to implement NYNOC. It is envisioned that NYNOC would eventually assume
responsibility for operation of all the nuclear plants in New York State,
including the Company's totally owned Ginna Nuclear Plant and jointly owned Nine
Mile Two. The Company believes that NYNOC could contribute to maintaining a
high level of operational performance, contribute to continued satisfactory
Nuclear
<PAGE>
25
Regulatory Commission (NRC) compliance, provide opportunities for continued cost
reduction and provide the basis for satisfactory economic regulation by the PSC.
Various groups are now involved in the detailed studies and analyses required
before a definitive decision to proceed with NYNOC can be made. The organizing
utilities have submitted comments on the PSC Staff position paper on nuclear
generation (discussed below under the heading PSC Position Paper on Nuclear
Generation) noting that the Staff proposal would nullify the potential benefits
of NYNOC.
PSC POSITION PAPER ON NUCLEAR GENERATION. On August 27, 1997, the PSC
requested comments from interested parties on a PSC Staff position paper
concerning the treatment of nuclear generation after a transition period. The
Staff paper concludes that (1) nuclear generation should operate on a
competitive basis, (2) sale of generation plants at auction to third parties is
the preferred means of determining market value and offers the greatest
potential for mitigation of stranded costs and the elimination of anti-
competitive subsidies, and (3) where third party sales are not feasible, "to-go"
costs (fuel, labor and other operating costs, prospective capital additions,
property taxes and insurance) must be recovered in the wholesale market price of
power.
On October 15, 1997, the Company and four other utilities jointly responded
to the PSC. The utilities believe that the inherent operating characteristics of
nuclear generation and the implications of NRC regulation require that nuclear
plants have access to an adequate revenue stream and that such plants should be
treated for dispatch purposes as baseload, must run units. The utilities urge
the PSC to adopt a process that would enable all parties to fully develop the
necessary facts and analyses and to invite the NRC to participate in addressing
the future of nuclear generation in New York State. Certain other parties have
filed comments on the position paper, some of which oppose full recovery of
"stranded costs" that could result from sales of plants at less than book costs.
The Company is unable to predict the outcome of the PSC's consideration.
FERC OPEN TRANSMISSION ORDERS AND COMPANY FILINGS. 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. 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. On March 6, 1997,
the Company reached a settlement in principle with the other parties respecting
rate issues. FERC approval of the settlement was granted on June 25, 1997.
On January 31, 1997, the utilities filed a "Comprehensive Proposal To
Restructure the New York Wholesale Electric Market" with the FERC. As proposed,
the existing New York Power Pool (NYPP) will be dissolved and an independent
system operator (ISO) will administer a state-wide open access tariff and
provide for the short-term reliable operation of the bulk power system in the
state. In addition to proposing a FERC-endorsed ISO, the proposal calls for
creation of a New York Power Exchange and a New York State Reliability Council.
An additional supplemental filing with FERC was made on December 19,1997 which
lays out a specific timeframe for the implementation of a competitive wholesale
electricity market in New York State. The utilities have requested FERC
approval of their restructuring plan no later than March 31, 1998, which would
allow the ISO to be operational by June 30, 1998. The timetable for retail
competition will be determined for each utility in accordance with individual
settlements in the Competitive Opportunities Proceeding.
Significant changes to pricing procedures now in effect within NYPP are
expected, 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 ultimately adopted by FERC will
have, if any, on future operations or the financial condition of the Company.
GAS RESTRUCTURING AND PSC NEGOTIATIONS. In March 1996 the PSC issued an
Order and approved utility restructuring plans designed to open up the local
<PAGE>
26
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. During a three-year phase-in period 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. The PSC has indicated that it will address the issue of how the
costs of such capacity would be recovered after the three-year period during the
third year of the phase-in period. The PSC Staff has recently issued a position
paper on The Future of the Natural Gas Industry in which the Staff proposes that
local distribution companies (such as the Company) exit the merchant function in
five years. Treatment of existing pipeline capacity contracts and Provider of
Last Resort responsibilities are substantial issues to be worked out between the
PSC, the local gas distribution companies and other stakeholders. See Note 10 of
the Notes to Financial Statements for further information about the PSC gas
restructuring proceedings and the PSC Staff position paper.
Gas customers have had a choice of suppliers since November 1, 1996. Under
separate transportation tariffs, the Company distributes the gas and charges 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. Through
December 31, 1997, 150 customers were being served under this service.
In July 1997, the Company commenced negotiations with the PSC Staff and
other parties with the objective of developing a multi-year settlement of issues
pertaining to the Company's gas business that would take effect upon expiration
of the current 1995 Gas Settlement (see Rates and Regulatory Matters) on June
30, 1998. A further objective of these negotiations is to maximize the
efficiencies of the entire business by structuring a settlement that will be as
consistent as possible with the provisions of the Settlement in the Competitive
Opportunities Proceeding, as discussed earlier. Negotiations are at an early
stage; accordingly, the Company can make no prediction as to their outcome.
COMPETITION AND THE COMPANY'S PROSPECTIVE FINANCIAL POSITION. 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 SFAS-71. These deferred costs are shown as Regulatory
Assets on the Company's Balance Sheet and a discussion and summarization of such
Regulatory Assets is presented in Note 10 of the Notes to Financial Statements.
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. Estimates of
such strandable assets are highly sensitive to the competitive wholesale market
price assumed in the estimation. In a competitive natural gas market,
strandable assets would arise where customers migrate away from dependence on
the Company for full service, leaving the Company with surplus pipeline and
storage capacity, as well as natural gas supplies, under contract. A discussion
of strandable assets is presented in Note 10 of the Notes to Financial
Statements.
At December 31, 1997 the Company believes that its regulatory and
strandable assets, if any, are not impaired and are probable of recovery. The
Settlement in the Competitive Opportunities Proceeding does not impair the
opportunity of the Company to recover its investment in these assets. However,
the PSC has published a Staff paper to address issues surrounding nuclear
generation, including the determination of fair market value for facilities
after a five year restructuring transition period. It appears that the PSC may
seek to apply similar principles to other types of generating facilities. A
determination in this proceeding could have an impact on strandable assets.
<PAGE>
27
RATES AND REGULATORY MATTERS
1996 ELECTRIC 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. The
Competitive Opportunities Settlement (Settlement) supersedes the 1996 Rate
Settlement. A rate reduction for the first rate year under the Settlement of 0.5
percent ($3.5 million) commencing July 1, 1997 is equal to the previously
approved planned reduction under the 1996 Rate Settlement. After approval of the
Settlement becomes final and non-appealable, the Company will terminate its
petition seeking judicial review of the 1996 Rate Settlement.
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 ending in mid-1998, gas rate
increases exclusive of the cost of natural gas and certain cost increases
imposed by interstate pipelines.
- - The Company has agreed not to charge customers for pipeline capacity costs
in 1996, 1997 and 1998 of $22.5 million, $24.5 million, and $27.2 million,
respectively. The Company may sell its excess transportation capacity in
the market under FERC rules.
- - The Company agreed to write off excess gas pipeline capacity and other
costs incurred through 1995.
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 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' periods ending October 31, 1997 and October
31, 1996, thereby avoiding negative financial impacts for those periods. The
Company believes that it will also be successful in meeting the Settlement
targets in the remaining year of the Settlement period, although no assurance
may be given.
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. Pursuant to the terms of
the Settlement under the Competitive Opportunities Proceeding, 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 contracts represent approximately 42 percent of the
Company's revenues from its commercial and industrial customers. The Company
has not experienced any significant customer loss due to competitive alternative
arrangements. Certain provisions of a flexible rate contract with the
University of Rochester have been challenged by the Antitrust Division of the
United States Department of Justice as discussed in Note 10 to the Financial
Statements under the heading Litigation.
LIQUIDITY AND CAPITAL RESOURCES
Cash flow, mainly from operations, provided the funds for construction
expenditures, debt reductions, redemption of Preferred Stock and the payment of
dividends during 1997 (see Consolidated Statement of Cash Flows).
<PAGE>
28
CAPITAL AND OTHER REQUIREMENTS. The Company's capital requirements
relate primarily to expenditures for energy delivery, including electric
transmission and distribution facilities and gas mains and services as well as
nuclear fuel, electric production and the repayment of existing debt. In 1996
the Company completed replacement of the two steam generators at the Ginna
Nuclear Plant which resulted in improved plant efficiency. The Company spent
approximately $46 million on this project in 1996 and $29 million in 1995. The
Company has no plans to install additional baseload generation.
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 Company
has no other long-term obligations to purchase energy from Qualifying
Facilities.
Year 2000 Computer Issues. As the year 2000 approaches many companies
face a potentially serious information systems (computer) problem because most
software application and operational programs written in the past will not
properly recognize calendar dates beginning with the year 2000. At this time,
the Company believes that the problem is being addressed properly to prevent any
adverse operational or financial impacts. The Company believes it will incur
approximately $15 million of costs through January 1, 2000, associated with
making the necessary modifications identified to date. Total costs incurred in
1997 were approximately $1.4 million.
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 $1 million in 1995, $49 million
in 1996, and approximately $152 million in 1997. Included in discretionary
redemptions for 1997 were nearly $102 million of tax-exempt securities which
were refinanced with new multi-mode tax-exempt bonds as discussed under
Financing.
<PAGE>
29
CAPITAL REQUIREMENTS - SUMMARY. Capital requirements for the three-
year period 1995 to 1997 and the current estimate of capital requirements
through 2000 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 outstanding
long-term securities.
<TABLE>
<CAPTION>
Capital Requirements
- -------------------------------------------------------------------------------
Actual Projected
1995 1996 1997 1998 1999 2000
Type of Facilities (Millions of Dollars)
- -------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Electric Property
Production $ 48 $ 57 $ 9 $ 19 $ 17 $ 13
Energy Delivery 25 23 28 43 32 28
---- ---- ---- ---- ---- ----
Subtotal 73 80 37 62 49 41
Nuclear Fuel 17 16 19 15 16 27
---- ---- ---- ---- ---- ----
Total Electric 90 96 56 77 65 68
Gas Property 14 17 22 23 17 18
Common Property 4 6 9 24 18 6
---- ---- ---- ---- ---- ----
Total 108 119 87 124 100 92
Carrying Costs
Allowance for Funds Used During
Construction 3 2 1 1 1 1
---- ---- ---- ---- ---- ----
Total Construction Requirements 111 121 88 125 101 93
Securities Redemptions, Maturities
and Sinking Fund Obligations* 1 67 182 40 10 30
---- ---- ---- ---- ---- ----
Total Capital Requirements $112 $188 $270 $165 $111 $123
---- ---- ---- ---- ---- ----
</TABLE>
* Excludes prospective refinancings.
FINANCING. Capital requirements in 1997, including the discretionary
redemption of $49.7 million of securities, were satisfied primarily with
internally generated funds. In addition, the Company at its option refinanced
$101.9 million of outstanding tax-exempt securities with the proceeds from the
sale on August 19, 1997 of $101.9 million of New York State Energy Research and
Development Authority (NYSERDA) multi-mode tax-exempt bonds due August 1, 2032.
Interest rates on these bonds may be set weekly or may be set for varying
periods based on market conditions at the time. The weighted average interest
rate on these bonds was 3.65 percent for 1997.
On September 16, 1997, the Company completed arrangements for the
delivery in September 1998 of $25.5 million of 5.95% NYSERDA tax-exempt bonds
due September 1, 2033. Proceeds will be used to redeem an issue of tax-exempt
first mortgage bonds which is not redeemable until December 1998.
Under the Company's Performance Stock Option Plan, options for 403,605
shares of Common Stock became exercisable due to Common Stock market price
performance during 1997. During 1997, Common Stock shares outstanding increased
by 10,883 shares as a result of those options which were actually exercised
during the year. These were the only shares of Common Stock issued by the
Company during 1997.
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. Moreover, in 1998 the
Company may begin funding a stock repurchase program and investments in
unregulated businesses as discussed under Competition.
<PAGE>
30
Capital and other cash requirements during 1998 are anticipated to be
satisfied primarily from a combination of internally generated funds and the use
of short-term credit arrangements. The Company may refinance maturing long-term
debt and Preferred Stock obligations during 1998 depending on prevailing
financial market conditions.
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. For information with respect to short-term borrowing
arrangements and limitations, see Note 9 of the Notes to Financial Statements.
As financial market conditions warrant, the Company may also, from time to time,
redeem higher cost senior securities.
RESULTS OF OPERATIONS
The following financial review identifies the causes of significant
changes in the amounts of revenues and expenses, comparing 1997 to 1996 and 1996
to 1995. The Notes to Financial Statements contain additional information.
OPERATING REVENUES AND SALES. Operating revenues in 1997 were lower
than 1996 with the effect of electric base rate decreases in July 1996 and 1997
and lower therm sales of gas due to milder weather than last year partially
offset by higher customer electric kilowatt-hour sales resulting from increased
customers and higher electric sales to other utilities. Despite lower operating
revenues, operating revenues less fuel expenses were nearly unchanged reflecting
primarily a decline in purchased electricity expense as a result of increased
availability of the Company's generating facilities.
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. Compared to a
year earlier, weather in the Company's service area was 9.0 percent warmer
during the first three months of 1997 and 1.1 percent warmer for the entire year
on a calendar month heating degree day basis. In contrast, weather during 1996
was 7.1 percent colder than 1995 on a calendar month heating degree day basis.
With elimination of a 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. Cooler than normal summer weather during
1997 and 1996 hampered the demand for air conditioning usage, with a more
pronounced effect in 1997 with the 1997 weather being approximately 27 percent
cooler than 1996.
Compared with a year earlier, kilowatt-hour sales of energy to retail
customers were up 1.2 percent in 1997, following a 0.3 percent increase in 1996.
Sales to commercial customers achieved the largest gain in 1997. Sales to
industrial customers led the increase in 1996 compared to a year earlier and
were driven by one large industrial customer who purchased more electric power
as an alternative to power produced at its own plant. Decreased electric demand
for air conditioning usage caused by cooler summer weather had an impact on
kilowatt-hour sales in 1996 and 1997.
Fluctuations in revenues from electric sales to other utilities are
generally related to the Company's customer energy requirements, the wholesale
energy market, availability of transmission, and the availability of electric
generation from Company facilities. Revenues from electric sales to other
utilities rose in 1997 due to increased sales resulting from greater
availability of our combined nuclear and fossil generation, a favorable
wholesale market in the second half of the year, and increased marketing of
available capacity. In contrast to 1997, revenues from sales to other electric
utilities declined in 1996 reflecting decreased kilowatt-hour sales to such
utilities and less generation from the Company's Ginna Nuclear Plant.
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 16.6 million dekatherms in 1997 and 16.8
million dekatherms in 1996. These purchases by eligible customers have caused
decreases in Company revenues, with offsetting decreases in purchased gas
<PAGE>
31
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 retail 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 were down 4.1 percent in 1997,
after increasing nearly eight percent in 1996. 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 about 1.5 percent in 1997 over 1996, while non-residential
sales, including gas transported, would have increased approximately two percent
in 1997. The average use per residential gas customer, when adjusted for normal
weather conditions, showed a modest decrease in 1996 and 1997.
FOSSIL UNIT RATINGS AND STATUS. Several of the Company's fossil-
fueled generating units have been temporarily derated since February 1997 to
maintain acceptable opacity levels while the Company investigates additional
engineering solutions to address the opacity of the Units' emissions ( see Note
10 of the Notes to Financial Statements under the heading "Environmental
Matters, Opacity Issue"). The financial impact of the deratings includes the
lost opportunity associated with energy sales and, at times, the need to make
additional purchases to meet system requirements. While the deratings have
decreased earnings, and will continue to do so, the amount is not expected to be
material.
The NYPP is in the process of evaluating new rules for its system load
regulation. Opacity limitations are expected to reduce the ability of the
Company to react to changes in load and provide system load regulation services
when called upon by the NYPP, resulting in additional costs. Depending on the
new NYPP requirements, and whether the deratings remain in effect, the revised
rules could result in the Company having to purchase additional regulation
services which may cost between $500,000 and $2,500,000 annually. The Company
intends to make a $2.7 million capital upgrade to the precipitator of one of its
fossil-fueled generating units which is expected to remove a substantial portion
of the opacity exceedance which led to the derating.
On January 21, 1998 the Company decided to retire Beebee Station by
mid-1999. Factors such as the plant's age, location in an area no longer
consistent with the surrounding development, lack of a rail/coal delivery system
and more stringent clean air regulations made the plant uneconomical in the
developing competitive generation business. The retirement of Beebee Station is
not expected to have a material effect on the Company's financial position or
results of operations. The plant will be fully depreciated at the time of
retirement. The Settlement provides that all prudently incurred incremental
costs associated with the shut down and decommissioning of the plant are
recoverable through the Company's distribution access tariff. The electric
capability and energy currently provided by the plant is expected to be replaced
by purchased power as needed.
On December 1, 1997 Niagara announced a plan to sell its fossil-fueled
and hydroelectric generating stations by auction in 1998. This plan was agreed
to as part of Niagara's Power Choice Settlement currently under review by the
PSC. The Company intends to include its 24 percent share of the Oswego Steam
Station Unit 6 (Oswego 6) for sale as part of Niagara's auction. Any gains or
losses realized by the Company from the sale of its share of Oswego 6 would be
treated in accordance with the terms of the Settlement under the Competitive
Opportunities Proceeding.
OPERATING EXPENSES
Energy Costs - Electric. Higher fuel expense for electric generation
in 1997 compared with a year earlier reflects increased generation from both
fossil and nuclear-fueled plants. Total Company electric generation was up
approximately 21 percent in 1997 over 1996. For the 1996 comparison period,
lower electric fuel costs resulted from less electric generation. The fuel cost
adjustment clause has been eliminated effective July 1, 1996. Company
<PAGE>
32
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. Increased
availability and efficiencies following the 1996 installation of new steam
generators at the Ginna nuclear plant resulted in lower kilowatt-hour purchases
of electricity in 1997 which led to a decline in purchased electric power
expense. Despite an increase in kilowatt-hours purchased in 1996, electric
purchased power expense was also down in 1996 reflecting, in part, lower
purchases from the higher-cost Kamine facility as discussed below.
Under a contract with Kamine, the Company has been required to
purchase unneeded energy at uneconomical rates (see Note 10 of the Notes to
--
Financial Statements). The Company purchased 337 thousand megawatt-hours of
energy from Kamine at a total price of $16.6 million in 1995. 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 compared to 1995.
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 the Empire State Pipeline (Empire) and the CNG Transmission Corporation (CNG)
pipeline systems, as well as to upstream pipeline transportation and storage
services. The combined CNG and Empire transportation capacity is adequate to
meet the Company's current requirements.
For the 1997 comparison period, gas purchased for resale expense
declined driven by a reduced volume of purchased gas resulting from a warmer
heating season. Higher commodity costs and increased volumes of purchased gas
caused an increase in gas purchased for resale expense in 1996 compared to 1995.
Operations Excluding Fuel Expenses. For the 1997 comparison period,
the increase in operations excluding fuel expenses reflects mainly higher
outside services expenses, recognition of obsolete and unproductive materials
inventory, storm costs, and regulatory compliance costs partially offset by
lower payroll costs and decreased expense associated with uncollectible
accounts. For the 1996 comparison period, the increase in operations excluding
fuel expenses 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. An additional expense accrual
for doubtful accounts increased operating expenses by $15.0 million in 1995.
The Company is continuing to take aggressive steps to improve its
collection efforts. Uncollectible expense in 1997 was $18 million, compared
with $20 million in 1996. In 1995, uncollectible expense was $23 million.
For both comparison periods, the increase in depreciation expense
reflects 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.
Taxes Charged To Operating Expenses. Local, state and other taxes
decreased in 1997 reflecting mainly lower property taxes due to decreases in
assessments and/or rates and lower revenue taxes due to decreases in revenues
and the New York State revenue tax surcharge rate. The decrease in these taxes
for 1996 reflects mainly lower property taxes due to decreases in assessments.
The decrease in federal income tax in 1997 reflects mainly the
reversal of a prior provision for the in-service date of Nine Mile Two as a
result of an agreement reached with the Internal Revenue Service.
<PAGE>
33
OTHER STATEMENT OF INCOME ITEMS. For the 1996 comparison period, the
variation in non-operating federal income tax reflects mainly accounting
adjustments related to regulatory disallowances.
Recorded under the caption Other Income and Deductions is the
recognition of regulatory disallowances in connection with the 1995 Gas
Settlement (see Rates and Regulatory Matters).
Other (Income) and Deductions, Other--net decreased in 1997 due mainly
to recognition of expense associated with management performance awards and the
Company's Performance Stock Option Plan. 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.
Both mandatory redemptions and the optional redemptions of certain
higher-cost long-term debt have helped to reduce long-term debt interest expense
over the three-year period 1995-1997. Compared to the prior year, the average
short-term debt outstanding was up slightly in 1997 following a decrease in
1996.
Preferred Stock dividends decreased in 1997 due to the Company's
discretionary redemption in April of its 7.50% Preferred Stock, Series N and the
mandatory sinking fund redemption of its 7.45% Preferred Stock, Series S in
September.
DIVIDEND POLICY. The level of future cash dividend payments on Common
Stock will be dependent upon the Company's future earnings, its financial
requirements, and other factors. 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.
<PAGE>
34
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, 1997.
Consolidated Statement of Retained Earnings for each of the three years
ended December 31, 1997.
Consolidated Balance sheet at December 31, 1997 and 1996.
Consolidated Statement of Cash Flows for each of the three years ended
December 31, 1997.
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.
<PAGE>
35
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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, 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 23, 1998
<PAGE>
36
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1997 1996 1995
- --------------------------------------------------------- --------- ---------- ----------
<S> <C> <C> <C>
Operating Revenues
Electric $679,473 $690,883 $696,582
Gas 336,309 346,279 293,863
---------- ---------- ----------
1,015,782 1,037,162 990,445
Electric sales to other utilities 20,856 16,885 25,883
---------- ---------- ----------
Total Operating Revenues 1,036,638 1,054,047 1,016,328
---------- ---------- ----------
Operating Expenses
Fuel Expenses
Fuel for electric generation 47,665 40,938 44,190
Purchased electricity 28,347 46,484 54,167
Gas purchased for resale 196,579 202,297 167,762
---------- ---------- ----------
Total Fuel Expenses 272,591 289,719 266,119
---------- ---------- ----------
Operating Revenues Less Fuel Expenses 764,047 764,328 750,209
Other Operating Expenses
Operations excluding fuel expenses 268,474 266,094 259,207
Maintenance 46,635 47,063 49,226
Depreciation and amortization 116,522 105,614 91,593
Taxes - local, state and other 121,796 126,868 133,895
Federal income tax 65,279 69,501 66,215
---------- ---------- ----------
Total Other Operating Expenses 618,706 615,140 600,136
---------- ---------- ----------
Operating Income 145,341 149,188 150,073
Other (Income) and Deductions
Allowance for other funds used during construction (351) (684) (585)
Federal income tax (3,704) (3,450) (16,948)
Regulatory disallowances - - 26,866
Other, net 3,308 (712) 9,631
---------- ---------- ----------
Total Other (Income) and Deductions (747) (4,846) 18,964
Interest Charges
Long term debt 44,615 48,618 53,026
Other, net 6,676 9,328 9,056
Allowance for borrowed funds used during construction (563) (1,423) (2,901)
---------- ---------- ----------
Total Interest Charges 50,728 56,523 59,181
---------- ---------- ----------
Net Income 95,360 97,511 71,928
---------- ---------- ----------
Dividends on Preferred Stock 5,805 7,465 7,465
---------- ---------- ----------
Earnings Applicable to Common Stock $89,555 $90,046 $64,463
---------- ---------- ----------
Earnings per Common Share - Basic $2.30 $2.32 $1.69
Earnings per Common Share - Diluted $2.30 $2.32 $1.69
========== ========== ==========
</TABLE>
CONSOLIDATED STATEMENT OF RETAINED EARNINGS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1997 1996 1995
- --------------------------------------------------------- --------- ---------- ----------
<S> <C> <C> <C>
Balance at Beginning of Period $90,540 $70,330 $74,566
Add
Net Income 95,360 97,511 71,928
Adjustment Associated with Stock Redemption (846) - -
---------- ---------- ----------
Total 185,054 167,841 146,494
---------- ---------- ----------
Deduct
Dividends declared on capital stock
Cumulative preferred stock - at required rates 5,805 7,465 7,465
Common Stock 69,936 69,836 68,699
---------- ---------- ----------
Total 75,741 77,301 76,164
---------- ---------- ----------
Balance at End of Period $109,313 $90,540 $70,330
========== ========== ==========
Cash Dividends Declared per Common Share $1.80 $1.80 $1.80
========== ========== ==========
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
37
<TABLE>
<CAPTION>
CONSOLIDATED BALANCE SHEET
(Thousands of Dollars) At December 31 1997 1996
<S> <C> <C>
Assets
Utility Plant
Electric $2,439,108 $2,413,881
Gas 416,989 391,231
Common 134,938 129,946
Nuclear fuel 243,042 224,701
------------ ------------
3,234,077 3,159,759
Less: Accumulated depreciation 1,510,074 1,381,908
Nuclear fuel amortization 204,294 187,170
------------ ------------
1,519,709 1,590,681
Construction work in progress 74,018 69,711
------------ ------------
Net Utility Plant 1,593,727 1,660,392
------------ ------------
Current Assets
Cash and cash equivalents 25,405 21,301
Accounts receivable, net of allowance for doubtful accounts:
1997 - $ 26,926; 1996 - $ 17,502 104,781 112,908
Unbilled revenue receivable 48,438 53,261
Materials, supplies and fuels 39,929 39,888
Prepayments 23,818 23,103
------------ ------------
Total Current Assets 242,371 250,461
------------ ------------
Deferred Debits
Nuclear generating plant decommissioning fund $ 132,540 $ 91,195
Nine Mile Two deferred costs 30,309 31,360
Unamortized debt expense 16,943 14,820
Other deferred debits 20,411 28,759
Regulatory assets 231,988 284,489
------------ ------------
Total Deferred Debits 432,191 450,623
------------ ------------
Total Assets $2,268,289 $2,361,476
============ ============
Capitalization and Liabilities
Capitalization
Long term debt - mortgage bonds 485,434 555,054
- promissory notes 101,900 91,900
Preferred stock redeemable at option of Company 47,000 67,000
Preferred stock subject to mandatory redemption 35,000 45,000
Common shareholders' equity:
Common stock 699,031 696,019
Retained earnings 109,313 90,540
------------ ------------
Total Common Shareholders' Equity 808,344 786,559
------------ ------------
Total Capitalization 1,477,678 1,545,513
------------ ------------
Long Term Liabilities (Department of Energy)
Nuclear waste disposal 83,261 79,057
Uranium enrichment decommissioning 13,465 14,695
------------ ------------
Total Long Term Liabilities 96,726 93,752
------------ ------------
Current Liabilities
Long term debt due within one year 30,000 20,000
Preferred stock redeemable within one year 10,000 10,000
Short term debt 20,000 14,000
Accounts payable 53,195 49,462
Dividends payable 18,791 19,349
Taxes accrued 5,041 4,694
Interest accrued 8,593 10,317
Other 43,697 30,395
------------ ------------
Total Current Liabilities 189,317 158,217
------------ ------------
Deferred Credits and Other Liabilities
Accumulated deferred income taxes 344,969 370,028
Pension costs accrued 67,361 69,806
Other 92,238 124,160
------------ ------------
Total Deferred Credits and Other Liabilities 504,568 563,994
------------ ------------
Commitments and Other Matters - -
------------ ------------
Total Capitalization and Liabilities $2,268,289 $2,361,476
============ ============
The accompanying notes are an integral part of the financial statements.
</TABLE>
<PAGE>
38
ROCHESTER GAS AND ELECTRIC CORPORATION
CONSOLIDATED STATEMENT OF CASH FLOWS
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1997 1996 1995
<S> <C> <C> <C>
CASH FLOW FROM OPERATIONS
Net income $ 95,360 $ 97,511 $ 71,928
Adjustments to reconcile net income to net cash provided
from operating activities:
Depreciation and amortization 133,942 121,824 109,575
Deferred fuel 489 (6,501) 3,432
Deferred income taxes (10,064) 6,391 (8,047)
Allowance for funds used during construction (914) (2,107) (3,486)
Unbilled revenue, net 4,823 10,908 (9,899)
Stock option plan 2,399 - -
Nuclear generating plant decommissioning fund (20,331) (11,732) (8,837)
Pension costs accrued (3,398) (2,494) 6,280
Post employment benefit internal reserve 6,189 6,626 4,636
Regulatory disallowance - - 26,866
Provision for doubtful accounts 5,078 4,987 14,893
Changes in certain current assets and liabilities:
Accounts receivable 3,049 3,228 (25,599)
Materials, supplies and fuels (41) (1,238) 6,837
Taxes accrued 347 (13,944) 15,167
Accounts payable 3,733 (3,116) 9,644
Other current assets and liabilities, net 7,344 (5,186) 9,639
Other, net 6,847 (3,931) 28,762
----------- ------------ ------------
Total Operating 234,852 201,226 251,791
=========== =========== ===========
CASH FLOW FROM INVESTING ACTIVITIES
Net additions to utility plant (84,068) (114,274) (109,547)
Other, net (1) 9,204 11,124
----------- ------------ ------------
Total Investing (84,069) (105,070) (98,423)
=========== =========== ===========
CASH FLOW FROM FINANCING ACTIVITIES
Proceeds from:
Sale/Issuance of common stock 272 8,612 17,074
Issuance of long term debt 101,900 - -
Short term borrowings, net 6,000 14,000 (51,600)
Retirement of long term debt (151,568) (67,332) (1,000)
Retirement of preferred stock (30,000) - -
Dividends paid on preferred stock (6,366) (7,465) (7,465)
Dividends paid on common stock (69,933) (69,657) (68,347)
Other, net 3,016 2,866 (719)
----------- ------------ ------------
Total Financing (146,679) (118,976) (112,057)
----------- ------------ ------------
Increase (Decrease) in cash and cash equivalents $ 4,104 $ (22,820) $ 41,311
Cash and cash equivalents at beginning of year $ 21,301 $ 44,121 $ 2,810
----------- ------------ ------------
Cash and cash equivalents at end of year $ 25,405 $ 21,301 $ 44,121
=========== =========== ===========
</TABLE>
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
<TABLE>
<CAPTION>
(Thousands of Dollars) Year Ended December 31 1997 1996 1995
<S> <C> <C> <C>
Cash Paid During the Year
Interest paid (net of capitalized amount) $ 50,681 $ 55,545 $ 56,592
Income taxes paid $ 70,500 $ 76,890 $ 43,500
=========== =========== ===========
</TABLE>
The accompanying notes are an integral part of the financial statements.
<PAGE>
39
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 (now
"Energetix") 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. In late 1996, Energyline sold
its investment in the Empire State Pipeline.
The Roxdel (now "Energetix") activity is 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. On January 25, 1995, the Company suspended the weather normalization
adjustment in an effort to mitigate high billings due to the warm weather, and
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
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
<PAGE>
40
Allowance for Other Funds Used During Construction, a part of Other Income. The
rate approved by the PSC for purposes of computing AFUDC was 5.0% during the
three-year period ended December 31, 1997. 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.
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. 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 costs were charged
to expense as incurred. Expenditures for the years 1997, 1996, and 1995 were
$4.5 million, $4.9 million and $5.2 million respectively.
ENVIRONMENTAL REMEDIATION COSTS. The Company accrues for losses associated
with environmental remediation obligations when such losses are probable and
reasonably estimable. Accruals for estimated losses from environmental
remediation obligations generally are recognized no later than completion of the
remedial feasibility study.
Such accruals are adjusted as further information develops or circumstances
change. Costs of future expenditures for environmental remediation obligations
are not discounted to their present value.
MATERIALS SUPPLIES AND FUELS. Materials and supplies inventories are
valued at the lower of cost or market using the first-in, first-out method.
Fuel inventories are valued at average cost. 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.
STOCK-BASED COMPENSATION. Financial Accounting Standards Board Statement
No. 123 (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. SFAS-123 was applied to the valuation of the 1996
Performance Stock Option Plan (PSOP), which became effective on January 22,
1997. The aggregate amount charged to expense as a result of these plans
approximates $1.0 million annually in 1996 and 1995, and approximates $8.2
million in 1997. Additional information on the PSOP is included in Note 8.
RECLASSIFICATIONS. Certain amounts in the prior years' financial
statements were reclassified to conform with current year presentation.
EARNINGS PER SHARE. SFAS-128, Earnings Per Share, was adopted by the
Company in the fourth quarter of 1997. This statement replaces the presentation
of primary Earnings Per Share with Basic Earnings Per Share, and also requires
presentation of Diluted Earnings Per Share. Basic Earnings Per Share (EPS) is
computed by dividing income available to common shareholders by the weighted
average number of common shares outstanding for the period. Diluted EPS
reflects the potential dilution that could occur if securities or other
contracts to issue
<PAGE>
41
common stock were exercised or converted into common stock or resulted in the
issuance of common stock that then shared in the earnings of the Company.
The following table illustrates the calculation of both Basic and Diluted EPS
for the year ended December 31, 1997:
<TABLE>
<CAPTION>
Income Shares Per-Share
(Numerator) (Denominator) Amount
<S> <C> <C> <C>
Basic EPS:
- ----------
Net Income $95,360
Less:
Preferred Stock Dividends (5,805)
Income available to
Common Shareholders 89,555 38,853 $2.30
-----
Diluted EPS:
- ------------
Effect of Dilutive Securities
Stock Option Plan 56
------
Income available to
Common Shareholders plus
assumed conversions $89,555 38,909 $2.30
=====
</TABLE>
As there were no dilutive shares in prior years, basic and dilutive earnings per
share were the same for 1996 and 1995.
<PAGE>
42
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.
<TABLE>
<CAPTION>
(Thousands of Dollars)
1997 1996 1995
<S> <C> <C> <C>
Charged (Credited) to operating expense:
Current $69,812 $65,757 $ 65,368
Deferred (4,533) 3,744 847
------- ------- --------
Total 65,279 69,501 66,215
Charged (Credited) to other income:
Current 1,828 (6,097) (9,996)
Deferred (3,100) 5,079 (4,520)
Deferred investment tax credit (2,432) (2,432) (2,432)
------- ------- --------
Total (3,704) (3,450) (16,948)
Total federal income tax expense $61,575 $66,051 $ 49,267
</TABLE>
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 at the statutory tax rate of 35%.
<TABLE>
<CAPTION>
(Thousands of Dollars)
1997 1996 1995
<S> <C> <C> <C>
Net Income $ 95,360 $ 97,511 $ 71,928
Add: federal income tax expense 61,575 66,051 49,267
-------- -------- --------
Income before federal income tax $156,935 $163,562 $121,195
Computed tax expense at statutory tax rate $ 54,927 $ 57,247 $ 42,418
Increases (decreases) in tax resulting from:
Difference between tax depreciation
and amount deferred 10,772 10,796 7,197
Deferred investment tax credit (2,432) (2,432) (2,432)
Miscellaneous items, net (1,692) 440 2,084
Total federal income tax expense $ 61,575 $ 66,051 $ 49,267
</TABLE>
A summary of the components of the net deferred tax liability is as
follows:
<TABLE>
<CAPTION>
(Thousands of Dollars)
1997 1996 1995
<S> <C> <C> <C>
Nuclear decommissioning $(20,807) $(17,880) $(14,797)
Accelerated depreciation 216,704 213,907 197,952
Deferred investment tax credit 27,981 29,562 31,143
Depreciation previously flowed through 157,538 169,562 183,077
Pension (23,166) (24,570) (24,241)
Other (13,281) (553) 4,518
-------- -------- --------
Total $344,969 $370,028 $377,652
</TABLE>
<PAGE>
43
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, 1997 and
1996 was $160 million and $175 million, respectively. In conjunction with the
recognition of this liability, a corresponding regulatory asset was also
recognized.
<PAGE>
44
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:
<TABLE>
<CAPTION>
(Millions)
1997 1996
-------- -------
<S> <C> <C>
Accumulated benefit obligation, including
vested benefits of $384.7 in 1997 and
$374.6 in 1996 $ (404.0)* $(392.6)*
======== =======
Projected benefit obligation for service
rendered to date $ (499.3)* $(480.2)*
Less: Plan assets at fair value, primarily
listed stocks and bonds 638.4 567.1
-------- -------
Plan assets in excess of projected benefits 139.1 86.9
Unrecognized net loss (gain) from past
experience different from that assumed
and effects of changes in assumptions (219.0) (170.7)
Prior service cost not yet recognized in
net periodic pension cost 10.7 11.6
Unrecognized net obligation at December 31 1.8 2.4
-------- -------
Pension costs accrued $ (67.4) $ (69.8)
======== =======
</TABLE>
* Actuarial present value.
Net pension cost included the following components:
<TABLE>
<CAPTION>
(Millions)
1997 1996 1995
-------- ------- -------
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 6.2 $ 7.4 $ 6.0
Interest cost on projected benefit obligation 33.0 33.4 35.4
Actual return on plan assets (104.3) (80.8) (101.1)
Net amortization and deferral 63.1 39.0 56.1
------- ------ -------
Net periodic pension (credit) cost $ (2.0) $ (1.0) $ (3.6)
======= ====== =======
</TABLE>
The projected benefit obligation at December 31, 1997 and December 31,
1996 assumed discount rates of 6.75% and 7.25%, 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.
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
<PAGE>
45
1997, 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:
<TABLE>
<CAPTION>
(Millions)
1997 1996
-------- -------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retired employees $(73.9) $(65.6)
Active employees (15.1) (13.5)
------ ------
$(89.0) $(79.1)
Less - Plan assets at fair value 0.0 0.0
------ ------
Accumulated postretirement benefit
obligation (in excess of) less than
fair value of assets (89.0) (79.1)
Unrecognized net loss (gain) from past experience
different from that assumed and effects
of changes in assumptions 8.4 3.7
Prior service cost not yet recognized in
net periodic pension cost 8.9 7.1
Unrecognized net obligation at December 31 39.5 42.3
------ ------
Accrued postretirement benefit cost $(32.2) $(26.0)
====== ======
</TABLE>
Net periodic postretirement benefit cost included the following components:
<TABLE>
<CAPTION>
(Millions)
1997 1996
-------- ------
<S> <C> <C>
Service cost - benefits attributed to the period $ 0.9 $ 1.0
Interest cost on accumulated postretirement
benefit obligation 5.8 5.4
Actual return on plan assets 0.0 0.0
Net amortization and deferral 3.5 4.2
----- -----
Net periodic postretirement benefit cost $10.2 $10.6
===== =====
</TABLE>
The Accumulated Postretirement Benefit Obligation at December 31, 1997
and 1996 assumed discount rates of 6.75% and 7.25%, 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.
<PAGE>
46
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.
<TABLE>
<CAPTION>
(Thousands of Dollars)
1997 1996 1995
---------- ---------- ----------
<S> <C> <C> <C>
Electric
Operating Information
Operating revenues $ 700,329 $ 707,768 $ 722,465
Operating expenses, excluding
provision for income taxes 516,793 521,222 523,105
---------- ---------- ----------
Pretax operating income 183,536 186,546 199,360
Provision for income taxes 61,837 61,901 59,500
---------- ---------- ----------
Net operating income $ 121,699 $ 124,645 $ 139,860
---------- ---------- ----------
Other Information
Depreciation and amortization $ 103,395 $ 92,615 $ 78,812
Nuclear fuel amortization $ 17,419 $ 16,209 $ 17,982
Capital expenditures $ 58,522 $ 95,334 $ 93,634
Investment Information,
Identifiable assets (a) $1,783,825 $1,877,224 $1,913,762
Gas
Operating Information
Operating revenue $ 336,309 $ 346,279 $ 293,863
Operating expenses, excluding
provision for income taxes 309,225 314,136 276,935
---------- ---------- ----------
Pretax operating income 27,084 32,143 16,928
Provision for income taxes 3,442 7,600 6,715
---------- ---------- ----------
Net operating income $ 23,642 $ 24,543 $ 10,213
---------- ---------- ----------
Other Information
Depreciation $ 13,127 $ 12,999 $ 12,781
Capital expenditures $ 25,546 $ 18,940 $ 15,913
Investment Information
Identifiable assets (a) $ 441,849 $ 447,865 $ 477,758
</TABLE>
(a) Excludes cash, unamortized debt expense, and other common items.
<PAGE>
47
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.
<TABLE>
<CAPTION>
Oswego Nine Mile Point
Unit No. 6 Nuclear Unit No. 2
---------- ------------------
<S> <C> <C>
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)
December 31, 1997
------------------------------
Plant In Service Balance $98.9 $879.3
Accumulated Provision For Depreciation $41.4 $478.7
Plant Under Construction $ 0.6 $ 3.3
</TABLE>
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.
<PAGE>
48
Note 6. LONG-TERM DEBT
<TABLE>
<CAPTION>
FIRST MORTGAGE BONDS
(Thousands of Dollars)
Principal Amount
December 31
% Series Due 1997 1996
- --------------------------- ---------------------- -------------- -------- --------
<S> <C> <C> <C> <C>
6 1/4 W Sept. 15, 1997 $ - $ 20,000
6.7 X July 1, 1998 30,000 30,000
8.00 Y Aug. 15, 1999 - 29,668
6 1/2 EE Aug. 1, 2009 - 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
-------- --------
$516,000 $575,668
Net bond discount (566) (614)
Less: Due within one year 30,000 20,000
-------- --------
Total $485,434 $555,054
======== ========
</TABLE>
(a) The 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 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. Payments of the
principal of, and interest on the Series 1992 A and Series 1992 B Bonds are
guaranteed under a Bond Insurance Policy by MBIA Insurance Corporation.
(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 1997 and 1996 requirements were met
with funds deposited with the Trustee, and these funds were used for redemption
of outstanding bonds of Series Y.
On May 1, 1997 the Company redeemed all its outstanding First Mortgage 8%
Bonds, Series Y, due August 15, 1999 and all its outstanding First Mortgage
6 1/4% Bonds, Series W, due September 15, 1997. On October 15, 1997, the
Company redeemed all its outstanding First Mortgage 6 1/2% Bonds, Series EE.
<PAGE>
49
Sinking fund requirements and bond maturities for the next five years are:
<TABLE>
<CAPTION>
(Thousands of Dollars)
1998 1999 2000 2001 2002
-------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Series X $ 30,000
7% Series $ 30,000
Series QQ $100,000
-------- -------- -------- -------- --------
$ 30,000 $ - $ 30,000 $ - $100,000
</TABLE>
PROMISSORY NOTES
<TABLE>
<CAPTION>
(Thousands of Dollars)
December 31
Issued Due 1997 1996
- ------ --- -------- --------
<S> <C> <C> <C>
November 15, 1984/(d)/ October 1, 2014 $ - $51,700
December 5, 1985/(e)/ November 15, 2015 - 40,200
August 19, 1997/(f)/ August 1, 2032 101,900 -
-------- -------
Total $101,900 $91,900
======== =======
</TABLE>
(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. On October 1, 1997, the
Company redeemed all the outstanding Series 1984 Bonds. The average
interest rate was 3.43% through September 30, 1997, 3.38% for 1996 and
3.68% for 1995.
(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. On November 15, 1997 the Company
redeemed all the outstanding Series 1985 Bonds. The annual interest rate
was adjusted to 3.60% effective November 15, 1996 and to 3.75% effective
November 15, 1995.
(f) Multi-mode pollution control notes totaling the principal amount of $101.9
million were issued in connection with NYSERDA's Pollution Control Revenue
Bonds (Rochester Gas and Electric Corporation Project), $34,000,000 1997
Series A, $34,000,000 1997 Series B and $33,900,000 1997 Series C. The
Multi-mode Revenue Bonds have a structure that enables the Company to
optimize the use of short-term rates by allowing for the interest rates to
be based on a daily rate, a weekly rate, a commercial paper rate, an
auction rate or a multi-year fixed rate. Payment of the principal of, and
interest on the Multi-mode Revenue Bonds is guaranteed under Bond Insurance
Policies by MBIA Insurance Corporation. At December 31, 1997, the Multi-
mode Revenue Bonds bore interest at the weekly rate and the average annual
interest rate for all three series was 3.65%.
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.
Based on an estimated borrowing rate at year-end 1997 of 6.62% for long-
term debt with similar terms and average maturities (13 years), the fair value
of the Company's long-term debt outstanding (including Promissory Notes as
described above) is approximately $655 million at December 31, 1997.
<PAGE>
50
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.
On September 16, 1997, the Company completed arrangements for the delivery
in September 1998 of $25.5 million of 5.95% NYSERDA tax-exempt bonds due
September 1, 2033. Proceeds are expected to be used to redeem the Series OO,
tax-exempt, first mortgage bonds which are not redeemable until December 1998.
Note 7. PREFERRED AND PREFERENCE STOCK
<TABLE>
<CAPTION>
Par Shares Shares
Type by Order of Seniority Value Authorized Outstanding
- ------------------------------ ----- ---------- -----------
<S> <C> <C> <C>
Preferred Stock (cumulative) $100 2,000,000 920,000*
Preferred Stock (cumulative) 25 4,000,000 -
Preference Stock 1 5,000,000 -
</TABLE>
* 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:
<TABLE>
<CAPTION>
Shares (Thousands) Optional
Outstanding December 31, Redemption
% Series December 31, 1997 1997 1996 (per share) #
- ------ ------ ----------------- ------- ------- -------------
<S> <C> <C> <C> <C> <C>
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 - - 20,000 102
------- ------- -------
Total 470,000 $47,000 $67,000
======= ======= =======
</TABLE>
# May be redeemed at any time at the option of the Company on 30 days minimum
notice, plus accrued dividends in all cases. The Series N were redeemed on
April 22, 1997.
B. PREFERRED STOCK, SUBJECT TO MANDATORY REDEMPTION:
<TABLE>
<CAPTION>
Shares (Thousands) Optional
Outstanding December 31, Redemption
% Series December 31, 1997 1997 1996 (per share) #
- ------ ------ ----------------- ------- ------- ------------------
<S> <C> <C> <C> <C> <C>
7.45 S - $ - $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 450,000 $45,000 $55,000
Less: Due within one year 100,000 10,000 10,000
------- ------- -------
Total 350,000 $35,000 $45,000
======= ======= =======
</TABLE>
+ Thereafter at $100.00
<PAGE>
51
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 T, Series U. All of the shares are subject to redemption
pursuant to mandatory sinking funds on 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 1997 of 5.67% for
Preferred Stock, subject to mandatory redemption, with similar terms and average
maturities (5.92 years), the fair value of the Company's Preferred Stock,
subject to mandatory redemption, is approximately $48 million at December 31,
1997.
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.
<PAGE>
52
Note 8. COMMON STOCK AND STOCK OPTIONS
In December 1997, the Board of Directors of the Company authorized the
repurchase of up to 4.5 million shares of the Company's Common Stock on the open
market. None of the shares were purchased prior to year end.
At December 31, 1997, there were 50,000,000 shares of $5 par value
Common Stock authorized, of which 38,862,347 were outstanding. No shares of
Common Stock are reserved for warrants, conversions, or other rights. There
were 1,445,141 shares of Common Stock reserved for employees under the 1996
Performance Stock Option Plan, as further described below. 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
<TABLE>
<CAPTION>
Shares Amount
Outstanding (Thousands)
----------- -----------
<S> <C> <C>
Balance, January 1, 1995 37,669,963 $670,569
Shares Issued through Stock Plans 783,200 17,074
Decrease (Increase) in
Capital Stock Expense (125)
----------- --------
Balance, December 31, 1995 38,453,163 $687,518
Shares Issued through Stock Plans 398,301 8,612
Decrease (Increase) in
Capital Stock Expense (111)
----------- --------
Balance, December 31, 1996 38,851,464 $696,019
Shares Issued through Stock Plans 10,883 272
Additional Paid in Capital 2,399
Decrease (Increase) in
Capital Stock Expense 341
----------- --------
Balance, December 31, 1997 38,862,347 699,031
</TABLE>
PERFORMANCE STOCK OPTION PLAN
Effective January 22, 1997, the Company adopted a Performance Stock
Option Plan which provides for the granting of options to purchase up to
2,000,000 authorized but unissued shares or treasury shares of $5 par value
Common Stock to executive officers and other key employees. No participant
shall be granted options for more than 200,000 shares of Common Stock during any
calendar year. The options would be exercisable for a period to be determined by
the Committee on Management (the Committee). The Committee may in its sole
discretion grant the right to receive a cash payment upon any exercise of an
option equal to the quarterly dividend payment per share of Common Stock paid
from the date the option was granted to the date of exercise.
In 1997, the Board of Directors granted 504,700 options at an exercise
price of $19.0625 per share. These options are vested at 50% when the stock
closes at $25 per share, 75% at $30 per share and 100% at $35 per share.
Also in 1997, the Board of Directors granted 50,159 options at an
exercise price of $24.75 per share. These options are vested at 25% when the
stock closes
<PAGE>
53
at $25 per share, 50% at $30 per share, 75% at $35 per share, and 100% at $40
per share.
In order for the options to become vested, the closing prices must be
sustained at or above the levels indicated above for a minimum of five
consecutive trading days.
Since the Company adopted FAS 123, compensation expense associated
with the options granted is reflected in 1997 net income. For calendar 1997,
the compensation expense recorded was $2.4 million. In applying FAS 123, the
fair value of each option granted is estimated on the date of the grant using
the Black-Scholes option pricing model with the following assumptions: risk-free
rate of return ranging between 6.39% and 6.56%, expected dividend yield of
9.44%, and expected stock volatility of 17%.
A summary of the Company's stock option activity is presented below:
<TABLE>
<CAPTION>
Weighted
Options Average Price
---------- -------------
<S> <C> <C>
Options granted 1997 554,859 $19.577
Options exercised (10,883) $19.063
---------
Outstanding at 12/31/97 543,976 $19.587
Vested at 12/31/97 392,722 $19.426
Available for future grant at 12/31/97 1,445,141
</TABLE>
<PAGE>
54
Note 9. SHORT-TERM DEBT
On December 31, 1997, the Company had short-term debt outstanding of
$20.0 million. At December 31, 1996 the Company had short-term debt outstanding
of $14.0 million. The weighted average interest rate in 1997 on short-term debt
outstanding at year end was 6.64% and was 6.07% for borrowings during the year.
The weighted average interest rate on short-term debt borrowed during 1996 was
5.86%.
In December 1997 the Company's $90 million revolving credit agreement
was amended extending its term to five years, terminating December 31, 2002.
Commitment fees related to this facility amounted to $113,000 in 1997 and 1996,
and $165,000 in 1995.
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, 1997, the
Company would be able to incur approximately $103.8 million of additional
unsecured debt under this provision. The Company has unsecured lines of credit
totaling $27 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 $30 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, 1997, borrowings outstanding were $4.34 million of 636
Notes (recorded on the Balance Sheet as a liability under Deferred Credits and
Other Liabilities).
<PAGE>
55
Note 10. COMMITMENTS AND OTHER MATTERS
COMPETITION
OVERVIEW. The PSC, through its Competitive Opportunities Proceeding,
has embarked on a fundamental restructuring of the electric utility industry in
the state. Among other elements, the PSC's goals included lower rates for
consumers and increased customer choice in obtaining electricity and other
energy services. During 1996 and 1997, the Company, the Staff of the PSC, and
several other parties negotiated a Settlement Agreement (the "Settlement") which
was approved by the PSC in November 1997. The Settlement sets the framework for
the introduction and development of open competition in the electric energy
marketplace.
PSC COMPETITIVE OPPORTUNITIES CASE SETTLEMENT. The Settlement
provides for a transition to competition during its five year term (July 1, 1997
to June 30, 2002) and establishes the Company's electric rates for each annual
period. A Retail Access Program will be phased in, allowing customers to
purchase electricity, and later electricity and capacity commitments, from
sources other than the Company. The Company will be given a reasonable
opportunity to recover prudently incurred costs, including those pertaining to
generation and purchased power. The Settlement also requires the Company to
functionally separate its component operations: distribution, generation, and
retailing. Any unregulated retail operations must be structurally separate from
the regulated utility functions but may be funded with up to $100 million.
Although the Settlement provides incentives for the sale of generating assets,
it requires neither divestiture of generating or other assets nor write off of
stranded costs. The Company believes that the Settlement will not adversely
affect its eligibility to continue to apply SFAS 71 with the exception of
certain to-go costs associated with non-nuclear generation. If, contrary to the
Company's view, such eligibility were adversely affected, a material write-down
of assets, the amount of which is not presently determinable, could be required.
Rate Plan. Over the five year term of the Settlement, cumulative
rate reductions will be: Rate Year 1: $3.5 million; Rate Year 2: $12.8 million;
Rate Year 3: $27.6 million; Rate Year 4: $39.5 million; and Rate Year 5: $64.6
million. The Rate Plan permits the Company to offset against the foregoing
reductions certain inflation-related expenses and certain amounts related to a
purchase power agreement with Kamine. In the event that the Company earns a
return on common equity in excess of 11.50% over the entire five year term of
the Settlement, 50% of such excess will be used to write down deferred costs
accumulated during the term, and 50% will be used to write down accumulated
deferrals or investment in electric plant or regulatory assets.
Retail Access. The Company's Energy Choice Program will be available
to all of its customers on an equal basis up to certain usage caps. On July 1,
1998, customers whose electric loads represent approximately 10% of the
Company's total annual retail sales will be eligible to purchase electricity
(but not capacity commitments) from alternative suppliers. On July 1, 1999, the
percent of total sales moves to 20%, and customers would purchase both
electricity and capacity commitments. On July 1, 2000, the percent moves to
30%, and on July 1, 2001, all retail customers will be eligible to purchase
energy and capacity from alternative suppliers.
During the initial, energy only stage of the Retail Access Program,
the Company's distribution rate will be set by deducting 2.3 cents per kilowatt
hour ("KWH") from its full service ("bundled") rates and Load Serving Entities
acting as retailers in the Company's service area will be entitled to purchase
electricity from the Company at a rate of 1.9 cents per KWH. During the energy
and capacity stage, the rate will generally equal the bundled rate less the cost
of the electric commodity and the Company's non-nuclear generating capacity.
These commodity and capacity costs, generally referred to as "contestable
costs," are estimated to be 3.2 cents per KWH, inclusive of gross receipts
taxes.
Generating Assets. The Company will not be required to divest any of
its generation facilities. To the extent that the Company sells any generating
<PAGE>
56
assets during the term of the Settlement, gains on such sales will be shared
between the Company and customers. With regard to losses on such sales, the
Settlement acknowledges an intent that the Company will be permitted to recover
such losses through distribution rates during the term of the Settlement.
Future rate treatment is to be consistent with the principle that the Company is
to have a reasonable opportunity to recover such costs.
"To-go costs" of the Company's non-nuclear resources (i.e., capital
costs incurred after February 28, 1997, operation and maintenance expenses, and
property, payroll and other taxes) are to be initially recovered through
distribution rates. The fixed portion of to-go costs would be recovered in full
until July 1, 1999, and be subject to the market thereafter in accordance with
the phase-in schedule for the Retail Access program. The variable portion of
non-nuclear to-go costs would also be subject to the market in accordance with
the phase-in schedule. Under the Settlement, nuclear costs would remain
recoverable through regulated rates.
Miscellaneous. The present Settlement supersedes the 1996 Rate
Settlement. Various incentive and penalty provisions in the 1996 Rate
Settlement are eliminated.
EITF ISSUE 97-4 - DEREGULATION OF THE PRICING OF ELECTRICITY. In
July, 1997, the Financial Accounting Standards Board's Emerging Issues Task
Force (EITF) reached a consensus on accounting rules for utilities' transition
plans for moving to more competitive environments and provided guidance on when
utilities with transition plans will need to discontinue the application of
SFAS-71, "Accounting for the Effects of Certain Types of Regulation".
The major EITF consensus was that the application of SFAS-71 to a
segment (e.g. generation) which is subject to a deregulation transition plan
should cease when the legislation or enabling rate order contains sufficient
detail for the utility to reasonably determine what the transition plan will
entail. The EITF also concluded that a decision to continue to carry some or
all of the regulatory assets (including stranded costs) and liabilities of the
separable portion of the business that is discontinuing the application of SFAS-
71 should be determined on the basis of where the regulated cash flows to
realize and settle them will be derived. If a transition plan provides for a
non-bypassable fee for the recovery of stranded costs, there may not be any
significant write-off if SFAS-71 is discontinued for a segment.
The Company's application of the EITF 97-4 consensus has not affected
its financial position or results of operations because any above-market
generation costs, regulatory assets and regulatory liabilities associated with
the generation portion of its business will be recovered by the regulated
portion of the Company through its distribution rates, given the Settlement
provisions. The Settlement provides for recovery of all prudently incurred sunk
costs (all investment in electric plant and electric regulatory assets) as of
March 1, 1997 by inclusion in rates charged pursuant to the Company's
distribution access tariff. The Settlement also states that "the Parties intend
that the provisions of this Settlement will allow the Company to continue to
recover such costs, during the term of the Settlement, under SFAS-71", and that
"such treatment shall be consistent with the principle that the Company shall
have a reasonable opportunity beyond July 1, 2002 to recover all such costs".
As noted previously, the fixed portion of the non-nuclear generation to-go costs
after July 1, 1999 and the variable portion of the non-nuclear generation to-go
costs after July 1, 1998 are subject to market forces and would no longer be
able to apply SFAS-71. The Company's net investment at December 31, 1997 in
nuclear generating assets is $698.4 million and in non-nuclear generating assets
is $122.0 million.
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 SFAS-71. These deferred
costs are shown as Regulatory Assets on the Company's Balance Sheet. Such cost
<PAGE>
57
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 SFAS-121). In certain cases, the entire
amount could be written off.
SFAS-121 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 summarization of the Regulatory Assets as of December 31,
1997 and 1996:
<TABLE>
<CAPTION>
(Millions of Dollars)
1997 1996
------- -------
<S> <C> <C>
Income Taxes $159.6 $174.6
Uranium Enrichment Decommissioning Deferral 16.4 17.7
Deferred Ice Storm Charges 11.5 14.0
FERC 636 Transition Costs 11.0 32.3
Demand Side Management Costs Deferred 4.4 8.4
Gas Deferred Fuel 7.1 7.7
Other, net 22.0 29.8
------ ------
Total - Regulatory Assets $232.0 $284.5
====== ======
</TABLE>
- - 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.
- - 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.
- - 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.
- - 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.
- - 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 2002.
- - Gas Deferred Fuel: These costs result from a PSC-approved annual
reconciliation of recoverable gas costs with gas revenues in which the
excess or deficiency is refunded to or recovered from customers during a
subsequent period.
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
<PAGE>
58
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, 1997 depends on
market prices and the competitive market in New York State which is still under
development and subject to continuing changes which are not yet determinable,
but could be significant. Strandable assets, if any, could be written down for
impairment of recovery in the same manner as deferred costs discussed above.
In a competitive natural gas market, strandable assets would arise where
customers migrate away from dependence on the Company for full service, leaving
the Company with surplus pipeline and storage capacity, as well as natural gas
supplies, under contract. The Company has been restructuring its
transportation, storage and supply portfolio to reduce its potential exposure to
strandable assets. Regulatory developments discussed under " GAS RESTRUCTURING
PROCEEDING," below, may affect this exposure; but whether and to what extent
there may be an impact on the level and recoverability of strandable assets
cannot be determined at this time.
At December 31, 1997 the Company believes that its regulatory and
strandable assets, if any, are not impaired and are probable of recovery. The
settlement approved in the Competitive Opportunities proceeding does not impair
the opportunity of the Company to recover its investment in these assets.
However, the PSC has published a Staff paper to address issues surrounding
nuclear generation, including the determination of fair market value for
facilities after a five year restructuring transition period. It appears that
the PSC may seek to apply similar principles to other types of generating
facilities. A determination in this proceeding could have an impact on
strandable assets.
CAPITAL EXPENDITURES
The Company's 1998 construction expenditures program is currently estimated
at $124 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 $116.1 million through December 31, 1997
and is authorized to collect approximately $22 million annually through June 30,
2002 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 $86.4 million to this fund and, including realized and unrealized
investment returns, the fund has a balance of $132.5 million as of December 31,
1997. 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, 1997 is $29.7 million.
The NRC is currently considering proposals which may impact financial
funding requirements for decommissioning of nuclear power plants. Under current
<PAGE>
59
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 NRC has released for comments a notice of proposed rulemaking (NOPR)
modifying certain aspects of the financial assurance requirements for
decommissioning nuclear power reactors. The NOPR includes, among other things,
changes to the definition of "electric utility" for the purposes of providing
financial assurance for decommissioning as well as new reporting requirements
regarding each licensee's progress on external funding. The Company does not
anticipate a material impact from the application of these rules in their
proposed form; however it cannot predict the impact of these rules as resolution
of stranded asset issues proceed in New York.
The PSC in August 1997 issued for comment a report by its staff proposing
norms by which nuclear plants in the state would relate to the competitive
electricity market following the period covered by electric utility
restructuring agreements then pending before the PSC. Among other things, the
report envisioned the sale of these plants at auction, but with the selling
utilities remaining responsible for ultimate decommissioning as well as for
disposal of certain spent fuel. Recognizing that bidders may not be attracted
to certain units -- which could include both the Company's Ginna plant and the
Nine Mile Two plant in which it has a 14% interest, the report contemplated
their early shutdown unless they could compete with other forms of generation.
In Fall 1997, the Company and others commented on these and other facets of the
report. Through mid-January 1998, the PSC had taken no action on the report and
comments.
The Staff of the Financial Accounting Standards Board are 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.
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. Under the
National Energy Act, 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 the Company's
share of Nine Mile Two are estimated to total $22.1 million, excluding inflation
and interest. Installments aggregating approximately $9.4 million have been paid
through 1997. 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, 1997 is $15.1 million ($13.4 million as a long-term
liability and $1.7 million as a current liability). The Company is recovering
costs through base rates of fuel.
In July 1996, the Company joined other utilities in a civil action against
the U.S. Department of Energy (DOE), concerning these assessments. After a
favorable initial decision in a parallel case, the Court of Appeals for the
Federal Circuit in May 1997 reversed the lower court and held that the federal
<PAGE>
60
government could assess licensees for the clean-up of these federal facilities.
In January 1998, the U.S. Supreme Court refused to hear the case, effectively
upholding the dismissal of the utility claims.
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 proposing 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 $83.3 million at December 31, 1997. The Company
is allowed by the PSC to recover these costs in rates. The estimated fees are
classified as a long-term liability and interest is accrued at the current
three-month Treasury bill rate, adjusted quarterly. The Nuclear Waste Act also
requires the DOE to provide for the disposal of nuclear fuel irradiated after
April 6, 1983, for a charge of approximately one mill ($.001) per KWH of nuclear
energy generated and sold. This charge (approximately $3.6 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.
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
<TABLE>
<CAPTION>
Estimated
Site Name Location Company Cost
------------- --------------- ---------------------
<S> <C> <C>
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,
1997 of $4.3 million.
</TABLE>
* Voluntary agreement signed.
<PAGE>
61
TABLE II - SUPERFUND AND NON-OWNED OTHER SITES
<TABLE>
<CAPTION>
Estimated
Site Name Location Company Cost
------------- --------------- ---------------------
<S> <C> <C>
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 1997 of less than $1.0
PAS of Oswego* Oswego, NY million.
</TABLE>
* 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 $13.6 million, $12.8 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 received 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 gasification
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
<PAGE>
62
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 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 a November 1997 letter, the County has claimed that the
Company was the original generator of the materials. It asserts that it will
hold the Company liable for 50% of all County costs -- presently estimated at a
total of approximately $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 1995 investigation of
this area, which is estimated to cost no more than $150,000, but no commitment
has been made toward any subsequent investigations or remedial measures which
may be recommended by the investigations.
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 not expected to exceed $500,000.
SUPERFUND AND NON-OWNED 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. On May
12, 1997, the Company signed an Administrative Order on Consent with the NYSDEC.
This agreement served to obligate the respective parties to pay NYSDEC's past
costs at the Site, the Company's share of which was determined to be $1,500.
There is as yet, no information on which to determine the cost to design and
conduct at the
<PAGE>
63
site any remedial measures which federal or State authorities may require, the
Company does not expect its additional costs to exceed $150,000.
On May 21, 1993, the Company was notified by NYSDEC that it was
considered a PRP for the Frontier Chemical Pendleton Superfund Site located in
Pendleton, NY. The Company has signed, along with other participating parties,
an Administrative Order on Consent with NYSDEC. The Order on Consent obligates
the parties to implement a work plan and remediate the site. The PRPs have
negotiated a work plan for site remediation and have retained a consulting firm
to implement the work plan. Preliminary estimates indicate the Company's share
of additional site remediation costs are not expected to exceed $350,000. 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 additional costs of investigation and
remediation is not expected to exceed $250,000.
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 additional
projected costs is not expected to exceed $71,000. 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 generating
facilities. The strategy being developed is a combination of hardware solutions
which have a capital and operation and maintenance (O&M) component and allowance
trading solutions which have strictly an O&M impact. The most recent strategic
developments still envision this combination of efforts as the most cost
effective means of proceeding although State legislative activity could impact
the Company's ability to rely upon the emission allowance market to meet some of
its environmental commitments. The Company cannot predict the outcome of these
proceedings in the Legislature and, as a result, the Company's projections are
based solely on the combination strategy. A range of capital costs between $2.9
and $3.5 million has been estimated for the implementation of several potential
alterations for meeting the foreseeable nitrogen oxide, opacity and sulfur
dioxide requirements of the Amendments, as well as $1.0 to $1.5 million per year
in operating expenses. These capital costs would be incurred between 1998 and
2000. The O&M expenses would be for the year 1999. For the year 2000 and
beyond, the Company estimates that the annual operating expenses would rise to
between $2.4 million and $3.7 million. Any additional post-2000 capital costs
and operating expense cannot be predicted until resolution of State and federal
legislative activity enables the Company to finalize its compliance strategy.
OPACITY ISSUE. In May 1997, the Company commenced negotiations with
the NYSDEC to resolve allegations of past opacity violations at the Company's
Beebee and Russell Stations. The opacity standard is a regulation which limits
the density of the smoke emitted from the Stations' smokestacks. The Company
believes that it will reach an agreement with NYSDEC on this issue and that the
amount of any civil penalty will likely include both cash and environmental
benefit project components which, in the aggregate, will not be material. In
addition, the Stations have been temporarily derated since February 1997 to
maintain acceptable opacity levels while the Company investigates additional
engineering solutions to address opacity emissions. The financial impact of the
deratings includes the lost opportunity associated with energy sales and, at
times, the need to make additional purchases to meet system requirements. While
the deratings have decreased earnings, and will continue to do so, the Company
does not expect the amount to be material. Finally, the New York Power Pool
(NYPP) is in the process of evaluating new rules for its system load regulation.
The current Station deratings for opacity reasons would reduce the ability of
the Company to react to changes in load and provide regulation services when
called
<PAGE>
64
upon by the NYPP, resulting in additional costs. Depending on the new NYPP
requirements, and whether the deratings remain in effect, the revised rules
could result in the Company having to purchase additional regulation services
which may cost between $500,000 and $2,500,000 annually.
GAS COST RECOVERY
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 local distribution
companies (LDCs) would be permitted to require customers converting from sales
service to take associated pipeline capacity for which the LDCs had originally
contracted. Prior to the beginning of the third year, the LDCs would be required
to demonstrate their efforts to dispose of "excess" capacity. On September 4,
1997, the PSC issued an Order clarifying the March 28, 1996 Order. The
September 4 Order requires, among other things, that the LDCs (a) assess
strandable costs; (b) evaluate and pursue options to address strandable costs,
including exploration of alternative uses and quantification of market values
for the capacity that could be stranded by converting customers; (c) actively
encourage competition including collaboration with marketers to expand the
number of customers taking transportation service from the LDC and to provide
customer education; and (d) to the extent LDCs cannot shed all their capacity as
contracts expire, to continue to seek lower cost options and more flexibility
and shorter contract terms, where cost-effective. LDCs are required to file
plans addressing the foregoing issues by April 1, 1998. Pursuant to the PSC's
orders, the cost of capacity defined as "excess" may not be fully recoverable in
rates. Accordingly, the Company's ability to avoid absorbing this cost will
depend on the success of remarketing and portfolio structuring efforts 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 eliminated.
The Company is engaged in negotiations with the Staff of the PSC and other
parties to address these and other issues related to the future provision of gas
service. At this time, no assessment of the potential impact of these
requirements on the Company can be made.
On September 4, 1997, the PSC also issued for comment a Staff position
paper which proposes that LDCs exit their merchant function, i.e., cease to
supply the natural gas commodity to their existing customers, within five years
and that they eliminate or restructure transportation and storage capacity
contracts extending beyond five years so as to eliminate obligations beyond that
point, except where capacity is required to fulfill operational requirements or
the LDC's obligations as the "supplier of last resort" to customers having no
competitive alternative. If adopted by the PSC, the Staff proposal could
require the Company to remarket more capacity and to do so more rapidly than
currently contemplated. The comment period concluded on December 20, 1997, and
no prediction can be made as to whether the Staff proposal will be adopted or,
if so, the extent of its potential impact on the Company.
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, 1997,
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 year 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's petition
to the U.S. Court of Appeals was denied on January 16, 1998. The Company is
evaluating its next steps.
<PAGE>
65
LEASE AGREEMENTS
The Company leases five properties for administrative offices and
operating activities. The total lease expense charged to operations was $4.2
million, $3.9 million and $2.4 million in 1997, 1996 and 1995, respectively.
For the years 1998, 1999, 2000, 2001 and 2002 the estimated lease expense
charged to operations will be $4.1 million, $2.4 million, $2.4 million, $2.4
million and $2.4 million, respectively. Commitments under capital leases were
not significant to the accompanying financial statements.
LITIGATION
SPENT NUCLEAR FUEL LITIGATION. The Nuclear Waste Act (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. In
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's course of
action was in violation of its obligations under the Act, 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, 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. By letter dated December 17, 1996, DOE invited the parties to the
proceeding to provide written comments on how DOE's anticipated inability to
meet its January 31, 1998 obligation to begin accepting SNF could "best be
accommodated". The Company and a number of other parties responded to that
invitation. By Joint Petition for Review, dated January 31, 1997, the Company
and a number of other nuclear utilities petitioned the United States Court of
Appeals for the District of Columbia Circuit for a declaration that the
Petitioners were relieved of the obligation to pay fees into the Nuclear Waste
Fund, and authorized to place those fees into escrow when and until DOE
commences disposing of SNF. The Petition further requested that DOE be ordered
to develop a program that would enable it to begin acceptance of SNF by January
31, 1998. By Order dated November 14, 1997, the D. C. Circuit held that DOE
could not exercise delay in accepting fuel on grounds that it lacked an SNF
repository, and that the utilities had a "clear right to relief". Rather than
grant funding relief and order the DOE to move fuel, however, the Court referred
the utilities to the remedies set forth in their contracts with the DOE. The
Company is pursuing such remedies.
DEPARTMENT OF JUSTICE LAWSUIT. On June 24, 1997, the Antitrust
Division of the United States Department of Justice filed a civil complaint
against the Company in the United States District Court for the Western District
of New York. The complaint follows a Civil Investigative Demand investigation.
That investigation included a broad look at the Company's activities in the
electric power industry including initially, the Company's power purchase
agreement with an independent power producer. The investigation then focused
primarily upon the flexible rate long term contracts entered between the Company
and a number of its large customers under a tariff approved by the PSC. The
tariff and the PSC policies it implemented recognized that if large customers
took their electrical load off the system, the rates for remaining customers
would have to increase to cover the fixed costs of operation.
The Division in its complaint has challenged only certain provisions of one
flexible rate contract, the contract with the University of Rochester. The
Complaint alleges that those provisions in that contract violate Section 1 of
the Sherman Act by restricting the customer's right to compete with the Company
in the sale of electricity and seeks an injunction prohibiting the Company from
enforcing that contract and from entering other agreements that limit
competition in the sale of electricity to other customers.
<PAGE>
66
The Company believes that the investigation and the Complaint reflect the
desire by the Antitrust Division to become involved in the deregulation of
electric utilities, but that the proper way to do that is in the proceedings
before the PSC in the Competitive Opportunities Case.
On September 3, 1997, the Company filed its answer which denied the material
allegations of the Complaint. At the same time, the Company filed a Motion for
Summary Judgment asking the Court to dismiss the action with prejudice on the
grounds that the Company's actions are immune from antitrust liability under the
State action exemption, that the Company's actions did not injure competition
and that the Department of Justice's claims are speculative. On November 3,
1997, the Department of Justice filed its opposition to the Company's Motion for
Summary Judgment and filed its own Motion for Summary Judgement. The Company's
response to the Justice Department motion was filed on December 5, 1997.
These Motions for Summary Judgment were argued on December 19, 1997. In
Court, the parties agreed to a resolution of the dispute, suggested by the Judge
which, in the Company's opinion, would not have any material effect on its
contract with the University. The Antitrust Division, however, has expressed
its unwillingness to agree to a Consent Decree based on the agreement reached in
Court and the matter is still pending.
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
<PAGE>
67
laws. The complaint seeks damages in the amount of $420,000,000, when trebled,
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 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. As of June 16, 1997, the Company filed a Second Amended Complaint
in the State Court action asserting additional claims based on subsequent
occurrences.
On March 19, 1997, the Bankruptcy Court stayed the Adversary Proceeding
pending resolution of the contract issues in the New York State court trial.
Kamine has indicated it will not appeal this action.
On June 26, 1997, the defendants filed a Joint Notice of Removal of Action,
removing the action to the United States District Court for the Western District
of New York. There have been no further proceedings to date.
Numerous other procedural motions have been presented in the Bankruptcy
Court, some of which may now be considered by the New York State court. While
these proceedings are pending, the Company would pay approximately two cents per
kilowatt hour when the plant operates. It is not operating at the present time.
GENERAL ELECTRIC CAPITAL CORPORATION LAWSUIT. On July 3, 1997, General
Electric Capital Corporation (GECC) filed a complaint against the Company in the
United States District Court for the Western District of New York in connection
with the Kamine project in Hume, New York, for which GECC provided financing.
The complaint asserts that the Company violated the antitrust laws in its
dealings with Kamine and seeks injunctive relief, treble damages and alleged
actual damages of not less than $100,000,000. The claims made in the complaint
filed are substantially similar to the claims made by Kamine in the same court
under Kamine's version of the terms of the Power Purchase Agreement for the Hume
project. The court denied Kamine's motion for a preliminary injunction on
grounds which included Kamine's failure to establish a likelihood of success on
the merits of its claims. Kamine had filed a notice of appeal from a decision
denying Kamine's motion for a preliminary injunction. Kamine subsequently
withdrew the appeal. The Company believes the complaint by GECC is also without
merit and intends to defend the action.
<PAGE>
68
INTERIM FINANCIAL DATA
In the opinion of the Company, the following quarterly information includes
all adjustments, consisting of normal recurring adjustments, necessary for a
fair statement of the results of operations for such periods. The variations in
operations reported on a quarterly basis are a result of the seasonal nature of
the Company's business and the availability of surplus electricity. The sum of
the quarterly earnings per share may not equal the fiscal year earnings per
share due to rounding.
<TABLE>
<CAPTION>
(Thousands of Dollars)
Earnings per Common Share
Operating Operating Net Earnings on (in dollars)
Quarter Ended Revenues Income Income Common Stock Basic Diluted
<S> <C> <C> <C> <C> <C> <C>
December 31, 1997 $271,039 $24,406 $14,031 $12,726 $ .32 $ .32
September 30, 1997 221,335 34,616 21,724 20,419 .52 .52
June 30, 1997 229,419 31,125 18,172 16,681 .42 .42
March 31, 1997 314,845 55,194 41,433 39,729 1.02 1.02
December 31, 1996/1/ $274,431 $33,048 $22,228 $20,362 $0.52 $ .52
September 30, 1996 234,843 36,159 21,062 19,196 0.49 .49
June 30, 1996 235,577 23,115 11,732 9,866 0.25 .25
March 31, 1996 309,195 56,866 42,489 40,623 1.05 1.05
December 31, 1995/1,2/ $270,518 $32,324 $ (387) $(2,253) $(.05) $(.05)
September 30, 1995 245,145 41,738 26,934 25,068 .65 .65
June 30, 1995 219,546 29,454 14,861 12,995 .34 .34
March 31, 1995 281,119 46,557 30,520 28,653 .75 .75
</TABLE>
/1/ Reclassified for comparative purposes.
/2/ Includes recognition of $28.7 million net-of-tax gas settlement adjustment.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None
<PAGE>
69
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 15, 1998, will be set forth under the heading
"Election of Directors" in the Company's Definitive Proxy Statement for such
Annual Meeting of Shareholders.
The information required by Item 10 of Form 10-K with respect to executive
officers is, pursuant to instruction 3 of paragraph (b) of Item 401 of
Regulation S-K, set forth in Part I as Item 4-A of this Form 10-K under the
heading "Executive Officers of the Registrant".
Item 11. EXECUTIVE COMPENSATION
The information required by Item 11 of Form 10-K will be set forth under
the headings "Report of the Committee on Management on Executive Compensation",
"Executive Compensation" and "Pension Plan Table" in the Company's Definitive
Proxy Statement for the Annual Meeting of Shareholders.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 of Form 10-K will be set forth under
the headings "General" and "Security Ownership of Management" in the Company's
Definitive Proxy Statement for the Annual Meeting of Shareholders.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information required by Item 13 of Form 10-K will be set forth under
the heading "Election of Directors" in the Company's Definitive Proxy Statement
for the Annual Meeting of Shareholders.
Pursuant to General Instruction G(3) to Form 10-K, Items 10 through 13 have
not been answered because, within 120 days after the close of its fiscal year,
the Registrant will file with the Commission a definitive proxy statement
pursuant to Regulation 14A which involves the election of directors. Regis
trant's definitive proxy statement dated March 3, 1998 will be filed with the
Securities and Exchange Commission prior to April 30, 1998. 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 15, 1998 is not deemed to be filed as part of this
Report.
<PAGE>
70
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(a) 1. The financial statements listed below are shown under Item 8 of this
Report.
Report of Independent Accountants.
Consolidated Statement of Income for each of the three years ended
December 31, 1997.
Consolidated Statement of Retained Earnings for each of the three
years ended December 31, 1997.
Consolidated Balance sheet at December 31, 1997 and 1996.
Consolidated Statement of Cash Flows for each of the three years
ended December 31, 1997.
Notes to Consolidated Financial Statements.
(a) 2. Financial Statement Schedules - Included in Item 14 herein:
For each of the three years ended December 31, 1997.
Schedule II - Valuation and Qualifying Accounts.
(a) 3. Exhibits - See List of Exhibits.
(b) Reports on Form 8-K
The Company filed a Form 8-K dated December 5, 1997, reporting under Item
5, Other Events, approval by the PSC of the Company's Competitive Opportunities
Case Settlement with the PSC staff and other parties with respect to the
restructuring of the electric utility industry in New York State.
<PAGE>
71
ROCHESTER GAS AND ELECTRIC CORPORATION
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Thousands of Dollars)
FOR THE YEAR ENDED DECEMBER 31, 1995
<TABLE>
<CAPTION>
Additions
---------
Balance at Charged to Charged Balance
Beginning Costs and To Other at End
Descriptions of Period Expenses Accounts Deductions of Period
- ------------ ---------- -------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Reserves for:
Uncollectible accounts $950 $14,893 $3,893 $11,950
Materials and supplies
obsolescence 0 736 736
</TABLE>
FOR THE YEAR ENDED DECEMBER 31, 1996
<TABLE>
<CAPTION>
Additions
---------
Balance at Charged to Charged Balance
Beginning Costs and To Other at End
Descriptions of Period Expenses Accounts Deductions of Period
- ------------ ---------- -------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Reserves for:
Uncollectible accounts $11,950 $4,987 $ 565 $17,502
Materials and supplies
obsolescence 736 (375) 361
</TABLE>
FOR THE YEAR ENDED DECEMBER 31, 1997
<TABLE>
<CAPTION>
Additions
---------
Balance at Charged to Charged Balance
Beginning Costs and To Other at End
Descriptions of Period Expenses Accounts Deductions of Period
- ------------ ---------- -------- -------- ---------- ---------
<S> <C> <C> <C> <C> <C>
Reserves for:
Uncollectible accounts $17,502 $5,078 $4,346 $26,926
Materials and supplies
obsolescence 361 2,839 3,200
</TABLE>
Beginning in 1992 the Company no longer charges uncollectible expenses
through the uncollectible reserve. The total amount written off directly to
expense in 1995 was $8,170, in 1996 was $15,039 and in 1997 was $12,912.
<PAGE>
72
LIST OF EXHIBITS
Exhibit 3-1* Restated Certificate of Incorporation of Rochester Gas and
Electric Corporation under Section 807 of the Business
Corporation Law filed with the Secretary of State of the State of
New York on June 23, 1992. (Filed in Registration No. 33-49805 as
Exhibit 4-5 in July 1993)
Exhibit 3-2* Certificate of Amendment of the Certificate of Incorporation of
Rochester Gas and Electric Corporation Under Section 805 of the
Business Corporation Law filed with the Secretary of State of the
State of New York on March 18, 1994. (Filed as Exhibit 4 in May
1994 on Form 10-Q for the quarter ended March 31, 1994, SEC File
No. 1-672.)
Exhibit 3-3* By-Laws of the Company, as amended to date. (Filed as Exhibit 3-1
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.)
<PAGE>
73
Exhibit 10-3* Agreement dated September 25, 1984 between the Company and the
United States Department of Energy, as amended. (Filed as Exhibit
10-3 in February 1995 on Form 10-K for the year ended December
31, 1994, SEC File No. 1-672-2)
Exhibit 10-4* Agreement dated February 5, 1980 between the Company and the
Power Authority of the State of New York. (Filed as Exhibit 10-10
in February 1990 on Form 10-K for the year ended December 31,
1989, SEC File No. 1-672-2)
Exhibit 10-5* Agreement dated March 9, 1990 between the Company and Mellon
Bank, N.A. (Filed as Exhibit 10-1 in May 1990 on Form 10-Q for
the quarter ended March 31, 1990, SEC File No. 1-672)
Exhibit 10-6* Basic Agreement dated September 22, 1975 as amended and
supplemented between the Company and Niagara Mohawk Power
Corporation. (Filed as Exhibit 10-11 in February 1993 on Form
10-K for the year ended December 31, 1992, SEC File No. 1-672-2)
Exhibit 10-7* Operating Agreement effective January 1, 1993 among the owners of
the Nine Mile Point Nuclear Plant Unit No. 2. (Filed as Exhibit
10-12 in February 1993 on Form 10-K for the year ended December
31, 1992, SEC File No. 1-672-2)
Exhibit 10-8* (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. (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 10-12* (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) Change of Control Agreement dated January 1, 1998 between
the Company and Thomas S. Richards, Chairman of the Board,
President and Chief Executive Officer.
<PAGE>
74
Exhibit 10-15* (A) Change of Control 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 10-16* (A) Change of Control 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 10-17* (A) Change of Control Agreement dated January 2, 1997 between
the Company and Michael J. Bovalino, Senior Vice President,
Energy Services. (Filed as Exhibit 10-18 in February 1997
on Form 10-K for the year ended December 31, 1996, SEC File
No. 1-672-2)
Exhibit 10-18 Amended and Restated Settlement Agreement dated October 23,
1997 between the Company the Staff of the New York Public
Service Commission (PSC), and certain other parties (Filed
as Exhibit 10-4 on Form 10-Q for the quarter ended
September 30, 1997, SEC File No. 1-672) as amended pursuant
to an order of the PSC issued January 14, 1998 (excluding
Appendices) filed herewith.
Exhibit 10-19* (A) Form of Rochester Gas and Electric Corporation 1996
Performance Stock Option Plan Agreement. (Filed as Exhibit
10-1 in November 1997 on Form 10-Q for the quarter ended
September 30, 1997, SEC File No. 1-672)
Exhibit 10-20* (A) Agreement, dated October 1, 1997, between the Company and
Michael T. Tomaino, Senior Vice President and General
Counsel. (Filed as Exhibit 10-2 in November 1997 on Form
10-Q for the quarter ended September 30, 1997, SEC File
No. 1-672)
Exhibit 10-21* Agreement dated as of September 23,1997 between the Company
and International Business Machines Corporation. (Filed as
Exhibit 10-3 in November 1997 on Form 10-Q for the quarter
ended September 30, 1997, SEC File No. 1-672)
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.
<PAGE>
75
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ROCHESTER GAS AND ELECTRIC CORPORATION
By: /S/ THOMAS S. RICHARDS
---------------------------------
Thomas S. Richards
Chairman of the Board,
President and
Chief Executive Officer
DATE: February 11, 1998
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.
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- --------- ----- ----
<S> <C> <C>
Principal Executive Officer:
/S/ THOMAS S. RICHARDS Chairman of the Board, February 11, 1998
- ------------------------------- President and
(Thomas S. Richards) Chief Executive Officer
Principal Financial Officer:
/S/ J. B. STOKES Senior Vice President February 11, 1998
- ------------------------------- Corporate Services and
(J. Burt Stokes) Chief Financial Officer
Principal Accounting Officer:
/S/ WILLIAM J. REDDY Controller February 11, 1998
- -------------------------------
(William J. Reddy)
</TABLE>
<PAGE>
76
<TABLE>
<CAPTION>
SIGNATURE TITLE DATE
- --------- ----- ----
<S> <C> <C>
Directors:
/S/ WILLIAM BALDERSTON III Director February 11, 1998
- -------------------------------
(William Balderston III)
/S/ ANGELO J. CHIARELLA Director February 11, 1998
- -------------------------------
(Angelo J. Chiarella)
/S/ ALLAN E. DUGAN Director February 11, 1998
- -------------------------------
(Allan E. Dugan)
Director February , 1998
- -------------------------------
(Mark B. Grier)
/S/ SUSAN R. HOLLIDAY Director February 11, 1998
- -------------------------------
(Susan R. Holliday)
/S/ JAY T. HOLMES Director February 11, 1998
- -------------------------------
(Jay T. Holmes)
/S/ SAMUEL T. HUBBARD,JR Director February 11, 1998
- -------------------------------
(Samuel T. Hubbard, Jr.)
/S/ ROGER W. KOBER Director February 11, 1998
- -------------------------------
(Roger W. Kober)
/S/ CONSTANCE M. MITCHELL Director February 11, 1998
- -------------------------------
(Constance M. Mitchell)
/S/ CORNELIUS J. MURPHY Director February 11, 1998
- -------------------------------
(Cornelius J. Murphy)
/S/ CHARLES I. PLOSSER Director February 11, 1998
- --------------------------------
(Charles I. Plosser)
/S/ THOMAS S. RICHARDS Director February 11, 1998
- -------------------------------
(Thomas S. Richards)
</TABLE>
<PAGE>
EXHIBIT 10-14
ROCHESTER GAS AND ELECTRIC CORPORATION
SEVERANCE AGREEMENT
This Severance Agreement is made effective as of January 1, 1998, by and
between Rochester Gas and Electric Corporation, a New York corporation having
its principal place of business in Rochester, New York (the "Company"), and
Thomas S. Richards, an individual currently residing in Rochester, New York (the
- ------------------
"Employee"). As of January 1, 1998, this Agreement supersedes in its entirety
the Severance Agreement between the Company and the Employee that was effective
as of August 17, 1995.
1. Payment of Severance Amount. If the Employee's employment by the
Company or any subsidiary or successor of the Company shall be subject to a
Voluntary Termination or an Involuntary Termination within the Covered Period,
then the Company shall pay the Employee a lump sum amount equal to the
applicable Severance Amount, payable within 15 business days after the
Termination Date.
2. Definitions. All the terms defined in this paragraph 2 shall have the
meanings given below throughout this Agreement.
(a) "Annual Salary" shall, as determined on the Termination Date, be equal
to the greater of:
i. the Employee's annual salary plus bonus on the date of the earliest
Change of Control to occur during the Covered Period, or
ii. the Employee's annual salary plus bonus on the Termination Date.
Bonus for the purpose of this definition of Annual Salary shall mean the bonus
for the Employee's final year or the average of the bonuses for the last three
years, whichever is greater.
(b) "Change in Duties" shall mean any one or more of the following:
i. a significant change in the nature or scope of the Employee's
authorities or duties from those applicable to him immediately prior to the date
on which a Change of Control occurs;
ii. a reduction in the Employee's Annual Salary from that provided to him
immediately prior to the date on which a Change of Control occurs;
iii. a diminution in the Employee's eligibility to participate in bonus,
incentive award and other compensation plans which provide opportunities to
receive compensation, from the greater of:
. the opportunities provided by the Company (including its
subsidiaries) for executives with comparable duties; or
. the opportunities under any such plans under which he
<PAGE>
2
was participating immediately prior to the date on which a
Change of Control occurs;
iv. a diminution in employee benefits (including but not limited
to medical, dental, life insurance and long-term disability plans) and
perquisites applicable to the Employee, from the greater of:
. the employee benefits and perquisites provided by the
Company (including its subsidiaries), to executives with
comparable duties; or
. the employee benefits and perquisites to which the Employee
was entitled immediately prior to the date on which a
Change of Control occurs;
v. a change in the location of the Employee's principal place
of employment by the Company (including its subsidiaries) by more than fifty
miles from the location where he was principally employed immediately prior to
the date on which a Change of Control occurs; or
vi. a reasonable determination by the Board of Directors of the
Company that, as a result of a Change in Control and a change in circumstances
thereafter significantly affecting his position, he is unable to exercise the
authorities, powers, functions or duties attached to his position immediately
prior to the date on which a Change of Control occurs.
(c) a "Change of Control" shall be deemed to have occurred if:
i. any "person," including a "group" as determined in
accordance with the Section 13(d)(3) of the Securities Exchange Act of 1934 (the
"Exchange Act"), is or becomes the beneficial owner, directly or indirectly, of
securities of the Company representing 20 percent or more of the combined voting
power of the Company's then outstanding securities;
ii. as a result of, or in connection with, any tender offer or
exchange offer, merger or other business combination, sale of assets or
contested election, or any combination of the foregoing transactions (a
"Transaction"), the persons who were directors of the Company before the
transaction shall cease to constitute a majority of the Board of Directors of
the Company or any successor to the Company;
iii. the Company is merged or consolidated with another
corporation and as a result of the merger or consolidation less than 70 percent
of the outstanding voting securities of the surviving or resulting corporation
shall then be owned in the aggregate by the former stockholders of the Company,
other than (x) affiliates within the meaning of the Exchange Act or (y) any
party to the merger or consolidation;
iv. a tender offer or exchange offer is made and consummated for
the ownership of securities of the Company representing 20 percent or more of
the combined voting power of the Company's then outstanding voting securities;
or
v. the Company transfers substantially all of its assets to
another corporation which is not a wholly-owned subsidiary of the Company.
(d) "Covered Period" for the Employee shall mean a period of time
following the occurrence of the Change of Control equal to the lesser of (i) the
Employee's period of employment with the Company, any subsidiary, or
<PAGE>
3
any predecessor of either prior to that Change of Control, or (ii) two years
following the occurrence of the Change of Control.
(e) "Involuntary Termination" shall mean any termination which:
i. does not result from a resignation by the Employee (other
than a resignation pursuant to clause ii of this subparagraph (e)), or
ii. results from a resignation following any Change in Duties;
provided, however, the term "Involuntary Termination" shall not include:
x. a Termination for Cause, or
y. any termination as a result of death, disability, or
normal retirement pursuant to a retirement plan to which the Employee was
subject prior to any Change of Control.
(f) "Severance Amount" is equal to:
i. in the case of an Involuntary Termination, three (3) times
the Employee's Annual Salary, except if the Employee is within three years of
age 65 at the time of Involuntary Termination, the Severance Amount shall be
reduced to the number of whole months remaining to age 65, with a minimum
payment of one (1) times the Employee's Annual Salary; or
ii. in the case of a Voluntary Termination, one (1) times the
Employee's Annual Salary, except if the Employee is within one year of age 65 at
the time of Voluntary Termination, the Severance Amount shall be reduced to the
number of months remaining to age 65, with no minimum payment.
(g) "Termination for Cause" shall mean only a termination as a result
of fraud, misappropriation of or intentional material damage to the property or
business of the Company (including its subsidiaries), or commission of a felony
by the Employee.
(h) "Voluntary Termination" shall mean any termination which is not:
i. an Involuntary Termination;
ii. a Termination for Cause, or
iii. the result of death, disability, or normal retirement
pursuant to a retirement plan to which the Employee was subject prior to any
Change of Control.
(i) "Voting Securities" shall mean any securities which ordinarily
possess the power to vote in the election of directors without the happening of
any pre-condition or contingency.
(j) "Termination Date" shall mean the date on which the Employee's
employment terminates.
3. Golden Parachute Payment Reduction. It is anticipated that the
payments to be made to the Employee under this Agreement (and other agreements)
may become subject to the excise tax imposed by Section 4999 of the Internal
Revenue Code of 1986, as amended (the "Code") (or any similar tax
<PAGE>
4
that may hereafter be imposed), on account of "excess parachute payments" as
defined in Section 280G of the Code. The Employee and the Company agree that
the total Severance Amount payable under Section 2(f) of this Agreement shall be
the amount such that the Employee's net after-tax benefit of all such payments
is the greater of either (I) the largest amount that will avoid the imposition
of the excise tax, or (ii) the amount payable without regard to any such
limitation (and that will be subject to the imposition of the excise tax). The
term "net after-tax benefit" means the amount that would be left to the Employee
after the excise tax and federal and state income taxes. The determination of
the amount to be paid hereunder shall be made at the expense of the Company by
the independent certified public accounting firm acting as auditors for the
Company on the date of a Change of Control (or another accounting firm
designated by that firm).
4. Notices. Notices and all other communications under this Agreement
shall be in writing and shall be deemed given when personally delivered or when
mailed by United States registered or certified mail, return receipt requested,
postage prepaid, addressed as follows:
If to the Company, to:
Rochester Gas & Electric Corporation
89 East Avenue
Rochester, New York 14649-0001
ATTENTION: Group Manager Human Resource Services
If to the Employee, to:
Thomas S. Richards
-------------------------
57 Dorchester Road
-------------------------
Rochester, New York 14610
-------------------------
or to such other address as either party may furnish to the other in writing,
except that a notice of change of address shall be effective only upon receipt.
5. Applicable Law. This contract is entered into under, and shall be
governed for all purposes by, the laws of the State of New York.
6. Severability. If a court of competent jurisdiction determines that
any provision of this Agreement is invalid or unenforceable, then the invalidity
or unenforceability of that provision shall not affect the validity or
enforceability of any other provision of this Agreement and all other provisions
shall remain in full force and effect.
7. Withholding of Taxes. Company may withhold from any benefits payable
under this Agreement all Federal, state, city or other taxes as may be required
pursuant to any law, governmental regulation or ruling.
8. Not an Employment Agreement. Nothing in this Agreement shall give the
Employee any rights (or impose any obligations to continued employment by the
Company or any subsidiary or successor of the Company), nor shall it give the
Company any rights (or impose any obligations) for the continued performance of
duties by the Employee for the Company or any subsidiary or successor of the
Company.
<PAGE>
5
9. No Assignment. The Employee's right to receive payments or benefits
under this Agreement shall not be assignable or transferable, whether by pledge,
creation of a security interest or otherwise, other than a transfer by will or
by the laws of descent or distribution. In the event of any attempted
assignment or transfer contrary to this paragraph, the Company shall have no
liability to pay any amount so attempted to be assigned or transferred. This
Agreement shall inure to the benefit of and be enforceable by the Employee's
personal or legal representatives, executors, administrators, successors, heirs,
distributees, devisees and legatees.
10. Successors. This Agreement shall be binding upon and inure to the
benefit of the Company, its successors and assigns (including, without
limitation, any company into or with which the Company may merge or
consolidate). The Company agrees that it will not effect the sale or other
disposition of all or substantially all of its assets unless either (i) the
person or entity acquiring the assets or a substantial portion of the assets
shall expressly assume by an instrument in writing all duties and obligations of
the Company under this Agreement, or (ii) the Company shall provide, through the
establishment of a separate reserve for the payment in full of all amounts which
are, or may reasonably be expected to become, payable to the Employee under this
Agreement.
11. Indemnity and Release. In consideration for the cash payment provided
in paragraph 1 above, the Employee releases and discharges the Employer, its
officers, agents, employees, subsidiaries, and successors, from all claims of
any kind, which the Employee, or the Employee's agents, executors, heirs, or
assigns ever had or now have, whether known or unknown, up to and including the
date this Agreement is signed. This release includes, but is not limited to,
the following: any action or cause of action asserted or which could have been
asserted under the Age Discrimination in Employment Act of 1967, as amended,
Title VII of the Civil Rights Act of 1964, all state statutes related to
discrimination, the Employee Retirement Income Security Act or the Americans
With Disabilities Act; claims for wrongful discharge, unjust dismissal, or
constructive discharge; claims for breach of any alleged oral, written or
implied contract of employment; claims for salary or severance payments not
provided by this Agreement; claims for benefits; claims for attorneys fees; and
any other claims under any Federal, state or local statute, law, rule or
regulation; provided that in any event all such actions or claims relate to
employment or benefits matters.
IN EXECUTING THIS AGREEMENT, THE EMPLOYEE ACKNOWLEDGES THAT EMPLOYEE HAS
BEEN GIVEN AT LEAST TWENTY-ONE (21) DAYS IN WHICH TO CONSIDER SIGNING THIS
AGREEMENT AND THE RELEASE CONTAINED IN THIS PARAGRAPH 11. EMPLOYEE ACKNOWLEDGES
THE OPPORTUNITY TO CONSULT WITH AN ATTORNEY OF EMPLOYEE'S CHOICE CONCERNING THIS
AGREEMENT AND RELEASE. EMPLOYEE HAS CAREFULLY READ AND FULLY UNDERSTOOD ALL THE
PROVISIONS OF THIS AGREEMENT AND RELEASE, AND IS ENTERING INTO THIS AGREEMENT
AND RELEASE VOLUNTARILY. EMPLOYEE ACKNOWLEDGES THAT THE CONSIDERATION BEING
RECEIVED IN EXCHANGE FOR EXECUTING THIS AGREEMENT AND RELEASE IS GREATER THAN
THAT WHICH EMPLOYEE WOULD BE ENTITLED TO IN THE ABSENCE OF THIS AGREEMENT AND
RELEASE. EMPLOYEE HAS NOT RELIED UPON ANY REPRESENTATION OR STATEMENT, WRITTEN
OR ORAL, NOT SET FORTH IN THIS DOCUMENT. EMPLOYEE ACKNOWLEDGES THAT THIS
DOCUMENT SETS FORTH THE ENTIRE AGREEMENT WITH THE COMPANY AND THAT IT MAY NOT BE
CHANGED ORALLY. EMPLOYEE HAS THE RIGHT TO REVOKE THIS AGREEMENT WITHIN SEVEN
(7) DAYS OF SIGNING IT, AND THAT THIS AGREEMENT SHALL NOT BECOME EFFECTIVE OR
ENFORCEABLE UNTIL THIS SEVEN DAY PERIOD HAS EXPIRED.
<PAGE>
6
12. Term. This Agreement shall be effective as of the date first above
written and shall remain in effect until terminated by written agreement of both
parties. In the event of a Change of Control during the term of this Agreement,
this Agreement shall remain in effect for the Covered Period.
IN WITNESS WHEREOF, the parties have caused this Agreement to be executed
and delivered as of January 1, 1998.
ROCHESTER GAS AND ELECTRIC CORPORATION
By: J B STOKES
-----------------------------
Its: SR. V.P.
-----------------------------
By: THOMAS S. RICHARDS
-----------------------------
Employee
Thomas S. Richards
<PAGE>
Exhibit 10-18
STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
OPINION NO. 98-1
CASE 96-E-0898 - In the Matter of Rochester Gas and Electric
Corporation's Plans for Electric Rate/
Restructuring Pursuant to Opinion No. 96-12.
OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT
SUBJECT TO CONDITIONS AND CHANGES
Issued and Effective: January 14, 1998
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
----
<S> <C>
APPEARANCES
INTRODUCTION 1
PROCEDURAL HISTORY 2
Procedural Concerns 4
THE REVISED SETTLEMENT 5
REVENUE REQUIREMENT 10
Strandable Costs 10
Kamine Cost Recovery 15
Return on Equity 17
Gain on Sale of Generating Plants 21
SBC Funding 22
Other Proposals 23
REVENUE ALLOCATION AND RATE DESIGN 25
THE PROGRAM 30
Single Retailer Model 30
Implementation Schedule 31
Delivery Rates 34
Other Retail Access Issues 38
CORPORATE STRUCTURE 39
ENVIRONMENTAL MATTERS 41
MARKET POWER MITIGATION 42
FINDINGS UNDER SEQRA 43
CONCLUSION 46
ORDER 47
APPENDIX A
APPENDIX B
APPENDIX C
</TABLE>
<PAGE>
CASE 96-E-0898
APPEARANCES
-----------
FOR ROCHESTER GAS AND ELECTRIC CORPORATION:
Nixon, Hargrave, Devans & Doyle (by Robert J. Bird, Richard N. George,
and Stanley W. Widger, Jr., Esqs.), Clinton Square - P.O. Box 1051,
Rochester, New York 14603
FOR DEPARTMENT OF PUBLIC SERVICE STAFF:
Michelle Phillips, Esq., Three Empire State Plaza, Albany, New York
12223-1350
FOR ATTORNEY GENERAL OF THE STATE OF NEW YORK:
Glen C. King, Esq., The Capitol, Albany, New York 12247
FOR NEW YORK STATE CONSUMER PROTECTION BOARD:
Anne Curtin and James Warden, Esqs.,
99 Washington Avenue, Suite 1020, Albany,
New York 12210
FOR NEW YORK POWER AUTHORITY:
Eric J. Schmaler, Esq., 1633 Broadway, New York, New York 10019
FOR AMERICAN ASSOCIATION OF RETIRED PERSONS:
Ward, Sommer & Moore, LLC (by Douglas H. Ward, Esq.),
122 South Swan Street, Albany, New York 12210
FOR PUBLIC INTEREST INTERVENORS AND FOR PACE ENERGY PROJECT:
David Resnick, Esq., 78 North Broadway, White Plains,
New York 10606
FOR IPPNY:
Aaron Breidenbaugh, 291 Hudson Avenue, Albany, New York 12210
FOR ENRON TRADE & CAPITAL RESOURCES:
Read & Laniado (by Kevin Brocks, Esq.),
23 Eagle Street, Albany, New York 12207
-i-
<PAGE>
CASE 96-E-0898
APPEARANCES
-----------
FOR MULTIPLE INTERVENORS:
Couch, White, Brenner, Howard & Feigenbaum (by Robert M. Loughney, Esq.),
540 Broadway, P.O. Box 2222, Albany, New York 12201
FOR RETAIL COUNCIL OF NEW YORK:
Cohen, Dax & Koenig (by Paul Rapp, Esq.),
90 State Street, Albany, New York 12211
FOR WHEELED ELECTRIC POWER COMPANY:
Joel Blau, Esq., 32 Windsor Court, Delmar, New York 12054
FOR CONSOLIDATED EDISON COMPANY OF NEW YORK, INC.:
John F. Gallagher, Esq., 4 Irving Place, New York, New York 10003
FOR CONSOLIDATED NATURAL GAS COMPANIES:
Whiteman, Osterman & Hanna (by Michael Whiteman, Esq.),
One Commerce Plaza, Albany, New York 12260
FOR NEW YORK STATE ELECTRIC & GAS CORPORATION:
Huber Lawrence & Abell (by Andrew Fisher, Esq.),
605 Third Avenue, New York, New York 10158
PRO SE:
Jerome Bowe, 104 Brentwood Drive, Penfield, New York 14526
Charles A. Straka, 6 Oakwood Lane, Fairport, New York 14405
-ii-
<PAGE>
STATE OF NEW YORK
PUBLIC SERVICE COMMISSION
COMMISSIONERS:
John F. O'Mara, Chairman
Maureen O. Helmer
Thomas J. Dunleavy
CASE 96-E-0898 - In the Matter of Rochester Gas and Electric Corporation's
Plans for Electric Rate/ Restructuring Pursuant to Opinion No. 96-12.
OPINION NO. 98-1
OPINION AND ORDER ADOPTING TERMS OF SETTLEMENT
SUBJECT TO CONDITIONS AND CHANGES
(Issued and Effective January 14, 1998)
BY THE COMMISSION:
INTRODUCTION
------------
This proceeding concerns issues related to rates and the restructuring of
the electric utility industry for Rochester Gas and Electric Corporation (RG&E
or the company). Interested parties were encouraged to reach a negotiated
resolution of the complex issues raised by the transition to a competitive
market for the supply of electricity./1/
After filing a Settlement Agreement dated April 8, 1997 (April 8
Settlement), the parties proposed further revisions to resolve concerns
identified by us at our October 8, 1997 session. These further revisions were
reflected in an Amended and Restated Settlement Agreement (Revised Settlement)
dated October 23, 1997 reached by RG&E, Department of Public Service Staff
(Staff), Multiple Intervenors, Joint Supporters, and the National Association of
Energy Service Companies. After careful review of the April 8 Settlement, the
Revised Settlement, the comments received, the evidence, and arguments in this
proceeding, we
/1/ Cases 94-E-0952 et al., In the Matter of Competitive Opportunities
-- --- ------------------------------------------
Regarding Electric Service, Order Establishing Procedures and Schedule (issued
- --------------------------
October 9, 1996), p. 3, (October 9 Order).
<PAGE>
CASE 96-E-0898
issued an order adopting the Revised Settlement subject to certain conditions
and changes./1/
The findings and decision made in that order are hereby incorporated, and
this opinion describes the bases for our decision.
PROCEDURAL HISTORY
------------------
Opinion No. 96-12/2/ required five of the State's electric utilities to
file plans to bring to New York State consumers the benefits of a competitive
electricity market. In compliance with that opinion and order, RG&E submitted
its plan on October 1, 1996.
Considerable public comment on the April 8 Settlement was received
through educational forums, public statement hearings,/3/ and consumer
correspondence. While the comments generally supported our goals for a
competitive marketplace, four areas of concern were identified by the public:
system and service reliability; the impact of competition on low- and fixed-
income consumers; the effect of strandable costs on rates; and the need for
consumer education.
Concerns were also expressed about the relatively smaller revenue
decreases for residential and small commercial customers; the increase in the
residential and small commercial customers' monthly customer charge, which would
have resulted in an overall bill increase for roughly 43% of the residential
customers; the failure to quantify and require sharing of strandable costs,
which it was alleged would have justified
- ----------------------
/1/ Case 96-E-0898, Order Adopting Terms of Settlement Subject to Conditions
and Changes (issued November 26, 1997) (November 26 Order).
/2/ Cases 94-E-0952 et al., In the Matter of Competitive Opportunities
-- --- ------------------------------------------
Regarding Electric Service, Opinion No. 96-12 (issued May 20, 1996).
--------------------------
/3/ Educational forums and public statement hearings were held on May 28 and
29, 1997 in Canandaigua and Rochester, respectively.
2
<PAGE>
CASE 96-E-0898
further rate reductions; the slow pace of conversion to retail access--about
five years; and the lack of a system to decide who would be afforded retail
access first.
Evidentiary hearings on the April 8 Settlement were held from June 3
through June 5, 1997; the record contains 2,029 transcript pages (Tr.) and 82
exhibits. In addition, statements and briefs in support of or in opposition to
the April 8 Settlement were submitted by numerous parties.
On July 16, 1997, a recommended decision by Administrative Law Judge
Walter T. Moynihan was issued, which generally supported adoption of the April 8
Settlement. Briefs and/or reply briefs on exceptions were received from RG&E;
Staff; Joint Supporters; the Department of Law (Attorney General);/1/ Multiple
Intervenors; State Consumer Protection Board (CPB); New York Power Authority
(NYPA); American Association of Retired Persons (AARP); Public Interest
Intervenors (PII), a broad-based umbrella coalition comprising 18 consumer and
environmental organizations; Public Utility Law Project of New York, Inc.
(PULP), a not-for-profit public interest firm representing the interests of low-
income residential consumers; Retail Council of New York (Retail Council), an
association of nearly 5,000 retail enterprises in New York State; Independent
Power Producers of New York, Inc. and Enron Capital & Trade Resources
(IPPNY/Enron), Wheeled Electric Power Company (WEPCO), independent power
marketers; and Mr. Jerome P. Bowe, a pro se intervenor.
--- --
After reviewing the recommended decision and the parties' exceptions, we
requested the parties to renegotiate the terms of the April 8 Settlement/2/ to:
achieve greater rate reductions for residential and other small customers;
consider ameliorating the impacts of the proposed increase in the monthly
customer charge; increase the ratepayers' share of possible excessive earnings
and gains on the sale of generating units,
- -------------------
/1/ Appendix A is a list of abbreviations used in this document.
/2/ These issues were discussed at our session on October 8, 1997.
3
<PAGE>
CASE 96-E-0898
while still encouraging divestiture; accelerate the pace of retail access if
warranted; increase the back-out rate during the Energy Only stage of retail
access; and establish minimum spending limits for the system benefits charge
(SBC).
As a result of further negotiations, the Revised Settlement was filed and
parties were invited to submit further written comments./1/ Thirteen parties
submitted comments/2/ including the five signatories to the Revised Settlement
and eight others that oppose its adoption.
In our November 26 Order, we found that with certain modifications the
terms of the Revised Settlement offer a sound regulatory framework for RG&E, its
competitors, and its customers in the transition to fully competitive generation
and energy service markets.
Procedural Concerns
- -------------------
The recommended decision rejected an argument that most of the active
parties were unfairly or improperly excluded from discussions among Staff, the
company, CPB, and Multiple Intervenors. The recommended decision observed that
we waived in part our settlement guidelines/3/ in the instant case to enhance
the parties' ability to be creative and communicate freely./4/ Thus, the
recommended decision concluded the caucusing among some parties was not
proscribed, and the April 8 Settlement should not be rejected or modified based
on this procedural argument.
AARP and Mr. Bowe except, arguing the April 8 Settlement was reached as a
result of procedures that denied parties a meaningful opportunity to
participate. AARP also
- -------------------
/1/ Case 96-E-0898, Notice Inviting Comments on Proposed Settlement (issued
October 24, 1997).
/2/ Appendix B is a list of the parties who filed comments.
/3/ Cases 90-M-0255 et al., Settlement Procedures and Guidelines, Opinion No.
-- --- -------------------------------------
92-2 (issued March 24, 1992), Appendix B, p. 4 (guideline B.(3)).
/4/ October 9 Order.
4
<PAGE>
CASE 96-E-0898
asserts that, because we truncated important procedures, the April 8 Settlement
should be rejected. RG&E replies that earlier negotiations were unproductive
when all parties were present.
The procedures followed in this case have afforded all parties ample
opportunities to shape the decisions reached in this case. As the recommended
decision notes, we waived our settlement guidelines to permit caucusing to
enhance the parties' ability to be creative, communicate freely, and reach an
expeditiously negotiated resolution. The waiver of the guidelines permitted not
only the caucusing mentioned above, but also discussions among Staff and other
parties. As a result of the caucusing, a draft agreement was prepared and
circulated among all the parties. After further negotiations, at which all
parties had an opportunity to attend, modifications were incorporated in the
agreement based on the various parties' comments. This modified agreement is
the April 8 Settlement. In addition, all parties were afforded an opportunity
to conduct discovery, present testimony and pre-hearing position papers, cross-
examine witnesses, submit post-hearing briefs, and file briefs on and opposing
exceptions to Judge Moynihan's recommended decision. Moreover, all parties were
given a further opportunity to comment on the Revised Settlement. These
procedural steps gave each party a reasonable opportunity to participate.
Consequently, AARP's and Mr. Bowe's procedural exceptions are denied.
THE REVISED SETTLEMENT
----------------------
Generally, the Revised Settlement is intended to resolve all issues in
this proceeding. In addition to a number of miscellaneous provisions, the
Revised Settlement addresses three main topics: rate reductions, retail access,
and corporate restructuring. The Revised Settlement would establish electric
rates for a five-year period (July 1, 1997 through June 30, 2002) at levels that
are, overall, below their current levels. While rates for all customer classes
would be reduced, large industrial and commercial customers would receive the
biggest decreases.
5
<PAGE>
CASE 96-E-0898
The Revised Settlement calls for rate reductions in each of five years
culminating in a net $40.6 million (6.1%) decrease in RG&E's electric revenues
in the fifth year as compared with rates in effect on July 1, 1996. The
cumulative revenue decrease, subject to certain contingencies discussed infra,
-----
would be $101.6 million. In addition, RG&E would forgo $73 million of incentive
payments and lost net revenues otherwise due it arising from discounts contained
in its flex-rate contracts.
The rates to be established to produce the foregoing revenue reductions
would not be modified to reflect changes in revenues or expense, state and local
taxes (other than gross receipts taxes and property taxes) and asset sales
during the term of the Revised Settlement except for the following items, some
of which are the subject of exceptions as more fully discussed infra:
-----
a. Kamine/Besicorp - Allegany L.P. (Kamine) recovery;
b. Variations in the levels of mandated relief;
c. Securitization benefits;
d. Deferrals; and
e. Adjustments
Except for changes arising from a mandated SBC and securitization, which
would be reflected in rates without any limitations, rates will only be changed
if the pre-tax net effect of all other such items, on a projected cumulative
basis during the term of the Revised Settlement, would be greater than $30
million. However, no such rate adjustment would be made in rate years/1/ one or
two, and adjustments in the final three rate years would be subject to monetary
limitations, which ensure that
- --------------------
/1/ A rate year is a one-year period commencing on July 1 of one calendar year
and terminating on June 30 of the following calendar year.
6
<PAGE>
CASE 96-E-0898
there would be rate decreases during the five years. Any amounts that are not
recovered as a consequence of the monetary limitations may be deferred.
Generally, the Revised Settlement provides that the revenue decreases
would be allocated to RG&E's service classes based on their responsibility for
generation costs. The proposed revenue reductions are in addition to the base
rate reductions and the elimination of fuel adjustment charges effective July 1,
1996, in accordance with a settlement agreement (1996 Settlement) that we
approved with modifications./1/ Pursuant to the 1996 Settlement, the total
reductions for the 12 months ended June 30, 1997 approximated 2.5% for
residential customers and 4.5% for non-residential customers./2/
Several specific rate design changes are also set forth in the Revised
Settlement, including a proposed yearly $1.50 increase in the monthly customer
charge for the residential and small business customers, elimination of the
difference between the peak and shoulder-peak energy charges as of July 1, 1997
for large industrial customers, and modification of the energy audit requirement
in the flex-rate tariffs. In addition, beginning July 1, 1999 and continuing
through June 30, 2002, certain incremental manufacturing load of at least 50 kW
would be served at an average rate of $0.059 per kWh. All other changes in
revenues would be allocated uniformly within each service classification.
With respect to the Retail Access Program (Program), the Revised
Settlement requires RG&E to open its electric system to competition at a pace
such that all retail customers would be
- -------------------
/1/ Cases 95-E-0673 et al., Rochester Gas and Electric Corporation, Order
-- --- --------------------------------------
Approving Terms of Settlement Agreement With Changes (issued June 27,
1996), which was restated in Cases 95-E-0673 et al., Opinion No. 96-27
-- ---
(issued September 26, 1996). Our modification of the 1996 Settlement is the
subject of an Article 78 proceeding that will be terminated upon approval
of the pending Revised Settlement.
/2/ These decreases reduced the company's revenues by $23 million annually.
7
<PAGE>
CASE 96-E-0898
allowed to choose their own supplier of energy and capacity by July 1, 2002.
The signatories recognize that RG&E's ability to undertake the Program is
contingent upon factors such as a functioning statewide energy and capacity
market, which are not in the direct control of the company. They agree to
modify the Program, if necessary, to account for such factors, and to address
such matters in good faith.
The Revised Settlement would adopt a single-retailer model, which would
allow a Load Serving Entity (LSE)/1/ to purchase power on the open market and
distribution access from RG&E. The LSE would market the power to customers/2/
and be responsible for scheduling deliveries.
The Program would be deployed in stages. In the Energy Only stage, which
would commence on July 1, 1998, customers (up to 10% of the systemwide energy
sales of 6,714 gWh) would be able to choose their own supplier of electric
energy. The back-out rate during this stage is estimated to be approximately
$.019 per kWh./3/ On July 1, 1999, the Energy and Capacity stage would be
introduced, which would permit customers using up to 20% of the total energy to
choose their own supplier of energy and capacity. The back-out rate for this
stage, $.032 per kWh, is generally equal to the variable costs and specified
fixed costs that RG&E incurs to produce power from its fossil and hydro
generating units and from power purchased (other than from Kamine). On July 1
of the following two years, the Program would be expanded to include 30% and 46%
of the energy, and on July 1, 2002 all of
- ----------------
/1/ An LSE is analogous to the energy services company (ESCO) in a two-retailer
model.
/2/ An individual customer could qualify as an LSE and procure energy to meet
its own needs.
/3/ The Revised Settlement calls for a back-out rate of $.004 per kWh for
retailing costs plus an allowance of $.01905 per kWh as the value of energy
(equivalent to the company's buy-back rate). Thus, RG&E would deduct a
total of approximately $.02305 per kWh from bundled rates during the
Energy Only stage.
8
<PAGE>
CASE 96-E-0898
the company's energy. The schedule may be accelerated if the market price for
power exceeds $.032 per kWh on a persistent and sustained basis during the
Energy and Capacity stage. Also, to the extent that energy consumption by end-
use customers grows beyond a level of 6,714 gWh, the energy caps on eligibility
will be increased by the amount of additional consumption.
As for corporate restructuring, RG&E would functionally divide existing
operations into the following activity-based units: distribution unit (DISCO),
generating unit (GENCO), regulated load service entity (RLSE), and, at its
option, a functionally separate holding company (HOLDCO). The company would
also create a structurally separate unregulated load serving entity (ULSE). The
ULSE would be an energy marketer and provider of other energy services both
within and outside RG&E's DISCO service territory.
The DISCO would continue RG&E's transmission and distribution service,
which would be provided to the ULSE and the RLSE pursuant to regulated tariffs.
The GENCO would be responsible for operating RG&E's generating facilities.
RG&E's GENCO would consist of a portfolio of nuclear and non-nuclear sources.
The output from nuclear sources would be "dedicated" to regulated load, which is
subject to change to conform with the outcome of any separate statewide
proceeding on nuclear issues. Output from non-nuclear sources (which would
initially serve regulated load) would serve load on a competitively priced basis
as customers migrate away from the RLSE. The RLSE would continue to serve as a
provider of last resort (POLR) and provide bundled service under tariffs to
customers who elect to continue receiving bundled service or who do not have a
practicable alternative. In addition, RG&E would commit to working with Staff
to develop an experimental alternative to provide POLR service on a competitive
basis.
The Revised Settlement also provides for continuation of a program to
assist low-income customers and a service quality program to maintain safe and
reliable service. Further, the
9
<PAGE>
CASE 96-E-0898
Revised Settlement responds to our directive/1/ to introduce retail access to
farm and food processor customers on an expedited basis and affects three
pending appeals of our prior decisions concerning RG&E./2/ Finally, except as
expressly provided otherwise, the Revised Settlement would supersede the 1996
Settlement.
Parties took a number of exceptions to the recommended decision and
submitted comments on the Revised Settlement. In addition, we imposed
conditions and changes in our November 26 Order before adopting the Revised
Settlement. Inasmuch as issues were raised at various stages, this opinion will
address the parties' exceptions as stated in their briefs on exceptions and
briefs opposing exceptions (where relevant), any corresponding revisions made in
the Revised Settlement, the parties' comments on these revisions, and the
conditions as stated in our November 26 Order.
REVENUE REQUIREMENT
-------------------
Strandable Costs
- ----------------
For the five-year term of the April 8 Settlement (and the Revised
Settlement), RG&E's tariff rates are presumed to include all prudently incurred
investment in electric plant and electric regulatory assets (sunk costs) as of
March 1, 1997.
- -----------------------
/1/ Cases 96-E-0948 et al., Petition of Dairylea Cooperative Inc., Order
-- --- -------------------------------------
Concerning Retail Access Proposals (issued February 25, 1997).
/2/ RG&E will petition the court for permission to withdraw (1) as a party to
the appeal in the Article 78 proceeding brought to challenge Opinion
No. 96-12, Energy Association v. Public Service Commission (Sup. Ct.
-----------------------------------------------
Albany Co. Index No. 5830-96); (2) the company's pending Article 78
proceeding Rochester Gas and Electric Corporation v. Public Service
--------------------------------------------------------
Commission (Sup. Ct. Albany Co. Index No. 6616-96). (In the latter case,
----------
we rejected the 1996 Settlement's Kamine provisions); and (3) the
company's pending Article 78 proceeding Rochester Gas and Electric
--------------------------
Corporation v. Public Service Commission (Sup. Ct. Albany Co.
-----------------------------------------
Index No. 6531-97) brought to challenge our June 23, 1997 Order
Establishing Retail Access Pilot Programs in Cases 96-E-0948 et al.
-- ---
10
<PAGE>
CASE 96-E-0898
Rates would be reduced without identifying cost savings. Thus, neither RG&E's
rates for full service nor its rates for unbundled service would reflect any
savings specifically identified as arising from the exclusion of strandable
costs, but the company must manage its business to reduce costs in line with the
revenue reductions in order to maintain its rate of return.
In addition, for those customers who choose to purchase power in the
competitive market, there may be additional cost savings. These customers can
avoid paying RG&E's back-out energy, capacity, and retailing rate of $.032 per
kWh and pay the market price for such power. They would reap the savings from
lower priced market power and RG&E's stockholders would bear the loss if the
company were unable to reduce its generating cost to the market price.
In the Revised Settlement, the signatories agreed to meet prior to July
1, 2000 (one year earlier than agreed to in the April 8 Settlement) to discuss
future ratemaking treatment for sunk costs. In addition, at the end of the
five-year term, there may be funds available to offset some of the sunk costs.
These funds could come from earnings in excess of the allowed rate of return on
equity, unused funds set aside to match a potential liability for Kamine (both
discussed more fully infra), and, if we approve, the customers' share of any
-----
gains on the sale of generating plants.
In the meantime, both the April 8 Settlement and the Revised Settlement
provide that the costs of RG&E's nuclear generating facilities, Ginna Station
and the company's 14% share of Nine Mile Point 2, would be recovered in retail
rates at least through 1999. RG&E further commits to participate in good-faith
negotiations with Staff and with the other cotenants of Nine Mile Point 2
regarding future rate treatment of this facility. The signatories anticipate
that similar treatment will be applied to Ginna Station.
For the non-nuclear generating facilities, both agreements address the
"fixed" and "variable" portions of RG&E's fossil generating units, hydroelectric
generating units, gas
11
<PAGE>
CASE 96-E-0898
turbines, and power purchase contracts (other than Kamine), collectively known
as the "To-Go Costs." In the Energy Only stage, the company would allow $.01905
per kWh as the estimated market value for energy provided and would agree to
sell to retailers at this rate. With an allowance of $.004 per kWh for
retailing costs, the allowance would be $.02305 per kWh, which is greater than
the estimated $.013 per kWh in the April 8 Settlement. The variable portion of
the To-Go Costs would be subject to the market for electricity commencing July
1, 1998, the start of the Energy Only stage.
The fixed portion of such costs is the remainder of all To-Go Costs not
defined as variable. The fixed portion comprises all capital costs incurred
after February 28, 1997, O&M expenses, and property, payroll and other taxes.
The fixed portion of the To-Go Costs are assumed to be recovered in full through
the company's distribution access tariff until July 1, 1999, the start of the
Energy and Capacity stage, after which recovery of the combined fixed and
variable To-Go Costs and retailing costs, a total of $.032 per kWh, would be
subject to competition.
The recommended decision did not include specific estimates of strandable
costs in the computation of RG&E's revenue requirement. According to the
recommended decision, studies of RG&E's strandable costs are speculative at
present because of the lack of a competitive market for electricity. The
recommended decision also noted that the April 8 Settlement calls for rate
reductions without specifying an estimate of strandable costs and allows for
future consideration of such costs when some of the variables, such as the
actual market price for electricity, will be known.
The recommended decision also pointed out that, except for nuclear power
and Kamine purchases, the recovery of the remaining half of RG&E's To-Go Costs
for generation would depend upon the company's ability to compete with outside
sources of power. If the competitive prices are lower than RG&E's back-out
rates, customers who purchase that power will automatically enjoy
12
<PAGE>
CASE 96-E-0898
the benefits and stockholders will bear the effects of the revenue loss.
Several parties except, insisting that strandable costs should be
calculated now and that further rate reductions should be authorized by
disallowing a portion of the strandable costs. AARP renews its claim that
strandable costs amount to $800 million to $940 million, and AARP calls for an
equal sharing of strandable costs between ratepayers and stockholders unless the
financial integrity of RG&E is in jeopardy or legislation is passed prohibiting
sharing.
AARP maintains the recommended decision is inconsistent with Opinion No.
96-12, which stated that strandable costs should be allocated through a "careful
balancing of interests and expectations"; that "innovative means must be used to
reduce the amount of strandable costs before they are considered for recovery";
and that these costs should be "recovered with an eye to lowering rates, [and]
fostering economic development. . . ."/1/
According to AARP, the recommended decision admits that the April 8
Settlement is not supported by substantial evidence of the amount of strandable
costs because the signatories did not estimate them and they did not set forth
how such costs will be estimated in the future.
CPB reiterates its estimated range of $1,200 million to $1,500 million
for strandable costs, but notes that a precise estimate of strandable costs is
not needed to require immediate rate reductions of up to ten percent. CPB also
claims that the recommended decision fails to recognize that the disparities
between competitive electric prices and current rates will be at their zenith
over the next several years, which should be taken advantage of to reduce rates.
Finally, CPB responds to various criticisms of its strandable cost proposal by
noting that (1) with respect to bond ratings, CPB would limit its strandable
cost disallowance to maintain an equity ratio of at least 40%,
- -------------------
/1/ Cases 94-E-0952 et al., supra, Opinion No. 96-12, mimeo pp. 89-90.
-- --- -----
13
<PAGE>
CASE 96-E-0898
and (2) with respect to sharing, CPB's proposals would allocate 30% of the total
strandable costs to RG&E's shareholders.
RG&E and Staff support the recommended decision's conclusions with
respect to strandable costs. They point out that the April 8 Settlement does
not guarantee recovery of strandable costs; and note that approximately $155
million in cumulative rate reductions and forgone credits are called for in the
April 8 Settlement without specifying how the company is to reduce its costs.
The comparable figure for the Revised Settlement is $174.6 million.
Staff explains that the strandable cost studies submitted by CPB and AARP
contain data and computational errors that render them unreliable as a basis for
modifying the April 8 Settlement. An example of the errors contained in the
studies that staff observed is AARP's reliance upon 1995 data, which does not
provide an accurate representation of the costs of the Kamine purchased power
contract. The omission of the Kamine contract costs alone, staff suggests,
could increase strandable costs by over $101 million, and a double count of
regulatory assets would decrease strandable costs by $210 million. On the other
hand, Staff notes that the April 8 Settlement provides meaningful rate
reductions, strong incentives to mitigate costs, including strandable costs, and
powerful incentives for RG&E to manage its operations efficiently and
aggressively.
RG&E argues that CPB's position is consistent with its advocacy of
confiscating investors' funds in order to provide a short-term benefit today for
customers, regardless of the long-term consequences. For example, RG&E
maintains that it would suffer a bond downgrading were CPB's proposals to be
implemented, and that its stock value would decline significantly. RG&E points
to the stocks of utilities in Texas, which suffered a significant and immediate
drop in prices when the Texas commission announced that those utilities would
have to write off a portion of strandable costs. Likewise, the company cites a
50% decline in the stock price and a bond downgrading of the parent company of
Public Service Company of New Hampshire when that
14
<PAGE>
CASE 96-E-0898
state's commission announced the utility would have to absorb some strandable
costs.
In comments on the Revised Settlement, the Retail Council repeats the
calls for a current estimation of stranded costs, in order to justify further
rate relief.
We find reasonable the Revised Settlement's treatment of strandable
costs. First, by including in the back-out rate a component for the fixed
portion of the To-Go Costs, RG&E's customers have a meaningful opportunity to
avoid the equivalent of some of RG&E's strandable costs if they can purchase
electric power on the market at a price below the back-out rate. In addition,
the Revised Settlement calls for rate reductions and the relinquishment of other
benefits without specifying how RG&E is to achieve the complementary savings
needed so that it can maintain its overall rate of return. The Revised
Settlement also requires the parties to meet prior to July 1, 2000 to discuss
the future ratemaking treatment of RG&E's sunk costs. Finally, the exceptions
calling for an immediate estimate of strandable costs are denied because the
estimates proffered on the record contain data and computational errors.
Kamine Cost Recovery
- --------------------
RG&E is involved in litigation pertaining to its power purchase from
facilities owned by Kamine. The April 8 Settlement's Kamine recovery provisions
permit RG&E to set aside $33.2 million ($32.9 million in the Revised Settlement)
over the five-year term to cover costs related to resolution of the litigation.
Assuming a settlement of the Kamine litigation, RG&E would be allowed to
continue after July 1, 2002 to reflect in rates $10.6 million per year ($10.5
million in the Revised Settlement) until the cost of that settlement is
recovered.
However, if no settlement were reached and RG&E were obligated to pay,
RG&E would be permitted to recover from ratepayers up to seven-eights of the
cost of the maximum output of Kamine during the five-year term, less amounts
already accrued and any securitization benefits forthcoming. Also the
15
<PAGE>
CASE 96-E-0898
$10.6 million ($10.5 million under the Revised Settlement) automatic recovery
would end at the termination of the five-year term. The unrecovered balance, if
any, would be deferred for future recovery, and we would determine the timing of
future recovery.
The recommended decision supports the April 8 Settlement's treatment of
the Kamine dispute. The recommended decision also pointed out that, in the
absence of a settlement of that dispute, there are limits on the immediate rate
impacts of Kamine cost recovery, and recovery of Kamine costs on a long term
basis may be subject to the forces of a competitive market for electricity. For
these reasons, the Judge recommended approval of the Kamine cost recovery
provisions.
CPB excepts, contending footnote 31 of the April 8 Settlement limits the
company to recovery of prudent and verifiable costs, and that any court ordered
damage payments could be, but should not be, recovered in rates. In addition,
CPB notes that, if the Kamine dispute is settled, RG&E would be entitled to 100%
recovery of strandable Kamine costs. CPB requests that this provision be
clarified to assure recovery only if the total cost of the settlement is less
than the Kamine contract price.
The Attorney General argues that there should be no automatic recovery of
Kamine costs, and that we should insist on a prudence review of all payments to
Kamine.
RG&E responds that it has steadfastly pursued all available avenues to
relieve its customers of the burden they would bear if the Kamine contract were
enforced. In the process, it states, the company has saved its customers tens
of millions of dollars. It criticizes CPB's suggestion that it should continue
to devote its resources to avoiding excessive Kamine power costs, while bearing
the entire risk of damages, as "the ultimate form of cynical, one-way-street
regulation." With respect to CPB's second point, RG&E does not anticipate
settling the contractual claim for an amount greater than that payable under the
contract.
16
<PAGE>
CASE 96-E-0898
At our October 8, 1997 session, we noted our discretion to reduce rates
during the five-year term if it becomes clear that the Kamine cost recovery
clause would recover more funds than needed to resolve the contract dispute.
The Revised Settlement expressly acknowledges that discretion. In comments on
the Revised Settlement, RG&E, Staff, CPB, and Multiple Intervenors maintain this
flow-through provision is reasonable. Further, as alluded to above, footnote 31
states specifically "[n]o cost referenced in this [Revised] Settlement may be
considered for recovery, true-up or deferral unless it is prudent and
verifiable."
Return on Equity
- ----------------
Under the April 8 Settlement, if RG&E achieves a return on common equity
for its regulated operations in excess of 11.80% for the entire five-year term,
the company would be entitled to retain 50% of the amount in excess of 11.80%
and to use the remaining 50% to write down accumulated deferrals or sunk costs.
The recommended decision found these provisions reasonable. It noted that CPB's
proposed 10.2% return on equity did not include a stayout premium, which at the
time was computed to be 1.44% based on the spread between the June 1997 treasury
bills and May 2002 treasury bonds. The recommended decision noted that adding a
stayout premium to CPB's return would increase it to 11.64%, close to the April
8 Settlement's sharing threshold.
CPB, the Attorney General, and the Retail Council take exceptions. CPB
claims that its proposed 10.2% return on equity should be used as the sharing
threshold. CPB's 10.2% equity return was based on discounted cash flow, capital
asset pricing model, comparable earnings, and risk premium methods. CPB also
contends the recommended decision miscalculated the stayout premium. Citing the
recommended decision in the Generic Finance Proceeding (Case 91-G-0509), CPB
claims the premium should be based on one-half of the spread, which it says
would reduce the recommended decision's figure from 11.64% to 10.92%.
17
<PAGE>
CASE 96-E-0898
CPB also renews its call for different sharing of earnings over the
threshold, with 50% to write down strandable costs, 25% for the stockholders and
25% for the ratepayers for earnings in excess of 10.2%. It proposes this
computation be performed annually instead of for five years.
The Attorney General supports continuation of the 11.2% sharing threshold
in the 1996 Settlement, contending RG&E will assume little additional risk as a
result of the introduction of competition.
The Retail Council calls for the flow through of all excess earnings to
ratepayers. According to it, the April 8 Settlement gives 100% of excess
earnings to stockholders because the portion that would be used for write downs
is simply a return of capital to shareholders. The Retail Council argues we
should reject the concept of a "regulatory compact," which it sees as
guaranteeing shareholder recovery of all past investments.
RG&E responds that CPB's proposed 10.2% return on equity is about 130
basis points below the average allowed returns for electric utilities in the
fourth quarter of 1996 and first quarter of 1997. Also RG&E observes that CPB's
implied spread over bond yields is about 160 basis points, which is less than
that employed in the Generic Finance Proceeding, where a 350 basis point risk
premium above the utilities' bond yields was generally employed and 250 basis
points was considered the low-end of the range. RG&E conducted its own studies
and concludes that its current cost of equity is between 11.95% and 12.20%.
Moreover, RG&E points out that CPB's strandable cost proposal would
weaken the company's financial position by lowering its equity ratio and
increasing its risk, which could lead to a decline in its bond ratings. RG&E
suggests its equity ratio would be reduced from the existing 49% to 36.3% if
CPB's total rate base disallowances were adopted.
Finally, RG&E observes that CPB's proposed allocation of excess earnings
on an annual basis would be unfairly asymmetrical because excess earnings in
good years would be shared with the ratepayers but earnings shortfalls in bad
years
18
<PAGE>
CASE 96-E-0898
would be completely absorbed by the stockholders. RG&E suggests it would never
earn the target return if this change is adopted.
At our October 8, 1997 session, we suggested that the 11.8% return on
equity sharing threshold was too high, especially given that the company had
recently earned excess profits, which it would retain fully under the April 8
Settlement, and that the provisions related to deferrals could result in the
need for rate increases at the end of the five-year term.
RG&E, Staff, and Multiple Intervenors maintain that the Revised
Settlement addresses our concerns. They cite the Revised Settlement's provision
that imputes 150 basis points of the 1997 rate year overearnings to the 11.8%
return on equity measurements over the five-year term. This would effectively
reduce the sharing cap to 11.5%.
The excess earnings allocation would also be reallocated such that (1)
half of the excess would be used to write down deferred costs accumulated during
the term, and any portion of this half remaining after deferrals are written
down would be retained by the company as earnings; and (2) with regard to the
other half of any excess earnings, the first $800,000 would be used to reduce
rates for certain large industrial and commercial customer classes. The
remainder would be used to write down accumulated deferrals or sunk costs, and
to the extent that any part of this latter half remains after writing down such
deferrals and sunk costs, we would determine its disposition.
Multiple Intervenors states that the $800,000 allocation for large
customers is intended to correct for the fact that a disproportionate share of
the SBC reallocation was directed to small customers. Staff asserts that the
Revised Settlement reduces the likelihood of rate increases at the end of the
five-year term.
CPB reiterates its claim that the earnings sharing trigger should be
10.2% and notes that, since the time its direct testimony was submitted,
interest rates on 30-year treasury bonds have declined by about 60 basis points,
which it claims would justify a lower equity return.
19
<PAGE>
CASE 96-E-0898
The Retail Council reiterates that the treatment of excess earnings is
unacceptable because the reallocation of excess earnings benefits only
shareholders or large customers.
The 11.5% sharing threshold falls within the range of equity returns
presented in this case: from 10% by CPB to 12.2% by RG&E. Although a cursory
view would lead to the conclusion that the 11.5% is on the high side, a closer
examination will show the 11.5% effective threshold is reasonable. First, it
must be remembered that we recently established an 11.2% sharing threshold in
the company's last case/1/ that covers the three-year period ending June 30,
1999. If earnings exceed that, over the entire three-year period, they were to
be shared equally between shareholders and customers, with the customers' share
being used to write down assets.
Second, the Revised Settlement would extend the stayout period by two
years, and would increase the company's business risk by removing its monopoly
status and subjecting it to competition. In addition, the Revised Settlement's
revenue reductions place more risk on the shareholders. The combination of the
two-year extension, increased business risk, and reduced revenues more than
justify the increase in the threshold for sharing.
Third, the Revised Settlement allocates more of any excess earnings to
write down deferred costs or sunk costs.
We do have one reservation about the provision that $800,000 of excess
earnings will be used to reduce rates for certain large customer classes. We
conclude that large customers will already receive substantial benefits under
other provisions of the Revised Settlement; thus, there is no need for this
unique additional benefit. Accordingly, we adopt this term of the Revised
Settlement on the condition that the first sentence of Paragraph 10(b) is
removed, and the words "...of this amount..." are deleted from the second
sentence.
- -------------------
/1/ Cases 95-E-0673 et al., supra, Opinion No. 96-27, mimeo pp. 7, 21, and 27.
-- --- -----
20
<PAGE>
CASE 96-E-0898
Gain on Sale of Generating Plants
- ---------------------------------
The April 8 Settlement contains no separate provisions for the
disposition of gains, if any, on the sale of electric generating plants.
Rather, any gains would be included in the return on equity and shared if that
return exceeds certain thresholds.
At our October 8, 1997 session, we stated our belief that the April 8
Settlement was unbalanced with respect to its treatment of any gain on the sale
of generating assets. We also sought a provision that would encourage RG&E to
sell generating plants. The Revised Settlement contains provisions that
increase the customers' share of gains realized on such sales, and provide an
incentive to encourage prompt divestiture of generation.
Staff and RG&E observe that the Revised Settlement generally provides for
a 20%/80% split between shareholders and ratepayers of any net gains over the
five-year term and that customers will benefit from any such gain on the sale of
generating assets regardless of the company's level of equity return. The split
may change to 40% shareholder and 60% ratepayer on the first $20 million of net
gain in the first three years of the Revised Settlement. These parties maintain
this additional allocation to the shareholder is a sufficient incentive to
encourage prompt divestiture.
CPB replies that a divestiture incentive is unwarranted because RG&E's
rates are among the highest in the nation and any rate reduction resulting from
the flow through of a net gain to ratepayers would make the company's rates more
competitive, produce additional sales, and increase shareholders' earnings.
We find that the Revised Settlement's treatment of gains on the sale of
generating assets is reasonable because it ensures ratepayers will receive a
substantial portion of any net gains on the sale of plants that were acquired on
behalf of and financially supported by the ratepayers. In addition, we adopt
the incentive for RG&E to divest generating assets promptly because divestiture
will hasten the development of a competitive power market, the benefits of which
will redound to ratepayers,
21
<PAGE>
CASE 96-E-0898
consistent with Opinion No. 96-12, and, ensure a fair quantification of
strandable costs./1/
SBC Funding
- -----------
The recommended decision supported the April 8 Settlement provisions
related to the SBC charge, i.e., to flow through to ratepayers all mandated
----
increases and decreases in spending for SBC programs, which include research and
development, energy efficiency, low income, and environmental protection. The
level of spending already reflected in rates had been established in the 1996
Settlement, which set rates for the three-year period ending June 30, 1999.
AARP, CPB, and PII except to the recommended decision's conclusion not to
modify the April 8 Settlement provisions related to the SBC charge. They seek
specific spending levels. For example, CPB requests that the 1995 spending
levels be maintained throughout the five-year term, while PII supports
expenditures derived from a $.0015 per kWh rate charged to all energy sales.
Staff points out that the Revised Settlement would build specific SBC
expenditures into the rates, the cost of which would be greater than the total
that would be spent if the SBC were set at $.001 per kWh for three years.
However, Staff further explains that the expenditures would be spread over five
years because most of the expenditures relate to ongoing energy savings and
incentive payments that the company is obligated to pay for under its DSM
bidding program.
PII opposes the SBC modifications contained in the Revised Settlement
because it would reduce expenditures for these programs by nearly half from $7.8
million in 1995 to an average of $4.78 million beginning in 1998. PII sets
forth several examples of specific spending reductions that would result and
states that the cuts are inconsistent with the clearly expressed
- -------------------
/1/ Cases 94-E-0952 et al., supra, Opinion No. 96-12, mimeo p. 60.
-- --- -----
22
<PAGE>
CASE 96-E-0898
intention to preserve these programs at least during the transition period./1/
Furthermore, PII calls for the elimination of the Large Customer Credit
Program, which allows industrial customers to elect not to participate in the
DSM program and thereby receive a $.0003 per kWh credit. Arguing that RG&E will
no longer offer DSM programs, PII believes the credit should be terminated.
Since the SBC funding allowance contained in the Revised Settlement meets
our stated goal, we find these provisions acceptable. With respect to PII's
position that the Large Customer Credit Program be eliminated, we note that the
credit is subject to recalculation in the event that RG&E's spending on DSM
programs changes materially./2/
Other Proposals
- ---------------
Several parties support other changes to parts of the Revised Settlement
that are unchanged from the April 8 Settlement.
PII proposes a "price cap plus" mechanism for RG&E's revenue requirement,
which is a combined revenue cap and price cap. Under price cap plus, the
initial year's revenue cap would be set using traditional cost of service
regulation and in subsequent years, the revenue cap would be adjusted for three
factors: inflation, productivity, and growth. In addition, PII's price cap
plus includes a revenue cap true-up.
PII's price cap plus proposal is not acceptable because it could lead to
increased rates if productivity is not sufficient to offset inflation and, in
any event, would require annual regulatory oversight of the true-up mechanism.
In effect, this proposal runs counter to our objective, which is to rely more on
competition and less on regulation.
- -------------------
/1/ Cases 94-E-0952 et al., supra, Opinion No. 96-12, mimeo p. 61.
-- --- -----
/2/ Cases 95-E-0673 and 95-G-0674, Rochester Gas and Electric Corporation -
----------------------------------------
DSM, Opinion No. 95-20 (issued December 27, 1995), mimeo Appendix p. 9.
---
23
<PAGE>
CASE 96-E-0898
CPB proposes to reduce the revenue requirement by $235,000 to reflect
reforms in Workers' Compensation Law. CPB's adjustment is subsumed in the
overall revenue reductions required by this order and is rejected because this
change is but one of many changes expected in the future that will affect
earnings subject to the sharing threshold.
CPB also proposes we modify the provision that would permit RG&E to defer
the costs of operation and maintenance related to inflation in excess of 4.0%.
CPB states we should simultaneously require the return on equity to drop below
9% before deferral is permitted. The CPB's modification is asymmetrical, i.e.,
----
RG&E would have to bear 100% of the excess inflation risk as the return on
equity drops from 11.5% to 9.0%, but the company would only retain a small
portion of the upside benefit above the 11.5% equity return because of other
equity return sharing mechanism we adopted supra. Consequently, this proposal
-----
is not adopted.
AARP excepts to the property tax incentive, which would allow RG&E to
defer for future recovery or pass back to ratepayers 50% of any property tax
expense increase or decrease in comparison to the base level, i.e., the actual
----
tax expenditures during the 12 months ended February 28, 1997 less taxes related
to any assets sold after June 30, 1997. The other 50% would be reflected in the
rate of return computations. AARP characterizes the provision as a bribe to get
the company to lobby for tax reductions.
AARP's exception is rejected because the provision will encourage RG&E to
pursue reductions in the cost of property taxes, or failing that, because the
provision will spare customers half of any increase in such costs.
We note that certain provisions of the Revised Settlement (i.e., (P)(P)8,
----
11-17, 24 (with respect to shut-down costs), and (P)30) provide for deferral and
recovery without requiring further petition to or approval by us. Without
altering the intent of these terms, we adopt them on the condition that a formal
petition will be filed with us prior to
24
<PAGE>
CASE 96-E-0898
establishing deferrals or commencing any recovery during the five-year term.
Finally, we also observe that the Revised Settlement refers to possible
Statewide resolution of the future ratemaking and ownership of nuclear
facilities. Paragraph 23(d) states that "no change in the treatment of RG&E's
nuclear facilities shall be implemented until at least January 1, 2000." The
January 1, 2000 date might be construed as precluding a sale or transfer,
through an auction or otherwise, of the company's interest in nuclear facilities
until at least the year 2000 and, thus, could conflict with subsequent action on
the August 1997 Staff Report on Nuclear Generation. We adopt this paragraph on
the condition that (P)23(d) is modified to read as follows: "no change in the
treatment of RG&E's nuclear facilities shall be implemented prior to the
Commission's resolution of the August 1997 Staff Report on Nuclear Generation."
REVENUE ALLOCATION AND RATE DESIGN
----------------------------------
Pursuant to the April 8 Settlement, revenue decreases would generally be
allocated to RG&E's service classes based on their responsibility for generation
costs. As a result, the large industrial customers would receive rate
reductions of 10% to achieve an average rate of $.056 per kWh; large commercial
customers would receive rate reductions of 8% to achieve an average rate of
$.068 per kWh; other industrial and commercial customers would receive rate
reductions of 3.7% to achieve an average rate of $.08 per kWh; and residential
and small business customers would receive rate reductions averaging 2.5%, with
rates varying depending on usage and classification. Several specific rate
design changes were also set forth, including among others a proposed annual
$1.50 increase in the monthly customer charge for residential and small business
customers.
The Judge recommended the allocation favoring the large industrial
customers because (1) as Multiple Intervenors had observed, RG&E's residential,
commercial, and industrial rates were in 1995, respectively, 34.6%, 32.1%, and
61.5% above
25
<PAGE>
CASE 96-E-0898
corresponding national average rates, which justifies proportionately greater
reductions for the industrial class, and (2) the allocation of revenues and
individual rate changes would move RG&E's rates closer to the marginal costs,
which is economically efficient and makes sense in an increasingly competitive
electricity market.
With respect to the increases in the monthly charge, the recommended
decision concluded that the ultimate customer charge of $17.50 is justified by
the fact that the comparable marginal cost is about $20./1/
CPB excepts, arguing greater attention can and should be paid to rates
charged for electricity around the country. It provides extensive legal
arguments in support of this proposition. Assuming we were to adopt this
approach, CPB concludes we should adopt equal across-the-board percentage
decreases for all classes.
AARP objects to residential customers receiving smaller decreases and
argues substantial joint and common costs should not be allocated to customer
costs so more of them can be covered in rates paid by non-residential users.
PULP contends that we have no statutory authority to favor larger
industrial customers over other customers. PULP also asserts it is irrational
and illegal to favor this one customer class over others as there assertedly has
been no showing the industrial customers need such a decrease.
PII claims that the customer charge should not be increased from the
current $10 monthly charge to $17.50 over the five years because the marginal
cost study was calculated three years ago and was not submitted in this case,
and because the effect of such a charge would increase bills for 43% of the
residential class even with an overall revenue decrease. In addition, PII is
concerned that the decrease to energy rates would carry negative environmental
consequences. According to
- -------------------
/1/ Exhibits 50 and 51, Tr. 1,450-1,459.
26
<PAGE>
CASE 96-E-0898
PII, the increase in sales would be accompanied by an increase in pollution.
Staff, RG&E, and Multiple Intervenors support the recommended decision's
findings with respect to revenue allocation and rate design. They note that
rates must be realigned to promote economic development and industrial
competitiveness. For example, Staff reasons that industrial customers who may
be considering whether to expand in Rochester or to relocate and expand
elsewhere might be induced by lower rates to remain in the RG&E service
territory. The resulting expansion of facilities and creation of new jobs,
Staff states, would have positive economic impacts for the ratepayers and for
the local community.
These parties further assert that marginal costs are a rational basis
upon which to set rates, and large customers are contributing revenues
disproportionately in excess of their marginal costs of service relative to
residential and other small customers.
With respect to the annual $1.50 increase in the monthly customer charges
over the term of the April 8 Settlement, Staff and RG&E readily concede that
about 43% of the residential class would experience bill increases, but they
note that the current customer charge is well below the $20 marginal costs, and
energy prices overall are well above marginal costs, resulting in improper price
signals upon which customers base their decisions. RG&E also notes that its low-
income customers are just as likely to consume more than the average level of
energy as they are to consume less than average. Therefore, RG&E believes that
the increase in the customer charge will not fall disproportionately on low-
income customers.
At our October 8, 1997 session, we did not question the rate reductions
for large industrial customers but expressed interest in providing larger rate
decreases to residential and other small customers. In addition, we asked the
parties to reconsider the customer impact of five annual increases of $1.50
27
<PAGE>
CASE 96-E-0898
in the monthly customer charge, but acknowledged that larger rate reductions for
small customer classes might allay this concern.
RG&E, Staff, and Multiple Intervenors note that the Revised Settlement
would give all service classifications at least a five percent reduction. They
explain that through reallocation of the SBC funding and the use of Gross
Receipts Tax (GRT) reductions the overall revenue decrease will change from
$27.1 million (4.1%) to $40.6 million (6.1%). Multiple Intervenors points out
that a disproportionate share of the SBC reallocation (approximately $800,000)
was directed to the residential and small commercial customers. Staff states
that every class will receive the benefits of the GRT reductions.
The Attorney General, CPB, Retail Council, PII, PULP, and Mr. Straka
claim that even further reductions are warranted for the residential and small
commercial classes. PULP maintains the allocation of the revenue decrease is
not balanced and there is no support for the proposition that the industrial
customers are paying a subsidy under current rates. PII, CPB, and Mr. Straka
also observe that the planned rate reductions for residential and small
commercial customers are back-end loaded, i.e., by year four these customers
----
will receive a 2.62% reduction and then in year five jump to the full decrease
of about 5%. On the other hand, PII states that the largest industrial
customers will receive 11.2% decreases, or most of their reductions, by year
four. The Attorney General adds that the flow through of the GRT reductions
would cost RG&E nothing and the rates contained in the Revised Settlement would
still be uncompetitive.
Mr. Owens, Mr. Straka, and CPB claim that 36% of residential customers
would still receive a bill increase under the Revised Settlement, which they
state is unacceptable. Mr. Owens recommends that the monthly charge increase be
halved to $.75 per year, while CPB would eliminate any increase in this rate.
As CPB argues, we can consider a number of factors in determining a
proper level of rates. An important consideration is the competitiveness of
RG&E's rates with those of other areas
28
<PAGE>
CASE 96-E-0898
in the nation. As large industrial customers have the widest array of
competitive alternatives, and are very sensitive to the level of rates, their
rates should be aligned as closely as possible to comparative alternatives.
Under the April 8 Settlement, the large industrial rates would have been
ultimately reduced to $.056 per kWh on average, which approaches the industrial
national average price for electricity of approximately $.046 per kWh. Under
the Revised Settlement, the industrial rates would be $.055 per kWh.
However, we find that the residential and small commercial customers/1/
would not receive sufficient revenue reductions under the Revised Agreement. We
will increase the revenue reductions for those customers from approximately 5.0%
to 7.5% in the final year of the term. This change requires a corresponding
adjustment to the Revised Settlement's cumulative reduction from $51.1 million
to $64.6 million for July 1, 2001.
The Revised Settlement provides that, beginning July 1, 1999 and
continuing through June 30, 2002, Incremental Manufacturing Load shall be served
at an average rate of $.059 per kWh. We adopt this term on the condition that
the average rate instead is $.045 per kWh so that it approximates the national
average rate.
With respect to the increase in the residential and small commercial
customer charges, we observe that the increases are based on comparisons of
rates and marginal costs, which suggest energy rates should be reduced and that
customer charges may be increased without exceeding cost. This realignment is
consistent with the coming competitive market for electricity and retailing
services. We note that the further rate reductions approved for the residential
customers will reduce to 27% the percentage of customers who will receive bill
increases on average. It should also be noted that the yearly $1.50 increase
- -------------------
/1/ Residential and other small users are identified in the Revised Settlement
schedules by their lower voltage class as "pri-pri," "sec-sec," and
"pri-sec."
29
<PAGE>
CASE 96-E-0898
in the monthly customer charge had already been approved for the three years
ending June 30, 1999 in the company's last rate proceeding. The Revised
Settlement reasonably extends the increase for three more years.
Lastly, PII's opposition to a decrease in energy charges, because of
potential negative environmental impacts, is rejected. Even with the change,
energy rates will remain above marginal costs and PII has offered no evidence
that environmental impacts are so substantial as to exceed the environmental
thresholds discussed infra.
-----
THE PROGRAM
-----------
Single Retailer Model/1/
- ---------------------
The single retailer model is the foundation upon which the entire Program
is built. According to the April 8 Settlement, a single retailer, or LSE, would
purchase power on the open market and distribution access from RG&E. The LSE
would market the power to customers and would be responsible for scheduling
deliveries based on load shapes or real-time meter data. Also, for the first
three years of the Program, RG&E would offer billing services to the LSEs so
that they may commence operations without having to wait for development of
their own billing systems. RG&E would retain ownership of the meters.
Numerous objections were raised. The recommended decision considered
many of these but did not address WEPCO's security deposit concerns because the
issue would be the subject of an operating agreement.
On exception, WEPCO asserts that the single retailer model would preclude
all but the largest LSEs from entering the market because it fears RG&E will
require LSEs to post security deposits, and to participate in service
restoration efforts and
- -------------------
/1/ The issue of the applicability of the Home Energy Fair Practices Act to
single retailers has been considered in another Commission order. Cases
94-E-0952 and 96-E-0898, supra, Order Regarding Regulatory Regime for
-----
Single Retailer Model (issued December 24, 1997).
30
<PAGE>
CASE 96-E-0898
power quality matters. In lieu of a security deposit, WEPCO proposes a "lock
box" approach, i.e., a shared bank account between the LSE and RG&E.
----
RG&E responds that these issues should be part of the discussion leading
up to an operating agreement because there are less costly approaches than the
"lock box" approach such as individual guarantees, letters of credit, and escrow
arrangements. With respect to participation in service restoration and power
quality issues of WEPCO, RG&E argues that these customer contacts are an ongoing
element of being a retailer.
We agree with the Judge that these issues should be considered in
connection with an operating agreement especially in view of our recent opinion
to require utilities to file tariffs covering various operating procedures./1/
Until the parties have an opportunity to address both the proposed tariffs and
operating agreements, these issues are not ripe for decision.
Implementation Schedule
- -----------------------
As noted above, retail competition would be introduced in stages over
five years, beginning with a one-year Energy Only stage and then a multi-year
Energy and Capacity stage. The recommended decision supported this approach to
give RG&E sufficient time to overcome problems relating to its nuclear plants
and load pockets.
A number of parties except. CPB urges full retail access no later than
one year after the implementation of the independent system operator (ISO). The
Attorney General believes that an accelerated schedule is needed because the
five-year term would be too restrictive, precluding chances to take advantage of
arising opportunities. In the meantime, the Attorney General urges that the
1996 Settlement be left in effect, the company be
- -------------------
/1/ Case 94-E-0952, In the Matter of Competitive Opportunities Regarding
----------------------------------------------------
Electric Service, Opinion No. 97-5 (issued May 19, 1997), mimeo p. 34.
- ----------------
31
<PAGE>
CASE 96-E-0898
required to solve its nuclear and load pocket problems, and retail access be
implemented shortly after competition becomes technically feasible.
IPPNY/Enron and WEPCO assert that RG&E's problems are not technical but
rather financial. They believe that the problems can be addressed now and the
Program can be accelerated. According to IPPNY/Enron, the April 8 and Revised
Settlements themselves support its statement that there are no technical
impediments because they provide for an accelerated retail access schedule if
the market price for power is above RG&E's back-out rate of $.032 per kWh.
Several parties point to the more rapid introduction of retail access required
in other states as justification for a quicker timetable for RG&E.
At our October 8, 1997 session, we urged the parties to consider and
explore ways to speed up the introduction of retail access. We noted that the
April 8 Settlement calls for an accelerated schedule only if a statewide
resolution of nuclear generation issues permitted an earlier placement of such
power on the market, or if market prices for power exceeded $.032 per kWh on a
persistent and sustained basis. The Revised Settlement contains a new
provision, which establishes a process whereby the parties will meet prior to
July 1, 2000 to assess the feasibility of accelerating retail access.
Staff believes that this new process is preferable to renegotiating a
number of important provisions related to the retail access schedule.
CPB, the Attorney General, WEPCO, the Retail Council, and Mr. Straka
disagree. They assert that the retail access schedule is protracted and will
cause RG&E to fall behind other upstate utilities such as NYSEG and Niagara
Mohawk, which have proposals under which all customers would be eligible for
retail access by the end of 1999. WEPCO contends that RG&E's nuclear generation
is not a reason to delay implementation of retail access because we indicated
that the State should move toward retail competition with due speed even without
a statewide
32
<PAGE>
CASE 96-E-0898
solution to nuclear issues./1/ CPB wants full retail access for RG&E by 1999 or
within 12 months of the implementation of the ISO.
The Attorney General seeks clarification of the modified language. It
notes that the provision to consider accelerating retail access could be read as
providing RG&E with veto power concerning any change in the schedule for
implementation of competition, and the Attorney General would rather have us
grant other parties the right to submit a recommendation without RG&E's
concurrence. In addition, the Attorney General understands that the "risk" that
must be addressed relates to RG&E's profits, which it claims should be
explicitly stated./2/
We recognize that RG&E is unique among the state utilities in that more
than half its generation is nuclear fueled, and therefore believe that a phase-
in of retail access should be long enough to give RG&E sufficient time to
address this fact. However, we find the five-year phase-in period for retail
access to be excessive, and conclude that four years should suffice.
Consequently, we will require full implementation for the Program by July 1,
2001, which is one year earlier than provided for in the Revised Settlement.
The last sentence of (P)52 of the Revised Settlement (which is set forth
in the preceding footnote) provides for a
- -------------------
/1/ Cases 94-E-0952 et al., supra, Opinion No. 96-12, mimeo p. 88.
-- --- -----
/2/ The relevant portion of (P)52 of the Revised Settlement is as follows:
The parties further agree that, prior to July 1, 2000, they shall meet to
review the progress of retail access under the Program and shall consider
and recommend to the Commission, as appropriate, any changes to the
implementation schedule that are determined to be necessary; provided,
however, that no such changes shall be recommended unless they are revenue
neutral and do not materially increase the level of risk borne by the
Company.
33
<PAGE>
CASE 96-E-0898
possible increase in the pace of retail access implementation if certain
conditions are met. In light of our modification of the retail access schedule,
the last sentence is unnecessary, and therefore, is not adopted.
Not only will full retail access be achieved one year earlier, but also
the effective percentage of retail access available for the non-contract
customers should be greater than identified in the Revised Settlement. This is
because a large part of RG&E's load is under contract and these contract
customers cannot participate in the Program until their contracts expire.
Consequently, a greater proportion of the non-contract customers will be able to
switch to the Program in the early years.
Delivery Rates
- --------------
The April 8 Settlement includes rates for delivery during both stages of
the Program. During the Energy Only stage, the distribution access rate would
equal the average rate for bundled retail service less the per-unit retailing
cost and the per-unit energy-related cost of all non-nuclear energy sources,
estimated to be at least $.013 per kWh.
In the Energy and Capacity stage, the rates charged to LSEs would equal,
on average, the rates for bundled retail service less $.032 per kWh, which
includes retailing cost of $.004 per kWh and the per-unit fixed and variable To-
Go Costs of non-nuclear energy sources, exclusive of a portion of property
taxes. Twenty percent of the property tax component of the per-unit non-nuclear
To-Go Costs would be deducted from bundled rates upon commencement of the Energy
and Capacity stage and an additional 20% commencing every 12 months thereafter
during the term of the April 8 Settlement. The actual distribution access rates
would be filed as tariff changes.
Pursuant to the April 8 Settlement, when the Program is opened to all
retail customers on July 1, 2002, the company would be authorized to modify its
distribution access rates, so as to hold constant the degree to which its To-Go
Costs are at
34
<PAGE>
CASE 96-E-0898
risk for recovery through the market. The signatories to the April 8 Settlement
agree to meet before July 1, 2001 to discuss the future of these ratemaking
plans.
The recommended decision found the average rate reasonable and rejected
calls for a higher back-out rate and periodic updating. However, the
recommended decision found the retailing costs for residential customers is
greater than the average of $.004 per kWh. Thus, it would require RG&E to
estimate and reflect the actual retailing costs in each class's back-out rate
when it is filed.
AARP and WEPCO except, arguing the back-out rate is too low and will
inhibit competition. These parties ask us to order RG&E to reflect the proper
retailing costs in each class's back-out rate. In addition, WEPCO questions the
justification for an Energy Only stage because the $.013 per kWh is so low that
it is unlikely that LSEs or customers would participate in this stage. WEPCO
supports its argument by pointing to the experience in Orange and Rockland
Utilities' pilot program, which contained an energy-only format. According to
WEPCO, that program did not produce sufficient savings to warrant participation
by small customers. WEPCO requests that the initial back-out rate be set at
$.032 per kWh with appropriate updating each year.
WEPCO also argues that a fixed back-out rate for a period of two to five
years in a highly uncertain environment would entail considerable risks. If the
fixed back-out rate understates the market price of energy and capacity, WEPCO
claims that a robust competitive retail market will not develop. When entering
into a highly uncertain situation, WEPCO advises, the best course of action is
to build in checkpoints such as an annual reset of the back-out rate.
RG&E agrees with WEPCO that the Energy Only stage has limited value, but
observes that until the necessary supporting mechanisms and structures for a
capacity market are in place, capacity charges will be incurred by RG&E, which
it must recover. RG&E opposes an annual update of the $.032 per kWh back-out
rate because (1) a fixed rate will provide competitors with a stable
35
<PAGE>
CASE 96-E-0898
target against which to compete and (2) a fixed rate will limit the risk faced
by the company from customer migration to retail access. Periodic updating,
RG&E notes, would subject it to a variable level of risk and therefore upset the
balance struck by the signatories to the April 8 Settlement.
Staff maintains that the April 8 Settlement does not preclude update of
the back-out rate if circumstances warrant such action, but agrees that at this
time the overriding concern is to create a stable and certain rate for LSEs.
With respect to the appropriate level of retailing costs to include in
the back-out rate, Staff and RG&E oppose the recommended decision's proposal to
compute each class's retailing costs. Staff observes that such a proposal would
add an unwarranted level of complexity in the tariffs. RG&E maintains that even
if the $.004 per kWh retailing cost is less than actual for the residential
customer class, it does not follow that the overall back-out rate is understated
given that residential customers receive substantial allocations of NYPA
hydropower at low rates. The net effect, according to the company, is that the
combined cost of energy, capacity, and retailing is approximately equal over all
classes.
At our October 8, 1997 session, we expressed our desire to have the back-
out rate during the Energy Only stage approximate market energy prices and to
require the company to sell energy at that price.
According to RG&E, Staff, and Joint Supporters, the Revised Settlement's
back-out rate of $.02305 per kWh (inclusive of $.004 per kWh retailing costs) is
designed to address our concern that the earlier estimated $.013 per kWh back-
out rate was too low to encourage competition. Staff observes that the
significant increase in the back-out rate also automatically reduces the
delivery rate charged to LSEs. The proponents further note that RG&E is now
committed to giving LSEs the option of purchasing energy from RG&E at $.01905
per kWh, the energy portion of the back-out rate. CPB agrees that this rate
appears reasonable.
36
<PAGE>
CASE 96-E-0898
WEPCO acknowledges that the new rate is an improvement, but maintains it
still falls short of WEPCO's estimate of approximately $.028 per kWh for the
wholesale cost of purchasing power. Consequently, it believes that LSEs will be
forced to purchase power from RG&E. WEPCO objects to the use of the $.004 per
kWh company-wide average cost of retailing, reiterating its claim that the
actual retailing costs for small customers is higher. It cites our recent
decision in the Dairylea Case/1/ in which a $.01 per kWh adder was adopted for
small customers.
We conclude that the Revised Settlement's back-out rate during the Energy
Only stage is acceptable. The Energy Only stage is expected to be implemented
before the development of a mature statewide energy and capacity market. In
addition, RG&E should gain valuable experience during the Energy Only stage
because it will provide a controllable and workable environment in which to
prepare for the remaining phase of retail access. In sum, we are unpersuaded by
WEPCO's objections to the Energy Only stage.
With respect to the Energy and Capacity stage, the use of the $.032 per
kWh fixed back-out rate should contribute to a stable competitive market because
the rate is based on RG&E's costs and the lack of periodic updating will provide
potential competitors with predictable competitive target back-out and
distribution rates--significant inputs to their price.
One item still concerns us, however. The Revised Settlement identifies a
contestable rate of $.032 per kWh, but does not indicate whether GRT is
considered in the derivation of that amount. We adopt this rate subject to the
clarification that the $.032 rate includes the impact of GRT.
Finally, the recommended decision's suggestion to reflect actual
retailing costs in each service classification is rejected because it would add
a layer of unnecessary complexity. This complexity would arise not only from the
allocation of
- -------------------
/1/ Case 96-E-0948, supra, Order Establishing Retail Access Pilot Program, pp.
-----
13-16.
37
<PAGE>
CASE 96-E-0898
retailing costs themselves, but also from consideration of other class specific
changes that parties would no doubt raise as further refinements.
Other Retail Access Issues
- --------------------------
PULP's claims that we lack the authority (1) to approve general retail
wheeling for all customer classes, and (2) to deregulate new generation
providers. PULP is essentially repeating the arguments it raised in an Article
78 proceeding challenging Opinion No. 96-12. The Supreme Court/1/ has rejected
PULP's claims, and they are rejected here based on the rationale set forth in
the Con Edison rate/restructuring decision./2/
NYPA's and RG&E's exceptions to the recommended decision's refusal to
consider a separate Economic Development Power (EDP) tariff rate are denied.
Since NYPA has no EDP customers in RG&E's service territory and the Revised
Settlement does not address EDP rates, we see no need to address this issue in
this decision. However, if a customer requests an EDP rate in the future, we
will address the issue at that time.
CPB's request to require LSEs to provide price information to applicants
in a common format is rejected. This requirement is unnecessary in a
competitive market where participating marketers have the incentive to show
prospective customers how their prices, however packaged, compare to those
offered by others.
AARP's call for a fund to establish a POLR that would provide consumers
with electricity at affordable prices is denied. Recognizing that innovative
POLR pilot programs could be
- -------------------
/1/ Energy Association et al. v. Public Service Comm'n, 169 Misc. 2d 924, 933
--------------------------------------------------
(1996).
/2/ Case 96-E-0897, Consolidated Edison Company of New York, Inc., Opinion and
---------------------------------------------
Order Adopting Terms of Settlement Subject to Conditions and
Understandings, Opinion No. 97-16 (issued November 3, 1997), mimeo p. 30.
38
<PAGE>
CASE 96-E-0898
explored, we have decided that, "[f]or now, the utilities will function as
POLRs."/1/
AARP, CPB, and PULP also raise a number of concerns about consumer
protections and marketing guidelines. As these concerns were either already
considered or are the subject of a separate proceeding,/2/ all of these
exceptions are denied.
Finally, CPB calls for the development of a customer education program
because it believes the April 8 Settlement (and for that matter the Revised
Settlement) does not address this item. CPB's exception is denied; the Revised
Settlement ((P)73) sets forth the requirement that RG&E file a consumer
education plan. This Department will also be continuing broad outreach and
education efforts, as well as monitoring and overseeing the utilities' own
outreach and education efforts, which should be considerable.
CORPORATE STRUCTURE
-------------------
The Revised Settlement incorporates the April 8 Settlement's provisions
that would require RG&E to functionally separate its existing operations and
structurally separate its ULSE. In addition, RG&E would be permitted to form a
holding company. The recommended decision agreed with these proposals because
the high cost of divestiture effectively precludes structural separation,
especially with respect to the company's sizable nuclear assets. In addition,
the recommended decision found reasonable the principles set forth in the April
8 Settlement relating to affiliate relationships, code of conduct, cost
allocations, protections, and restrictions because they were based on standards
approved in other cases and would permit our review in the event of abuse.
Finally, the recommended decision concluded that no proscriptions, prohibitions
against competition, or royalty payments should be imposed on RG&E
- -------------------
/1/ Cases 94-E-0952 et al., supra, Opinion No. 97-5, mimeo p. 43 and Opinion
-- --- -----
No. 97-17, mimeo p. 21.
/2/ Ibid., p. 26.
-----
39
<PAGE>
CASE 96-E-0898
because the rate reductions, among other things, are a quid pro quo for the
---- --- ---
benefits the company expects to receive through the operation of its unregulated
businesses.
The Attorney General and CPB prefer divestiture of generation to prevent
self-dealing and other abuses arising from affiliate relationships. The
Attorney General fears that Staff may not have the resources to audit
effectively the various transactions among the affiliates. CPB would extend the
standards for the relationship between distribution entity, i.e., the DISCO and
----
its ULSE, to the DISCO's relationship with the RSLE. CPB also supports physical
separation.
WEPCO seeks to prohibit RG&E's unregulated marketing affiliate from using
RG&E's name, relying on the expertise and experience of utility personnel, and
relying on RG&E's financial resources. Furthermore, WEPCO asks that RG&E's
affiliates be excluded from competing in the service territory for two years or
until 20% of the company's customers are served by LSEs.
The Attorney General and CPB seek a royalty payment from the unregulated
subsidiaries to compensate the regulated utility for good will that RG&E's name
and affiliation will bring them.
RG&E has stated that it will transition out of its wholly-owned fossil
and hydro generation over the next several years. The company plans to retire
or otherwise remove Ginna Station from rate base when its license expires in
2009, and prior to that Ginna Station and Nine Mile 2 are subject to a statewide
resolution of nuclear plant ownership and ratemaking. In view of the relatively
short remaining lives on much of the company's generation, the pending
resolution of nuclear plant issues, and the incentive to divest plants,
functional separation of RG&E's existing operations is accepted. The structural
separation of its ULSE are subject to the various rules, codes, and restrictions
set forth in the Revised Settlement. Inasmuch as most of these provisions are
based on standards we established in other proceedings, and are expected to
anticipate likely
40
<PAGE>
CASE 96-E-0898
potential abuses, they are adopted without the modifications proposed by CPB.
RG&E's affiliates will not be prohibited from using the name of RG&E or
competing in the company's service territory, or be required to pay a royalty
for the use of the RG&E name and its affiliation. These concessions were part
of the give and take in the negotiations and will not be disturbed.
Finally, whether RG&E conducts its unregulated activities through a
holding company or a separate subsidiary of a utility parent, the company would
be permitted initially to fund its activities in the amount of $50 million under
the terms of the Revised Settlement. Except for the $50 million, RG&E's
regulated business segments would not be permitted to fund such unregulated
operations, and would neither be allowed to make loans to, nor guarantee or
provide credit support for, the obligations of unregulated affiliates.
In view of our changes and modifications to the Revised Settlement,
especially the acceleration of the introduction of retail access, and our desire
to bring the benefits of a competitive electric generation industry to New York
consumers, we will increase the maximum for funding for unregulated activities
to $100 million.
ENVIRONMENTAL MATTERS
---------------------
The recommended decision did not support calls for a mandatory disclosure
of generation sources and the imposition of more stringent environmental
requirements on older generation facilities. We previously considered and
rejected similar requests in a separate proceeding./1/ PII and CPB except,
pointing out that we did not expressly reject these proposals and arguing they
should be considered here.
PII and CPB are correct in part. In fact, at our October 8, 1997
session, we directed the parties to consider designing a method of providing
customers with environmental
- -------------------
/1/ Case 94-E-0952, supra, Opinion No. 97-5.
-----
41
<PAGE>
CASE 96-E-0898
information. The Revised Settlement contains language requiring the company to
work with LSEs on developing such environmental information.
However, we will not impose more stringent emission standards on older
generation facilities. We view this request by PII as a thinly disguised
attempt to impose new environmental standards on older plants, which will not
likely create a level playing field for competing generation sources. The fact
that these plants have an advantage in costs attributed to lower emission
standards is but one cost consideration. PII did not address the total cost,
which includes other factors that may more than offset this advantage.
MARKET POWER MITIGATION
-----------------------
During the five-year term, RG&E would be required to maintain its system
in the most cost effective manner, file a market power mitigation plan with the
Federal Energy Regulatory Commission (FERC),/1/ and take appropriate action in
accordance with the outcome of that filing. The Revised Settlement also
reserves our right to implement market power mitigation measures for retail
service after the five-year term. The recommended decision found these
provisions reasonable.
A number of parties raise concerns that anticipate problems related to
market power and load pockets. In comments on the Revised Settlement, PII
suggests RG&E is only bound to "consider" a range of options to maintain the
reliability of its system. Accordingly, PII repeats its demand that the company
be "obligated" to undertake various forecasts, load monitoring programs,
evaluations, and implement alternates to major transmission and distribution
additions.
- -------------------
/1/ RG&E filed its request to engage in wholesale sales of capacity and energy
at market based rates with FERC on July 1, 1997 and amended it on July 25,
1997. RG&E addressed the issue of market power in its request to FERC. By
order issued September 12, 1997, FERC accepted RG&E's filing.
42
<PAGE>
CASE 96-E-0898
These exceptions are denied without prejudice. As noted in its FERC
filing, RG&E has committed to implement transmission system upgrades, which by
June 1999 will eliminate load pockets for all but 3% of summer hours. Moreover,
because RG&E must maintain system reliability within load pockets by operating
its units, the cost of which are already in rates, market power concerns are
mitigated. Any auction of RG&E generation will be subject to our approval to
ensure, among other things, that any market power concerns are addressed. If a
specific problem should arise in the meantime, we will address it on an ad hoc
-- ---
basis.
FINDINGS UNDER SEQRA
--------------------
In conformance with the State Environmental Quality Review Act (SEQRA),
we previously issued a Final Generic Environmental Impact Statement (FGEIS) on
May 3, 1996./1/ We also required individual utilities to file an environmental
assessment of their October 1996 restructuring proposals. RG&E filed an
Environmental Assessment Form (EAF) concerning the April 8 Settlement on June
24, 1997./2/
Subsequent to filing of the EAF, PII filed a petition asking that a
Supplemental Environmental Impact Statement be filed. In its arguments
supporting the petition, PII raised several substantive issues for SEQRA
consideration. In a June 19, 1997 ruling, Chief Administrative Law Judge Lynch
narrowed the issues needing further consideration in the environmental
assessment.
The information provided by RG&E in its EAF, the parties' comments, the
Revised Settlement, and other information were evaluated in order to determine
whether the potential impacts resulting from adopting the Revised Settlement's
terms would be within the bounds and thresholds of the FGEIS adopted in
- -------------------
/1/ Cases 94-E-0952 et al., supra, Opinion No. 96-12, mimeo pp. 76-81.
-- --- -----
/2/ The final Environmental Assessment Form is Appendix C.
43
<PAGE>
CASE 96-E-0898
1996. The evaluation also considered the conditions and changes to the Revised
Settlement that we adopted at our session on November 25, 1997.
Arguably, all of the potential impacts need not be considered, given that
some result from Type II exempt rate actions. Nonetheless, the analysis
examined all areas in which impacts could reasonably be expected.
No impacts were found to be associated with price cap regulation. RG&E
currently operates under a form of price cap regulation; the continuation of
this rate setting approach for the regulated transmission and distribution
company, consequently, does not constitute a change induced by competition or by
the Revised Settlement. Moreover, the possibility of prudence review is seen as
an important deterrent to excessive infrastructure investments as well as an
incentive for promoting the use of targeted DSM as appropriate to avoid
excessive transmission and distribution upgrades.
No significant impacts were determined to result from either retirement
or new construction of generation as a result of the Revised Settlement. Also,
the company asserts it has no plans to either retire any of its existing
electric generating facilities or construct new generating facilities as a
consequence of the Revised Settlement.
The Revised Settlement will not result in significant new transmission
line construction impacts. The company's 1996 load pocket study indicates that
under high summer usage and equipment failures, load pockets may occur. An
application filed by the company with FERC (dated July 1, 1997 and amended July
25, 1997) contains RG&E's plan to reinforce its transmission and distribution
system in order to alleviate the two load pockets within its service territory.
The plan notes that with the exception of one new 115 kV transmission line
(under ten miles in length), the construction required will be limited to
capacitor and transformer work within existing substations.
44
<PAGE>
CASE 96-E-0898
Minor localized community economic impacts may occur (e.g. due to reduced
----
tax receipts), but these would be balanced by positive effects in other
localities.
A greater source of concern is the possible increase in air pollution
that could accompany increased demand for electric energy. It is likely that
increases in energy demand will result from the Revised Settlement's decrease in
rates (0.56% average annual increase in demand over the 1998-2012 period) and in
DSM expenditures (0.3% increase in demand). Each of these incremental growth
rates is an upper bound. For example, it is not clear that all of the rate
reductions from the Revised Settlement should be attributed to restructuring;
also, the lower DSM expenditures do not consider LSEs' DSM spending. Staff's
opinion is that the actual growth rates will be substantially less than the
corresponding rates in the FGEIS (1% annual incremental growth from the "high
sales" scenario, and 0.29% from the "no incremental utility DSM" scenario).
Because of the inherent uncertainty in forecasting future impacts, as a
matter of discretion, monitoring of RG&E's restructuring and environmental
impacts is being implemented,/1/ and an SBC is being established. While
limiting the rate decreases in the Revised Settlement, which were adopted after
extensive negotiations, could mitigate environmental impacts, this would reduce
the economic benefits of the rate reductions to consumers and businesses. The
mitigation methods we are adopting are reasonable in these circumstances.
Based on these analyses, the potential environmental impacts of the
Revised Settlement are found to be within the range of thresholds and conditions
set forth in the FGEIS. Therefore, no future SEQRA action is necessary.
- -------------------
/1/ November 26 Order, p. 8.
45
<PAGE>
CASE 96-E-0898
CONCLUSION
----------
Our Settlement Guidelines establish the following standards for assessing
a proposed settlement in light of our obligation to set just and reasonable
rates and a utility's burden, under the Public Service Law, of showing the
reasonableness of a rate change it is proposing:
a. A desirable settlement should strive for a balance among (1)
protection of the ratepayers, (2) fairness to investors, and (3)
the long term viability of the utility; should be consistent with
sound environmental, social, and economic policies of the Agency
and the State; and should produce results that were within the
range of reasonable results that would have arisen from a
Commission decision in a litigated proceeding.
b. In judging a settlement, the Commission shall give weight to the
fact that a settlement reflects the agreement by normally
adversarial parties./1/
Generally, we find that the Revised Settlement as modified/2/ provides for
reductions that are reasonable and provide ratepayers significant benefits over
the five-year term. In addition, ratepayers will no longer be liable for
credits arising from flex-rate discounts and past incentives. Furthermore, the
rates will be redesigned to more closely reflect marginal costs, which should
not only remove some of the inter- and intra-class return discrepancies, but
also bring the rates close to those expected when the electricity market is
competitive.
The Program in the Revised Settlement, as modified, is reasonable because
it phases in competition at a pace that will allow RG&E to overcome problems
related to its reliance on
- -------------------
/1/ Cases 90-M-0225 et al., supra, Opinion No. 92-2, Appendix B, p. 8.
-- --- -----
/2/ The November 26 Order required RG&E to submit a written statement
unconditionally accepting the conditions and modification contained
therein. On December 1, 1997, such a statement was duly filed with
the Secretary.
46
<PAGE>
CASE 96-E-0898
nuclear power, gives customers prompt access to a retail electricity market, and
provides for back-out rates at a level that should stimulate competition.
The proposed restructuring of RG&E in conjunction with the incentives to
operate its generating facilities efficiently, and the safeguards governing the
transactions of the various affiliates, are reasonable as discussed above.
While RG&E's ULSE will benefit by being permitted to use the corporate name and
up to $100 million of funding from the company, the ULSE will be an added source
of competition, the benefits of which should redound to electric consumers.
Although all of the signatories did not submit their litigation positions,
RG&E did. It is clear from reviewing the company's October 1, 1996 submission
that RG&E made substantial concession especially with respect to rate
reductions. Multiple Intervenors notes that it would have argued for larger
rate decreases, a faster phase-in of retail access, and a greater sharing of
stranded costs during the transition period.
It should also be kept in mind that a number of parties opposed the April 8
Settlement and the Revised Settlement and they litigated their positions. After
considering the facts and reasons behind their positions, we adopted a number of
modifications to the Revised Settlement.
In light of all of the above, we adopt the terms of the Revised Settlement
subject to the conditions and changes described above, which were previously
included in the November 26 Order.
The Commission orders:
- ---------------------
1. Clauses one through five contained in the Order Adopting Terms of
Settlement Subject to Conditions and Changes (issued November 26, 1997) are
adopted in their entirety and are incorporated as part of this opinion and
order.
47
<PAGE>
CASE 96-E-0898
2. Case 96-E-0898 is continued.
By the Commission,
(Signed) JOHN C. CRARY
Secretary
48
<PAGE>
EXHIBIT 23
Consent of Independent Accountants
We hereby consent to the incorporation by reference in the Prospectuses
constituting part of the Registration Statements on Forms S-3 (File Nos. 33-
60753 and 33-49805) and in the Registration Statement on Form S-8 (File No. 333-
22139) of Rochester Gas and Electric Corporation of our report dated January 23,
1998 appearing in Item 8A of the Rochester Gas and Electric Corporation Annual
Report on Form 10-K for the year ended December 31, 1997.
/s/PRICE WATERHOUSE LLP
PRICE WATERHOUSE LLP
Rochester, New York
February 11, 1998
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